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Does a utility letter prove grid capacity? An interconnection evidence checklist
Evaluate a site's power claim by load phase, delivery point, study status, contract obligations and the deadlines that keep the evidence current.
Direct answer
A utility letter supports a grid-capacity claim only for the customer, delivery point, load phase and conditions its issuer commits to. For new service, the strongest preconstruction evidence combines current studies, executed service and construction agreements, and fulfilled financial obligations. A queue position records process status; AEP Ohio's November 7, 2025 load-study letter shows that even signed service agreements can retain conditional energization dates.
On this page
What does a utility letter actually prove?Capacity evidence strength hierarchyIs this a load queue or a generation queue?What belongs in a usable capacity letter?Which study milestones strengthen a capacity claim?What do agreements and financial commitments add?Capacity expiration register: what goes stale?How should you estimate time to power?Do solar, batteries or onsite generation prove grid readiness?Worked example: requested, studied and contracted capacityPreacquisition interconnection evidence checklistHow should buyers compare sites and request current evidence?Sources, method and how to cite this checklistOpen the related tool for the calculation, checklist, or packet.
What does a utility letter actually prove?
Read the operative commitment before assigning value to the document title. A feasibility letter addresses preliminary service potential; a construction letter of agreement allocates cost exposure; an electric service agreement establishes service obligations. AEP Ohio issues its local service plan, letter of agreement (LOA) and electric service agreement (ESA) as distinct documents. [P1] [P2]
Separate five claims in the seller's package: infrastructure exists, a study accepts specified assumptions, service is contracted, construction dependencies are complete, and operation is authorized. Match every claim to the customer, parcel, delivery point and phased import demand. A power purchase agreement records an energy purchase; the site still needs its applicable local service commitment. [P2] [P3] [P4]
Use how the grid and substation deliver power to trace the physical path and construction and buildout phases to plan the downstream work.
Capacity evidence strength hierarchy
In Anvilfield's capacity evidence rubric, a queue entry supports process status, a completed study supports a conditional technical finding, and an executed service agreement supports a contractual commitment. The rubric, reviewed November 2026, is an editorial classification of the cited utility and operator processes.
| Level | Document or observation | Supported claim | Missing proof / next document | Basis |
|---|---|---|---|---|
| E0: visible infrastructure | Dated aerial image, verified asset record, substation nameplate | Observed asset and location as of the record date | Utility-confirmed available service and delivery point | Anvilfield synthesis; P2, P4 |
| E1: preliminary correspondence | Inquiry response or feasibility letter | Issuer's stated preliminary feasibility, MW and assumptions | Accepted application and scoped study | P1, P2 |
| E2: accepted request | Queue record, paid study request, study agreement | Process entry, identity and stated scope | Completed technical findings | P1, P5 |
| E3: studied service | Current reviewed study and service plan | Technical feasibility subject to listed upgrades/assumptions | Executed agreements, security and current schedule | P2, P4, P8 |
| E4: contracted future service | Executed ESA and required construction agreements; obligations current | Contractual service commitment within its conditions | Completed dependencies and applicable operating authorization | P1-P3 |
| E5: authorized existing service | Applicable utility/operator permission, service records and approved capacity | Authorized service at the documented delivery point and load | Separate approval for expansion or changed operating mode | P3-P5 |
Table basis: [P2] [P4] [P1] [P5] [P8] [P3].
Assign the strongest current level separately to each phase. An E4 agreement for curtailable service remains E4 with its curtailment conditions recorded; E5 authorization for an existing hall does not approve the next hall. Evidence strength and usable capacity are separate fields, so averaging levels across a campus hides the expansion risk.
Keep unsigned agreements classified as offers. When security has lapsed, retain the signed agreement and seek the issuer's current status determination before treating its obligations as current. Hosting-capacity maps remain screening evidence: establish whether they show proposed or existing assets and generator injection or load withdrawal. The issuer determines its project's actual status. [P1] [P3] [P14]
Is this a load queue or a generation queue?
A load-service request concerns power imported into the facility; a generator interconnection request concerns injection into the network. Record the application ID, responsible entity and approved operating mode for each interface. A nearby generator project can advance through its queue while the data center still lacks an import-service commitment.
| Request | Direction at interface | Evidence to obtain | What it does not establish | Source |
|---|---|---|---|---|
| Data center service | Import | Utility load/service request, plan, ESA, required operator studies | Right to export generation | P1-P4 |
| Generator interconnection | Export/injection | Generator study, interconnection agreement, operating limits | Retail load-service capacity at a nearby parcel | P13, P14 |
| Battery charging and discharge | Import and export, or approved non-export | Both operating envelopes, control strategy, applicable studies/agreements | Unlimited discharge energy or unlimited charging import | P10, P11 |
| Load plus behind-the-meter plant | Net flow changes by mode | Load service, generation agreement where required, curtailment/protection, changed-load study | Exemption merely because the plant sits behind the meter | P3, P4 |
| Islanded facility | Separated in approved island mode | Source/load balance, controls, fuel/energy, permits; reconnection conditions | Permission to parallel or reserve future utility backup | P4, P11 |
Table basis: [P1] [P4] [P13] [P14] [P10] [P11] [P3].
