Infrastructure Intelligence No. 11: Announcements Do Not Build Infrastructure

Energy. Power. Development. Capital. | November 10, 2026 | Issue No. 11

THE WEEK IN INFRASTRUCTURE

Washington Moves on Permitting as the Power Infrastructure Race Intensifies

The effort to accelerate American infrastructure development reached a significant procedural milestone this week.

On November 9, the U.S. Senate voted 73–25 to begin debate on sweeping bipartisan permitting legislation that could reshape how energy projects, transmission lines and major electricity-consuming developments move through federal approvals. The vote was not passage.

The legislation also addresses a rapidly emerging issue: requiring large data-center customers to bear more of the grid infrastructure costs attributable to them.

Energy markets continue moving regardless.

Duke Energy is executing a generation build targeting 16 GW by 2031. AEP has created a dedicated infrastructure business. Constellation signed the first contract under a new product that pairs new capacity with power supply for large customers.

The technology sector is moving deeper into energy infrastructure. According to Financial Times reporting, Anthropic has taken over orders for approximately 1.7 GW of natural-gas generators, an example of AI companies attempting to control their own power supply chains.

And in Utah, a 150 MW battery-storage project supporting Meta's data-center operations has reached commercial operation, a reminder of what contracted infrastructure looks like once it is built.

These developments reinforce an increasingly important distinction.

The industry has substantial demand and significant capital commitments. Its defining challenge is converting those commitments into permitted, financed and operating assets.

01 | THE LEAD

Senate Advances Major Permitting Reform in 73–25 Vote

On November 9, the Senate voted 73–25 to invoke cloture on the motion to proceed to the Bipartisan American Affordability and Jobs Act of 2026. Cloture required 60 votes.

The legislation, developed by Senators Mike Lee, Shelley Moore Capito, Martin Heinrich and Sheldon Whitehouse, proposes substantial changes to federal permitting and environmental review.

Its central objectives include accelerating approval schedules, improving predictability for infrastructure investment, facilitating transmission development and addressing how new electricity demand affects existing ratepayers.

A substitute amendment released November 7 incorporates revisions addressing tribal consultation, state involvement and other concerns raised during negotiations.

The legislation would also require major electricity-consuming customers, including data centers, to assume more responsibility for the grid infrastructure costs associated with their developments.

The vote was on the motion to proceed to H.R. 2347, the legislative vehicle for the proposal previously introduced as S. 5653, covered in Issues No. 07 and No. 10.

This was not final Senate passage, House passage or enactment. The Senate must still debate, amend and pass the bill, and the House must then accept it or negotiate a version both chambers can pass before this Congress ends.

Why This Matters

Permitting uncertainty remains a material development risk for generation, transmission and other large infrastructure projects.

Long federal reviews can increase financing costs, complicate equipment procurement and keep projects from reaching commercial operation even when demand and customer commitments are established.

Supporters argue the proposal would establish clearer review schedules and the certainty needed for long-term investment.

Critics, including several senators who voted against cloture, warn that changes to environmental review and judicial challenge procedures could weaken environmental protections and limit public and tribal participation.

Those concerns remain part of the debate, and the final structure may change through amendment.

Developer Takeaway

The potential benefits extend beyond faster approvals.

Predictable schedules can improve capital planning, financing negotiations, equipment reservations and overall project feasibility.

For developers of large electricity-consuming facilities, the cost-responsibility provisions could also influence electric-service agreements, transmission commitments and project economics. Those terms should be modeled now, not after enactment.

Regulatory certainty has financial value. But reform must produce predictable approvals without creating new legal and implementation risks.

03 | POWER & GRID

Duke Energy Targets 16 GW of New Generation by 2031

Duke Energy's November 5 third-quarter results, flagged on our radar in Issue No. 10, highlighted the expansion of its generating portfolio.

The utility says it is executing a record generation build designed to add 16 GW of capacity by 2031, supporting customer growth including data centers, industry and other large commercial customers.

