Infrastructure Intelligence No. 08: The Next Megawatt

Energy. Power. Development. Capital. | October 20, 2026 | Issue No. 08

THE WEEK IN INFRASTRUCTURE

The Next Megawatt: Building New Power and Unlocking What's Already There

The infrastructure market is pursuing two complementary approaches to its most pressing challenge: developing new generation and extracting more capacity from infrastructure already in place.

This week brought significant developments on both fronts.

In Indiana, American Electric Power, Amazon and X-energy announced an agreement to evaluate a proposed 960 MW advanced nuclear project at a former coal-generation site. The arrangement combines utility operating experience, advanced reactor technology, private development funding and an intended long-term power purchase agreement.

In Virginia and West Virginia, the Department of Energy announced up to $50 million in federal support for grid-enhancing technologies intended to unlock approximately 290 MW of additional transmission capacity along existing corridors.

FERC advanced two proposals addressing natural-gas infrastructure: a blanket authorization program for certain LNG facility activities, and a narrower approach to evaluating operational air-quality effects in federal environmental reviews.

Meanwhile, CBRE agreed to acquire a data-center infrastructure services company for consideration that could reach about $1 billion, and a California electricity provider closed a $1.4 billion financing intended to reduce long-term renewable-energy costs.

These developments point toward an increasingly important distinction:

The next wave of infrastructure value may come as much from improving the assets we already have as from building entirely new ones.

Developers capable of evaluating existing energy infrastructure, expanding transmission capacity, securing equipment, coordinating capital and navigating regulatory requirements will have an increasingly important role.

The opportunity is not simply identifying where additional electricity is needed.

It is determining the most executable pathway to delivering it.

01 | THE LEAD

Amazon, AEP and X-energy: A Former Coal Plant Could Become a 960 MW Nuclear Development

On October 19, X-energy and American Electric Power announced a joint development agreement to advance feasibility work on a proposed 960 MW advanced nuclear plant in Sullivan County, Indiana.

The site is the former Breed Generating Station, a retired coal plant owned by AEP's Indiana Michigan Power subsidiary. The proposed plant would use 12 of X-energy's Xe-100 small modular reactors, each rated at 80 MW.

Amazon is providing milestone-based development capital under a separate agreement. If the project proceeds, Amazon would be the first customer and intends to buy the output under a long-term contract covering the facility's costs and operations for the duration of that contract. It is the second project under Amazon and X-energy's goal of more than 5 GW of new nuclear capacity by 2039, after the Cascade Advanced Energy Facility in Washington State.

AEP's chief executive said the agreements provide the capital protections and financial safeguards AEP has said are essential before any nuclear project can move forward. The plant would serve the regional grid rather than an isolated data-center campus.

The project is in feasibility evaluation. No final investment decision has been announced, and no cost or schedule has been disclosed. The 960 MW is not approved, financed or scheduled capacity. Licensing, permitting, engineering, financing and construction all remain ahead.

The announcement follows the Google and Constellation uprate agreement covered in Issue No. 07: another case of a technology company funding generation before it exists rather than buying power after it is built.

Why This Matters

The announcement illustrates three increasingly important developments.

First, former generation properties may provide valuable starting points for new power infrastructure because of their industrial history, existing utility corridors and potential transmission access.

Second, large electricity customers are becoming participants in generation development rather than simply purchasing power after facilities are constructed.

Third, project economics increasingly depend on establishing customer commitments and cost protections early enough to support major infrastructure investment.

The result is a development model that brings together utilities, technology providers, power customers and capital before construction begins.

Developer Takeaway

Retired energy facilities deserve renewed attention as potential development platforms.

But the advantages of an existing site must be tested against current transmission capability, licensing, environmental conditions, water availability, equipment requirements and commercial feasibility.

A former power plant may offer valuable infrastructure.

It does not automatically offer an approved pathway to new generation.

The development opportunity lies in converting legacy infrastructure into a financeable, permitted and commercially supported energy asset.