Berkeley Lab's Queued Up, 2026 Edition covers proposed generation and storage through December 31, 2025, reporting 1,312 GW of generation and approximately 749 GW of storage. Those totals describe proposed supply projects, not data center import-service reservations. Its report was published in June 2026 and its spreadsheet updated in May. [P13]
FERC Order No. 2023's 150-day cluster-study framework concerns generator interconnection, with implementation governed by approved provider tariffs. DOE's January 2025 DER roadmap recognizes storage as both generation and load; obtain charging import, discharge export and non-export limits separately. [P14] [P11]
What belongs in a usable capacity letter?
A usable letter identifies the utility issuer and authorized contact, customer legal entity, parcel, service address, delivery point and voltage. It states current and ultimate MW, phase dates, study references, normal and contingency assumptions, operating restrictions, dependencies and expiry clauses. Missing identity or boundary information prevents a reliable match between the offer and the land being purchased.
Reconcile IT load with total facility demand using the engineered peak, including cooling and auxiliary loads. Annual power usage effectiveness (PUE) is insufficient to turn an IT forecast into a guaranteed peak import requirement. Follow facility and IT capacity planning and the power distribution chain to keep losses and demand boundaries consistent.
AEP's transmission requirements, Revision 6 effective December 31, 2024, interpret close-to-unity load power factor as at least 0.95 lagging; its generator leading-to-lagging capability requirement is a separate rule. Anvilfield estimates 105.26 MVA for a selected 100 MW load at 0.95 power factor: divide real-power MW by power factor, or 100 / 0.95. Establish transformer rating, ambient and cooling basis, losses and contingency loading separately. [P4]
An existing substation rating describes equipment capability; the utility study must identify available service after existing commitments and upstream constraints. Record who can curtail service, the triggers, notice, duration limits, restoration conditions and allowed import after a source trips. The agreement's definitions of firm, interruptible, temporary and standby service control. [P2] [P3]
Ask for a phase schedule, not one campus total
Give each load block its own delivery point, MW, date, agreement and upgrade dependencies. Two feeds are additive only to the extent the approved configuration permits simultaneous use; redundancy requires identifying the surviving path and shared upstream constraints. Carry that distinction into generator sizing and surviving capacity.
Which study milestones strengthen a capacity claim?
Study milestones strengthen a claim when the report covers the current design and its status is documented. Record whether each report is completed, reviewed, approved or superseded, together with the model year, load ramp, contingency set, assumed upgrades, affected systems and cost allocation. The stages below describe functions; utilities use different names and sequences. ERCOT's current Batch Zero process covers large loads of 75 MW or greater; retain the applicable path and operator classification. [P5]
| Milestone | Retained evidence | Actual reviewed rule or interval | Remaining dependency | Source |
|---|---|---|---|---|
| Load-study request accepted | Legal applicant, site control, load ramp, fee receipt | AEP application process: pay fee within 45 days | Study findings and service plan | P1 |
| Load system analysis | Model case, load, contingency results, required upgrades | AEP November 2025 study used PJM 2030 Summer RTEP case; N-1 thermal and N-1-1 thermal/voltage analyses | Regional/local upgrade completion | P2 |
| Load dynamic study validated | Study date, author, reviewed status, model changes | ERCOT July 2026 transition form v2 checks updated dynamic data for the pre-July 10 study cohort | Current operator determination | P8 |
| Service/facilities plan | Local scope, regional dependencies, CIAC estimate | AEP issued local plan, LOA and ESA as distinct documents | Execution and funding obligations | P2 |
| Generator cluster study | Report and applicable provider tariff | FERC Order 2023 baseline: 150 days for generator cluster study | Restudies, facilities study, agreement, construction | P14 |
| ERCOT eligibility verified | RIOO response, supporting exhibits, operator classification | Type C/D reference guide: TSP response within 10 business days of RFI issuance | Final classification and subsequent applicable steps | P5, P6 |
| Service authorized | Approved load/operating mode and connection release | ERCOT requires its applicable energization request approval before energization | Any separately requested expansion | P5 |
Table basis: [P1] [P2] [P8] [P14] [P5] [P6].
