R Street Institute
Regulatory Comments

“Comment on DOE RFI on Accelerating Speed to Power” Outreach to the Department of Energy

by Devin Hartman, Olivia Manzagol, Chris Villarreal, Kent Chandler, Michael Giberson
Nov 21, 2025
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issues: Electricity Policy, Energy and Environment, Federal Government Affairs

November 21, 2025

United States Department of Energy
Grid Deployment Office
SpeedtoPowerRFI@hq.doe.gov

From:
Devin Hartman, Olivia Manzagol, Michael Giberson, Kent Chandler, and Chris Villarreal
R Street Institute
1411 K Street NW, Ste. 900
Washington, D.C. 20005
(202) 525-5717
dhartman@rstreet.org

Re: Comments of the R Street Institute in Response to Request for Information (RFI) – Accelerating Speed to Power

The R Street Institute (RSI) appreciates the Department of Energy’s (DOE) RFI regarding stakeholder input on how to best utilize DOE funding programs and authorities to rapidly expand energy generation and transmission grid capacity to meet electric demand growth. RSI particularly supports DOE’s emphasis on reliability and affordability.

The power industry is not designed for rapid infrastructure change. Delays are, to some extent, unavoidable, as generation, transmission, and distribution infrastructure take years to develop. This has created an imbalance in response to the unexpected load growth seen in recent years.

Pairing competitive markets for power generation and retail services with sound cost-of-service oversight for transmission and distribution would provide a cost-effective path to correct this imbalance, but current regulatory and market structures cannot support the conditions this approach requires. As a recent RSI briefing for DOE highlighted, the main issues threatening least-cost, reliable service are rooted in government failures: anti-competitive generation and retail laws alongside deeply flawed permitting, siting, interconnection, transmission, and distribution policy. Because transmission policy falls largely under federal jurisdiction, another RSI briefing for DOE outlined federal reforms that lower electricity cost trajectories while expanding capacity.

Although DOE does not have the authority to reform most policy flaws, it does have significant influence as a convener, information provider, funder, and innovation hub. Our comments herein suggest the ways in which DOE influence could be most impactful in this regard. They draw from:

The DOE RFI poses questions within five categories; we have organized our suggestions in the same categories for ease of review.

1. Large-Scale Generation and Transmission Projects to Enable Load Growth

Section one of the RFI inquires specifically about proposed projects with respect to DOE funding, technical assistance, and siting and permitting support. As a public policy think tank, RSI refrains from identifying specific projects worthy of DOE support. Instead, we suggest key project selection criteria DOE should strongly consider:

2. High-Priority Geographic Areas for Targeted DOE Investment

The most significant infrastructure needs that follow geographic patterns tend to be areas with the least transmission headroom. Low-cost, rapid-deployment applications include:

Federal investments should anticipate future congestion patterns, which are driven by changes in the generation fleet and load patterns. Given large geographic variances in load-growth readiness, the location of load growth is arguably as or more important than the level of load growth. For example, whether data-center expansion occurs more within existing clusters (i.e., exacerbates load pockets) or in areas with transmission headroom has enormous bearing on grid-infrastructure requirements.

Past may not be prologue. Only in recent years have grid constraints become a central factor in siting criteria, while artificial intelligence workloads—particularly model training that has different latency and compute timing needs—have led data center developers to favor locations with higher and more reliable power capacity than earlier applications required. Energy constraints now appear to be the foremost consideration in many regional site-selection processes, though this trend could be offset by other factors, such as an increase in county-level moratoria on data-center construction. Given these dynamics, RSI stresses the need for DOE to have independent information sources that reflect emerging commercial conditions affecting where data-center and manufacturing load growth will likely occur.

3. Use of DOE Funding, Financing, and Technical Assistance

Generally, DOE technical assistance is most effective when it remedies information deficiencies. DOE funding and financing should deploy taxpayer dollars prudently to address legitimate market failures, such as knowledge spillovers and learning-by-doing. RSI recommends aligning DOE spending with research and development (R&D) spillover benefits and pursuing better program implementation practices. These include outcomes-based improvements to “program performance metrics, constant program reevaluation to determine when to phase-out government investment, stronger linkages to private sector needs and interests, and scrutinizing expenditures in the context of a constrained fiscal environment.” R&D programs must also be durable across administrations to strengthen their performance.

