America’s power grid has plenty of new customers and no shortage of new ideas. What it lacks is a regulatory system capable of connecting the two.
Artificial intelligence data centers, advanced manufacturing, and cryptocurrency operations are driving electricity demand sharply higher. Yet the rules for connecting new power sources and major users remain slow, fragmented, and rigid. The grid’s emerging bottleneck is therefore less a failure of technology than of institutions.
The Federal Energy Regulatory Commission (FERC) has begun to confront that mismatch. It is pursuing two major reform tracks: a series of Section 206 “show cause” orders focused on connecting large electricity users to the grid, and an overhaul of the Natural Gas Blanket Certificate program aimed at speeding infrastructure approvals.
That turn toward market realities is welcome. But success will depend on whether FERC resists the temptation to replace one thicket of rules with another. Its final policies should instead draw on basic law & economics principles: reduce transaction costs, clarify property rights, and avoid overconfident central planning.
Reform will also require addressing the regulatory friction between FERC and the Nuclear Regulatory Commission (NRC), which can leave even promising projects trapped between agencies.
Let the Regions Compete
In its large-load directive, issued in response to the U.S. Department of Energy, FERC ordered the nation’s six jurisdictional regional grid operators—the PJM Interconnection (PJM), the Midcontinent Independent System Operator (MISO), the Southwest Power Pool (SPP), the California Independent System Operator (CAISO), the New York Independent System Operator (NYISO), and ISO New England (ISO-NE)—to overhaul how they process transmission requests and evaluate co-located generation. The goal is to cut review times to roughly 60 to 90 days while protecting existing ratepayers.
From a market perspective, FERC’s decision to reject a rigid, “one-size-fits-all” national rule is exactly right. As I have argued in other contexts involving rapidly evolving technologies, centralized planning often suppresses the experimentation that drives better outcomes. By using regional “show cause” proceedings instead, FERC allows different market designs to compete in real time.
That process is already underway as grid operators race to meet the 2026 compliance deadlines. FERC’s co-location order directed at PJM, for example, found the absence of formal tariff rules governing behind-the-meter generation (BTMG)—power generated on-site rather than drawn from the grid—to be unjust and unreasonable.
PJM’s stakeholders responded by proposing clearer transmission-service categories that distinguish among Network Integration Transmission Service (NITS), firm contract demand, and non-firm contract demand. The goal is simple: align transmission charges more closely with how much each customer actually relies on the grid.
The proposal also seeks to reduce cost-shifting. It would cap retail BTMG netting at a cumulative 50-megawatt threshold, ensuring that large data centers bear the network costs they create while exempting emergency backup generators needed for reliability. To reduce the growing backlog of interconnection requests, PJM also created an Expedited Interconnection Track for shovel-ready generation projects larger than 250 megawatts, with a 10-month review target backed by substantial, nonrefundable readiness deposits to discourage speculative applications.
Other regions are testing different approaches. SPP, for example, has proposed its High Impact Large Load (HILL) framework and Conditional High Impact Large Load Service (CHILLS), which would give major electricity users expedited, non-firm transmission service for up to seven years while permanent network upgrades are completed. This diversity of regional approaches gives the market an opportunity to discover which contractual arrangements reduce transaction costs most effectively.
As FERC finalizes these reforms, it should pair “user-pays” obligations with strong property rights. If a data center developer finances a major transmission upgrade, it should receive transferable capacity rights or credits. Turning a regulatory obligation into a marketable asset would encourage private investment in grid infrastructure while accelerating grid expansion.
The Courts Pull the Plug
As FERC moves to complete these infrastructure reforms, it must also contend with a more skeptical federal judiciary. Agencies have long treated phrases such as “the public interest” and “public convenience” as elastic grants of authority. Recent appellate decisions suggest that era is ending.
Consider the D.C. Circuit’s decision vacating FERC’s approval of the Transco natural-gas project. The court did not merely send the matter back for further explanation. It struck down the authorization because FERC had failed to substantiate “market need” under Section 7 of the Natural Gas Act. The message was blunt: balancing the public interest is not a license for agency intuition. It requires evidence that a project’s benefits outweigh its costs and market distortions.