AEP Ohio's November 7, 2025 study used N-1 thermal and N-1-1 thermal, voltage-magnitude and voltage-drop analyses. N-1-1 tests sequential outages with intervening redispatch, while simultaneous N-2 events represent a different condition. ERCOT's stability form v2 covered studies performed on or before July 10, 2026 and was due July 24; it records the performer, study date, ERCOT review/approval and effects of updated dynamic data. [P2] [P8]
Does the study also prove enough generation is available?
AEP Ohio's November 7, 2025 transmission study assumed adequate generation and did not evaluate generation sufficiency or wholesale generation prices. Maintain separate records for local delivery service, the energy purchase and applicable market capacity or resource-adequacy obligations. Identify the utility, supplier or responsible market entity that confirms each. [P2] [P3]
FERC's June 18, 2026 large-load action directed region-specific tariff responses within 60 days and separate generation-adequacy reporting. That response clock applied to the ordered entities; it supplied no site energization deadline. Read the region's effective tariff and applicable orders. [P15]
What do conflicting study results mean?
First compare delivery point, load, power factor, generation mode, model vintage and upstream projects. Thermal studies test equipment loading; voltage studies test voltage levels and changes; dynamic studies test the response over time to disturbances. A thermal pass leaves the other applicable studies unresolved. AEP Revision 6 §4.3.1 requires restudy and remodeling of transformer impacts when end-use customers add behind-the-meter generation or DERs that modify the delivery point. Obtain the revised transformer-impact findings and models before energization. [P4]
What do agreements and financial commitments add?
Agreements establish who carries construction exposure, service obligations and continuing financial commitments. AEP Ohio's process distinguishes the LOA's buildout-cost obligation from the ESA's service terms and good-faith estimated energization date; the final service plan remains subject to RTO approval. [P1]
The governing tariff here is Ohio Power's November 2026 tariff book, Schedule DCT, first revised sheets 223-1 through 223-8, effective August 28, 2026. Its data-center definition exceeds 25,000 kW, while the application instructions include requests of 25,000 kW or greater. At exactly 25 MW, obtain written applicability and fee confirmation. [P3] [P1]
| Item | Verified value/rule | Applies to | Evidence/cost treatment | Source/edition |
|---|---|---|---|---|
| Load-study fee, lower band | $10,000 for requests greater than 25,000 kW and less than 50,000 kW | Current application process | Fee, not construction price or reservation | P1, checked 2026-11-05 |
| Load-study fee, middle band | $50,000 for requests at least 50,000 kW and less than 100,000 kW | Same process | Exactly 50 MW enters this band | P1 |
| Load-study fee, upper band | $100,000 for requests at least 100,000 kW | Same process | Exactly 100 MW enters this band | P1 |
| Fee payment | Within 45 days | That process | Unpaid request treated as withdrawn | P1 |
| Load-study target | 60 days with regional transmission upgrades; 45 days otherwise | Paid requests in described process | Reasonable efforts, not energization deadline | P1 |
| LOA/ESA signature | Within 60 days; November 2025 letter specifies from receipt | Offered contracts | Failure to sign forfeits queue place | P1; P2 p. 5 |
| LOA exposure | 100% of buildout costs upon cancellation or delay greater than 12 months before target energization | Current process's LOA description | Obtain actual agreement and project cost schedule | P1 |
| Load ramp | Maximum 4 years; minimum ramp-capacity fractions 50%, 65%, 80%, 90% | DCT New Load | Billing floor during ramp is 85% of load-ramp contract capacity | P3 sheets 223-1, 223-2, 223-4 |
| Initial service term | Not less than ramp period plus 8 years | DCT New Load | Minimum is 8 years with zero ramp or 12 years with four-year ramp; longer terms remain possible | P3 sheet 223-5 |
| Post-ramp contract minimum, lower band | 15,000 kW + 85% of capacity above 25,000 kW | 25,001 to 75,000 kW aggregate contract capacity | Also compare historical-demand floor and actual billing demand | P3 sheet 223-4 |
| Post-ramp contract minimum, upper band | 57,500 kW + capacity above 75,000 kW, capped at 85% of total capacity | 75,001 kW and above | Historical floor is 85% of highest established billing demand in prior 11 months | P3 sheet 223-4 |
| Collateral | At signing, guarantee or collateral equal to 50% of full-term minimum charges unless financial exemption applies | DCT New Load | Exemption requires both at least A- from S&P and A3 from Moody's, plus GAAP-audited cash/equivalents greater than 10 times the requirement; a qualifying parent/affiliate guarantee is an allowed way to satisfy the obligation | P3 sheets 223-6, 223-7 |
| Letter of credit | Initial and renewed terms at least 360 days; renew or extend no later than 30 days before expiry | Security supplied as a letter of credit (LOC) | Failure permits immediate draw | P3 sheet 223-7 |
| CIAC / network work | Project-specific amount in service plan and agreement | Actual site | Use the actual upgrade scope and allocated cost | P2, P4 |
Table basis: [P1] [P2] [P3] [P4].