The company continues to operate under a $103 billion five-year capital plan, with a potential $5 billion to $10 billion of additional generation and transmission spending tied to large-load contracts.

The program includes substantial investment in natural-gas generation, battery storage and supporting utility infrastructure.

Delivery will depend on permitting, equipment availability, construction performance, regulatory decisions and customer demand. The 16 GW is planned capacity, not capacity in service.

Developer Takeaway

Large utility investment programs create opportunities across the value chain, including surveying, engineering, generation development, transmission, equipment procurement and construction management.

But projected capacity should not be treated as available electricity until the facilities reach operation.

The ability to align generation construction with customer energization dates is becoming a critical utility capability.

AEP Establishes a Dedicated Infrastructure Business

On November 3, American Electric Power created AEP Infrastructure, a business unit focused on investing in, building and operating energy infrastructure.

The organization brings together AEP's competitive generation, infrastructure development, and retail and wholesale energy businesses.

It will evaluate generation acquisitions, including the proposed purchase of the Longview Power Plant, develop new resources backed by long-term customer contracts, such as a recently announced 20-year fuel-cell agreement with Google in Wyoming, and pursue customer-owned transmission and distribution opportunities.

The unit builds on AEP's $100 billion capital plan for 2027 through 2031, which includes approximately $37 billion for transmission, $36 billion for generation and $22 billion for distribution.

AEP also reports 84 GW of incremental contracted load through 2031, based on executed electric-service agreements and letters of agreement. That is contracted future demand, not energized load.

Developer Takeaway

A dedicated infrastructure business illustrates how utilities are expanding beyond the traditional regulated model.

Customer-specific generation, infrastructure ownership and integrated power agreements may create new openings for development partnerships.

Utilities are increasingly becoming infrastructure development platforms, not simply providers of electric service.

04 | DATA CENTER / MISSION CRITICAL

Anthropic Reportedly Takes Over $3.4 Billion of Gas-Generator Orders

Financial Times reporting on November 8 describes an agreement, reportedly reached in late September, under which Anthropic committed approximately $3.4 billion for 1.7 GW of Caterpillar natural-gas generators.

The orders were originally placed about two years ago by San Antonio-based OnePWR Solutions, which needed financing to complete them. Rather than buy power from OnePWR, Anthropic took over the equipment orders; OnePWR is to provide engineering and installation support. Anthropic did not acquire the company.

The generators are reportedly scheduled for delivery over the next two years.

Neither Anthropic nor Caterpillar has publicly confirmed the transaction, and Reuters said it could not immediately verify the report.

The 1.7 GW is equipment on order, not generating capacity installed, permitted or operating.

Developer Takeaway

Technology companies are increasingly trying to reduce their dependence on uncertain utility energization schedules by securing generation equipment directly.

That creates opportunities for engineering firms, developers and procurement partners able to deliver integrated power solutions.

It also creates risk. Owning equipment does not resolve fuel supply, air permitting, site readiness or construction.

The AI infrastructure race is extending from securing electricity contracts to securing the equipment that produces electricity.

05 | ENERGY INFRASTRUCTURE

Utah Battery Project Supporting Meta Reaches Commercial Operation

On November 10, Lydian Energy announced that its 150 MW / 600 MWh Faraday battery-storage project in Utah County has reached commercial operation.

The project began operating on September 18 under a long-term agreement with PacifiCorp that supports Meta's Eagle Mountain data-center operations. Lydian says it went from mobilization to commercial operation in about 10 months.

The four-hour battery sits next to the 525 MW Faraday solar facility and shares that facility's substation and interconnection.

Sharing the connection can reduce the need for separate electrical infrastructure, though it does not remove the storage installation's own engineering and operating requirements.

This is operating infrastructure, not proposed capacity.

Developer Takeaway

The project shows the value of finding expansion opportunities inside existing electrical infrastructure.

