Infrastructure Intelligence No. 02: The Power Business Is Becoming a Regulated Development Business

Energy. Power. Development. Capital.  |  September 8, 2026  |  Issue No. 02

THE WEEK IN INFRASTRUCTURE

Last week's inaugural issue argued that the data center business is becoming the power business. This week the market began answering a harder question: which large-load projects are real enough to receive that power, and who decides.

ERCOT issued its first conditional classifications for Batch Zero on September 3, sorting projects into those that may advance, those reclassified into more intensive study, and those excluded — while the entire process remains subject to a statewide verification and audit ordered by the Governor and targeted for completion December 10. MISO filed reliability requirements at FERC that would hold large computational loads to performance standards closer to those applied to generation. Google contracted 396 MW of enhanced geothermal generation before committing to the data center that generation may ultimately serve. And a federal executive order declaring a national emergency over foreign-produced grid equipment took effect, with implementing rules due before year end.

The constraint is no longer only megawatts. It is increasingly the ability to convert a load request into a verified, engineered, compliant and financeable power plan — and to prove it to a regulator.

01 | THE LEAD

ERCOT Sorts Batch Zero — Inside a Process That Remains Under Audit

ERCOT completed the first screening of its Batch Zero large-load study on September 3, privately notifying transmission and distribution service providers of each project's conditional classification.

Projects were sorted into three outcomes. Some were conditionally included. Some submitted as base load were reclassified into the more intensive studied-load category, where they may face additional grid studies, transmission upgrade costs, curtailment requirements or delays. Others were excluded outright.

The classifications cover projects seeking interconnection of 75 MW or greater, and follow a delay ERCOT attributed to data validation and due diligence after an original August 31 target. ERCOT screened roughly 250 to 300 projects representing approximately 200 GW of prospective demand, drawn from a large-load queue the Governor's office has put at more than 474 GW, of which data centers represent approximately 90 percent.

Three qualifications matter more than the classifications themselves.

Conditional inclusion is not interconnection approval. It establishes no energization date. Projects that fail to satisfy their conditions can be removed from Batch Zero and required to enter a future interconnection process. Conditions can include verification of the Interconnecting Large Load Entity, correction of deficiencies in dynamic-model information, or a PUCT good-cause exception where a project did not fully satisfy an eligibility requirement at submission. ERCOT has said it will not pursue every good-cause exception requested, and has privately identified to service providers which requests it will not seek.

Reclassified and excluded projects have recourse, on a clock. Transmission and distribution providers must notify affected customers of a reclassification within two business days. Customers may challenge a decision through Batch Zero's dispute and reconciliation process; excluded projects may seek relief through ERCOT's Alternative Dispute Resolution procedure.

The process sits inside an active audit. Issue 01 reported the pause as it was ordered; what has changed since is that the verification machinery is now running. On August 3 the Governor directed the PUCT and ERCOT to conduct a comprehensive verification and audit of data center projects advancing through the interconnection process, pausing new data center interconnections pending its outcome. ERCOT is running two workstreams: a Batch Zero eligibility verification applicable to large loads seeking to advance through Batch Zero, and a separate community impact information collection applicable to computational loads of 25 MW or greater, whether or not they are in Batch Zero. Both will be conducted through requests for information issued to Interconnecting Large Load Entities via their service providers, with further rounds expected through October and November.

The intake machinery went live on September 4, when ERCOT took its Resource Integration and Ongoing Operations system offline for a 90-minute off-cycle release to deploy a new platform for receiving Batch Zero Verification RFI and Community Impact RFI submissions. ERCOT stated it would issue further market notices once the RFIs themselves are issued — meaning that as of that release the platform was ready and the requests had not yet formally gone out. ERCOT is targeting a December 10 filing to the PUCT of its Batch Zero Eligibility Verification Report and Community Impact Review Report.

ERCOT expects a final transmission plan for the Batch Zero group in fall 2027.

Developer Takeaway

Interconnection readiness is now development readiness, and it is being audited rather than assumed.

A credible ERCOT project requires more than acreage near transmission. Site control, accurate load modeling, realistic phasing, coordination with the serving TSP or DSP, defensible dynamic-model data, and now documented community impact — water sourcing, onsite generation, public financial assistance, ownership and controlling interests — all bear on whether a project advances.

Two practical consequences follow. First, attestations made at submission are being tested against evidence; ERCOT has said it will remove a project where it determines an attestation was materially false or the entity fails to respond within the time specified. The diligence file needs to be assembled to a standard that survives review, not to a standard that clears a form. Second, the recourse windows are short. A two-business-day notification requirement is not a schedule a developer can absorb reactively.

The interconnection package should be developed alongside the site, not after it.