DOE Programs

DOE would benefit from strengthening its innovation agenda, investing less in low-risk, mature technology, which typically crowds out private capital, and investing more in riskier, early-stage concepts and technologies, even if failure rates are higher. The Advanced Research Projects Agency-Energy (ARPA-E) is one such model. 

To start on this path, DOE should reform the Loan Programs Office (LPO) and return to its roots as an innovation program. This would require building a performance-based risk tolerance. Past RSI work has suggested that LPO reform should:

Recent DOE decisions underscore the need for these reforms. DOE recently withdrew a loan for the Grain Belt Express project—one of the few competitive transmission projects using novel technology and voluntary cost allocation (i.e., market revenues, rather than captive customers)—but approved a loan for a routine and largely risk-free American Electric Power transmission system rebuild. This substitution of liquid private capital formation with public loans is an inefficient use of taxpayer spending that risks crowding out investment in innovative, competitive projects.

With regard to other programs:

Gaps in Capital Availability

Although capital availability does not appear to be a major barrier to generation or transmission investment in most regions, many utilities lack sufficient balance-sheet capacity to finance all the generation expansion to meet rising load growth. This problem should not be placed on federal taxpayers but rather addressed by states, recognizing that generation is not a natural monopoly and by opening access to competitive generators and allowing consumers to contract freely. The “speed-to-market” responsiveness between competitive generators in restructured states and cost-of-service generators is evident.

Transmission capital is already robust, with monopoly utilities typically recovering costs automatically in a nearly risk-free environment. Such cost-of-service regulation often carries perverse incentives for project selection based on cost and speed-to-market. The capital-access limitations instead accrue to third-party developers or transmission customers who bear costs and risk themselves but are often shut out of the marketplace by incumbent transmission owners. For example, third-party suppliers and customers are often willing to finance grid enhancements like network upgrades to expedite low-cost interconnection, yet utilities seek to block this form of market access. If a lack of utility capital were the norm, utilities in RTOs would likely welcome prospective generators and customers paying for network upgrades upfront.

For transmission and generation, DOE could incentivize more efficient business models and productive state and federal policy reforms by making funding conditional on competitive ownership status (i.e., competitive suppliers and voluntary consumer offtakers). This would naturally direct capital toward geographic areas where markets identify the greatest need. For example, competitive-project eligibility would reward merchant models that do not result in captive customer bases or the purchase of anchor capacity through a network open season in transmission-constrained areas (e.g., northern Virginia, Columbus, etc.) that are not fully subscribed.

Technical Assistance and Interagency Coordination

RSI’s reliability paper flagged the lack of coordination between policymaking authorities as a core impediment to generation and transmission development. DOE technical assistance would be highly valuable in improving interagency coordination with the Federal Energy Regulatory Commission (FERC) on speed-to-power initiatives. Memoranda of Understanding are useful tools to routinize interfaces that match interagency competencies and resources. A specific suggestion is for FERC and DOE to co-host a technical conference or workshop on speed to power. Considerations for this action include:

There is a clear precedent and need for this action. Conferences and workshops are among FERC’s most powerful tools to address pressing or novel issues. The ability of the Commission to engage interested parties directly and for those parties to provide relevant and responsive information into a record that can be used to effectuate outcomes is powerful. FERC has routinely used technical conferences and workshops to better understand interested parties’ resources, retail ratemaking perspectives, RTO market issues, and bulk reliability concerns. FERC also has experience jointly hosting these fact-finding opportunities, including coordination with both state regulators and NERC.

DOE staff expertise and resources can identify high-impact projects and inform permitting and siting decisions at the state and federal levels. For example, joint efforts by DOE and the Department of the Interior under the previous administration identified categorical exemptions under the National Environmental Policy Act (NEPA). In light of the Supreme Court’s Seven Counties decision, DOE may wish to assist broader efforts within the administration to determine the new regulatory baseline for NEPA permitting. The Coordinated Interstate Transmission Applications and Permits instrument can streamline federal transmission permits and serve as a conduit for state participation, creating a single process while respecting jurisdictional boundaries.

Although the RFI only prompted federal interagency coordination, RSI asserts that most of the variables in load growth readiness reside under state authority. Identifying and implementing effective state reforms requires specialized expertise in electricity as well as permitting and siting—skills that exceed the capacity of many state agencies. Therefore, DOE should aim to maximize state interfaces, either through its own initiatives or by augmenting those of other agencies, such as the collaboration between FERC and the National Association of Regulatory Utility Commissioners (NARUC). 