Pairing storage with established interconnection assets may create development efficiencies and make better use of grid connections already in place.

Existing infrastructure can become a platform for additional capacity when engineering and commercial requirements align.

Vistra Adds Gas Generation and Places New Solar Into Service

Vistra's November 6 results, also on our Issue 10 radar, reported several milestones.

The company closed its acquisition of Cogentrix Energy on October 30, adding approximately 5,500 MW of existing natural-gas generation.

Vistra also began operating its 405 MW Pulaski Solar Facility in Illinois, under a power purchase agreement with Microsoft, and its 100 MW Deer Creek Solar & Energy Storage Facility in California.

Cogentrix is an acquisition of existing plants; Pulaski and Deer Creek are new facilities reaching commercial service. Only the latter add generation to the system.

Developer Takeaway

Vistra's activity shows two complementary ways of meeting demand: acquiring operating generation and building new resources.

Both have value, but they carry different schedules, capital requirements and execution risks.

Portfolio growth and new-build generation should be evaluated separately when assessing real increases in available power.

06 | EQUIPMENT & SUPPLY CHAIN

Infineon Guides to Nearly €4 Billion in Data-Center Power Revenue

Infineon Technologies' November 10 results are another measure of the investment required beyond data-center buildings and computing chips.

The company expects revenue from data-center power supplies to approach €4 billion in fiscal 2027, which began October 1, up from about €2.2 billion in fiscal 2026. Of that fiscal 2026 figure, about €1.7 billion came from AI data centers.

Infineon now reports a single figure for all data-center business, so the new outlook is not directly comparable with its earlier AI-only target.

On November 5, Infineon and SOLUM signed a memorandum of understanding to expand their work on high-voltage direct-current power for AI data centers, covering power supply units, intermediate bus converters and battery backup units.

A memorandum of understanding is not a supply contract, and the systems it covers have not reached commercial-scale deployment.

Developer Takeaway

The equipment challenge extends well beyond transformers, gas turbines and switchgear.

Power conversion, electrical distribution architecture and the semiconductors behind them are increasingly important to the efficiency and reliability of computing infrastructure.

For developers and engineering teams, electrical-architecture decisions can shape equipment selection, facility design, cooling requirements and long-term operating costs.

The next bottleneck may appear inside the data center as readily as at the utility connection.

07 | CAPITAL & DEAL FLOW

Constellation Signs Its First Peak+ Agreement

Constellation Energy's November 9 third-quarter results disclosed a 20-year agreement for 270 MW of energy, capacity and attributes from its existing nuclear fleet, beginning in 2028.

It is the first transaction under Peak+, an offering that combines new capacity, including new generation and demand response, with energy products for large customers.

The results also update two earlier announcements.

Constellation's agreement to acquire the Rhode Island State Energy Center from Shell Energy North America for approximately $715 million, announced September 10, remains pending. The plant is a 609 MW combined-cycle gas station in ISO New England, and the deal is subject to regulatory approvals and closing conditions.

In October, Constellation signed a conditional commitment under which DOE would guarantee up to $5 billion in loans for nuclear uprates. It is subject to a loan agreement not yet executed, and is not funded financing. The uprates build on customer agreements including Google's, covered in Issue No. 07.

Developer Takeaway

Generation acquisitions, uprates, customer contracts and conditional federal financing together show how layered capital structures in energy infrastructure have become.

Operating plants can provide nearer-term capacity and revenue; uprates and new development provide longer-term supply.

For investors and developers, the distinctions between conditional financing, signed agreements, pending acquisitions and operating capacity remain essential.

Capital strategy must reflect not just the value of an asset but the maturity and execution risk behind it.

08 | THE INTERCONNECTION DESK

ERCOT

Medium-Sized Data-Center Projects Face Scrutiny

ERCOT is examining whether large data-center developments are being divided into projects below 75 MW, the threshold for its Batch Zero large-load process, according to the San Antonio Express-News.