02 | POLICY & GRID SECURITY

FERC Proposes Faster Reviews for LNG and Natural-Gas Infrastructure

On October 15, FERC advanced two proposals intended to accelerate the development and modification of natural-gas infrastructure.

The first, a notice of proposed rulemaking in Docket RM26-2-001, adopted unanimously, would establish a blanket authorization program for qualifying LNG facility activities, modeled on the Commission's existing blanket certificate program for interstate pipelines.

It proposes three tiers. Activities that do not increase a plant's authorized capacity or exceed its footprint or design limits could proceed automatically. Activities that may increase capacity but stay within the plant's footprint would require 60 days' prior notice. Construction of new LNG facilities, such as liquefaction trains, tanks and marine berths, would require 90 days' prior notice, subject to limits on type, location and size.

The second, a draft policy statement in Docket PL26-3-000, would end FERC's routine request for air-dispersion modeling from Natural Gas Act applicants and its reliance on that modeling in assessing operational air-quality effects under NEPA. FERC says it would continue to address air-quality effects, relying more on Clean Air Act permitting by EPA and the states.

The policy statement was adopted 4–1. Commissioner Chang dissented, arguing that the change would deprive the public of local air-quality information and create greater legal uncertainty for projects.

Neither proposal is final. Comments on the draft policy statement are due November 16. Comments on the LNG proposal will be due 60 days after it is published in the Federal Register.

Developer Takeaway

Permitting duration is a significant component of infrastructure development risk.

Reducing duplicative reviews and establishing predictable authorization procedures could improve construction scheduling, capital deployment and the economics of facility upgrades.

However, streamlined federal procedures would not eliminate state approvals, environmental obligations or engineering requirements. And a narrower federal record may invite more litigation, not less, until courts test it.

Developers should distinguish between proposals under consideration and procedures that have actually taken effect.

Regulatory efficiency creates development value only when it produces a dependable path to approval.

03 | POWER & GRID

DOE Backs Grid Technologies That Could Unlock 290 MW Without New Transmission Corridors

On October 16, the Department of Energy announced its intent to provide up to $50 million in Defense Production Act funding for advanced transmission technologies in Virginia and West Virginia.

The proposed 48-month project, led by Virginia Energy in coordination with Appalachian Power, Potomac Edison and regional partners, would deploy advanced reconductoring and dynamic line rating along existing transmission corridors.

DOE estimates the work could add approximately 290 MW of transmission capacity across Appalachian Power's Virginia system, one to four years faster than conventional transmission upgrades.

That is an important distinction.

The project would not construct 290 MW of new generation.

It would increase the grid's ability to move electricity over infrastructure that already exists. The same idea underlies the reconductoring provision in the Senate permitting bill covered in Issue No. 07.

The announcement follows DOE's October 13 plan to support the Tennessee Valley Authority in funding 84 transmission and distribution projects across eight states, expected to add approximately 2.5 GW of grid capacity. The award totals about $581 million: $250 million in federal funding and about $331 million in applicant cost share. DOE first selected the award in October 2024.

Both initiatives remain subject to final agreements, project requirements and approvals.

Developer Takeaway

For developers seeking capacity in constrained electricity markets, the solution may not always require a new transmission corridor.

Reconductoring, dynamic line ratings, substation improvements and other grid-enhancing technologies can potentially increase the usefulness of existing infrastructure.

That creates another development question:

Can existing transmission capacity be expanded or better utilized before entirely new infrastructure is required?

For power-intensive projects, the answer can materially influence site selection, interconnection strategy and the schedule for delivering electricity.

Grid optimization is becoming a development opportunity.

04 | DATA CENTER / MISSION CRITICAL

Google's Arkansas Expansion Puts a Price on Ratepayer Protection

On October 19, Entergy Arkansas announced a second phase of service for Google's West Memphis data-center campus.

Google will cover approximately $600 million in planned investment and a solar power purchase agreement, including:

• A 1,000 MWh battery-storage system at Driver Solar near Osceola and a 400 MWh system near Hot Springs, both expected in 2028.

• A 440 MWac solar power purchase agreement from the Big Island solar facility in Mississippi County.