State public service commissions (PSCs) face a severe capacity deficit that limits their ability to enact and implement the reforms needed for load-growth readiness. DOE could reinvigorate state-assistance programs to enhance technical knowledge on issues including large-load tariffs, load forecasting, interconnection and transmission practices, and the merits of joining or reforming organized wholesale electricity markets. DOE previously had a cooperative agreement with NARUC, which may be an avenue for future program administration. Should DOE pursue this again, it is important to view states as innovative laboratories rather than subordinates, meeting each according to its individual PSC needs.

Data Access and Sharing

Customers, suppliers, and other collaborating groups need access to grid and energy usage data to evaluate bill impacts, identify optimal locations to site new resources and large loads, generate bills, and participate in RTO markets. DOE has supported work to develop model data-access and privacy practices for customer energy-usage data (DataGuard) as well as a standard to support access to such data (Green Button). Nevertheless, data access continues to be a barrier to customer choice and the development of new resources and services that support infrastructure deployment. For projects receiving DOE grant funding that include a data-access component, DOE should require adherence to data-access practices and requirements, including reliance on available standards to support sharing data (e.g., Green Button).

Transmission congestion remains difficult to assess outside of RTOs. This lack of visibility has prompted a coalition of consumer groups, led by the Electricity Consumers Resource Council, to advocate for an Independent Transmission Monitor. FERC has made no progress on advancing such an effort. DOE could assist by collecting and publishing proxies for transmission congestion outside of organized wholesale electricity markets or by financing third parties to do so. Evaluating the economic merits of ATTs in these regions is highly valuable, and the inability to measure avoided congestion outside organized markets has hindered further FERC policy on ATT use beyond Order 881. Without better congestion data, it will be difficult to implement the transmission reforms sought by the Trump Administration’s AI Action Plan.

Transmission project transparency is also very poor, and DOE could help address this issue. Within RTOs, data is non-standardized and often unreliable. Outside RTOs, the data is even worse, if it is available at all. Specifically, there is very limited publicly available information on cost drivers, project scope, and project timelines, nor is there any systematic or uniform recordkeeping. The Energy Information Administration (EIA) publishes some aggregated transmission-expenditure data but does not provide detailed build costs or full breakdowns by project or region. Overall, the modeling and forecasting of transmission in EIA’s Annual Energy Outlook remains limited.

4. Load Growth Trends

Load growth rates, location, and shape all have major implications for infrastructure use, needs, total costs, rate impacts, and system reliability. One of RSI’s DOE briefings highlighted the following high-level observations on load growth trends:

RSI assessed load growth trends in three footprints at the center of the load-growth discussion for this set of comments. Specifically, we used monthly data from three RTOs: the Midcontinent Independent System Operator (MISO), the PJM Interconnection (PJM), and the Electric Reliability Council of Texas (ERCOT). We also pulled forward market data from the Intercontinental Exchange. We observed the following load patterns:

DOE can improve load forecasting accuracy in various ways. These include:

DOE action to promote voluntary information sharing between load forecasting experts and regulators would be beneficial. However, DOE should refrain from the pursuit of forecasting standards. Centralized standards for load forecasting may constrain innovation and limit discovery.

5. Grid Infrastructure Constraints

In this section, RSI provides an overview of load growth readiness factors, as well as specific insight into two prompted areas of the RFI inquiry: interconnection and policy and regulatory uncertainty. To underscore the importance of reforms to unleash all resource types, we conducted a novel scenario analysis of resource additions by 2030. We also provide insights into the importance of demand-side management, which the RFI did not specifically seek but is critical to the objective of speed to power.

As we outlined in an October 2025 DOE briefing, six items factor into load-growth readiness: 

  1. Accurate load forecasting;
  2. Effective wholesale competition;
  3. Effective retail competition;
  4. Efficient permitting and siting, especially at the state level;
  5. Efficient interconnection; and
  6. Economical transmission expansion.