ERCOT has identified nearly 10 GW of proposed medium-sized loads (25 MW to just under 75 MW) and sent 132 information requests to utilities about their status. Its community-impact review already extends to facilities of 25 MW and above.

The question matters because Batch Zero, followed since Issue No. 01, remains paused. ERCOT's September Board update states that the study process and final classification have been paused since August 3, and that energization of new large-load data centers of 75 MW or more is paused until the verification, audit and community-impact review are complete.

The 10 GW is proposed demand, not approved or operating load.

Developer Implication

Size projects to genuine operational and engineering requirements. Splitting a campus into requests below 75 MW should not be assumed to avoid scrutiny or the pause.

CAISO

FERC Filing Due by November 16

CAISO's Board-approved large-load framework, covered in Issue No. 10, is to be filed with FERC by November 16. It includes provisions on large-load interconnection, reliability and a flexible interim service. FERC approval remains outstanding.

Developer Implication

Interim service may support phased development, but developers must account for curtailment, operating limits and the conditions for moving to full service.

PJM

Large-Load and Co-Location Proceedings Remain Active

November 16 is also a procedural date for PJM: its response is due in FERC's large-load show-cause proceeding, and FERC extended the co-located-load deadline to the same date.

Separately, PJM's revised Reliability Backstop Procurement, the Issue No. 10 lead, remains before FERC following its October 29 filing.

These are distinct processes, each with implications for cost allocation, generation supply and service requirements.

Developer Implication

Treat interconnection authorization, capacity procurement, co-location arrangements and retail electric service as related but separate requirements.

09 | ON OUR RADAR

U.S. Senate | November 10

Debate continues today on the motion to proceed to the permitting package. Watch for amendments, further procedural votes and whether the bill advances toward passage.

CAISO | November 16

Targeted FERC filing of the Board-approved large-load framework. Filing is not approval.

PJM / FERC | November 16

PJM's response in the large-load proceeding and the extended co-location deadline.

ERCOT | November 19

Large Load Working Group meeting on policies and technical requirements for integrating major loads.

ERCOT | December 10

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

THE INTERFACE VIEW

The Development Advantage Is Shifting Toward Integrated Execution

For several years, the energy infrastructure industry has focused on the extraordinary growth in electricity demand from artificial intelligence, advanced manufacturing and electrification.

That demand remains significant.

But this week's developments show that the more important question is how the industry will deliver the infrastructure required.

Congress is considering changes to federal permitting and to who pays for large-load grid costs.

Utilities are expanding generation programs and creating specialized infrastructure businesses.

Technology companies are securing generation equipment rather than relying solely on conventional utility supply.

Equipment manufacturers are scaling the power technologies that increasingly complex data centers require.

And storage projects are reaching commercial operation through agreements that tie infrastructure investment to specific customer needs.

These activities reflect a convergence of previously distinct markets.

Energy development.

Electrical infrastructure.

Digital infrastructure.

Equipment procurement.

Project finance.

Regulatory compliance.

The opportunity is no longer limited to participating in one segment. It increasingly involves bringing these capabilities together.

For developers, an opportunity should be judged by much more than its location or projected demand.

Site control must align with real infrastructure capacity.

Commercial agreements must support the capital required to deliver generation and transmission.

Equipment procurement must reflect achievable delivery schedules.

Regulatory strategy must be set early enough to avoid costly redesign and delay.

And financing structures must account for the difference between projected demand and contracted, operating infrastructure.

The Development Equation

Land + Power + Interconnection + Equipment + Permitting + Capital + Execution

At Interface Holdings and Development Firm, this integrated approach reflects the increasingly complex environment facing infrastructure markets.

The industry will continue to announce extraordinary amounts of investment and capacity.

But announcements do not build infrastructure.

Lasting value will be created by developers who can identify realistic opportunities, manage the dependencies and move projects from concept to commercial operation.

That is where infrastructure demand becomes infrastructure value.

Interface Holdings and Development Firm

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