Behind the Meter Is Not Behind the System

“Behind the meter” sounds like an answer to interconnection delay, network upgrades, and grid cost. It is not the answer. It is the first line of a diligence request.

A data center can sit beside a generator, take little or nothing from the wider grid during ordinary operations, and still depend on the system for backup service, controls, reliability support, and settlement. Physical distance is visible. The service bargain is documentary.

The meter tells you where to start reading. It does not tell you where the obligations stop.

Adjacency is visible. Service is not.

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Ted Shaffrey · Associated Press · 14 Jan 2025

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The physical proximity is real. So is the temptation to let the photograph answer questions it cannot. This view of the Susquehanna plant record does not reveal the meter boundary, current service, tariff enrollment, withdrawal right, or direction of power flow. Those facts have to be proved separately.

This distinction matters now because PJM's framework is moving on different clocks. Selected interconnection options are already effective. The three transmission-service paths most “limited grid use” claims rely on have been directed and materially shaped, but they do not yet have an approved effective date. At the same time, FERC has opened six tailored proceedings asking organized markets to confront large-load integration.

A useful analysis does not begin by choosing between “behind” and “in front” of the meter. It begins by resolving five linked questions:

• Physical configuration — Where are the load, generator, meter, and point of interconnection? Is the campus fully islanded, synchronized behind a shared point, or served through a front-of-meter path?
• Withdrawal right — How much may the load take from the grid, under which conditions, and with what firmness? Contract demand is not gross load, current demand, or unlimited backup.
• Injection right — How much may the generator inject, and which studies or interconnection rights change when some output serves a nearby load?
• Operational duty — What metering, telemetry, controls, protection, curtailment, load-shed, and notice obligations govern the interface?
• Cost duty — Which transmission, ancillary-service, upgrade, administrative, and retail charges apply under the effective rules?

These are configurations, not rankings. Fully islanded can remove a transmission-service relationship only by giving up synchronized grid service. A co-located arrangement may limit withdrawals, but its contract and controls define the boundary. A front-of-meter structure can use familiar utility and wholesale paths while adding parties and obligations. The right answer depends on the service design and the evidence behind it—not on which label sounds more independent.

The new service design is not simply a cheaper or softer version of ordinary service. It exchanges a smaller or less-firm withdrawal right for stronger operational limits.

In its June order, FERC directed a framework under which PJM may terminate the affected transmission-service agreement after a second failure to follow a curtailment or load-shed instruction. A first misoperation of required control technology or protection systems can lead to a suspension of up to 120 days; a second can lead to termination.

Those are replacement-rate directions awaiting compliant tariff implementation—not proof that any named customer is subject to them today. But they expose the cost of a loose claim. A mistaken assumption about firmness, controls, or curtailment can reach the service agreement itself.

Co-location can change the net quantity withdrawn from the wider system, the firm or non-firm service requested, the facilities studied for that service, exposure to curtailment, and the commercial path among generator, customer, utility, and PJM.

It does not automatically remove grid dependence, grant unlimited backup, eliminate studies or charges, establish current load, or prove that one architecture is universally better. FERC's June order is especially clear on the cost edge: zero net withdrawal does not erase the regulation and black-start benefits a co-located load may receive, and the tariff must address recovery of those costs.

The same precision applies to Non-Firm Contract Demand. Eligible customers must be allowed to request it on an everyday basis during normal operations when transmission capacity is available. It remains non-firm, as-available, and curtailable. “Requestable every day” is not “continuously guaranteed.”

In 2024, PJM filed an amended interconnection service agreement seeking to increase the co-located-load treatment at Susquehanna from 300 MW to 480 MW. FERC rejected the agreement—not as a general verdict against nuclear-powered data centers, but because PJM did not meet the high burden for non-conforming provisions. The record did not show that those deviations from the pro forma agreement were necessary, and it relied in part on guidance that was not in the approved tariff.

That is the central lesson in miniature: the label could not substitute for the proof objects.

The next move was not “outside the grid.” Talen's June 2025 disclosure described a three-party front-of-meter path: Susquehanna would sell power into PJM, Talen would act as Amazon's retail generation supplier, and PPL Electric Utilities would provide transmission and delivery after physical reconfiguration. Talen's Q1 2026 Form 10-Q later reported that the revised front-of-meter PPA transition occurred in April 2026.

The public 1,920 MW figure belongs to the PPA's contractual ramp through 2042. It is not current campus load, current withdrawal, or current energized capacity. Nor does the April transition prove that AWS is taking Interim NITS, Firm Contract Demand, or Non-Firm Contract Demand.

The interface did not disappear when the structure moved front-of-meter. It acquired more parties.

In effect since 16 April 2026. Read the accepted interconnection provisions. FERC accepted selected PJM interconnection provisions, including the ability to request service below generator nameplate and be studied at the requested level, provisional interconnection service, surplus interconnection service, and existing acceleration provisions. These are interconnection-side options a developer can use within the order's scope.

Directed, with no approved effective date. Read the June replacement-rate order. Interim NITS, Firm Contract Demand, and Non-Firm Contract Demand are the ordered transmission-service architecture. PJM proposed 1 June 2029. FERC found the support insufficient, required reconsideration, and asked whether interim and non-firm service could arrive sooner. An analyst may describe the directed structure; they may not present any of the three services as generally available today.

Newly opened across six markets. Read FERC's six-market action. On 18 June, FERC opened tailored proceedings for PJM, MISO, SPP, CAISO, ISO New England, and NYISO around shared large-load reform questions. They are not one national rule. PJM's co-location questions remain in the separate EL25-49 track, while its new EL26-67 proceeding focuses principally on large loads that are not co-located.

Collapsing those clocks into “the rule is live” or “the rule is pending” produces the wrong decision in both directions.

The practical test is simple: turn the headline into a document request.

This is not paperwork for its own sake. The Susquehanna agreement failed its 2024 test because the required deviation was not established in the controlling record. In the current docket, confusing an order, a compliance filing, an accepted tariff sheet, and an effective service date can move the answer by years.

This analysis is current through 5 August 2026. The next checkpoints are unusually close:

• 17 August 2026 — responses are due in the six large-load show-cause proceedings.
• 18 August and 16 September 2026 — PJM has scheduled co-located-load stakeholder sessions.
• Later in 2026 — PJM's implementation materials point to additional filings, but those targets are plans, not approved effective dates.
• The effective-date decision — watch whether Interim NITS or NFCD can begin before the 2029 date PJM proposed and FERC sent back for support.

The enduring question is not “behind or in front?” It is: what may this site withdraw, what may its generator inject, how firm is the bargain, what happens when the on-site supply cannot carry the load, and which record proves each answer?