On July 14, New York created a 50 megawatt line for one specific purpose. Executive Order 62 directed the Department of Environmental Conservation to hold in abeyance certain discretionary permit, approval, and license applications for covered data centers that were pending before DEC and had not been determined complete before the order. Local permits were expressly excluded. The order defines covered data centers, for its own purposes, in part by whether a facility or group of facilities on the same or contiguous sites consumes or can consume at least 50 megawatts.1
That number is already being mistaken for something larger than it is. It is a policy threshold inside a particular New York process, not a finding that 49 megawatts is electrically inconsequential or that projects below the line deserve automatic approval. Other institutions draw different lines because they are solving different problems. AEP Ohio applies its specialized Schedule DCT process to new data center loads of 25 megawatts or more. ERCOT’s current Batch Zero process addresses eligible load facilities of 75 megawatts or greater. The North American Electric Reliability Corporation (NERC) is developing new registration criteria for computational loads, while the Federal Energy Regulatory Commission (FERC) has directed NERC to finalize registry criteria and initial reliability standards by the end of 2026.2
The useful conclusion is that megawatts are a triage variable. They can determine which pathway a project enters. They cannot replace evidence about the point of interconnection, the expected ramp, the system’s available capacity, on-site generation, power quality, water and emissions, upgrade costs, or who bears the risk if the forecast fails.
The Demand Is Large-the Decisions Are Local
A 2024 US Department of Energy report prepared with Lawrence Berkeley National Laboratory estimated that US data centers consumed about 176 terawatt-hours of electricity in 2023, or 4.4 percent of national electricity use. It projected 325 to 580 terawatt-hours by 2028, equivalent to roughly 6.7 to 12 percent of US electricity use under the report’s scenarios.3
Federal institutions are responding, but they are not creating one national siting code. On June 18, 2026, FERC issued Federal Power Act section 206 show-cause orders to the six regional grid operators under its jurisdiction and their transmission owners. The orders require them to justify existing tariffs or propose changes addressing large-load study processes, transmission cost shifting, co-location, flexible transmission service, and electrically proximate generation. FERC also stated that the orders do not displace state authority over generation siting and permitting or state public utility commission authority over retail rates, terms, and conditions.4
NERC is addressing a different layer: bulk-power-system reliability. Its May 2026 Level 3 alert called for actions involving computational-load modeling, studies, instrumentation, commissioning, operations, protection, and control. In July, FERC ordered NERC to complete new computational-load registry criteria and initial reliability standards by December 31, 2026. At this article’s cutoff, those registry criteria and standards were still under development, not mandatory final rules.5
These actions reinforce the same point. A data center can be small relative to a hyperscale campus and still be consequential to the utility, substation, feeder, water system, or county that must absorb it. The material question is not whether a project fits a marketing label. It is what the project obligates other institutions to build, reserve, finance, operate, and defend.
A Predictable Path
Developers are right to object when a project can spend months moving among a utility, transmission owner, county, water authority, air agency, and other offices without a clear sequence. But the remedy is not to waive review for projects below an arbitrary size. It is to define the evidence that makes a project ready for review and the commercial consequences that follow once capacity is reserved.
