Five FERC Changes in Five Minutes: What Energy Investors Need to Know

For financial institutions financing, investing in or valuing power-intensive projects, the rules governing large-load interconnections are becoming a material consideration for project timing, capital requirements and portfolio strategy.

Electricity demand from data centers, advanced manufacturing and other large industrial users is growing faster than many transmission systems were designed to handle. On June 18, 2026, the Federal Energy Regulatory Commission (FERC) issued show-cause orders directing all six regional grid operators to justify or reform their tariff rules for large-load interconnections within 60 days and file resource adequacy reports within 30 days.

These are not final rules. They open six parallel regional proceedings, and outcomes will likely vary by market. But the direction is unmistakable: FERC wants large-load projects to connect more efficiently, bear an appropriate share of the costs they create and demonstrate a credible relationship between new demand and available supply.

For lenders and investors, that means regulatory decisions could directly affect development timelines, financing needs, asset valuations and long-term portfolio strategy.

What FERC’s Large-Load Order Means for Energy Investors

FERC is not simply trying to make it easier for more large loads to connect to the grid. It is attempting to establish clearer terms for how those projects enter the system, who bears the associated costs and how new electricity demand will be matched with reliable supply.

For energy lenders and investors, that means interconnection is moving out of the technical appendix and into the center of the investment decision. Regional differences will matter — lenders and investors should expect different requirements, risks and opportunities across the country as each grid operator responds to the order.

The projects most likely to attract capital will not necessarily be those with the largest announced demand. They will be the projects that can demonstrate a credible, flexible and financeable path to power.

What These Changes Mean Together

FERC’s proceedings point toward a new model for large-load development, a model that demands more from projects before they can access the grid. Going forward, developers will increasingly be expected to demonstrate greater commercial readiness, clearer responsibility for grid costs, a realistic source of generation, operational flexibility where applicable and meaningful coordination between load, generation and transmission timelines.

For financial institutions, this redefines what project bankability means. Strong demand signals are not enough. A financeable project needs credible answers to five specific questions and those answers will vary across the six regional markets affected by the FERC order.

Here Are the Five Changes Investors Need to Understand

1.  Faster and More Disciplined Study Processes

FERC is directing regional grid operators to overhaul how large-load transmission applications are submitted, evaluated and studied including consideration of alternative transmission technologies that could expand grid capacity more efficiently.

According to Enverus Intelligence^® Research (EIR), the goal is to create a process that can distinguish credible developments from speculative, duplicative, or commercially unready requests. Projects that are genuinely ready may move through faster; less mature applications could lose their place in queue or face higher requirements.

Why this matters for financial services

A utility interconnection application or a proposed energization date should not be treated as evidence that power will actually be available. Before committing capital, lenders and investors should evaluate:

• Whether the developer controls the site and has made meaningful financial commitments
• Which interconnection studies have been completed — and which are still outstanding
• What network upgrades are required and whether the proposed timeline accounts for them
• Whether the load request reflects a realistic development schedule, not just an option

The core financial question:

Is this a real project with an executable path to power — or an attractive development story that hasn’t been stress-tested against grid realities?

2.  Stronger Protection Against Cost Shifting

FERC is focused on bringing transparency to transmission and network upgrade costs by ensuring those costs are borne by the projects that trigger them, not shifted to utilities and existing ratepayers.

A new data center or industrial facility can require substantial grid investment. If that project is delayed, downsized or cancelled, the infrastructure built to serve it may still need to be paid for. FERC wants clearer accountability for those outcomes.

Why this matters for financial services

Large-load developments will increasingly require meaningful financial commitments earlier in the project lifecycle. Depending on how regional rules evolve, exposure could include:

• Study deposits and scoping fees
• Network upgrade contributions and construction cost-sharing obligations
• Letters of credit and parent company guarantees
• Minimum payment requirements and obligations tied to requested capacity
• Costs associated with a delayed or reduced load ramp

These requirements will affect project leverage, liquidity, contingency reserves and the amount of sponsor equity required before operations begin. Transmission costs are becoming a material line item in the project capital structure.

3.  Greater Support for Co-location and Behind-the-Meter Generation

FERC is directing regional markets to develop clearer treatment of co-located projects — arrangements that pair a large electricity user with generation located on or near the same site. Under the new order, these projects receive an explicit regulatory tailwind: they are positioned to become the preferred pathway for connection requests.

That said, co-location changes the nature of the risk it doesn’t eliminate it. The entire power solution still requires rigorous diligence.

Why this matters for financial services

For gas-fired behind-the-meter generation, diligence should cover pipeline proximity, available transportation capacity, fuel price exposure, equipment availability, air permitting, operating reliability, backup power and grid import/export restrictions.

For renewable and storage combinations, the analysis should address intermittency, storage duration, grid backup requirements and contractual alignment with the facility’s actual operating profile.