Based on these parameters, the area that is the most load-growth ready is ERCOT. ERCOT has the most efficient interconnection process and the most robust wholesale and retail competition in the country. It also has a relatively economical transmission-expansion process. In addition, Texas has relatively efficient permitting and siting laws, and the state is projected to have the highest load growth in the country. Texas distribution utilities and ERCOT have had load-forecasting challenges such as those noted above, but these are somewhat tempered because Texas relies on forward market expectations—not capacity planning like other states—to drive generation decisions.

Every other footprint has major limitations in multiple categories. For example, the Northeast and Mid-Atlantic have mostly effective retail and wholesale competition but face challenging state permitting and siting regimes that inhibit infrastructure development. In the Southeast and much of the West, the opposite is true: Most states have ineffective retail and wholesale competition but more favorable infrastructure permitting and siting laws. Interconnection has lower barriers to entry in RTO footprints, but FERC-jurisdictional RTOs remain well behind ERCOT in efficiency.

Similarly, economical regional transmission practices are far superior in RTO footprints, which make greater use of ATTs, rely on independent planning and cost-benefit tests, and put many transmission needs out for competitive bid. However, more than 90 percent of transmission investments are made outside of these processes; they are initiated by incumbent transmission monopoly utilities as local projects or initiated by RTOs as reliability-need projects, which are exempt from economic criteria. Such projects are developed by monopoly utilities with no cost-benefit testing, with ineffective cost-of-service prudence reviews, and are exempt from competitive forces. A FERC complaint brought by leading electric consumer groups, on which RSI provided expert testimony, sought to close the regulatory gap over local and reliability-need projects and redirect capital toward economical processes conducted by independent entities.

While transmission warrants the most federal attention given jurisdictional considerations, DOE technical assistance, reporting efforts, and other functions should increasingly emphasize market advantages in the load-growth era. In previous eras of anticipated load growth, cost-of-service utilities made inefficient capital decisions that forced captive customers to pay stranded costs for decades. In contrast, competitive generators shouldered the risk of load-growth rates and location, resulting in more efficient capital decisions and better risk management. The current load-growth era is in its early stages, but competitive generators and retailers are showing signs of outperformance. This is buttressed by the fact that competitive markets are far more equipped to economically and reliably integrate unconventional resources, namely those that are variable (e.g., wind and solar), use-limited (e.g., energy storage), and flexible demand. Cost-of-service utility planning in fragmented territories is increasingly economically inefficient and poses a reliability liability for regional resource and energy adequacy. For example, more than 90 percent of MISO needs are met by state integrated resource planning, which has created inefficiencies and has already led to capacity shortfalls.

Interconnection

A recent RSI policy study on electric reliability identified generator interconnection (GI) as the main resource-adequacy concern within the industry’s control. Current GI practices unnecessarily increase network upgrade costs that, even though predominantly incurred by generators, are entirely passed on to customers under cost-of-service generation or partially passed on to customers (e.g., higher power purchase agreement prices). FERC issued Order 2023 to improve GI processes, but the order did not fix the primary problems. RSI subsequently organized a coalition of consumer groups calling for deeper FERC reform, which sparked Senate legislation. FERC did not, however, take policy action and instead held a workshop. In the absence of regulatory action, RTOs have brought customized reforms to FERC for approval by individual RTOs. As a result, ad-hoc, piecemeal, regional approaches to incremental GI reform have become the new status quo.

The overall impact of these incremental reforms is mixed. Some reduce financial, informational, or procedural barriers to entry, which expedite speed to power. For example, considerable optimism surrounds the Southwest Power Pool’s “consolidated planning process.” Other proposals, however, entrench incumbent transmission utilities further and undermine bedrock open-access transmission policy rather than hold transmission providers accountable for producing expeditious and accurate GI study assessments. The merits of some recent reforms remain unclear, such as the fate of cluster-study processes.

Together, this suggests significant value in continuing to research comparative GI practices and creating a community to determine best practices. Research at the Lawrence Berkeley National Laboratory has provided tremendous value and played a central role in FERC’s 2024 GI workshop. RSI highly recommends that the DOE continue to support this effort. RSI also reiterates the value of DOE support for i2x, which is an excellent community for identifying best GI practices. Such efforts are critical for identifying improvements to business processes and tools that provide information for generators in a manner that does not further burden GI queues in search of price discovery.