02 | POLICY & GRID SECURITY

A National Emergency Declaration Reaches Into Grid Equipment Sourcing

Issue 01 covered this order as it landed, on the provenance question it raises for equipment buyers. The development since is procedural, and it matters more. On August 26 the President issued Executive Order 14421, declaring a national emergency under the International Emergency Economic Powers Act concerning the foreign supply of bulk-power system electric equipment. It was published in the Federal Register on August 31.

The order directs the Secretary of Energy to restrict the importation and installation of bulk-power system equipment — broadly, equipment on systems operating above 69 kV — produced in or sourced from certain countries where the Secretary determines it presents national security risks. It took effect immediately on issuance and applies to covered transactions initiated after August 26.

Two deadlines follow. The Secretary must issue implementing regulations within 120 days, by December 24, 2026. Those regulations are expected to set the criteria for determining which equipment presents a risk, and may address conditions on the continued use, operation, maintenance, servicing or updating of equipment already installed. The Secretary may also establish and publish a list of pre-qualified equipment and vendors exempt from the restrictions.

Separately, within 180 days — by February 22, 2027 — the Secretary, in consultation with the Federal Acquisition Regulatory Council, must submit recommended revisions to the Federal Acquisition Regulation to ensure national security risks are considered in federal procurement concerning energy infrastructure and to prioritize acquisition of United States-manufactured energy infrastructure. The FAR Council then has 90 days to consider proposing amendments for notice and comment.

A note on sourcing: several client alerts circulated in the first days after issuance cited this order as Executive Order 14420. The Federal Register carries the authoritative number, 14421.

Developer Takeaway

The operative uncertainty is not the prohibition. It is that the criteria do not yet exist.

Between now and December 24 there is no published standard defining which equipment or vendors are covered, and no pre-qualified list. Procurement decisions made in that window carry a risk that cannot be fully priced. The exposure is not limited to new purchases — the order contemplates that implementing rules may reach equipment already installed, which puts a diligence question over existing assets and over acquisitions of projects holding them.

For anyone specifying transformers, switchgear, breakers or control systems for delivery beyond this year, country of origin and ownership of the supply chain now belong in the procurement record alongside price and lead time. For projects with any federal procurement exposure, the February FAR track is the one to watch.

03 | POWER & GRID

MISO Moves to Hold Large Loads to Generator-Grade Performance

On August 28 MISO filed large-load interconnection reliability requirements at FERC covering loads above 50 MW. The filing addresses ramp rates, ride-through performance and real-time monitoring.

The substance reflects a recognition that large computational loads do not behave like traditional industrial demand. MISO's proposals include real-time visibility requirements, advance forecasting of expected consumption, limits on how quickly load may rise or fall — discussed in the stakeholder process at approximately 30 MW per minute — and ride-through obligations requiring facilities to remain connected through brief voltage or frequency disturbances rather than dropping offline.

The ride-through provisions are the most developed. Facilities would generally be required to stay connected while voltage remains between 90 and 120 percent of nominal, with proportional rather than all-or-nothing reduction permitted during deeper dips, and restoration of at least 90 percent of normal consumption within two seconds after a disturbance clears. Those rules are being finalized into MISO's Business Practice Manual, BPM-032, effective on or about December 4, 2026. Stakeholder feedback on the draft is due September 8.

MISO is separately reworking how it reviews large-load projects. The proposed Large Load Project Reviews process would run roughly four months — 90 days of study plus 30 days for agreements — against recent approvals averaging about 100 days, following FERC direction that the process be faster and more transparent. Stakeholder feedback is due September 10, the same date as feedback on a proposed large-load forecasting requirement that would take effect September 1, 2027.

A separate concept to study new large loads and new generation in a single combined queue, presented to the working group by the Energy Futures Group under the name GALIP, is a stakeholder proposal rather than a MISO initiative. MISO is not required to respond to it formally.

Developer Takeaway

A data center in MISO is being asked to perform electrically more like a generator than like a load.

That is a design requirement, not a compliance formality. Ride-through capability, controlled ramping and real-time telemetry are decisions made in electrical architecture — UPS topology, controls, protection settings, metering — and they are far cheaper to design in than to retrofit against a manual that becomes effective in December.

The forecasting requirement deserves separate attention. An obligation to publish forward consumption, with the prospect of favorable or unfavorable treatment based on accuracy, converts operating discipline into a cost line. Projects with variable AI training workloads should understand what they are committing to before the tariff language is settled.

DOE Applies AI to the Grid-Planning Bottleneck

On September 1 the Department of Energy's Office of Electricity announced $11.5 million for GridFM 2.0, a research project led by Brookhaven National Laboratory under the Genesis Mission, developing AI foundation models for grid planning. Brookhaven has described the broader project at approximately $14 million. The award includes two deployments with utility partners intended to demonstrate the technology in operating environments.