Co-location also opens new investment opportunities across generation, storage, microgrids, gas infrastructure and related energy services.

4.  New Service Options for Flexible Large Loads

FERC is asking grid operators to consider new transmission-service options for large loads that can reduce or interrupt consumption when the grid is constrained. Projects with genuine operational flexibility may be able to connect faster, or at lower cost, because they don’t require the grid to serve their full maximum demand under every condition.

This is particularly relevant for projects supported by on-site generation, battery storage, staged load growth, demand-management technology, or curtailable operations.

Why this matters for financial services

Load flexibility can be a real source of project value — but only when it is technically credible and commercially structured. Before underwriting that value, investors should ask:

• How often can the project be curtailed and for how long?
• Who controls the curtailment decision — the utility, the operator, or an automated system?
• Does the project have backup supply that maintains operations during interruptions?
• Are tenant or customer contracts compatible with service interruptions?
• What happens to revenue during a curtailment event?

The core financial question:

Can the project reduce its grid demand without undermining the revenue and operating assumptions that support the investment thesis?

5.  Better Coordination Between Large Loads and Nearby Generation

The final reform area addresses how new generating facilities should be studied when they are intended to serve electrically proximate or co-located large loads. Historically, load development, generation interconnection and transmission planning have moved through separate processes on different timelines — a separation that is increasingly untenable when a large-load project depends on new generation arriving at roughly the same time.

Why this matters for financial services

Investors can no longer evaluate the load and its proposed power supply as independent projects. The two must be underwritten together. Key questions include:

• Does the generation project have its own credible interconnection path?
• Are transmission upgrades required for both the load and the generation?
• Can the generation legally and physically serve the load as proposed?
• How do delays in one project affect the economics of the other?
• Who bears the risk if the load and generation timelines don’t align?

This is especially important for projects promising accelerated access to power through a generation asset that hasn’t yet been constructed or interconnected. As EIR puts it, a proposed power source is only valuable when it can actually be delivered on the timeline embedded in the financial model.

Gas vs. Solar vs. Storage: How to Compare Apples to Apples in Power Investment

The power sector is experiencing a fundamental shift. AI-driven data center buildouts, electrification mandates and grid reliability concerns are driving demand for new generation capacity at a pace the industry hasn’t seen in decades. And for investors, developers and operators trying to allocate capital across that landscape, the question is no longer just which assets to pursue—it’s how you actually compare them.

A combined cycle gas plant in Texas. A utility-scale solar farm in New Mexico. A four-hour battery storage project in California. Each carries a different risk profile, a different revenue structure and a fundamentally different operational logic. Yet capital allocation decisions require putting all three on the same scale. That’s the challenge  and it’s one that the power investment world hasn’t solved cleanly. 

The Problem: Power Asset Classes Were Never Built to Be Compared

Three Asset Types at a Glance

	Natural Gas	Solar PV	Battery Storage
Revenue Driver	Energy & capacity markets; spark spread	PPA off-take; capacity factor	Energy arbitrage; ancillary services; capacity payments
Dispatch Type	Often misjudges arrival and duration of cold snaps or warm-ups	Intermittent (daylight hours only)	Flexible (charges & discharges on price signal)
Capex Profile	Higher upfront; stable over time	Declining rapidly ($/MW)	Tied to battery duration ($/MWh)
Key Risk Factor	Fuel price & carbon policy exposure	Curtailment risk; PPA counterparty quality	Revenue stack volatility; market rule changes
Underwriting Complexity	Moderate – heat rate, utilization assumptions	Moderate – irradiance, degradation curve	High – duration, stacked revenue sources

Source: Enverus Power & Renewables | For illustrative purposes

Natural gas, solar and storage differ in almost every financial dimension that matters to an investor. 

Natural gas earns revenue through energy and capacity markets, with dispatch economics tied to fuel costs, heat rates and spark spreads. Its returns are sensitive to gas prices, carbon policy and utilization assumptions. A gas plant that looks excellent at $3.50/MMBtu looks materially different at $5.00. Capex is typically higher upfront, but the asset can generate revenue around the clock — making it a baseload or peaking play depending on configuration. 

Solar PV operates on a completely different financial structure. Revenue is a function of irradiance, capacity factors and contracted off-take — typically a power purchase agreement (PPA) at a fixed or indexed price. Capex has fallen dramatically and continues to decline, but solar is intermittent by nature. It generates during daylight hours, which creates both curtailment risk and basis risk depending on how congested the local market gets around noon. Evaluating a solar deal requires understanding the shape of generation, the quality of the PPA counterparty and the long-run degradation curve of the panels. 

Battery storage is the most structurally complex of the three. It doesn’t generate power — it arbitrages it. Revenue comes from a combination of energy arbitrage, ancillary services (frequency regulation, spinning reserves) and increasingly, capacity payments. Duration matters enormously: a two-hour battery and a six-hour battery are nearly different asset classes from an investment standpoint. And the revenue stack is more volatile and less contracted than a typical PPA, meaning underwriting storage requires a fundamentally different set of assumptions about market structure. 

