Florida Large LoadGrid Requirements

What data center and 50 MW+ load developers must know before energizing in Florida — and how to keep a project on schedule under the state's toughest-yet interconnection rules.

Published by Keentel Engineering  |  Updated August 2026

Reading time: ~14 minutes

The short version

Florida has moved decisively to make large electricity users — data centers and industrial loads with a monthly peak demand of 50 MW or more — pay the true, full cost of connecting to the grid. Senate Bill 484, effective July 1, 2026, requires all four of the state's investor-owned utilities to file dedicated large-load tariffs with the Florida Public Service Commission (FPSC) by October 1, 2026. These tariffs shift the cost of grid connection, incremental generation, and transmission upgrades onto the large-load customer rather than everyday ratepayers, and they bar service to loads tied to certain prohibited foreign entities. In parallel, federal regulators at FERC are pushing every organized power market toward similar reforms. For developers, the message is simple: the era of cheap, fast, someone-else-pays interconnection is over. Early, rigorous engineering and a well-built application are now the difference between energizing on schedule and waiting years.

Why Florida Rewrote the Rules for Large Loads

The artificial-intelligence build-out has turned electricity into the scarcest input in the data center industry. Hyperscale campuses that once drew tens of megawatts now request hundreds, and they want power in 18 to 36 months rather than the five-to-seven-year horizon utilities traditionally plan around. Florida — with its warm climate, connectivity, tax posture, and rapidly growing population — sits squarely in the path of that demand. The result is a wave of interconnection requests large enough to reshape the state's grid.

That surge collided with a political reality: Florida households have watched their electric bills climb sharply, with the average residential bill up roughly 20% since 2021. State leaders were unwilling to let ordinary customers subsidize the grid expansions needed to serve some of the largest and best-capitalized companies in the world. When Governor Ron DeSantis signed SB 484 in May 2026, he framed it bluntly: Floridians should not have to subsidize “some of the wealthiest companies in the history of humanity.”

For developers, this is not a reason to avoid Florida — it is a reason to plan differently. The projects that will succeed here are the ones that arrive with credible load forecasts, defensible cost estimates, and an engineering strategy that anticipates what the utility and the Commission will demand. This guide walks through the requirements as they stand, the live utility proceedings that will define how the rules are applied, the federal backdrop at FERC, and the practical steps that keep a large-load project moving.

Senate Bill 484: The Framework in Detail

SB 484 is the centerpiece of Florida's large-load framework. It establishes who is covered, what they must pay for, how utilities must structure service, and which customers are prohibited outright. The following breaks down each pillar.

Who is covered: the 50 MW threshold

The law applies to high-demand utility customers — principally data centers and large industrial or commercial operations — whose monthly peak load reaches or exceeds 50 MW. This is the trigger that pulls a project into the large-load regime. It is a meaningful line: a single large data center hall, a cluster of AI training pods, or a major manufacturing expansion can easily cross it, while a mid-size commercial facility will not. Developers phasing a campus should pay close attention to how peak demand is measured and aggregated, because the threshold is where full cost-responsibility obligations attach.

What you pay for: full cost responsibility

The defining principle of SB 484 is that large-load customers bear the direct and incremental costs their demand imposes on the system, without shifting those costs to residential or general commercial ratepayers. In practice, that responsibility spans three broad categories:

• Direct grid-connection costs — the substations, interconnection facilities, metering, and dedicated lines required to physically connect the load.
• Incremental generation costs — the cost of the additional generating capacity needed to reliably serve the new demand, so that adding your load does not degrade reliability or raise costs for everyone else.
• Associated infrastructure and transmission upgrades — the network reinforcements (upgraded and new substations, transmission lines, and related facilities) triggered by the load.

The policy intent is a clean allocation of causation: the customer that causes the cost pays the cost. For a developer, this reframes the interconnection cost estimate from a background line item into one of the most important numbers in the entire project pro forma. Getting it wrong — or being surprised by it late — can undermine the economics of an otherwise sound site.

Why the cost estimate is now a core engineering deliverable

Because the applicant absorbs connection, generation, and upgrade costs, the accuracy and defensibility of the underlying studies directly drive project viability. A load-flow, short-circuit, and stability study that identifies the least-cost compliant path — including whether grid-enhancing technologies can substitute for expensive new lines — can move millions of dollars and many months. This is precisely where independent engineering pays for itself.

Who is prohibited: foreign-entity restrictions

SB 484 also carries a national-security dimension. It prohibits electric utilities from supplying power to large-load operations that are tied to specified prohibited foreign entities. Developers should treat ownership, financing, and control-structure diligence as a compliance prerequisite, not an afterthought — a load that cannot lawfully be served is a project that cannot be built, regardless of how strong the site or the engineering is.

How service is structured: mandatory large-load tariffs

SB 484 does not leave the terms of large-load service to negotiation. It requires all four of Florida's investor-owned utilities — including Florida Power & Light (FPL) and Duke Energy Florida — to file formal large-load tariffs with the FPSC by October 1, 2026. These tariffs are the rulebook that will govern how large interconnections are studied, priced, and contracted. Until each utility's tariff is approved, the exact terms a developer will face remain a moving target, which is why the current proceedings (discussed below) matter so much.