Use the filed tariff when an older letter or process summary differs. The November 2025 letter allowed collateral within 30 days after signing; current DCT sheet 223-6 requires the applicable guarantee or collateral at signing unless the financial exemption applies. Put the actual due date from the current offer into the obligation register. [P2] [P3]
Separate study fees, contribution in aid of construction (CIAC), collateral, minimum-demand charges and energy purchases. Match CIAC scope, exclusions, cost allocation, cancellation liability and payment triggers to the actual upgrade schedule.
Ohio Power's August 28, 2026 DCT sheet 223-5 requires at least 180 days' advance written notice for New Load seeking its Standard Service Offer (SSO) at startup, or customers switching or returning to SSO. Ohio Power then conducts separate procurement at the customer's full cost. Track that supply deadline alongside construction and the service date. [P3]
What is the minimum-demand exposure?
Apply the ramp and post-ramp rules separately. The worked table applies Ohio Power's August 28, 2026 DCT to a selected 100 MW contract and demand history. Billing demand combines the current meter result with the applicable contractual floors; keep it separate from the physical service limit.
| Input or result | Value | Calculation / applicable rule | Buyer interpretation |
|---|---|---|---|
| Selected final contract capacity | 100,000 kW | One New Load contract; no other affiliated New Loads in this check | Use this capacity to select the fee and demand bands |
| Published load-study fee | $100,000 | P1: 100,000 kW and greater | Study cost only |
| Selected four-year ramp | 50,000; 65,000; 80,000; 90,000 kW | P3 minimum ramp-contract fractions applied to 100,000 kW | Actual agreed ramp may be higher |
| Ramp billing floors | 42,500; 55,250; 68,000; 76,500 kW | 85% of those selected ramp capacities | Current measured demand can produce a larger bill |
| Minimum initial contract term | 12 years | Four-year ramp plus eight years, P3 sheet 223-5 | Record any longer agreed term |
| Post-ramp contract component | 82,500 kW | 57,500 + (100,000 - 75,000); below the 85,000 kW cap | Apply the upper band before testing the historical floor |
| Selected highest prior billing demand / current metered demand | 100,000 / 60,000 kW | Prior billing demand within preceding 11 months; current demand uses the highest 30-minute integrated kW peak | Both are selected worked inputs |
| Historical floor | 85,000 kW | 85% of 100,000 kW | Larger than the 82,500 kW contract component |
| Resulting post-ramp billing demand | 85,000 kW | Largest of current 60,000 kW, contract component 82,500 kW and historical floor 85,000 kW | Billing demand exceeds this month's metered demand by 25,000 kW |
Method: these Anvilfield estimates apply the current application fee bands and August 28, 2026 tariff to one selected 100 MW New Load contract, a four-year ramp and the stated demand history. Sheet 223-3 uses the highest 30-minute integrated kW peak, or a thermal-type demand meter at the utility's option. Calculate both post-ramp floors, then take the largest with the applicable meter result. A 50 MW contract without a larger historical floor yields 36.25 MW under the lower band, which explains why a blanket 85% rule is inaccurate. [P1] [P3]
Aggregate affiliated New Loads and allocate obligations across contracts as the tariff directs. A dollar bill additionally requires applicable rates, riders, voltage and supply arrangements. Billing capacity belongs in the financial model; physical availability and operating restrictions belong in the service record.
Capacity expiration register: what goes stale?
A capacity claim requires three separate date checks: literal expiry, an action deadline and changes to the studied design. Record the original document, trigger, present status and evidence needed to restore currency. An old document without an expiry clause still needs revalidation when its customer, load or network assumptions change.