• Expansion of the Galet substation near West Memphis.

• Two new 230-kV transmission lines serving the expanded campus.

Google pays the full cost of these resources over the 20-year contract. Combined with the Cypress Solar and battery facility under construction in Jefferson County, Entergy expects the resources to add more than 1,000 MW of solar and 2,800 MWh of battery storage to its system.

Entergy projects at least $500 million in additional customer savings over 20 years beginning in 2028, on top of about $1.6 billion projected from the first phase, for $2.1 billion in combined net benefits. These are the utility's projections, not realized savings.

The Big Island contract has a history. Arkansas regulators declined it in September when Entergy proposed it for general customers; Google says it added the PPA on the Commission's guidance.

The expansion has not been approved. Entergy will file it with the Arkansas Public Service Commission, and the 2028 in-service date depends on that review.

Why This Matters

The agreement attempts to answer a question becoming central to major data-center projects:

Can a large electricity customer pay for its own infrastructure needs while also benefiting the surrounding utility system?

It is the same question TeraWulf and Kentucky Power addressed with customer bill credits, covered in Issue No. 06, here answered with dedicated storage, transmission and a contracted solar supply.

Developer Takeaway

Major data-center developments increasingly require a commercial framework that addresses three constituencies simultaneously:

The data-center customer.

The utility and its infrastructure requirements.

The existing customers who share the electrical system.

For developers, the ability to demonstrate measurable ratepayer benefits may become an important component of regulatory approval and public acceptance. A resource regulators have declined for general customers may still be approvable when a single customer carries its cost.

That does not eliminate the need for rigorous project economics.

It makes those economics more transparent.

The next generation of large-load agreements will increasingly be judged by who receives the benefits and who bears the costs.

05 | ENERGY INFRASTRUCTURE

Entergy Places 1,215 MW Texas Power Station Into Service

While several of this week's announcements concern proposed generation, Entergy Texas reached a different milestone.

In mid-October, the utility placed its Orange County Advanced Power Station into service, adding 1,215 MW of natural-gas-fired combined-cycle capacity in Southeast Texas. Construction began in spring 2023.

Entergy expects the plant's fuel efficiency to generate more than $1 billion in customer savings over its life. The utility expects demand across its Southeast Texas territory to grow about 13% between 2024 and 2028, and plans more than 2.4 GW of new generation by 2028, including the Legend and Lone Star stations approved in 2025.

In an industry dominated by announcements of proposed generation, the Orange County facility is new capacity that has completed construction and entered service.

Developer Takeaway

The distinction between planned capacity and operating capacity remains fundamental to infrastructure economics.

As utilities expand their generation portfolios, developers should evaluate not only announced megawatts but the status of engineering, permitting, equipment procurement, construction and commercial operation.

Operational readiness is what ultimately converts development investment into deliverable electricity.

DOE Advances Proposed Constitution Pipeline

On October 19, DOE announced up to $42 million in Defense Production Act Title III funding to advance the proposed Constitution Pipeline, a 125-mile natural-gas line from Pennsylvania to New York.

The funding would support eligible pre-construction and permitting activities and, once permits are complete, complementary natural-gas infrastructure.

It is not a pipeline approval or an authorization to build. The project was cancelled in 2020 after New York denied a water-quality certification, and federal funding does not resolve that state approval.

In markets where gas generation is increasingly considered for firm electricity supply, fuel-delivery infrastructure can become a critical constraint on generation development.

06 | EQUIPMENT & SUPPLY CHAIN

Venture Global Positions Gas-Turbine Procurement Around a Potential 10 GW AI Infrastructure Platform

On October 15, Venture Global announced frame agreements with GE Vernova and Baker Hughes Energy Services for up to 16 new 720 MW combined-cycle power-island units and associated power transformer equipment.

The company says the units could support more than 10 GW of new behind-the-meter power capacity at sites it owns or controls, which it intends as the foundation of what it calls an AI utility. Reported timelines extend to the end of 2034.

The expansion builds on about 4.5 GW of gas-fired power-island capacity, six units in operation, under construction or on order, at its LNG facilities.

