Utility Large Load Planning: Why Data Center Requests Must Be Evaluated as a Portfolio

A utility may receive ten data center requests through ten separate channels.

Each request may have its own developer, site, target date, point of interconnection, and requested capacity.

The utility can study each project individually. That does not mean it has a credible view of the total demand.

Some projects may compete for the same customer. Others may depend on the same transmission corridor. Several may request service from the same constrained substation area.

A portion may never proceed.

This creates a portfolio-planning problem.

Utilities need a process that distinguishes a credible demand forecast from a list of requested megawatts.

That is the purpose of utility large load planning.

Why Project-Level Reviews Are No Longer Enough

An individual interconnection study answers a narrow question.

It evaluates how one project affects the system under defined assumptions.

Portfolio planning answers a different set of questions:

• How many requests are likely to proceed?
• Which projects may be duplicates?
• Where is load becoming concentrated?
• Which upgrades support several projects?
• What happens if projects arrive in another sequence?
• How much generation and capacity will the portfolio require?
• Which costs belong to an individual customer?
• Which investments serve the wider system?
• What commitments should precede major utility spending?

The distinction matters because large-load forecasts can change quickly.

Exelon recently reduced its reported data center and large-load pipeline from 43 GW to 36 GW after applying additional screening and financial-commitment requirements. The company said it excluded speculative projects from its capital assumptions.

That example shows why raw request totals should not be treated as firm demand.

The Industry Is Moving Toward Greater Visibility

PJM’s Board directed PJM to develop a Large Load Registry in July 2026.

Electric distributors would provide information intended to improve load-forecast accuracy and transparency. Relevant information would also support resource-adequacy and cost-allocation processes.

PJM’s Board also cited approximately 70 GW of projected new large-load demand by 2038 and roughly 15 GW of generation retirements since 2022.

FERC is addressing the issue across a wider geographic area.

In June 2026, FERC directed six regional grid operators to justify their existing rules or propose reforms for large loads.

The orders cover:

• Application and study processes
• Transmission-cost transparency
• Cost-shifting protections
• Co-location and behind-the-meter generation
• Flexible large-load service
• Studies of generation serving nearby large loads

The six affected operators are PJM, MISO, SPP, CAISO, ISO New England, and NYISO.

These actions reflect a common problem.

Utilities, grid operators, regulators, developers, and existing customers need a clearer picture of which large loads are credible and what infrastructure they require.

The Main Weakness in Many Utility Pipelines

The weakness is not always a lack of information.

It is the absence of a structure for comparing projects.

One utility team may track signed agreements. Another may track inquiries. Economic development staff may track announced projects. System planners may track submitted load requests.

These lists may use different names and development stages.

The same project can appear several times.

For example:

• A developer submits through two affiliated entities.
• A customer evaluates three competing sites.
• A transmission provider and distribution utility record the same request.
• A project changes its requested capacity but both values remain in separate reports.
• A campus appears as several phases without a clear total.

Adding every entry together produces an inflated pipeline.

Removing every uncertain project creates the opposite problem.

The utility needs probability, location, timing, and maturity, not a single undifferentiated total.

A Six-Stage Utility Large Load Planning Framework

Stage 1: Create one controlled intake process

Every large-load request should enter a common record.

The intake should capture:

• Customer and developer
• Parent company and affiliates
• Site location
• Requested capacity
• Load ramp
• Target energization date
• Point of interconnection
• Site-control status
• Study status
• Financial commitment
• Major equipment status
• Generation and BESS plans
• Flexibility or curtailment capability
• Confidentiality restrictions

The utility should assign a unique project identifier.

That identifier should remain consistent when the project changes name, ownership, capacity, or phase.

Stage 2: Identify duplicates and competing alternatives

The utility should test whether several requests represent the same underlying demand.

Useful questions include:

• Does the same developer control several nearby entities?
• Is one end customer considering several sites?
• Do several projects use the same engineering data?
• Do project schedules and capacities appear mutually exclusive?
• Has the customer identified one preferred location?
• Are several phases being reported as separate full-build projects?

The utility does not need to disclose confidential customer information across applicants.

It does need an internal method for avoiding double counting.

Stage 3: Assign a maturity tier

Not all projects deserve the same forecast weight.

A practical structure may include:

The exact tiers should match the utility’s regulatory and planning environment.

The principle is consistent: evidence should determine forecast treatment.

Stage 4: Aggregate requests by location

A utility should map the portfolio against the electrical system.

The analysis should group requests by:

• Transmission zone
• Substation
• Feeder
• Voltage level
• Transformer bank
• Transmission corridor
• Generation pocket
• County or municipality
• Expected in-service year

This step reveals concentration risk.

Three individually manageable projects may create a major constraint when connected in the same area.

Locational aggregation also helps identify shared infrastructure.

A new transmission line or substation may support several projects. Another upgrade may serve only one customer.

That distinction affects sequencing and cost responsibility.

Stage 5: Build probability-weighted scenarios

A single forecast cannot capture every development outcome.

The utility should build several cases.

Core case

Includes projects with strong evidence of construction and energization.

Expected case

Includes the core case plus probability-weighted study-ready and committed projects.