| Claim being carried | Trigger or date rule | Classification | Restoring/current evidence | Source |
|---|---|---|---|---|
| “Our unsigned AEP offer holds the place” | 60-day execution window from receipt passes without signature | Queue place forfeited under stated process | New/current utility determination and executed agreements | P1, P2 |
| “Our submitted application holds the place” | Required study fee not paid within 45 days | Request withdrawn under stated process | Current accepted and paid request | P1 |
| “Security remains valid until its printed expiry” | LOC renewal not provided at least 30 days before expiry | Renewal obligation missed; utility draw right | Accepted renewal/replacement and utility status confirmation | P3 sheet 223-7 |
| “The old ERCOT LLIS route is still available” | ERCOT ended old-process reviews and approvals after July 10, 2026; by November 5 that window is closed | Process superseded, not automatic cancellation of every project | Applicable Batch Zero path, current classification and evidence | P9 |
| “We can still enter AEP's October 1, 2026 study tranche” | Application cutoff was September 30, 2026; by November 5 it has passed | Published tranche window closed; not proof that all later applications are rejected | Submission receipt dated by cutoff, or written utility confirmation of the applicable later tranche | P1 |
| “Batch Zero eligibility is final” | Conditional classification still undergoing verification | Conditional, not final | RIOO response and final ERCOT determination | P5-P7 |
| “The old stability study covers the revised equipment” | New dynamic data adversely changes the studied behavior | Technical revalidation required | TSP study-validity determination and applicable restudy | P8 |
| “Our Studied-path ERCOT RFI can wait” | 10-business-day response deadline; TSP may request five more business days | Overdue response may result in Batch Zero removal; an extension request does not establish approval | Timely RIOO submission or confirmed extension/current ERCOT status | P7 p. 2 |
| “The import-only study covers our new BTM plant” | DER addition modifies delivery-point transformer impacts | Restudy/remodel trigger | Revised study/model and required agreement | P4 §4.3.1 |
| “An existing contract covers any expansion” | Under DCT New Load terms, load addition exceeds 100 kW | New contract required; distinct from the Existing Load expansion classification threshold of more than 25,000 kW | New contract and available-capacity confirmation; preserve any separately metered Existing Load status | P3 sheets 223-2, 223-6 |
| “The service transfers with the deed” | Applicant/contract party changes | Transfer status unverified until terms checked | Applicable assignment clause and required consent | Anvilfield review rule; P3 contract identity, P6-P7 entity evidence |
| “The letter has no expiry, so it is current” | Load, date, parcel, study assumptions or upstream projects change | Current applicability unverified | Issuer's dated reaffirmation or replacement | Anvilfield review rule; P2, P4 |
Table basis: [P1] [P2] [P3] [P9] [P5] [P7] [P8] [P4] [P6].
Calculate AEP's signature deadline from the customer's recorded receipt date, preserving the delivery email with the offered agreements. A missed letter-of-credit renewal gives the utility a draw right under DCT; record that remedy and the utility's status determination rather than assuming automatic capacity loss. [P2] [P3]
ERCOT's October 13, 2026 Type C/D guide v1.0 requires the transmission service provider (TSP) to respond within 10 business days of RFI issuance. Its September 19, 2026 Studied-path guide v1.1 also allows a request for five additional business days; approval must be confirmed. The live Resource Integration and Ongoing Operations (RIOO) request controls the filing. [P6] [P7]
Does buying the land transfer the power?
Match deed or lease control, project-company ownership, utility contract assignment and operator eligibility separately. Obtain required consents under the actual transfer clauses. AEP's public process permits requesting reallocation of up to 25% of contract capacity, subject to electrical feasibility, a receiving ESA, required collateral and costs, and written attestations that neither party exchanges compensation beyond the specified costs. Reallocation and sale of the project are different transactions; read the property's actual assignment terms. [P1]
How should you estimate time to power?
AEP Ohio's November 7, 2025 study planned Q4 2031 service for Clusters 1 and 3 and 2033 service for Cluster 2, subject to the named regional and local upgrades. These historical forecasts show how reinforcement controls timing; the site's current dated service plan supplies the buyer's planning date. [P2]
| Evidence/date | Reported interval or date | What it times | Dependency to record | Treatment in a current site review |
|---|---|---|---|---|
| AEP current application process | 45 or 60 days, reasonable efforts | Load study | Complete application, fee, upgrade requirement | Study milestone only [P1] |
| AEP November 7, 2025 letter | Q4 2031, Clusters 1 and 3 | Then-estimated in-service timing | Regional and local upgrades | Historical study forecast, obtain current ESA [P2] |
| Same letter, Cluster 2 | 2033 | Then-estimated in-service timing | Additional competitive regional solution | Historical planning estimate, not a guaranteed date [P2] |
| AEP February 13, 2026 release | Contracted projects progressively through 2035 | Portfolio schedule, not one parcel | Individual contracts and infrastructure | Record only the specific site's current phase dates [P12] |
| ERCOT current integration page | Conditional classification followed by verification | Eligibility status | RFI evidence and final determination | Eligibility alone supplies no energization date [P5-P7] |
| Actual project purchase orders | Date in accepted vendor order | Equipment delivery | Manufacturing, transport, installation | Use actual order, not a general equipment lead-time claim [P4; Anvilfield schedule method] |
Table basis: [P1] [P2] [P12] [P5] [P7] [P4].
Put studies, agreement execution, regional and local upgrades, permits, easements, equipment delivery, outage windows and connection authorization on one dependency schedule. For parallel work, use the latest required completion date, then add the remaining sequential connection work. Include required upstream work and preserve overlaps.
Record each dependency's owner, source, last confirmation, contractual status, next milestone and earliest, working or delayed date basis. Publish alternative dates only when their assumptions are documented. Refresh the record at the earliest binding deadline or material design or system change.