The stated targets indicate the scale of the problem more than the likelihood of the solution: evaluating as many as one billion grid scenarios within 24 hours, increasing planning throughput by more than 10,000 times, and accelerating certain grid calculations by more than 1,000 times relative to conventional methods.

Developer Takeaway

Faster study throughput does not shorten the path that follows it. Transmission, substations, transformers, permitting, procurement, generation and construction are unaffected by computational speed.

The value, if it materialises, is in what a planner can see rather than how quickly they can see it — the ability to test many more configurations of load, generation and network upgrade before a project commits to one. That is a research programme, not a 2027 schedule input. Treat it accordingly.

04 | DATA CENTER / MISSION CRITICAL

Google Contracts the Generation Before Committing to the Data Center

On September 1 Fervo Energy announced a 396 MW, 15-year power purchase agreement with Google covering its Cape Station enhanced geothermal development in Utah, with first power targeted for the third quarter of 2028. Fervo describes it as the largest enhanced geothermal PPA to date. The agreement includes an option for Google to expand offtake by approximately 600 MW, bringing total contracted volume to nearly 1 GW by June 2030.

The sequence is the story. The contracted generation is intended as a foundational power source for a potential Google data center in Utah — a facility to which Google has not yet made a final commitment. Fervo has stated the ultimate project remains subject to engineering feasibility, state and local approvals and commercial conditions.

The energy strategy is executed before the development decision.

Developer Takeaway

Power procurement is becoming a site-development instrument rather than an operating contract signed after development.

For a project of this scale, a secured generation pathway does work that land alone cannot: it anchors site selection, changes the character of utility discussions, supports entitlement strategy, and gives capital something concrete to underwrite before the facility exists. It also transfers risk in a specific way worth noting — the offtaker has taken generation-side commitment while retaining optionality on the load, which is the inverse of the historic pattern.

Not every developer can absorb that. But the direction is instructive for those structuring smaller projects: the credibility of the power plan increasingly determines whether the development is financeable, not the other way round.

Land establishes the opportunity. Power increasingly establishes the project.

06 | EQUIPMENT & SUPPLY CHAIN

Procurement Diligence Moves Upstream, and Now Includes Origin

The behind-the-meter build-out and the new federal sourcing restrictions land on the same procurement decision.

As large-load developers evaluate dedicated generation, microgrids, storage and hybrid utility/onsite architectures, the critical path extends backward into manufacturing capacity. Equipment historically specified after substantial engineering — generators, turbines, switchgear, transformers, control systems — increasingly has to be evaluated, reserved or secured during feasibility and pre-development, because the factory slot, not the engineering, sets the date.

Executive Order 14421 adds a second question to that same decision. Until implementing regulations issue in December, a developer reserving long-lead equipment cannot fully confirm whether a given vendor or country of origin will be permitted at the time of installation.

Developer Takeaway

Procurement diligence now has two axes: availability and admissibility.

A project can hold land, fuel, permits and a viable electrical concept and still lose a year to equipment lead times. It can now also lose a year to sourcing that was compliant when ordered and uncertain when installed. Neither risk is managed at the purchase order. Both are managed in how supply agreements are written — origin representations, substitution rights, change-in-law provisions, and delivery terms that contemplate a regulatory determination that does not yet exist.

For IHD, this is where development coordination earns its position: the procurement strategy and the interconnection strategy are now the same schedule.

07 | CAPITAL & DEAL FLOW

$5.85 Billion Directed at the Infrastructure Between Grid and Rack

Two transactions announced a day apart indicate where infrastructure capital sees value moving.

Flex announced on September 3 a definitive agreement to acquire EPC Power at a value of approximately $4.4 billion. EPC Power provides power conversion for data center, storage and grid applications, including grid-forming technology and next-generation 800V data center power architectures. The transaction is expected to close in the fourth quarter of calendar 2026, after which EPC Power would join Flex's Cloud and Power Infrastructure segment — which Flex has said it intends to separate into an independent public company in the first quarter of 2027.

A day earlier, on September 2, Vertiv announced an agreement to acquire UtilityInnovation Group for approximately $1.45 billion in cash at closing, with additional consideration of up to $1.15 billion based on EBITDA targets over 12- and 24-month periods. At the closing price the transaction represents approximately 13 times expected 2027 EBITDA. UIG, founded in 2020 and headquartered in Raleigh with European operations in Dublin and manufacturing in North Carolina and New Jersey, brings microgrid controls, onsite generation and storage orchestration, microgrid-specific switchgear and behind-the-meter power architecture design. Vertiv has described the strategy as extending its portfolio from grid interconnect to chip, independent of any single generation technology or supplier. Closing is expected in the fourth quarter of 2026, subject to regulatory approvals.

