The SURGE Act amends section 219 of the Federal Power Act to force a FERC rule that allows transmitting utilities to recover a portion of independently verified cost savings from efficiency improvements as a performance incentive. The bill prescribes standardized methodologies for establishing baselines, estimating and verifying savings, and setting recoverable percentages and recovery timelines, and it requires FERC to provide interim rate adjustments within fixed windows.
Beyond FERC jurisdiction, the Act directs the Department of Energy to publish guidance for State regulators, creates a DOE grant program to help states design and implement similar frameworks, and requires recurring DOE studies on how rate treatments affect incentives, costs, and grid performance. For utilities, vendors, and regulators, the bill creates a new, measurable pathway to monetize reductions in transmission losses and other grid-efficiency gains — but it also creates operational and verification obligations that will drive technical, regulatory, and data work at both the federal and state levels.
At a Glance
What It Does
The bill compels FERC to adopt a shared‑savings framework that lets covered transmitting utilities recover between 10% and 60% of verified cost savings from qualifying transmission efficiency actions and to set a 2–5 year rate recovery timeline. It prescribes standardized baseline, savings‑calculation, and verification methodologies, requires an initial filing with an independent verification and an immediate (60‑day) rate adjustment for a first‑year estimate, and mandates annual reconciliations.
Who It Affects
Directly affects transmitting utilities regulated by FERC, vendors of advanced conductors and grid‑enhancing technologies, Independent System Operators/Regional Transmission Organizations through data and modeling interactions, and State regulatory authorities and non‑jurisdictional utilities via DOE guidance and grants. Independent evaluators and consulting firms will see new demand for measurement, verification, and modeling work.
Why It Matters
This is a structural change to how transmission efficiency can be monetized — moving some compensation away from traditional capital‑recovery models toward pay‑for‑measured savings. That shift could accelerate deployment of non‑wires and grid‑enhancing options, alter investment priorities, and create new regulatory compliance burdens centered on data integrity and attribution.
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What This Bill Actually Does
The Act creates a two‑track program. For FERC‑jurisdictional transmitting utilities, it requires FERC to issue a final shared‑savings rule within one year that defines qualifying transmission actions (chiefly measures that reduce transmission physical losses), prescribes how to set baselines, how to estimate and verify cost savings, and how much and for how long a utility may recover those savings as an incentive.
A utility seeking the incentive must file an initial application that documents the one‑year baseline, describes the proposed action and expected improvements, estimates savings for the first year and the duration of the recovery period, and includes independent verification. FERC must provide a rate adjustment within 60 days to allow recovery of an upfront claim equal to 50% of the utility’s recoverable percentage for the first‑year estimate.
Each participating utility must then submit annual, independently verified reports comparing actual performance to the baseline, claiming the recoverable percentage of verified savings for the prior year and up to 50% of the next year’s estimate. If at any point the Commission or the utility finds that prior adjustments exceeded actual recoverable savings, the excess is credited back to ratepayers through a reconciliation rate adjustment.
FERC’s methodology work is intended to standardize treatment across ‘‘similarly situated’’ transmission segments, including normalizing for weather, demand swings, and third‑party operational changes; it also prescribes price proxies (for example, LMPs in RTO regions) to monetize avoided transmission energy losses.For utilities outside FERC’s ratemaking jurisdiction, the Secretary of Energy must publish DOE guidance within two years to help state regulators build comparable incentive frameworks. The guidance is to cover baseline setting, savings estimation, measurement and verification by independent evaluators, and potential state rate‑recovery mechanisms; the DOE will tailor separate guidance for different utility market structures (vertically integrated, transmission‑only, distribution‑only, and combined transmission/distribution utilities).
The Act complements that guidance with a DOE grant program to help states design and stand up frameworks and requires DOE to produce periodic studies (first due in three years, then every five years) on inefficiencies driven by current rate treatments and on alternative incentive models — providing evidence FERC and states should consider when expanding or revising frameworks.
The Five Things You Need to Know
FERC must issue a final shared‑savings rule within one year that allows covered transmitting utilities to recover an incentive equal to 10–60% of verified cost savings from qualifying actions.
The statute caps rate recovery windows for incentives at a minimum of 2 years and a maximum of 5 years and requires FERC to provide initial rate adjustments within 60 days of filings.
A utility’s initial filing must include an independent verification, baseline data for the prior year, an estimate of first‑year savings, and a claim equal to 50% of the utility’s recoverable percentage applied to that first‑year estimate.
DOE must publish guidance for state regulators within two years, with separate methodology guidance for vertically integrated, transmission‑only, distribution‑only, and combined utilities, and it will run a state grant program to fund development and implementation.
DOE must conduct a study within three years (and every five years thereafter) on transmission inefficiencies and alternative incentive frameworks, with findings required to inform future rulemaking and guidance.
Section-by-Section Breakdown
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Makes FERC’s section 219 authority explicitly cover shared‑savings and operational efficiency incentives
This amendment broadens the statutory language in FPA §219 to require rules that address incentives tied to operational improvements and efficiency (not just capital investment) and explicitly authorizes recovery amounts determined under shared‑savings frameworks. The practical effect is to remove a legal ambiguity that could have limited FERC’s ability to treat verified savings as a rate‑recovery base and to anchor FERC’s rulemaking obligations in the statute rather than in discretionary policy guidance.
