Utility Data Center Plans: What Q1 Disclosures Actually Prove

Correction, October 18, 2026: this article previously combined different announcement dates and measures, inferred equipment quantities and supplier orders from load forecasts, and treated NERC’s alert as an installation mandate. Those conclusions are withdrawn. The comparison below uses original utility disclosures and distinguishes their stated plans from procurement commitments.

A gigawatt figure can describe a customer agreement, a development pipeline, generation capacity or a facility under construction. Those measures answer different procurement questions. AEP, Entergy, Duke and Xcel’s early-2026 disclosures illustrate the distinction.

This is a dated comparison of the Q1 reporting cycle and related announcements, not a statement that every project has the same status today. AEP and Duke published their Q1 materials on May 5. Entergy reported on April 29 after its March 27 Meta announcement. Xcel announced its Minnesota Google agreement on February 24. They were not four new deals announced within 48 hours.

Compare the measure before comparing the total

Utility and source date	What the issuer reported	What the figure does not establish
AEP, May 5	63 GW of incremental contracted load by 2030; a $78 billion 2026-2030 capital plan	Energized load, identical contract terms across regions, or a supplier order book
Entergy, April 29	A $57 billion 2026-2029 capital plan; proposed Meta-related generation exceeding 5,200 MW	5.2 GW of contracted Meta load or an approved equipment bill of materials
Duke, May 5	About 7.6 GW of data-center service agreements, including about 5 GW of facilities under construction	A forecast that every quarter will add the same volume or proof of every equipment award
Xcel, February 24	A Google service agreement and a proposed supply package with wind, solar and long-duration storage	A disclosed 1 GW campus rating, a uniform multistate specification, or approval of every component

Sources: AEP release, Entergy presentation, Duke presentation, Xcel announcement.

AEP: distinguish the contract forms

AEP’s presentation separates its 63 GW total into 41 GW in ERCOT, 16 GW in PJM and 6 GW in SPP. The associated documents differ: ERCOT uses letters of agreement, while the PJM and SPP categories include different proportions covered by electric service agreements. The same headline therefore does not describe one uniform commitment. (AEP presentation, page 16)

The capital-plan increase from $72 billion to $78 billion is a separate measure. AEP attributes it to transmission investment and Indiana gas generation. A buyer needs the project, approval, engineering package and purchasing schedule before translating a share of that plan into a transformer or switchgear requirement. The earlier article’s hypothetical RTO-exit equipment list and supplier lead times are not established by these disclosures. (AEP release)

Entergy: generation capacity is not customer load

Entergy’s April presentation identifies a four-year capital plan of $57 billion, excluding capital funded by customer contributions in aid of construction. Its Meta-related investment slide describes a filing request in docket U-37882, including seven combined-cycle plants totaling more than 5,200 MW. The March announcement also describes transmission, storage and other resources. These are proposed infrastructure components; the generation number should not be relabeled as contracted data-center demand. (Presentation, PDF pages 6 and 21; March announcement)

The procurement question is which component has reached approval, design and award. The old per-plant transformer size, equipment-spend range and assertion that the strategy withstands a 30 percent load reduction were not supported by the reviewed sources. They are removed. A planned generation total does not supply those missing calculations.

Duke: keep load agreements and generation contracts separate

Duke’s presentation shows about 7.6 GW of data-center electric service agreements, up about 2.7 GW since its Q4 call. It places approximately 5 GW of data centers under construction within that agreement total, which itself sits within a larger late-stage pipeline. These are nested categories, not volumes to add together. (Duke presentation, pages 9-10)

A separate generation slide provides more specific commitment evidence: Duke reports 20 gas turbines secured through a GE Vernova partnership and EPC contracts for the first approximately 5 GW of generation projects. That supports a statement about those agreements. It does not establish distribution-equipment orders at every data-center campus. The two approximately 5 GW figures refer to different assets. (Duke presentation, page 7)

Do not extend the reported increase into a year-end load forecast without new evidence. Likewise, the presentation does not justify a generic transformer count for each 250 MW campus.

Xcel: funding does not determine the equipment specification

Xcel’s February announcement names the Pine Island, Minnesota project and says Google will cover costs for its new service and associated grid infrastructure. It describes 1,400 MW of wind, 200 MW of solar and 300 MW of long-duration storage. These supply resources are not a published campus-demand rating. The announcement said the electric service agreement would require Minnesota commission approval; that historical statement is not a current docket-status check. (Xcel announcement)

The cost-allocation statement does not show who selects each transformer specification, whether the utility or customer owns it, or which vendor receives an order. Those answers require the actual agreement and engineering scope. The earlier 1 GW campus assumption and three-to-five-transformer estimate are withdrawn, along with the claim that customer funding automatically produces a hyperscaler-controlled equipment specification across several states.

NERC alert reporting is separate from equipment purchases

The May 4 Level 3 alert required registered recipients to acknowledge receipt by May 11 and report activity status by August 3. Page 2 explicitly distinguishes those reporting duties from implementing the essential actions: the alert itself does not make implementation mandatory. Existing approved Reliability Standards still apply. The reporting deadline was not a universal deadline to purchase or install relays, fault recorders or PMUs. (Original alert, page 2)

The recommended actions cover modeling, studies, commissioning, protection, recording and operational communication. Action 6 allows collaboration with a load owner and access to existing recording devices. It does not establish a new PMU purchase at every substation, a particular supplier, or a guaranteed procurement spike. A facility may need engineering work or equipment under its actual applicable requirements; that conclusion needs a site-specific assessment. (Alert, Essential Actions 1-7)

The alert’s older registration footnote was a proposal, not automatic registration of every 20 MW facility. NERC’s August FAQ and first drafts describe proposed applicability using at least 50 MW of connected load supplied through equipment connected at at least 100 kV. The connection definition matters and can differ from the customer’s ownership boundary. Neither proposal alone establishes a named company’s registration or an equipment order. (Project FAQ)

FERC’s July 16 order requires initial standards and associated definitions to be filed by December 31, 2026, expects proposed registry revisions by that date, and requires an informational workplan by March 1, 2027. These are NERC filing milestones. They do not establish customer compliance dates or prove a 2027-2028 retrofit schedule. The final ballot concluded October 14; NERC announced passage and advancement to Board adoption, followed by FERC review. Passage of the ballot is not Board adoption or FERC approval. (FERC order; NERC project status)

For procurement, document the facility’s approved requirements, study findings, existing capabilities, responsible owner and implementation dates. Use those records to identify any equipment gap. Do not convert the alert’s reporting deadline or a proposed standard into a supplier commitment.

What to verify before prioritizing a purchase

For each project, record four distinct items:

1. The measured asset: customer load, generation capacity, storage power and energy, or transmission scope. Preserve the source date and unit.
2. The commitment: an announcement, letter of agreement, service agreement, regulatory approval, EPC contract or supplier award. Do not substitute one for another.
3. The equipment scope: the approved design, ownership boundary, existing equipment, specification authority and purchasing responsibility. A campus MW figure alone does not determine transformer count or rating.
4. The purchasing date: the actual project schedule and contract milestones. A forecast year, reporting deadline or proposed standard is not an order date.

This approach gives a procurement team a defensible project list. It also keeps a headline capital plan from becoming an unsupported inventory recommendation.

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Related reading

• Grid Modernization Procurement Guide
• Data Center Load Pipelines and Contracted Demand