The related issue of large-load interconnection is in a more nascent stage. Last month, DOE asked FERC to consider an advanced notice of proposed rulemaking (ANOPR) for interconnection of retail loads over 20 megawatts with final FERC action by April 30, 2026. This is warp speed by FERC standards. Stakeholders are scrambling to develop high-quality comments to DOE’s 14-page ANOPR, and the record at FERC will be lackluster, given the accelerated comments window for such a novel issue. This could be disastrous for FERC’s final rule. If FERC fails to support a final rule with sufficient evidence, it will not withstand judicial scrutiny.

To be clear, DOE’s ANOPR proposes that FERC extend its reach into planning processes far beyond what the agency oversees today. This is a highly sensitive federalist matter; FERC has never before exercised this type of authority over retail loads. This month, the National Association of Regulatory Utility Commissioners passed a resolution urging FERC to resist the ANOPR push to give the regulator jurisdiction over large interconnecting loads.  

For an issue this important and complicated, particularly given the major federalist questions, it is highly advisable that DOE give FERC more time, narrow the ask of FERC, or have FERC delay final action on aspects of the ANOPR by choosing not to implement it as proposed. A rushed rulemaking will be technically suboptimal, less durable, and more vulnerable to excessive litigation. Changes need to come immediately, as a final rule cannot deviate substantially from a notice of proposed rulemaking, which FERC will have to issue expeditiously to meet DOE’s timeline.

Policy and Regulatory Uncertainty

Research, such as a recent Energy Uncertainty Index, shows that energy-sector policy uncertainty is associated with slower economic growth. Debt markets remain resilient, but risks are mounting. In particular, the “main risk for debt issuance and spreads going into 2026 is continued uncertainty around US tariffs compressing margins for more levered borrowers.” 

The U.S. electric policy and regulatory landscape, both federally and in many states, has become less stable and predictable, creating substantial artificial risk. This is driving up risk premiums for all types of generation and transmission, as noted by former FERC chairs, industry analysts, and financial market behavior. In fact, leading developers recently remarked that risk premiums are “offsetting any benefits you’re getting from reduced interest rates. It’s counterproductive.” 

While the uncertainty of obtaining approvals for permits and interconnection receives much warranted attention, less attention has been paid to permitting permanence. Government approvals are rules-based constructs. Adherence to the rule of law is central to drive investor confidence, and thus paramount to drive speed to power for generation and transmission.

Generation and transmission infrastructure-investment horizons span five to eight presidential cycles. This makes investors less sensitive to the preferences of any given administration and more inclined to base decisions on the long-term policy climate. Actions like the Obama administration’s Keystone XL rejection, the Biden administration’s “LNG pause,” or the Trump administration’s pause on a nearly complete offshore wind project create long-term uncertainty and chill capital markets. Crucially, punitive actions on one resource class set a precedent for executive overreach, which drives long-term risk premiums for other forms of infrastructure. Relatedly, the domestic oil and gas industry has recently grown more uncertain about the future, given recent policy developments.

Sage advice came from Senator Lisa Murkowski in September: “We should not retreat from an all-of-the-above policy. It cannot just be empty rhetoric.” Indeed, the Trump administration and DOE must stay true to the spirit of unleashing all American energy, as envisioned in Executive Order 14154.

DOE has undertaken recent actions that exacerbate uncertainty, such as the overuse of emergency actions under Section 202(c) of the Federal Power Act to subsidize existing power plants. The law limits orders to just 90 days to let a unit waive environmental compliance. This is sufficient to address emergencies like hurricanes, fuel freezes, and wildfires that last days or weeks. However, DOE used the law in May to block two plants—Campbell and Eddystone—from retiring despite an absence of emergency conditions. Then DOE used it again in August when those orders expired. It is expected that DOE will do so again this month. This is problematic for a number of reasons, including:

RSI’s recent reliability paper has a section on appropriate policy responses to concerns over premature retirements. The main concern is states forcing premature retirements of economical power plants, which is not what DOE actions have addressed to date. The paper examines use parameters for reliability must-run (RMR) agreements, but similar guidelines may apply to the use of 202(c):

Accredited Capacity Additions by 2030

RSI conducted an analysis to demonstrate the effects of public policy on near-term capacity additions for reliability purposes. Given the long lead times to develop generation, we examined projects with mature development status (announced, permitted, or under construction) expected to be operational by 2030 (“Tier 1” resources). We accounted for uprates to nuclear and natural gas plants and one nuclear restart.

