Georgia Power’s Utility-Owned DER Program Sets a 200 kW Floor and a 1,000 kW Credit Threshold

A regulated, vertically integrated utility has taken the ownership position on the customer’s side of the meter, and it has published the entry thresholds.

Georgia Power’s DER Customer Program runs on two tariffs. Under the Resiliency Asset Service, the utility designs, procures, installs, owns, operates and maintains a customer-sited behind-the-meter distributed energy resource at premises with an annual peak load of at least 200 kilowatts. Under the Demand Response Credit rider, Schedule DRC-1, participating Resiliency Asset Service customers contract for at least 1,000 kilowatts of dispatchable demand reduction in exchange for bill credits.

The two thresholds. The 200 kW figure is a property of the premises: it is the annual peak load a site must reach before the utility will build on it. The 1,000 kW figure is a property of the contract: it is the dispatchable demand reduction a participating customer must commit to in order to earn credits. The first governs which buildings are eligible for utility-owned equipment. The second governs which of those buildings get paid for making that equipment available to the grid.

The gap between the two numbers is the structurally interesting part of the pairing. A 200 kW premises is a mid-size commercial building: an office floorplate, a grocery store, a small manufacturing line. A 1,000 kW dispatchable commitment is five times that peak. The program documentation that is public, the DER Customer Program FAQs and the DRC-1 tariff sheet, establishes both figures. What it does not establish is how many individual premises at the 200 kW floor can realistically reach a 1,000 kW credit commitment on their own.

The ownership position. The defining feature of the Resiliency Asset Service is not the technology. It is the balance sheet. A utility that designs, procures, installs, owns, operates and maintains equipment inside a commercial customer’s building has placed regulated capital on the customer’s side of the meter, where third-party vendors and customer-owned assets have historically competed without a regulated counterparty.

That has two consequences that run in opposite directions.

In Georgia, it narrows the third-party channel. At a premises that takes the Resiliency Asset Service, the utility has already supplied the asset, and the commercial question for any independent vendor becomes whether a site would have been better served buying its own equipment outright. That comparison is difficult to run from the public record, because the credit value that determines what the customer earns is set through the program rather than published as a single number on a rate sheet.

Outside Georgia, the same structure functions as a benchmark. A regulated utility paying bill credits for dispatchable customer-sited capacity is a priced, commission-reviewed statement that behind-the-meter demand reduction has value to the system beyond whatever the customer saves on its own bill. Vertically integrated Southeastern utilities tend to share regulatory structures, and tariff language often migrates between them; whether the two-tariff pairing appears in a neighboring territory is a question for the next round of resource planning filings rather than a settled outcome.

The control layer. Under a Georgia Public Service Commission-approved integrated resource plan stipulation, Georgia Power is deploying a distribution distributed energy resource management system for visibility, forecasting and control of behind-the-meter resources, across a 2025 to 2028 spend window.

Taken together with the Resiliency Asset Service, that describes a utility assembling both the assets and the software that dispatches them on the customer side of the meter. Most utility distributed-resource programs in the United States acquire one of those two things. Georgia Power is acquiring both, on an approved cost-recovery timeline, and the DERMS portion is not contingent on how many customers sign up for the Resiliency Asset Service. The control layer arrives whether or not the ownership model scales.

What is not in the public record. The materials available publicly, the program FAQs and the DRC-1 tariff sheet, set out the eligibility thresholds and the credit structure. They do not resolve the question a building owner would actually need answered: what a given site earns, over a given term, relative to what it would cost that site to procure equivalent capacity independently. That figure depends on the credit value applied to the contracted demand reduction, and the credit value is not a single published number.

The absence is not unusual for a program of this type, but it does determine who can evaluate the offer. A customer with the analytical capacity to model dispatchable capacity value against its own load shape can price the program. A customer without that capacity is comparing a monthly charge from its utility against a proposal from a vendor, with no independent basis for judging which one reflects the underlying value of the resource.

What to watch. Three things will determine whether the Georgia structure is a local arrangement or a template.

The first is subscription. A tariff that is approved but lightly taken up tells other commissions something different from one that fills.

The second is whether the operational restrictions on how the customer may use the asset loosen over time. The thresholds are published; what is permitted at the meter day to day is governed by program documentation and customer agreements, and that is where the commercial value of a behind-the-meter asset to its host is actually determined.

The third is replication. The two-tariff pairing, an ownership tariff with a demand-reduction credit rider stacked on top, is a specific piece of regulatory architecture rather than a general one. If it appears in another vertically integrated Southeastern territory, that is evidence of a template. If it does not, Georgia Power will have built a program shaped by its own resource plan and its own load growth, which is the more common outcome for utility distributed-resource pilots.

For now, two numbers are on the public record: a 200 kilowatt premises floor and a 1,000 kilowatt contract threshold. Those are the terms on which a regulated utility has decided customer-sited capacity is worth owning.

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