The result: comparing a gas plant to a solar farm to a battery project using a single spreadsheet model means rebuilding your assumptions from scratch every time or worse, forcing incompatible assets into the same template and hoping the outputs are meaningful. 

Most investment teams do something in between. They run separate models. They apply different discount rates subjectively. They benchmark against other deals they’ve seen rather than operating data. And they take weeks to get to a first-pass view on any single opportunity. 

What Happens When You’re Evaluating at Scale

The problem compounds quickly when you’re not evaluating one asset and you’re evaluating a pipeline of them. 

Consider a fund or developer that’s actively screening 50 opportunities across gas, solar, wind and storage in each quarter. Each asset type requires its own modeling conventions. Each team member has built their model slightly differently. PPA pricing assumptions vary. Capex benchmarks are pulled from memory or stale comps. The result is a portfolio of financial models that are internally consistent but externally incomparable. You can’t rank a solar project against a gas plant against a storage deal in any reliable way because the underlying assumptions were
never standardized. 

This is a structural problem with how power assets have historically been underwritten: one deal at a time, by specialists in each technology, using bespoke models. That approach made sense when gas dominated new capacity additions and the competitive set was narrow. It doesn’t work in a market where all three technology types are competing for the same capital simultaneously. 

The teams that are winning in this environment are building systems, a standardized financial framework that lets them evaluate gas, solar and storage on a consistent basis, rank them against real operating benchmarks and stress-test economics quickly across scenarios.

What “Apples to Apples” Actually Requires 

A true cross-asset comparison framework for power investment needs to do several things consistently: 

• Standardized financial outputs. 
  IRR, NPV, and payback period needs to be calculated using the same methodology across all asset types — same treatment of depreciation, tax equity, debt structure and 
  terminal value. 

• Consistent capex benchmarking. 
  Actual installed costs per MW – not developer proformas. Reflecting what gas, solar and storage really cost to build today, by region. 

• Technology-appropriate revenue modeling. 
  Gas runs on spark spread. Solar runs on PPA structure. Storage runs on a stacked revenue model. Each handled correctly — without rebuilding the logic. 

• Real-world operating benchmarks. 
  Returns benchmarked against how similar projects actually performed, not what was promised at financial close. 

• Scenario flexibility. 
  Power prices are up 20%. Capex over budget by 15%. Any framework that requires rebuilding from scratch to answer those questions is too slow. 

The Stakes Are High — And Getting Higher

The urgency here isn’t abstract. The AI-driven surge in power demand is repricing generation assets across all technology types simultaneously. Data center developers are signing long-term offtake agreements at prices that would have seemed unrealistic three years ago. Transmission constraints are creating regional basis differentials that significantly affect asset economics. The Inflation Reduction Act continues to reshape the economics of solar, wind and storage through the tax credit landscape. 

In this environment, investment decisions made on the basis of stale benchmarks, inconsistent models, or incomplete scenario analysis carry real downside risk. A gas plant underwritten against 2021 capex numbers may no longer pencil the way the original model suggested. A storage project benchmarked only against developer projections, without reference to how comparable projects have actually performed, may carry execution risk that isn’t showing up
in the IRR. 

The teams that are moving fastest and with the most conviction are the ones who’ve solved the apples-to-apples problem and who can screen hundreds of assets across all three technology types in days rather than weeks, benchmark against real operating performance and stress-test key assumptions without rebuilding from scratch. 

The Solution: Power Plant Portfolio Economics

That’s exactly the problem Enverus built Power Plant Portfolio Economics to solve. 

Power Plant Portfolio Economics delivers standardized, investment-grade financial analytics — IRR, NPV, payback period — across thousands of generation and storage assets, calculated using consistent methodology regardless of technology type. Gas, solar, wind and battery storage are all evaluated on the same financial framework, so your team can compare a combined-cycle plant in the Gulf Coast against a solar-plus-storage project in the desert Southwest without rebuilding a single model. 

The platform draws on actual operating and completed project data, not developer projections so your benchmarks reflect how assets actually perform in real market conditions. And scenario testing is built in: adjust capex, PPA pricing, or operating cost assumptions on the fly to run upside, downside and base-case views instantly. 

For investment teams operating at scale, funds screening large pipelines, developers prioritizing where to allocate development capital, operators benchmarking their portfolio against the market — it’s the difference between evaluating ten deals a month and evaluating a hundred. 

The power sector is moving faster than it ever has. The investment teams that will win are the ones who can see the whole picture, compare assets on equal footing and move from screening to decision in minutes, not weeks. 

Want to see how Power Plant Portfolio Economics works across your asset pipeline? Request a demo at Enverus.com