Confirm the individual ESA and updated service plan before scheduling occupancy against advertised power. Record any temporary supply separately, including its approved MW, operating restrictions, end date and transition to permanent service.
Do solar, batteries or onsite generation prove grid readiness?
Solar and battery nameplates describe equipment; usable supply also requires coincident output, stored energy and approved operating modes. Request an hourly load and solar model covering darkness, cloud conditions and recharge. Annual renewable-energy matching cannot establish power delivered at the moment the facility needs it.
EIA's August 2021 battery report defines nameplate duration by dividing energy capacity in MWh by power capacity in MW. For the actual duty, retain usable energy after operating reserves, initial state of charge, efficiency, aging and recharge assumptions. Equipment selection belongs with battery energy storage types and onsite generation and microgrid supply. [P10]
How many hours does the battery cover the import shortfall?
Select an 80 MW facility, 60 MW approved import, a 20 MW/80 MWh battery and 64 MWh of usable AC-delivered energy. Anvilfield estimates a 20 MW shortfall, four hours of nameplate duration and 3.2 hours of usable shortfall coverage. A twelve-hour zero-solar interval requires 240 MWh delivered; another approved source or load reduction must cover the remaining 176 MWh.
Method: subtract approved import from coincident load, then divide usable AC energy by the shortfall. Shortfall = load - import; coverage hours = usable AC MWh / shortfall MW. The selected usable-energy input already includes discharge-path losses and operating reserves. The approved discharge power must also meet the shortfall: below 20 MW, this battery cannot carry the full 20 MW gap even while energy remains. With 70 MW approved import, the same battery covers the resulting 10 MW shortfall for 6.4 hours.
Recharge requires its own operating interval. When the facility already consumes the entire 60 MW import allowance, grid charging needs additional approved headroom or reduced facility load. Retain the usable-energy warranty, converter power limit and operating-condition records supporting the calculation.
Which equipment and interface rules control?
AEP's August 28, 2026 DCT requires an agreement before another source connects, with a section-specific exception for emergency or backup generation not designed to parallel its system. A customer netting behind-the-meter generation against contract capacity must maintain equipment able to instantaneously curtail load by at least that generation output. [P3]
Document approved non-export controls, source-trip response, net output at site conditions and fuel or permit limits. Apply the actual interface requirements: DOE's January 2025 roadmap covers distribution and sub-transmission DER interconnection; AEP Revision 6 addresses transmission connections and directs distribution DER applicants to separate requirements. Equipment certification, electrical installation approval and utility permission establish different things. [P4] [P11]
Worked example: requested, studied and contracted capacity
AEP Ohio's February 13, 2026 update reported 13,022.7 MW requested and paid for study, followed by 5,642 MW of binding DCT contracts as of February 12. The published comparison gives buyers a concrete way to distinguish demand expressed through studies from demand backed by contracts. [P12]
| Input or result | Value | Calculation / provenance | Interpretation |
|---|---|---|---|
| Paid-study cohort | 13,022.7 MW | AEP February 13, 2026 release | Studied/requested stage denominator |
| Signed DCT contracts as of February 12, 2026 | 5,642 MW | Same release | Binding-contract stage numerator |
| Contracted share of studied MW | 43.32% | Anvilfield estimate: 5,642 ÷ 13,022.7 × 100 | Share of this published MW cohort at this date |
| Stage difference | 7,380.7 MW | Anvilfield estimate: 13,022.7 − 5,642 | Studied MW less subsequently contracted MW |
| Pre-tariff contracts | 12,219 MW | Same release; separate cohort | Not part of the paid-study denominator |
| Combined contracted portfolio | 17,861 MW | 12,219 + 5,642 | Reconciles AEP's reported total |
| Energized MW for paid-study cohort | Not reported in this release | No operating-capacity input provided | Request site operating/service records for that claim |
Table basis: [P12]; Anvilfield estimates for the calculated share and stage difference.
Anvilfield estimates that 43.32% of AEP Ohio's paid-study MW had reached binding contracts by February 12, 2026. This is a share of requested MW, not a project success rate; projects differ in size.
Method and interpretation
Divide contracted MW by paid-study MW and multiply by 100; subtract contracted MW from studied MW for the stage difference. Retain the published MW precision and round the percentage to two decimals. Keep the pre-tariff portfolio outside the paid-study denominator.
Preacquisition interconnection evidence checklist
Give every item an owner, document reference, review date and action. Use confirmed, conditional, missing or superseded as document statuses. The technical lead matches models; the utility contact confirms service and obligations; transaction, commercial and scheduling leads track transfer, money and dependencies.
- Identity: Match applicant, seller, utility customer and agreement signatories; reconcile differences using entity and authority records.
- Land: Match parcel, deed/lease/option and site-control period to the load request; obtain a corrected request if the site changed.