SB 484 at a glance

What SB 484 Means in Practice for Your Application

Translating the statute into a project plan means understanding the mechanics of a large-load application. While each utility's approved tariff will control the specifics, the following elements are already visible in the filings before the Commission and in the direction of the law.

A specialized tariff filing, not a standard service request

Large loads are being pulled out of the ordinary rate classes and given their own tariff structures. That means the application, the study process, the cost-recovery mechanism, and the contract terms are all purpose-built for 50 MW+ customers. Developers should expect to engage with the utility through this specialized pathway rather than the standard commercial interconnection process.

Long-term commitments and minimum service terms

Utilities are seeking long commitment periods to justify the capital they must build. Duke Energy Florida's proposed framework, for example, would apply to customers with demand of at least 50 MW at a single location and impose a 20-year minimum service term. A commitment of that length reshapes a developer's financing and offtake strategy, and it makes early load-forecast accuracy essential: you are contracting to a demand profile for two decades.



Protection against stranded-cost exposure

A central concern for regulators is what happens if a utility builds infrastructure for a data center that never energizes or ramps far below its projected load. The tariffs and cost-recovery agreements are being designed so that the applicant — not other customers — stands behind those commitments. Developers should expect financial assurances, deposits, or take-or-pay-style provisions tied to the capacity they reserve. Structuring these terms favorably, and phasing reserved capacity to match realistic ramp, is an area where engineering and commercial strategy intersect.

The Tariffs Taking Shape: Duke, FPL, and the First Test of SB 484

The statute sets the principles; the utility tariff proceedings are where those principles become concrete rules. As of mid-2026, the Duke Energy Florida filing has become the closely watched first test of what SB 484 actually requires.

Duke Energy Florida under scrutiny

Duke — which serves more than two million customers in Florida — submitted its large-load tariff application in April 2026 (FPSC Docket No. 02327-2026), ahead of the bill becoming law, and argued that its proposal “strikes the right balance” between existing ratepayers and new large-load customers. But at the FPSC's July 7, 2026 meeting, the Commission split over whether Duke's approach actually complies with the new law.

The core objection: rather than proposing a genuinely new tariff designed for large loads, Duke would allow new large-load customers to take service under its existing rates for now, deferring a custom-built large-load tariff until its next rate case (paired with a rate freeze). The Public Counsel, Walter Trierweiler — who represents ratepayers — moved (with the advocacy group Florida Rising) to dismiss Duke's bid, arguing it “facially violates Florida law with a regulatory scheme that ignores both the text and spirit of the freshly signed SB 484.” Duke opposed the motion, maintaining that its approach, coupled with the rate freeze, meshes with the law.

Commissioners voiced open skepticism. Commissioner Mike La Rosa dissented, saying, “I don’t believe that the overall customer protections are there the way the legislature drafted it.” Commissioner Gary Clark warned a Duke representative, “you’re on sticky ground if you ask me.” Ultimately, the panel voted 4–1 to let the application advance — but Chair Gabriella Passidomo Smith stressed the vote was procedural: “This has nothing to do with actual merits of the case, just whether we should flesh it out to a hearing or not.” The matter proceeds to a formal, two-day hearing on August 25–26, 2026.

Why the Duke case matters to you

The Duke hearing will establish how strictly the FPSC reads SB 484's cost-protection requirements. If the Commission demands a purpose-built large-load tariff with robust anti-cost-shifting provisions, every utility's framework — and every developer's cost exposure — will be shaped accordingly. Track this docket; it is the bellwether for the rules you will operate under.

Florida Power & Light: cost scrutiny and the transmission question

FPL, a subsidiary of NextEra Energy, is Florida's largest electric utility, serving about 12 million customers across most of the state's coastal counties. It, too, must file a large-load tariff under SB 484. But FPL is also at the center of a related fight over how transmission costs get scrutinized before customers pay — a fight that directly implicates data center load growth.

In 2026 the FPSC approved FPL's $782 million Andytown–Oasis transmission project, one of the most expensive local transmission projects ever proposed in Florida, to serve Miami-Dade County. The Environmental Defense Fund (EDF) intervened and has asked the Florida Supreme Court to review the Commission's approval, arguing the project was approved without the rigorous scrutiny a project of that size warrants.

For developers, one thread of EDF's challenge is especially notable: EDF's experts argued that FPL's load forecasting inappropriately attributed speculative data center growth to Miami-Dade County, helping justify the build. In other words, data center demand is increasingly being cited as the reason for expensive infrastructure — which makes the credibility of your own load forecast a matter of public record and scrutiny, not just an internal planning number.

