FERC–NARUC Collaborative: Regulators and Industry Press for More Gas Storage, Pipelines and Co‑ordinated Planning

FERC Chairman Mark Christie opened the joint Federal‑State Current Issues Collaborative on April 14, saying storage was the day’s central topic and that “gas has now become so critical to our electric generation system,” noting roughly “47% of all power gen in America now is gas.” The session, convened with state regulators through NARUC, aimed to build a public record and explore ways to improve gas‑electric coordination without addressing the merits of pending contested proceedings (docket AD24‑7).

The day’s presentations came from a cross‑section of system operators, utilities, trade groups and large customers. Jim Robb, president and CEO of the North American Electric Reliability Corporation (NERC), told the panel that a string of winter events over the past decade shows the gas and electric sectors must improve coordination, winterize infrastructure and expand deliverability — including storage — so that “the fuel system from wellhead to burner tip can match the supply needs of the electric grid.” Robb urged mechanisms to ensure market compensation for fuel assurance and to align scheduling with electric demand.

Gordon (representing ISO New England and speaking for the ISOs/RTOs) said regional gas systems are typically built for firm local heating loads, leaving generators exposed during the coldest days. In New England, he said, “about 50% of the energy comes from gas today” and that while the region has tools such as dual‑fuel units and LNG imports, ‘‘the economic case for new pipeline or storage infrastructure is complicated’’ because lower average gas demand can undermine cost recovery for long‑lived gas transport assets.

Trade groups framed how the industry sees the problem. Karen Harbert of the American Gas Association (AGA) said LDCs have a statutory obligation to serve and invest continuously; she told the panel that gas distributors invested roughly $38 billion last year and that storage provides price damping, seasonal balancing and emergency supply. Nancy Baggett of the Electric Power Supply Association (EPSA) urged a shift in planning from capacity adequacy to “energy adequacy,” arguing markets and products (for example multi‑day reserve products or valuing storage as an insurance product) must signal fuel procurement and retention properly.

Manufacturing and large consumers warned of economic risk. Paul Cicio of the Industrial Energy Consumers of America said many manufacturers rely on non‑firm pipeline capacity and have been curtailed during recent winter events, sometimes facing sharply higher prices; he urged greater transparency and asked FERC to convene a technical conference on the issue.

Dominion described a concrete example of the industry’s response: Ed Bain said Dominion received state approval in February for an on‑site LNG storage project to serve the Brunswick and Greensville power stations (about 2,900 MW combined) and expects the facility to be complete in 2027. Dominion framed the investment as part of a reliability and resilience portfolio for its vertically integrated zone.

In Q&A the panel focused on two technical and policy fault lines: (1) inertia and the stability implications of replacing spinning mass with inverter‑based resources, and (2) the mismatch between gas market design (long‑term, contract‑based) and electric operational needs (real‑time, variable). On inertia, witnesses pointed to a recent Iberian blackout as an example of how low inertia can permit fast cascades and said grid‑forming approaches exist but are not yet deployable at scale.

On the gas side, panelists and commissioners debated whether wholesale market changes can alone fix the problem. Several speakers said wholesale markets can price outputs well but struggle to procure or guarantee inputs (fuel) over long horizons; that suggests a role for state action or other planning constructs to underwrite pipelines or storage. Panelists proposed a two‑track approach: near‑term operational work (improving transparency, liquidity in gas trading, and exploring targeted storage builds) and medium‑to‑longer‑term regional analytics or institutional mechanisms to quantify needs and allocate costs fairly.

Multiple participants urged more and recurring regional studies rather than a one‑off exercise. Panelists pointed to the NPCC regional assessment and a DOE‑funded pilot examining gas fuel availability as useful models but said a systematic, continuing analytical process is needed to determine how much storage, transport and other investment is required by region.

On funding and allocation, panelists and commissioners diverged. Some argued that where demand for incremental capacity arises largely from electric system needs, states or regions should underwrite some of the infrastructure; others stressed the traditional model in which firm contracts (often held by LDCs or vertically integrated utilities) drive investment. Several noted legal and regulatory hurdles for changing certification or cost‑recovery frameworks for interstate pipelines and storage.

Takeaways and next steps: speakers coalesced around several practical priorities: (a) expand storage (underground and LNG) where regionally appropriate; (b) remove permit and siting bottlenecks that slow infrastructure deployment; (c) run repeated regional studies to quantify gas‑side adequacy and to design cost‑allocation mechanisms; and (d) refine market or product design to better value multi‑day fuel assurance and related ancillary services. The chairs scheduled a technical conference on resource adequacy in early June and a follow‑up forum in Boston in July to continue these discussions.

The collaborative produced no votes or formal orders; rather it recorded expert testimony and cross‑sector discussion that participants said should inform forthcoming technical workshops and rulemakings.