The D.C. Circuit made a similar point in Affirmed Energy LLC v. FERC. FERC has broad discretion to accept tariff revisions, but it still must offer a rational, evidence-based explanation. Otherwise, its decision risks being arbitrary and capricious.
The 3rd U.S. Circuit Court of Appeals reinforced the other side of that boundary in Transource Pennsylvania LLC v. DeFrank. The court held that state utility commissions may not independently second-guess a FERC-approved regional plan to reduce transmission congestion. Federal market rules may be constrained, but states cannot casually override them for protectionist ends.
FERC’s most important limit may come from the Supreme Court’s major-questions doctrine. In West Virginia v. EPA (2022), the court held that agencies addressing matters of “vast economic and political significance” must point to clear congressional authorization rather than vague or open-ended statutory language.
That principle matters because advocates of broader federal planning have often urged FERC to transform its duty to ensure “just and reasonable” wholesale rates into a mandate for sweeping environmental policy or government-directed shifts in energy resources. As Commissioner Mark Christie argued in his dissent from the Certificate Policy Statement, using the Natural Gas Act to deny infrastructure permits based on broad policy goals, including economywide greenhouse-gas projections, risks triggering the major-questions doctrine.
Energy policy has enormous economic consequences, but that does not give FERC a roving commission to redesign the grid. Vague appeals to the “public interest” cannot substitute for authority Congress never granted.
The lesson for FERC’s review of the Natural Gas Blanket Certificate Program is straightforward. By roughly doubling the cost thresholds below which pipeline and hydroelectric operators may proceed without project-by-project approval, FERC would reduce the costs and delays of administrative gatekeeping. Case-by-case certification can act as a barrier to entry, constraining supply and raising prices.
Predictable, quantitative rules offer a better path than open-ended public-interest balancing. To capture those gains and survive judicial review, FERC should tie any expansion of blanket authority to clear statutory mandates for infrastructure efficiency and automatically index the new cost thresholds to inflation.
Caught Between Two Regulators
FERC’s current reform agenda is a welcome start. But from a law & economics perspective, it leaves the biggest long-term obstacle largely untouched: the regulatory divide between FERC and the NRC.
The market is already signaling strong demand for next-generation nuclear power to supply energy-intensive facilities such as artificial intelligence data centers. One promising model is to co-locate a data center with a nuclear plant, allowing it to draw electricity directly from the facility “behind the meter” rather than through the broader transmission grid.
That arrangement, though, falls into a regulatory gap. FERC oversees wholesale electricity markets and grid interconnection, while the NRC regulates nuclear safety. Connecting a large data center directly to a nuclear plant can change the facility’s operating profile, affecting everything from reliability planning to emergency procedures.
Because FERC and the NRC lack a unified framework for evaluating these hybrid projects, developers face overlapping reviews, high transaction costs, and delays that can stretch for years.
The problem extends beyond jurisdictional overlap. The NRC has long relied on a highly prescriptive, zero-risk approach that often overlooks the economic costs of keeping reliable, carbon-free generation offline. A more risk-informed, performance-based regulatory framework would focus on measurable safety outcomes while giving developers greater flexibility in how they achieve them.
FERC also has a role to play. Its capacity markets should more accurately value the reliability benefits that nuclear generation provides, including its ability to reduce volatility during periods of high demand. Pricing those benefits directly would allow market incentives—not state intervention—to guide investment in dependable generating resources.
Get Out of the Grid’s Way
FERC’s reforms are a promising step toward easing the regulatory drag on America’s energy infrastructure. Stronger user-pays rules, clearer property rights for investors, and broader blanket-permitting authority could help the grid expand faster and more efficiently.
But the easy fixes will only go so far. Unless FERC and the NRC resolve the regulatory stalemate over co-located nuclear power, the government will keep throttling the energy growth it says it wants.
The grid does not need another plan. It needs regulators to get out of one another’s way.