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From
Site Control to Firm Power: What Data Center Development Looks Like on the
Ground Rich
Demon, CEO East Energy Renewables East
Energy Data, an affiliate of East Energy Renewables, entered data center
development with an advantage many newcomers lack: years of experience
building energy infrastructure in rural communities. Its
agricultural-waste-to-energy projects have sometimes been controversial, but
the company has built durable local relationships around all four of its
operating sites. When EED began pursuing data centers in early 2025, it
therefore expected community acceptance to be manageable. The
company deliberately avoided hyperscale projects. It targeted facilities of 8
to 49 MW, generally near its existing operations, and tried to size each
project around power that could be delivered without major transmission
upgrades. Preferred sites were established industrial areas requiring less
than 50 acres, with substantial buffers, reclaimed wastewater for cooling
where available, and onsite natural-gas generation for redundancy. The
first projects showed how difficult even that approach can be. At one site,
EED withdrew after encountering sustained public opposition. The town adopted
a one-year data center moratorium a week later. At a second site, the company
went further, spending approximately $35,000 on a utility impact study,
limiting the project to 8 MW to fit the capability of a nearby substation,
and beginning land procurement. That city also enacted a moratorium, and EED
shelved the project. A
third project has followed a different path. In mid-2025, EED selected a
160-acre site in a newly designated rural industrial zone, with more than 100
acres retained as forested buffer. It executed a memorandum of understanding
with the county and initiated a roughly $170,000, three-part utility impact
study involving the local electric cooperative and the larger organizations
responsible for supplying it. The
study subsequently indicated that approximately 15 MW could be available
within 12 months and 50 MW within 36 months. Yet even then the project was
not secure. As EED's site control expired, two other parties sought control
of the surrounding 600 acres for hyperscale development, and the county
initially declined to renew EED's agreement. EED
responded by making the development case in local terms: a smaller footprint,
separation from neighboring properties, potentially more than $600 million of
investment at 50 MW, local employment, community-college apprenticeships,
commitments to hire and promote locally, and recurring support for a local
service organization. The county ultimately renewed the MOU, creating a path
toward an option and eventual purchase if the remaining development work is
completed. The
experience illustrates why acreage and nominal electric capacity are poor
proxies for data center readiness. A viable project requires power that can
actually be delivered on an acceptable schedule, local institutions willing
to support the development, and community benefits residents regard as
credible. It
also exposes a broader industry problem. The rush to control large parcels
can begin before developers understand power availability or local
conditions. Those speculative efforts create expectations, competition, and
sometimes opposition that affect every project that follows. For
EED, the lesson has been clear: community engagement is no longer a
workstream that follows site selection. It has become part of the
infrastructure required to make a data center project executable. |
AEP Ohio provides a useful example of that architecture. Its data center tariff became effective July 23, 2025. For requests of 25 megawatts or more, a customer must control the property, provide a specific location, load ramp, and final load, and pay a study fee. AEP Ohio says it will make reasonable efforts to complete load studies within 45 days when regional transmission upgrades are not needed and 60 days when they are. Those are stated effort targets, not guarantees of energization.6
After the study, AEP Ohio presents a Letter of Agreement and an Electric Service Agreement. The Letter of Agreement can require reimbursement of 100 percent of buildout costs if the customer cancels or delays the project by more than 12 months before the target energization date. The service agreement begins on actual energization, not on a forecast date.7
The tariff also converts a forecast into a longer-term commitment. The ramp may not exceed four years; contract capacity floors rise during that period; the initial contract term equals the ramp period plus eight years; collateral can equal 50 percent of total minimum charges for customers that do not satisfy specified credit and liquidity tests; and minimum billing provisions continue to apply even when actual demand is lower.8
Those percentages are not a universal template. Their importance is institutional. A utility that is asked to reserve scarce capacity and trigger infrastructure construction can require evidence of readiness and place the risk of cancellation, delay, and underutilization on the customer that caused the commitment.
Contract the Load the Grid Must Actually Serve
A community-scale pathway should therefore center on the quantity that matters to electric service: maximum grid withdrawal at the point of interconnection, together with a staged ramp and the conditions under which that withdrawal may change. Nameplate campus size remains relevant, but it is not a substitute for the load the utility must plan to serve.
On-site generation complicates that calculation. A project that proposes 60 megawatts of computing load and 25 megawatts of behind-the-meter generation may expect to withdraw only 35 megawatts in normal operation. That does not mean the grid can automatically be studied as a permanent 35 megawatt load. The contract has to address generator outages, transition states, export, islanding, protection, and the equipment that prevents net grid withdrawals from exceeding the agreed limit.
AEP Ohio’s tariff illustrates the distinction. When behind-the-meter generation is used for netting, the customer must maintain equipment that can instantaneously curtail load by at least the output of the behind-the-meter generation so that loss of that generation does not cause the customer to exceed contract capacity. The same tariff aggregates certain affiliated or commonly owned loads when applying its minimum-demand rules and can aggregate multiple facilities at a single location when their combined load crosses the 25 megawatt threshold.9
That is a stronger model than a carveout. It governs the system that will actually exist, rather than the way a developer divides parcels, phases buildings, or describes the campus.
Flexibility as a Performance Obligation
Data centers may have batteries, deferrable computing, workload migration, or on-site generation. None of those capabilities has system value merely because it exists. Flexibility becomes useful to the grid when the contract identifies the trigger, notice, baseline, response time, duration, rebound behavior, measurement method, test regime, and consequence for nonperformance.