The distinction between a frame agreement and a firm equipment order is important.

Venture Global describes the agreements as preserving flexibility on the timing and scope of future deployments. It expects to place its first power-island purchase order by the end of 2026, with later investment dependent on customer commitments and market demand.

Developer Takeaway

The announcement illustrates an emerging response to long-lead equipment constraints.

Developers are attempting to establish access to manufacturing capacity before committing to every phase of construction.

This approach can create flexibility, but it requires careful coordination among customer commitments, equipment reservations, capital availability and project schedules.

For major energy and digital-infrastructure developments, procurement strategy increasingly begins well before financial close.

Securing the right equipment at the right time is becoming a fundamental component of development feasibility.

07 | CAPITAL & DEAL FLOW

CBRE Moves Further Into Digital Infrastructure With Proposed $1 Billion Acquisition

On October 20, CBRE announced a definitive agreement to acquire Onnec Group, a London-based provider of data-center infrastructure services across Europe and Asia Pacific.

The initial price is £460 million (about $610 million) in cash, with a multi-year earnout of up to £300 million (about $400 million) if Onnec meets growth thresholds. The total could therefore reach about $1 billion.

Onnec designs, deploys and maintains network, fiber and data-center infrastructure. CBRE expects it to generate about £370 million in revenue in 2027 and will place it in its Critical Infrastructure Services business.

The acquisition is subject to regulatory approvals, with completion expected around year-end.

Developer Takeaway

The transaction reflects a broader convergence of commercial real estate, infrastructure development and specialized technical services.

As data-center projects become more complex, value increasingly resides in the ability to coordinate land, power, construction, electrical infrastructure, connectivity and long-term operations.

For integrated development firms, the opportunity extends beyond identifying sites or completing individual transactions.

The market is placing increasing value on the ability to deliver the entire infrastructure solution.

Clean Power Alliance Closes $1.4 Billion Energy Financing

On October 19, California's Clean Power Alliance announced the closing of a $1.4 billion renewable-energy prepayment bond, its seventh.

The financing is expected to generate about $91.1 million in savings over its initial seven-year period. As a public agency, CPA can issue tax-exempt bonds to prepay for renewable electricity at a discount. J.P. Morgan was underwriter and prepaid energy supplier, and the bonds are rated Aa3.

The energy comes from existing long-term contracts covering 440.8 MW of wind. This is a financing of contracted supply, not 440.8 MW of new generation.

Developer Takeaway

The transaction demonstrates how capital structure can improve infrastructure economics independently of physical construction.

Long-term contracts, financing terms and counterparty creditworthiness can materially affect delivered electricity costs.

Infrastructure value is determined not only by what gets built, but by how the asset and its revenue are structured and financed.

08 | THE INTERCONNECTION DESK

PJM

Registry Accepted, Interim Service Still Unresolved

FERC's October 9 order in Docket ER26-3515-000, covered in Issue No. 07, accepted PJM's 50 MW large-load definition and its Large Load Registry, effective October 12.

It rejected the rest of the package, including Interim Resource Adequacy Service (IRAS) and the Bring Your Own New Capacity rules.

PJM must make a compliance filing within 30 days of the order, which falls due November 9. There is still no approved mechanism for serving new large loads that arrive without matching generation.

Developer Implication

Visibility into large loads is a regulatory step, not a service commitment.

A project can be visible to the grid operator without having a confirmed path to power.

ERCOT

Batch Zero Remains Paused for Verification

Texas' Batch Zero process, followed since Issue No. 01, remains subject to the verification and audit ordered before affected data-center projects are permitted to advance.

ERCOT's September Board update states that the Batch Zero study process and final classification have been paused since August 3, and that energization of new large-load data centers and crypto-mining facilities of 75 MW or more is paused until the verification, audit and community-impact review are complete.

The October 12 deadline for applicable State and Community Impact RFI responses, introduced in Issue No. 03, has passed. ERCOT expects to publish that report, coordinated with the PUCT, and to file its Batch Zero Eligibility Verification Report, both by December 10.