- Delivery point: Record bus/substation, voltage, meter and ownership boundary; resolve ambiguous “nearby power” claims with the utility.
- Demand boundary: Record peak facility MW, IT MW, auxiliary demand, power factor and load ramp; restate the claim in one consistent boundary.
- Process identity: Record load, generation and storage IDs separately; obtain the missing import or export record.
- Document status: Obtain signed complete documents, schedules and amendments; mark unsigned offers as offers.
- Study scope: Match load model, date, contingencies, DER and equipment assumptions; request revalidation where changed.
- Upgrades and supply: List regional/local/affected-system work, cost responsibility and required completion; tie every dependency to a project reference. Identify who confirms generation-supply adequacy and whether the reviewed study excluded it.
- Schedule: Separate target, good-faith estimate, conditional forecast and actual authorization; record the issuer and latest revision.
- Financial and supply obligations: Verify fee receipts, CIAC, collateral, minimum demand and energy-supply procurement; record due dates and current status.
- Expiry: Log execution windows, security renewal, site-control expiry and milestone remedies; obtain written status for missed deadlines.
- Transfer: Read assignment/change-of-control provisions and required consents; do not carry capacity into a new owner name without the applicable evidence.
- Operating restrictions: Record curtailment, import/export, BTM trip response and permitted island/parallel modes; calculate the usable load, usable AC battery duration and recharge headroom under those restrictions.
- Conclusion: Assign evidence level by phase, attach page-level sources, name remaining conditions and set the next review at the earliest contractual deadline or material design/system change.
Keep complete files with stable document IDs and page references. ERCOT's RFIs require exhibits and supporting references; the same discipline makes any purchase review traceable. Carry the accepted design into later commissioning levels and acceptance records. [P6] [P7]
How should buyers compare sites and request current evidence?
Compare sites at the same facility-load boundary and required phase date. Report MW, evidence level, service restrictions, next binding deadline and largest unresolved dependency alongside the broader data center site selection criteria. A campus total loses the conditions that determine whether the first hall can operate.
Obtain confirmation through the issuer's official contact channel, with applicant authorization where required. Review full executed documents and amendments against project IDs. A cropped signature page leaves its schedules unreviewed; existing bills establish recorded service and demand at a meter, while current agreements and utility records establish permitted capacity and transfer conditions.
Write the conclusion in a complete form: [Entity] holds [document/status] for [MW and phase] at [delivery point], with [service date status], subject to [named upgrades/conditions], checked [date]. Mark missing fields explicitly.
Worked review: a seller advertises 100 MW. Its current executed agreement covers 40 MW in the first phase; a completed study covers 60 MW in a later phase with no executed service agreement. Record 40 MW at E4 and 60 MW at E3, each with its conditions and date basis. The purchase memo should state “40 MW contracted; 60 MW studied; energized capacity unconfirmed” and carry the later phase as conditional expansion.
Regional acquisition teams first identify visible infrastructure and owner records for contact. During that search, [PorchRocket Asset Search](/asset-search?for=power) reports newly added, removed or altered visible power assets with dated views for acquisition teams. Place those observations at E0, then obtain the utility evidence that establishes the site's service.
Sources, method and how to cite this checklist
Anvilfield reviewed this checklist on November 5, 2026 against the primary sources listed below. Dates, fees and obligations retain their utility, operator, tariff and cohort scope. Worked examples label calculated results as Anvilfield estimates.
Reference units: evidence hierarchy, queue distinction, study milestones, expiration register and time-to-power uncertainty.
Update log, 2026-11-05: Reopened primary sources; clarified transition-form dates, collateral renewals, supply procurement and battery power limits; added a phased purchase review and cut repeated text.
How to cite this page: Anvilfield, Does a utility letter prove grid capacity? An interconnection evidence checklist, 2026, https://anvilfield.com/field-guides/datacenter/grid-capacity-claims-interconnection-evidence/
FAQ
Does a utility letter prove grid capacity?
It proves only what its issuer commits to in writing, so match it to current studies, service agreements and their conditions.
Is a queue position the same as power available?
No; a queue position establishes process status, while available service requires the applicable technical and contractual evidence.
Can I use Berkeley Lab's queue data to estimate my data center connection date?
Berkeley Lab's 2026 dataset covers generation and storage projects, so obtain the utility's load-service schedule for the actual site.
What does an interconnection study prove?
It establishes the study's technical findings for specified load models, network assumptions and required upgrades.
Does an executed service agreement guarantee the power date?
Read its date clause: AEP Ohio's described ESA uses a good-faith estimated energization date subject to infrastructure dependencies.
How long is a utility capacity letter valid?
Use its stated expiry and milestone conditions, and revalidate it when the load, site, ownership or network assumptions change.
Does utility capacity transfer when I buy the land?