High-growth case

Assumes a larger share of the credible pipeline proceeds.

Concentrated-growth case

Tests the outcome when several projects materialize within one constrained area.

Delayed-infrastructure case

Assumes generation, transmission, transformers, or permits arrive later than planned.

The utility should avoid false precision.

Probability weights represent planning judgments, not guaranteed outcomes. They should be reviewed as new evidence becomes available.

Stage 6: Connect the portfolio to an infrastructure roadmap

The final step converts the forecast into decisions.

The utility should identify:

• Near-term operating limits
• Substation additions
• Transformer requirements
• Transmission reinforcements
• Protection changes
• Generation and capacity needs
• BESS opportunities
• Demand flexibility
• Required land and rights-of-way
• Long-lead equipment
• Regulatory approvals
• Customer contribution requirements
• Decision dates

Each investment should have a trigger.

For example:

• Execute after financial security is posted.
• Begin design after two projects reach committed status.
• Order transformers after a defined customer agreement.
• Start permitting before final commitment because of long lead times.
• Defer construction if the portfolio falls below a threshold.

This creates a traceable link between customer evidence and utility spending.

How Portfolio Planning Protects Existing Customers

Large-load growth can require major infrastructure investment.

The central cost question is not whether the grid should grow.

It is who should bear the risk when a project does not proceed.

A sound planning framework can support:

• Customer deposits
• Financial security
• Minimum-demand charges
• Exit fees
• Construction contributions
• Milestone-based investment
• Shared-upgrade allocation
• Refund mechanisms
• Special contracts
• Regulatory review

The correct mechanism depends on state law, tariff design, utility ownership, and project circumstances.

The planning process should still identify the underlying cost causation.

FERC’s June 2026 orders specifically call for greater transmission-cost transparency and protections against cost shifting.

Why Municipal Utilities Need a Distinct Approach

Municipal and public-power utilities may face concentrated risk from one large project.

A single data center campus can exceed the utility’s existing peak demand or require infrastructure outside its normal capital plan.

The utility should evaluate:

• Wholesale power-supply obligations
• Transmission-service requirements
• Capacity exposure
• Credit support
• Retail rate design
• Distribution upgrades
• Staffing needs
• Emergency operating procedures
• Economic development commitments
• Consequences if the customer delays or exits

Economic development staff and utility planners should use the same project assumptions.

A public announcement should not become the load forecast without technical and commercial validation.

Common Planning Mistakes

Counting every request at 100 percent

This overstates likely demand and can produce premature investment.

Excluding uncertain projects entirely

This can leave the utility unprepared if several projects mature together.

Reviewing projects only in submission order

Submission order may not reflect maturity, system value, or likelihood of construction.

Ignoring geographic concentration

The system may have adequate regional capacity while one transmission corridor remains constrained.

Treating energization as one date

Large projects often ramp through several phases. Planning should reflect the load profile over time.

Separating generation adequacy from grid planning

A completed transmission connection does not prove sufficient generation or capacity exists to serve the load reliably.

Failing to update the portfolio

A large-load registry loses value when project status, ownership, capacity, and schedule are not maintained.

What Data Center Developers Gain From Better Screening

Developers may initially view stronger screening as another hurdle.

A clear process can also improve development decisions.

It helps developers understand:

• Which evidence the utility requires
• How their project will be classified
• When the utility will commit capital
• Which risks remain after the study
• How competing projects affect capacity
• What flexibility can improve the connection path
• Which milestone supports a credible power date

A credible developer can distinguish its project from speculative requests.

That can improve utility confidence and reduce time spent revisiting incomplete information.

Utility Large Load Planning Connects Requests to Decisions

The number of announced megawatts is not the same as a reliable demand forecast.

Utilities need a controlled process that connects project evidence to planning treatment.

Effective utility large load planning should:

1. Centralize project intake
2. Identify duplicates
3. Classify maturity
4. Aggregate demand by location
5. Build probability-weighted scenarios
6. Link infrastructure spending to defined triggers

POWER-tek USA LLC supports utilities and municipalities with large-load forecasting, transmission and distribution planning, grid-readiness assessment, system studies, infrastructure roadmaps, and cost and schedule risk analysis.

The objective is not to slow credible projects.

It is to separate credible demand from noise and prepare the system for the projects most likely to proceed.

Frequently Asked Questions

What is utility large load planning?

It is the process of screening, forecasting, aggregating, and sequencing major new electricity demands across a utility’s system.

Why should data center requests be evaluated as a portfolio?

Several requests may compete for the same capacity, involve the same customer, use the same transmission corridor, or carry different probabilities of completion.

How can a utility avoid double counting?

The utility can use common project identifiers, affiliate information, site data, customer relationships, study records, and internal cross-functional review.

What is a probability-weighted load forecast?

It assigns different planning treatment to projects based on evidence such as site control, technical readiness, financial security, agreements, permits, and construction progress.

What is a large load registry?

It is a controlled record of major load requests, their locations, status, capacity, timing, and relevant planning characteristics.

How often should the portfolio be updated?

Utilities should update material changes as they occur and conduct a formal review on a regular cycle, such as monthly or quarterly.