Together the two represent approximately $5.85 billion of announced upfront value directed at companies operating inside the power bottleneck.

Developer Takeaway

Infrastructure capital has historically separated the data center, the utility, the generation asset, the electrical equipment and the EPC contractor into distinct investment categories. These transactions blur those boundaries deliberately.

The signal for developers is not that equipment companies are expensive. It is that the capability to shorten energization is being valued as a business rather than as a service. A developer able to integrate interconnection, generation, equipment and microgrid strategy into a single bankable plan is assembling the same capability these buyers are paying for — and should price its own work accordingly.

One caution on reading the multiple: both are announced, not closed, and both are subject to customary conditions.

08 | THE INTERCONNECTION DESK

ERCOT. Conditional classifications issued September 3 across conditional inclusion, studied-load and excluded categories. The RIOO intake platform for the Batch Zero Verification and Community Impact RFIs was deployed September 4; ERCOT will issue further market notices when the RFIs are issued, with additional rounds expected through October and November and a December 10 report filing targeted to the PUCT. New data center interconnections remain paused pending the audit. The Board of Directors meets September 14 and 15 in Austin, with agendas not yet posted. The Large Load Working Group meets September 17. The Batch 1+ and Comprehensive Transmission Planning Workshop #2, originally set for September 10, has been rescheduled to September 24. A workshop on the SB6 large-load curtailment operations framework and registration is set for October 6.

MISO. Reliability requirements for loads above 50 MW filed at FERC August 28. Ride-through BPM feedback due September 8, effective on or about December 4. Large Load Project Reviews and large-load forecasting feedback due September 10. Feedback on the proposed split of regulation reserve into up and down products due September 17. Stakeholder review meetings on the BPM draft September 23 and October 29.

PJM. The Reliability Backstop Procurement is a proposed tariff change filed at FERC on July 31 under Docket ER26-3380-000 and has not been approved. As filed, it would address the 6,831 MW shortfall from the 2028/2029 base auction — which cleared at the $325/MW-day cap across the footprint — through commitments of up to 15 years at a maximum MW-weighted willingness to pay of $555/MW-day in UCAP terms, with a commercial operation deadline of June 1, 2032. The filed schedule runs a target adjustment window September 10 to October 9, a central bid window September 30 to October 21, and results by December 2. A bilateral matching track, in which large loads negotiate directly with new supply projects, opened in August.

FERC. The Section 206 show-cause proceedings issued June 18 against all six RTOs and ISOs and their transmission owners remain open. Responses justifying existing tariff language or proposing revisions were due August 17. In MISO, MISO and its transmission owners have committed to filing a full response by November 16.

09 | ON OUR RADAR

ERCOT verification outcomes. The classifications are the start of the filter, not the end. What matters now is how much proposed load survives verification, how ERCOT handles disputed exclusions, and what the December 10 reports disclose publicly.

EO 14421 implementing regulations. Due December 24. The definition of covered equipment and the composition of any pre-qualified vendor list will determine how much of the current supply base remains available.

MISO's September 10 deadline. Comments on the Large Load Project Reviews process and the forecasting requirement close Thursday. Both shape how generation-backed large loads are developed in the footprint.

PJM's backstop, pending at FERC. A one-time procurement of this size, if approved on the filed schedule, will produce the clearest available price signal for incremental reliability capacity in a high-load-growth region. The bid window opens September 30.

Equipment platforms as acquisition targets. If the Flex and Vertiv transactions mark a trend rather than two decisions, controls companies, microgrid developers and distributed-power platforms capable of accelerating energization become strategically scarce — and more expensive to partner with.

THE INTERFACE VIEW

Issue 01 argued that the data center business is becoming the power business. This week sharpens the claim.

The power business is becoming a regulated development business.

ERCOT is not merely studying transmission capacity; it is auditing whether applicants are who they said they were. MISO is not merely queueing loads; it is specifying how they must behave electrically. FERC has all six grid operators justifying their large-load rules at once. And the federal government has declared a national emergency over where grid equipment is manufactured.

These are not separate stories. They are the same adjustment: institutions that previously accepted a load request at face value are now testing it, and building the machinery to keep testing it.

That changes what a development platform has to be able to do. The stack looks like this:

Land + Power + Interconnection + Engineering + Equipment + Capital + Execution

Weakness in any one prevents the other six from creating value. And the sequence is no longer linear — the interconnection package, the procurement strategy and the capital plan are now developed concurrently with the site, because each is being reviewed against the others.

The competitive question is no longer where to put the project. It is whether the team can hold the whole system together under scrutiny, and prove it.

That is where development value is moving.

Interface Holdings and Development Firm

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