Unannounced greenfield projects are outside this delivery timeframe. Although some boilerplate industry reports (e.g., EIA) suggest that projects like new natural gas-fired plants and solar-plus-storage may have lead times of 2 or 3 years, this is not consistent with current commercial climates (e.g., supply chain backlogs, high artificial barriers to entry). Therefore, we excluded unannounced greenfield projects from consideration for projects with 2030 in-service dates.

We used DOE’s 2025 Resource Adequacy Report for nameplate capacity additions and reliability accreditation calculations. Capacity accreditation, or the portion of nameplate capacity that is considered reliable for meeting system peak demand, was based on Effective Load Carrying Capability (ELCC) or performance-based metrics. We used the ELCC factors based on averages of MISO, PJM, and SPP’s 2024 ELCC reports. These averaged: solar (35 percent), wind (12 percent), 4-hour battery (90 percent), natural gas (95 percent), and nuclear (95 percent). Although accreditation varies by footprint, this roughly represents national averages. Batteries are secondary power sources that contribute disproportionately to accredited capacity because of their high ELCC rating (90 percent), so we ran the analysis with and without storage across all scenarios.

Table 1. Capacity Additions by 2030, Four Scenarios

ResourceNameplate
Additions (GW)		Unrestricted
Accredited
Additions (GW)		60% Restricted
(wind, solar,
gas only)		60% Restricted
(wind, solar
only)		60% Restricted
(gas only)
Solar72.525.410.1610.1625.4
Wind52.86.32.522.526.3
Battery (4-hr)50.645.645.645.645.6
Gas20197.6197.6
Nuclear1.21.101.101.101.10
Total197.197.466.9878.3886
Total (no
storage)		146.551.821.3832.7840.4

We applied four scenarios to determine 2030 accredited capacity, as shown in Table 1. The first is an unrestricted scenario, used for illustrative purposes. New generation development is facing high artificial barriers to entry, particularly for wind, solar, and natural gas plants. Historical data (2000 to 2018) indicate that only about 19 percent of projects (and 14 percent of capacity) have reached operation. Therefore, we used three combinations of 60 percent restrictions (40 percent of projects online) on wind, solar, and gas to show three forward-looking, infrastructure-aware scenarios. This may be consistent with a realistic outlook of state and federal speed-to-power efforts to accelerate project completion by addressing bottlenecks.

Key findings include:

We believe this analysis undersells nuclear restarts because of data limitations in the DOE report. The report included only the restart of the Salem Generating Station in 2029, which is a 1,170 MW facility. This overlooks recent announcements to restart the Three Mile Island and Duane Arnold nuclear plants. Although incorporating these facilities should more than double accredited nuclear capacity additions, it would still be the smallest resource addition class by 2030 (i.e., less than 6.3 GW of accredited wind capacity additions). Nuclear restart potential is limited, and aspirations for new greenfield nuclear might factor into a 2040 analysis. Notably, it took 15 years to complete the Vogtle nuclear plant after the utility received approval to expand an existing facility.

RSI appreciates the opportunity to provide these comments to DOE.

Respectfully submitted,

/s/ Devin Hartman
Devin Hartman
Director, Energy and Environmental Policy
R Street Institute
1411 K Street NW, Ste. 900
Washington, D.C. 20005
(202) 525-5717
dhartman@rstreet.org

/s/ Olivia Manzagol
Olivia Manzagol
Fellow, Energy and Environmental Policy
R Street Institute
1411 K Street NW, Ste. 900
Washington, D.C. 20005
(202) 525-5717
omanzagol@rstreet.org

/s/ Christopher Villarreal
Christopher Villarreal
Associate Fellow, Energy and Environmental Policy
R Street Institute
1411 K Street NW, Ste. 900
Washington, D.C. 20005
(202) 525-5717
cvillarreal@rstreet.org

/s/ Kent Chandler
Kent Chandler
Senior Fellow, Energy and Environmental Policy
R Street Institute
1411 K Street NW, Ste. 900
Washington, D.C. 20005
(202) 525-5717
kchandler@rstreet.org

/s/ Michael Giberson
Michael Giberson
Senior Fellow, Energy and Environmental Policy
R Street Institute
1411 K Street NW, Ste. 900
Washington, D.C. 20005
(202) 525-5717
mgiberson@rstreet.org

November 21, 2025

See the original filing below:

Final – DOE RFI Speed – R Street InstituteDownload