The economics are also tariff-specific. In MISO, the current planning-reserve-margin requirement calculation uses a coincident-peak-demand forecast as an input. MISO is separately considering reforms that would allocate resource-adequacy obligations using hours that better reflect reliability risk rather than relying only on the current peak-based approach.10
In ERCOT, Four Coincident Peak calculations still identify each distribution service provider’s load during the system peak intervals for June, July, August, and September. Texas is also reviewing transmission-cost allocation, so the durability of today’s 4CP incentives should not be assumed. Whether and how those wholesale signals reach an individual data center customer depends on the applicable retail tariff or contract.11
A hypothetical 40 megawatt project that can curtail 20 megawatts might create meaningful value if it performs during the interval that sets a cost or capacity obligation. The same capability may be worth far less if it responds in the wrong hour, rebounds into another constraint, or is unavailable during the system event that matters. No publication-grade dollar value can be derived from nameplate demand and an average dollars-per-kilowatt-month charge alone.
A defensible structure is therefore two-part: firm service for the demand the utility must stand ready to supply, and a separately defined flexible block that earns a credit, accelerated treatment, or other benefit only after it is tested. Repeated nonperformance should remove the benefit or increase security if the governing tariff or contract authorizes that remedy.
Behind the Meter Does Not Mean Outside the Rules
The much larger Susquehanna nuclear example shows why proximity to generation is not a jurisdictional shortcut. Talen Energy’s first-quarter 2026 filing says its revised agreement with Amazon Web Services is expected to provide up to 1,920 megawatts through 2042 in a front-of-the-meter model and that the transition to the revised agreement occurred in April 2026.12 The project is not a community-scale analogue. It is evidence for a narrower proposition: a load located next to generation still has to be fitted into transmission, service, and reliability arrangements.
The same caution applies to the Public Utility Regulatory Policies Act. FERC describes a qualifying small power production facility as a generating facility of 80 megawatts or less whose primary energy source is renewable energy, biomass, waste, or geothermal resources, subject to the agency’s site and certification rules. Qualifying cogeneration is a different category and requires sequential production of electricity or mechanical energy and useful thermal energy under applicable standards.13
A conventional natural-gas generator does not become a PURPA small power production qualifying facility merely because it is below 80 megawatts. A project may have a separate cogeneration case, but that requires a project-specific legal and engineering analysis. In either case, qualifying-facility status does not erase every interconnection, retail-service, or environmental requirement.14
Air permitting is similarly equipment- and jurisdiction-specific. The US Environmental Protection Agency notes that most Clean Air Act permitting programs are administered by state and local air agencies, while stationary engines and turbines can also be subject to federal New Source Performance Standards or hazardous-air-pollutant requirements depending on the equipment and operating profile.15
Community Benefits Should Survive the Announcement
Community benefits need the same discipline as power commitments. Taxes owed under law, construction payroll, permanent employment, infrastructure built primarily for the customer, and negotiated community contributions are different categories. They should be reported separately.
New York’s Executive Order 62 directed Empire State Development to create a Community Investment Framework for local negotiations. The policy outline released with the order describes community funds, infrastructure, labor, public services, transparency, and other possible commitments. It also floated a recommended negotiation baseline of $1 million per megawatt of anticipated utility demand. That figure is a policy proposal and negotiation starting point, not a generally binding statewide payment requirement.16
The order separately directed the Department of Public Service to form a data center interconnection working group around 'beneficiary pays' principles and to consider mechanisms that could protect other customers from stranded-grid costs. Community investment and electric-system cost responsibility are related policy questions, but they are not the same transaction.17
Linn County, Iowa, offers a local example of converting some obligations into rules. In February 2026, the county adopted requirements for large data centers in unincorporated Linn County that include a water study, a water-use agreement with monitoring and reporting, and an economic-development agreement outlining community benefits. Effective July 1, the county then imposed an 18-month moratorium on accepting new applications to rezone property to its EU-3 Large-Scale Data Center Zoning District while it reviews cumulative impacts. The moratorium does not apply inside incorporated cities.18
The lesson is not that every county should copy Linn County or that New York’s proposed contribution level is the right number. It is that community promises become credible when they name a beneficiary, amount or formula, date, metric, reporting duty, enforcement authority, and consequence for failure—and when those obligations survive a sale or material change in the project.