Check the governing agreement's assignment and consent requirements separately from the deed transfer.
How much is an AEP Ohio data center load study?
$10,000 to $100,000 under AEP Ohio's process checked November 5, 2026, with the fee set by requested kW. The financial-obligations table gives the exact bands; obtain written confirmation at exactly 25 MW.
Can solar and batteries replace a firm grid-capacity commitment?
Only the approved supply design and operating agreements establish usable supply; solar nameplate MW and battery MWh alone do not.
Does behind-the-meter generation avoid an interconnection agreement?
AEP Ohio's August 28, 2026 DCT requires an agreement for another connected source. Its section-specific exception covers emergency or backup generation not designed to parallel the utility system.
How long does it take to get power to a data center?
AEP Ohio's November 7, 2025 study estimated Q4 2031 for Clusters 1 and 3 and 2033 for Cluster 2, subject to regional and local upgrades; use the site's current utility plan for its planning date.
Does a favorable interconnection study prove enough electricity supply exists?
Read its scope: AEP Ohio's November 7, 2025 transmission study assumed adequate generation and did not evaluate generation sufficiency, so that issue needs separate supply evidence.
People also ask
Sources checked
- [P1] AEP Ohio data center application process, checked November 5, 2026 Opened with curl November 5, 2026. Process steps, raw-HTML fee bands, tranche cutoff, LOA/ESA distinction and conditional capacity reallocation.
- [P2] AEP Ohio DCT Load Study Letter, November 7, 2025 Opened with curl November 5, 2026. Sections II-III: contingency studies, generation exclusion and historical service dates; section IV: receipt-based signature clock and earlier collateral instructions.
- [P3] Ohio Power November 2026 tariff book, Schedule DCT, effective August 28, 2026 Opened with curl November 5, 2026. Schedule DCT first revised sheets 223-1 through 223-8: definitions, ramp, metering, demand floors, 180-day SSO notice, term, collateral and BTM rules.
- [P4] AEP transmission interconnection requirements, Revision 6, December 31, 2024 Opened with curl November 5, 2026. Effective December 31, 2024; load power factor pp. 28-29; changed transformer impacts before energization, section 4.3.1, p. 36.
- [P5] ERCOT Large Load Integration, checked November 5, 2026 Opened with curl November 5, 2026. Batch Zero 75 MW scope, conditional classifications, path-specific forms and separate energization approval.
- [P6] ERCOT Type C/D verification RFI guide, October 13, 2026, v1.0 Opened with curl November 5, 2026. Published October 13, v1.0; p. 2: 10-business-day TSP filing, controlling RIOO request and document instructions.
- [P7] ERCOT Studied-path verification RFI guide, September 19, 2026, v1.1 Opened with curl November 5, 2026. Published September 19, v1.1; p. 2: 10-business-day response, requestable five-business-day extension and removal consequence; subsequent pages: exhibits and site/financial evidence.
- [P8] ERCOT Valid Stability Study Form v2, posted July 1, 2026 Opened with curl November 5, 2026. Historical transition form for studies on or before July 10, due July 24, 2026; current models and ERCOT review/approval fields. Listed July 1 on P5.
- [P9] ERCOT Market Notice M-B062326-04, July 8, 2026 Opened with curl November 5, 2026. July 8 notice: legacy LLIS reviews ended after July 10; later Batch Zero submission and classification milestones.
- [P10] EIA Battery Storage in the United States, August 2021 Opened with curl November 5, 2026. Figure 4 note, p. 9: nameplate-duration calculation; operating power and energy constraints. Historical cost figures are not used.
- [P11] DOE Distributed Energy Resource Interconnection Roadmap, January 16, 2025 Opened with curl November 5, 2026. January 16 roadmap: distribution and sub-transmission scope; energy storage acting as both load and generation.
- [P12] AEP Ohio data center load update, February 13, 2026 Opened with curl November 5, 2026. Published February 13, status February 12: 13,022.7 MW paid-study cohort, 5,642 MW subsequent contracts, separate 12,219 MW and combined 17,861 MW portfolios; timing through 2035.
- [P13] Berkeley Lab Queued Up, 2026 Edition, June report and May spreadsheet Reopened through the web tool November 5, 2026 after curl returned a 403 challenge. Generation/storage through December 31, 2025; artifact dates and queue totals.
- [P14] FERC Order 2023 explainer, updated January 23, 2025 Reopened through the web tool November 5, 2026 after curl returned a 403 challenge. Order 2023 generator scope, 150-day study framework, heatmaps and provider-specific implementation.
- [P15] FERC large-load integration announcement, June 18, 2026 Reopened through the web tool November 5, 2026 after curl returned a 403 challenge. June 18 action: entity tariff-response clock and separate generation-adequacy reporting.