Detailed prescription for baseline, savings calculation, verification, recovery percentages, timeline, and reconciliation
Section 3 lays out the core operational mechanics that FERC must adopt: standardized baseline methodologies (direct metering where possible, modeling otherwise), normalization for exogenous factors, savings‑calculation methodologies using price proxies (for RTO regions this can be locational marginal prices), and independent verification. It also sets explicit parameter ranges — recoverable percentages between 10% and 60% and recovery periods of 2–5 years — and creates a two‑step rate recovery: an upfront 60‑day adjustment for an initial claim (50% of one year’s recoverable share) followed by annual filings and reconciliations. This section shifts much of the practical calibration — e.g., how to normalize weather or define ‘‘similarly situated’’ segments — into FERC’s rulemaking and technical guidance.
DOE to provide model guidance for states to adopt comparable frameworks
Because many utilities operate under state ratemaking, the bill directs DOE, in coordination with FERC and states, to publish guidance to help state regulators design equivalent frameworks. The guidance must include baseline and savings methodologies, measurement and verification protocols using independent evaluators, and tools/technical support. Crucially, DOE must provide separate guidance tailored to four market structures, so states get model language for vertically integrated utilities versus transmission‑only or distribution‑focused systems.
Grant funding to help states develop, implement, and oversee incentive frameworks
DOE must establish a competitive grant program to fund state regulatory authorities to build or revise frameworks consistent with DOE guidance. Allowed uses include methodology development, data system build‑out, stakeholder engagement, and oversight capacity — but not direct payments to utilities. The bill limits federal administrative spending and prescribes allocation bands for planning versus implementation activities, and it requires annual reporting from grantees with penalties for noncompliance (ineligibility for further grants).
Periodic DOE studies on rate‑treatment inefficiencies and alternative frameworks
DOE, consulting FERC and national labs, must conduct a study within three years and every five years thereafter examining how existing rate treatments create inefficiencies and assess alternative frameworks (shared savings, decoupling, ROE adjustments, MYRPs, earnings sharing, total expenditure models, and performance scorecards). The reports must be public and are explicitly tied back to future rulemakings and DOE guidance revisions, making the studies a key evidentiary input for iterative policy evolution.
Precise definitions that narrow the scope to measurable transmission loss reductions and grid‑enhancing actions
The Act defines core terms — covered transmitting utility, covered action, covered transmission action, advanced conductor, transmission physical loss, transmission segment, and more — which constrains the program to actions that can be measured and verified (primarily reductions in transmission physical loss and deployment of grid‑enhancing technologies). Those definitions will be central in disputes over eligibility and whether a particular change qualifies as a ‘‘qualifying action.’
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Explore Energy in Codify Search →Who Benefits and Who Bears the Cost
Every bill creates winners and losers. Here's who stands to gain and who bears the cost.
Who Benefits
- FERC‑jurisdictional transmitting utilities — gain a new, quantifiable revenue stream for measured efficiency gains and grid‑enhancing investments, improving the business case for non‑wires options and advanced conductor deployments.
- Manufacturers and integrators of grid‑enhancing technologies and advanced conductors — see accelerated market demand because the incentive monetizes operational savings that these products generate.
- State regulatory authorities with grant awards — receive federal funding and technical support to pilot and adopt comparable frameworks, reducing their upfront resource burden for method development and data systems.
- Independent evaluators and technical consultants — stand to gain demand for baseline modeling, savings estimation, measurement and verification, and ongoing auditing services required by the statute.
- Ratepayers (potentially) — may benefit from lower long‑run system costs if the frameworks favor cost‑effective, non‑capital alternatives that reduce congestion and losses; the bill requires reconciliation that returns overpayments to customers.
Who Bears the Cost
- Ratepayers (near‑term) — could incur incentive payments embedded in rates during the recovery timeline; although reconciliations protect against overpayment, customers may carry interim costs until true‑up.
- FERC‑jurisdictional utilities — face increased compliance and reporting costs (data collection, independent verification, modeling) and bear risk if their estimates underperform and require reconciliations.
- State regulators and smaller utilities without grant support — may struggle with technical capacity to implement comparable frameworks, producing uneven adoption and potential administrative burdens.
- DOE and FERC — will need to allocate staff, technical resources, and contract support to produce methodologies, guidance, grant administration, and recurring studies, which could compete with other priorities.
- Market participants in ISOs/RTOs — may face modeling and market‑design complexity as incentive frameworks interact with locational pricing signals and dispatch outcomes, requiring additional coordination and data‑sharing.
Key Issues
The Core Tension
The bill wrestles with a classic regulatory dilemma: encourage faster deployment of cost‑reducing, grid‑enhancing actions by sharing verified savings with utilities, while avoiding overcompensation and misplaced costs on ratepayers — a balance that depends entirely on hard measurement, transparent verification, and conservative calibration of percentages and recovery periods.
Measurement and attribution are the program’s most fragile elements. Distinguishing savings caused by a specific transmission action from changes driven by weather, load shifts, generation dispatch, or unrelated network upgrades requires robust modeling and transparent, audited data.
The bill attempts to address this through standardized methodologies, normalization rules, and independent verification, but it leaves substantial calibration decisions to FERC rulemaking and DOE guidance — which means early rules will determine whether incentives reward genuine efficiency or simply compensate utilities for shifts outside their control.
The recoverable percentage and recovery timeline ranges create policy levers but also political and economic trade‑offs. A higher recoverable percentage or longer recovery window makes investments more attractive to shareholders but increases the risk that ratepayers pay for benefits that are difficult to attribute or that accrue outside the charging period.
The upfront 60‑day rate adjustment and the 50% initial claim accelerate utility cash flows but raise reconciliation pressure on FERC and the potential for interim overcollection. Finally, the program’s success depends on data access and interoperability: RTOs/ISOs, utilities, and states will need to agree on measurement nodes, LMP proxies, and what constitutes a transmission ‘‘segment’’ for independent verification.
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