The Earned-Predictability Package
A smaller project should be eligible for a standardized or expedited track only after it becomes measurable. The package below is a proposed governance design, not a statement that every jurisdiction already has authority to impose every term. Exact remedies must be grounded in the applicable tariff, contract, permit, ordinance, and state or federal law.
| Commitment | Required evidence and ongoing verification | Potential remedies for nonperformance |
|---|---|---|
| Project readiness | Documented site control, a project-specific load ramp, an equipment procurement plan, financing milestones, and deadlines for meeting readiness requirements. | Loss of queue position or reserved capacity, where permitted by the governing process. |
| Grid demand and load ramp | Studies covering expected demand at the point of interconnection and each stage of the load ramp; metering and telemetry to verify actual demand. | Deferral of capacity increases, curtailment, additional financial security, or other service remedies. |
| Cost responsibility | Study deposits, upgrade cost estimates, collateral, minimum billing obligations, and explicit allocation of cancellation and stranded-cost exposure. | Draws on financial security, exit charges, or reimbursement of assigned costs. |
| Committed load flexibility | A defined curtailment quantity, activation trigger, baseline, notice period, response time, duration, and rebound plan; performance testing and event telemetry. | Reduction or withdrawal of flexibility credit or expedited treatment; additional financial security where authorized. |
| Power quality and on-site generation | Equipment models, ride-through requirements, protection settings, export limits, procedures for outages and transitions between grid and on-site supply, commissioning tests, and notification of material changes. | Required mitigation, operating limits, restudy, or other reliability remedies. |
| Community commitments | Named beneficiaries; payment amounts or formulas; measurable employment and water-use commitments; reporting, audit, and financial security provisions; and obligations that survive changes in ownership or control. | Draws on escrow, clawbacks, damages, or permit-related remedies expressly established by the governing instrument. |
In return, the project should receive something concrete: a standard application, a defined study track, published evidence requirements, target schedules or written reasons for delay, staged energization where technically and legally feasible, and clear transition rules when policy changes. Predictability is valuable. It should be exchanged for commitments that make the project easier to study and safer for other customers to rely on.
A size threshold can still be part of that regime. Below a stated level, projects that satisfy impact screens could enter an expedited track. A project that fails a screen would move to fuller review rather than automatically die. Larger projects with unusually strong controls could receive staged treatment without being deemed harmless.
That is the useful meaning of community scale: not a legal safe harbor, but a development strategy in which the project accepts bounded, locally legible obligations. The developer gets a clearer path. The utility gets a credible load forecast, security, and operational limits. The community gets measurable commitments instead of a benefits list. Regulators keep the authority to look at cumulative effects.
The distinction is between a customer that asks everyone else to plan around a forecast and a project that makes the forecast enforceable. A carveout says the number is small enough to trust. A contract says what will be measured, who carries the risk, and what happens when the project does something different. That is the harder bargain. It is also the one most likely to make smaller data centers genuinely easier to approve.
Notes
1. Office of the Governor of New York, “No. 62: Establishing a Temporary Moratorium on Data Centers in New York While the State Develops Higher Standards for Data Center Development and Benefits Blueprint to Support Localities,” Executive Order 62, July 14, 2026, https://www.governor.ny.gov/executive-order/no-62-establishing-temporary-moratorium-data centers-new-york-while-state-develops.
2. AEP Ohio, “Data Center Tariff,” effective July 23, 2025, accessed August 17, 2026, https://www.aepohio.com/company/about/rates/data center-tariff/; Electric Reliability Council of Texas, “Large Load Integration,” Batch Zero Interconnection Study Process, accessed August 17, 2026, https://www.ercot.com/services/rq/large-load-integration; North American Electric Reliability Corporation, “Project 2026-02 Computational Loads,” accessed August 17, 2026, https://www.nerc.com/standards/reliability-standards-under-development/2026-02-computational-loads; NERC, “FERC Sets Year-End Deadline for NERC to Finalize Registry Criteria and Standards for Computational Loads,” July 16, 2026, https://www.nerc.com/newsroom/ferc-sets-year-end-deadline-for-nerc-to-finalize-registry-criteria-and-standards-for-computational-loads.
3. US Department of Energy, “DOE Releases New Report Evaluating Increase in Electricity Demand from Data Centers,” December 20, 2024, summarizing Lawrence Berkeley National Laboratory, 2024 United States Data Center Energy Usage Report, https://www.energy.gov/articles/doe-releases-new-report-evaluating-increase-electricity-demand-data centers.