Developer Implication

Large-load developers increasingly need to demonstrate that their proposed demand, infrastructure plans, schedules and community-impact assumptions are supported by evidence.

Technical progress is not regulatory clearance for energization.

CAISO

Large Loads Initiative Approaches Board Consideration

Comments on the draft final proposal and draft tariff language closed October 15. A stakeholder meeting on the draft tariff language was scheduled for October 19. Board of Governors consideration is anticipated October 28.

The proposed flexible interim load interconnection (FILI) service could allow certain large loads limited service before longer-term transmission upgrades are complete.

It is not an approved tariff mechanism. Nothing has been approved by the Board or filed with FERC.

Developer Implication

Earlier energization has value only when its operating limits are commercially manageable. Curtailment exposure, telemetry requirements and the path to firm service can materially affect development economics.

FERC

Broader Large-Load Proceedings Continue

The six Section 206 large-load proceedings opened in June, first covered in Issue No. 02, remain open. PJM's response in its own proceeding is due November 16. FERC has not issued final determinations in any of the six.

09 | ON OUR RADAR

FERC | October 21

The annual Commissioner-led Reliability Technical Conference, including the operational challenges of integrating large new loads.

FERC / NRC | October 22

A joint meeting on grid reliability, nuclear power, load growth and cybersecurity. Relevant as technology customers fund uprates and proposed new reactors.

CAISO | October 28

Board consideration of the Large Loads Initiative is anticipated. Board approval is not FERC approval or implementation.

PJM | November 9

Compliance filing due on FERC's October 9 order. Watch for any separate refiling on interim service and capacity responsibility.

FERC | November 16

Comments due on the draft NEPA air-quality policy statement, and PJM's response due in its Section 206 large-load proceeding.

Congress | Mid-November

The Senate returns after the November 3 election. Watch for floor consideration of S. 5653, covered in Issue No. 07, which needs 60 votes and then House passage.

ERCOT | December 10

The State and Community Impact report and the Batch Zero Eligibility Verification Report are both expected.

THE INTERFACE VIEW

Infrastructure Value Is Moving Beyond the Greenfield Development Model

For much of the past decade, infrastructure development has followed a familiar sequence:

Find the land. Secure the approvals. Arrange the capital. Build the project.

That sequence remains important.

But the convergence of energy infrastructure, digital infrastructure and rapidly growing electricity demand is changing the development equation.

This week's announcements illustrate several ways the industry is adapting.

Amazon, AEP and X-energy are evaluating whether a former coal-generation property can support a new advanced nuclear facility.

DOE is supporting technologies intended to unlock more transmission capacity from existing corridors.

Entergy has placed more than 1.2 GW of new generating capacity into service.

Google is paying for the storage, transmission and contracted solar supply its Arkansas expansion requires.

Venture Global is positioning its existing industrial power platform for potential expansion into large-scale digital infrastructure.

And CBRE is expanding beyond real estate services into the technical infrastructure required to deliver and operate data centers.

These developments differ in structure, scale and maturity.

But they share an important characteristic.

They treat infrastructure as an integrated development platform rather than a collection of unrelated assets.

For developers, that changes how opportunity should be evaluated.

A retired generating facility may have value beyond its current use.

An existing transmission corridor may have capacity that can be unlocked through new technology.

A utility customer may become a capital partner in generation development.

A long-term power contract may support infrastructure that benefits an entire regional system.

And a company's technical execution capabilities may become as valuable as its real estate or financial resources.

The next generation of infrastructure development will increasingly require the ability to evaluate these opportunities together.

Land + Existing Infrastructure + Power + Transmission + Equipment + Capital + Regulatory Certainty + Execution

That is the emerging development platform.

The industry will continue building entirely new infrastructure.

But some of its most valuable opportunities may come from identifying what existing infrastructure can become.

The competitive advantage is no longer simply finding the next project.

It is recognizing the infrastructure potential others have yet to unlock.

Interface Holdings and Development Firm

Building the Future of Infrastructure Through Strategy, Capital, and Integration.