The regional-planning and non-wires debate

EDF's broader argument is that Florida builds transmission one project at a time, based on isolated local reliability assessments, rather than evaluating whether regional planning or advanced technologies could meet the same needs at lower cost. Because investor-owned utilities earn a regulated return on the assets they build, critics argue their incentive points toward the most capital-intensive solution. EDF contends FPL never seriously evaluated lower-cost, faster-to-deploy “non-wires” alternatives, including:

• Grid-Enhancing Technologies (GETs) such as dynamic line rating and advanced power flow control, which add capacity to existing lines quickly;
• Transmission-tied battery storage; and
• Generation re-dispatch to relieve congestion and maximize existing capacity.

This debate is not academic for developers. Under SB 484, you may bear the cost of the upgrades triggered by your load. If a lower-cost GET or non-wires solution can serve your interconnection, identifying it can materially reduce your cost responsibility and shorten your schedule. The regulatory momentum — at both the state and federal level — is increasingly toward requiring these alternatives to be studied, which strengthens a developer's position in pushing for them.

The affordability backdrop



The average Florida household electric bill is up about 20% since 2021, and the return utilities are allowed to earn is among the highest in the country. That combination is exactly why SB 484 exists and why regulators are scrutinizing who pays for growth. Developers who show up with a credible, least-cost plan are aligned with — not fighting against — the political and regulatory current.

The Federal Backdrop: FERC's Section 206 Large-Load Reforms

Florida's state framework does not exist in a vacuum. In June 2026, the Federal Energy Regulatory Commission (FERC) took its most significant action yet to integrate large loads onto the grid — and while the mechanics differ from Florida's, the policy goals are strikingly aligned: connect large loads quickly, protect other customers from the costs those loads cause, and preserve reliability.

What FERC did

Acting under Section 206 of the Federal Power Act, FERC issued “show cause” orders to each of the six Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) and the transmission owners in their regions. Each grid operator must justify how its existing rates, rules, and practices adequately account for the interconnection of large and co-located loads — or propose revised terms that are just, reasonable, and not unduly discriminatory. Rather than launch a single nationwide rulemaking, FERC chose a bottom-up approach, letting each market propose region-specific solutions. The effective refund date for the proceedings is June 24, 2026.

The action traces back to an October 2025 U.S. Department of Energy directive (under Section 403 of the DOE Organization Act) instructing FERC to issue an Advance Notice of Proposed Rulemaking on large-load interconnection. FERC then addressed the issue case by case — including a December 2025 order directing PJM to adopt clear co-located-load rules and a January 2026 approval of SPP's High Impact Large Load initiative — before issuing the targeted June 2026 show cause orders. Together, the orders cover roughly two-thirds of the load subject to FERC-jurisdictional rates.

The six show cause orders

The five reform categories FERC is demanding

Each grid operator must show it already employs — or will adopt — measures in five areas. These are a useful checklist for any large-load developer, because they define what “best practice” interconnection looks like:

1. Clear application and study processes — defined application, study, and operational procedures for large loads, including evaluation of grid-enhancing technologies (dynamic line ratings, advanced power flow control). If GETs are not used, the operator must explain why.
2. Cost transparency and anti-cost-shifting — public, clear costs for connecting large loads, plus pro forma cost-recovery agreements so that if infrastructure is built for a data center that never comes online, other customers are not stuck with the stranded costs.
3. Co-location and behind-the-meter rules — clear terms for co-location arrangements and loads served by behind-the-meter generation.
4. New services for flexible large loads — an interim, non-firm network service available while upgrades are built, and permanent firm and non-firm contract-demand service that reflects a load's ability to limit its grid use.
5. Studying load and generation together — study pathways that evaluate generation serving “electrically proximate” large loads together with those loads, to avoid unnecessary build-out (SPP's rule, for example, requires the generator and load be no more than two substations apart).

FERC also directed each operator to explain how it will ensure adequate generation is available to serve existing and new large loads — the resource-adequacy question that sits underneath every interconnection request.

How this affects a Florida project

Here is the nuance that matters for Florida developers: most of Florida is not part of an RTO or ISO. FPL and Duke Energy Florida operate in the Southeast largely outside the organized markets FERC targeted, so these six show cause orders do not bind them directly. But the direction of travel is unmistakable, and it converges with SB 484 on the same principles: cost transparency, anti-cost-shifting, pro forma cost-recovery for stranded assets, flexible-load service options, and mandatory consideration of grid-enhancing technologies.

Notably, FERC Chairman Laura V. Swett said she is “under no illusion that the challenges … are somehow unique to the RTO/ISO regions,” and encouraged transmission providers outside those regions to make their own filings to address the same issues. Commissioner Lindsay S. See noted that real-world experience may reveal whether future action is needed on cost shifts. For a developer, the practical takeaway is that the same set of best practices — well-documented load forecasts, least-cost solution analysis, GET evaluation, and flexible-service structuring — will serve you whether your load lands in Florida's state-regulated system or in a federally regulated market elsewhere in your portfolio.

Key FERC deadlines (Section 206 proceedings)

These federal dates run in near-parallel with Florida's own timeline — the Duke hearing on August 25–26 and the October 1 tariff-filing deadline — making the late summer and fall of 2026 the decisive window for large-load policy at both levels.

Frequently Asked Questions: Florida Large Load Grid Requirements