4. Federal Energy Regulatory Commission, “FERC Launches Aggressive Targeted Action to Speed Large Load Integration,” June 18, 2026, https://www.ferc.gov/news-events/news/ferc-launches-aggressive-targeted-action-speed-large-load-integration; FERC, “Fact Sheet | FERC Takes Action to Supercharge America’s Grid for Efficiency, Reliability, and a Bold Energy Future,” June 18, 2026, https://www.ferc.gov/news-events/news/fact-sheet-ferc-takes-action-supercharge-americas-grid-efficiency-reliability-and.
5. North American Electric Reliability Corporation, “Computational Load Modeling, Studies, Instrumentation, Commissioning, Operations, Protection, and Control,” Level 3 Essential Actions Alert, May 4, 2026, https://www.nerc.com/globalassets/programs/bpsa/alerts/level-3-computational-load-alert.pdf; NERC, “FERC Sets Year-End Deadline for NERC to Finalize Registry Criteria and Standards for Computational Loads,” July 16, 2026, https://www.nerc.com/newsroom/ferc-sets-year-end-deadline-for-nerc-to-finalize-registry-criteria-and-standards-for-computational-loads.
6. AEP Ohio, “Data Center Tariff,” “Mandatory Process for Customers Interested in Moving Forward with Data Center Projects in AEP Ohio’s Service Territory,” accessed August 17, 2026, https://www.aepohio.com/company/about/rates/data center-tariff/.
7. AEP Ohio, “Data Center Tariff,” steps 3–4 of the Schedule DCT service-request process, accessed August 17, 2026, https://www.aepohio.com/company/about/rates/data center-tariff/.
8. AEP Ohio, “Data Center Tariff,” “Load Ramp Period,” “Contract Term,” “Collateral Requirement,” and “Minimum Demand Charges,” accessed August 17, 2026, https://www.aepohio.com/company/about/rates/data center-tariff/.
9. AEP Ohio, “Data Center Tariff,” “Aggregation” and “Behind-the-Meter (BTM) Generation,” accessed August 17, 2026, https://www.aepohio.com/company/about/rates/data center-tariff/.
10. Midcontinent Independent System Operator, “How Is Planning Reserve Margin Requirement (PRMR) Calculated,” updated July 6, 2026, https://help.misoenergy.org/knowledgebase/article/KA-01065/en-us; MISO, “RASC: PRMR Allocation Design (RASC-2019-2 and 2020-4),” April 15, 2026, https://www.misoenergy.org/engage/stakeholder-feedback/2026/rasc-prmr-allocation-design-rasc-2019-2-and-2020-4-20260415/.
11. Electric Reliability Council of Texas, “ERCOT Four Coincident Peak Calculations,” accessed August 17, 2026, https://www.ercot.com/mktinfo/data_agg/4cp; Public Utility Commission of Texas, Project No. 58484, “Evaluation of Transmission Cost Recovery,” filings through August 17, 2026, https://interchange.puc.texas.gov/Search/Filings?ControlNumber=58484.
12. Talen Energy Corporation, Quarterly Report on Form 10-Q for the quarter ended March 31, 2026, definition of “AWS PPA,” filed with the US Securities and Exchange Commission, https://www.sec.gov/Archives/edgar/data/1622536/000162253626000036/tln-20260331.htm.
13. Federal Energy Regulatory Commission, “PURPA Qualifying Facilities,” accessed August 17, 2026, https://www.ferc.gov/qf; see also 18 C.F.R. §§ 292.203–292.207.
14. FERC, “PURPA Qualifying Facilities.” Qualifying-facility status and the federal QF categories do not by themselves eliminate project-specific interconnection, retail-service, state-implementation, or environmental requirements. https://www.ferc.gov/qf.
15. US Environmental Protection Agency, “Clean Air Act Resources for Data Centers,” accessed August 17, 2026, https://www.epa.gov/stationary-sources-air-pollution/clean-air-act-resources-data centers.
16. Empire State Development, “Policy Outline for the New York State Data Center Community Investment Framework,” July 14, 2026, https://esd.ny.gov/sites/default/files/media/document/CIF-Policy-Outline-071426.pdf.
17. Office of the Governor of New York, Executive Order 62, sections 3–4, July 14, 2026, https://www.governor.ny.gov/executive-order/no-62-establishing-temporary-moratorium-data centers-new-york-while-state-develops.
18. Linn County, Iowa, “Data Centers in Unincorporated Linn County,” updated 2026, accessed August 17, 2026, https://www.linncountyiowa.gov/1862/Data centers-in-Unincorporated-Linn-Coun.
