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There is no standard upgrade package for a utility-scale solar-and-battery project. The transmission provider’s interconnection studies determine the actual work, based on the project’s point of interconnection, export capability, operating schedule, local equipment, wider-network constraints, and other queued projects. The result can range from connection-point equipment to major network construction—or to an operating agreement that limits exports at certain times.
Without a location, project size, inverter and battery configuration, proposed export profile, and study results, it is not technically defensible to promise that a project needs (or avoids) a new substation, transformer, transmission line, breaker, protection system, or synchronous condenser.
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What determines the upgrade list?
An interconnection request is evaluated at a specific point of interconnection (POI), not against a generic map of nearby lines. The provider models the project’s injections, withdrawals, fault behavior, voltage effects and contingency performance under the rules in its tariff. Available transfer capability, existing facilities, queued projects ahead of or alongside the request, and the condition of neighboring systems all influence the result.
A line that appears close to a proposed solar farm may have little usable capacity. Conversely, a project farther from a strong transmission node may require less work if its modeled impact is small. The controlling evidence is the provider’s interconnection study and the governing interconnection agreement.
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- Location and POI: The substation, bus, circuit or transmission line where the project will connect.
- Size and technology: Solar nameplate capacity, inverter controls, battery power rating, battery energy duration and whether the resources share one POI.
- Operating assumptions: Maximum export, charging from the grid, simultaneous solar-and-battery output, ramp rates and any proposed hourly schedule.
- Network conditions: Thermal loading, voltage, stability, short-circuit duty, protection coordination and other reliability criteria.
- Queue interactions: Other requests that can change the modeled flows or the allocation of upgrade costs.
- Affected systems: Neighboring transmission providers whose facilities could experience a reliability impact.
That is why two projects with identical megawatt ratings can receive very different upgrade requirements.
The four scopes of work a study can identify
| Scope | What it covers | What cannot be assumed in advance |
|---|---|---|
| Point-of-interconnection facilities | Equipment needed to physically connect, measure, control and protect the project at the agreed POI. | A universal list of transformers, breakers, relays or communications equipment. The study defines the actual facilities. |
| Network upgrades | Broader transmission work needed to accommodate the project’s injection while maintaining reliable operation, such as increasing transfer capability or correcting modeled overloads and voltage problems. | That every project requires a new line, substation or transformer replacement. The modeled violation and feasible alternatives control. |
| Affected-system upgrades | Work identified by a neighboring system after coordinated analysis finds that the proposed interconnection could affect its reliability. | That the host utility’s study is the only study or that the host system can waive another provider’s requirements. |
| Regional transmission expansion | Long-term facilities selected through regional planning to serve broader reliability, economic or policy needs. | That regional planning approval substitutes for the project’s interconnection study or guarantees that a planned facility will be available by the project’s needed date. |
FERC’s interconnection rules require transmission providers to evaluate alternatives rather than presuming one hardware solution. Candidate technologies can include advanced conductors, power-flow controls, transmission switching, voltage-source converters, static VAR devices, synchronous condensers and tower lifting. These are options for solving a modeled constraint, not a prescribed package for solar-plus-storage projects.
How the U.S. interconnection process produces the answer
- Define the request. The developer submits the POI, resource ratings, site-control information, electrical models, requested service, and operating assumptions required by the provider’s tariff.
- Enter the applicable study track. Under FERC Order No. 2023, transmission providers generally study proposed generating facilities in clusters rather than conducting a completely separate process for each request. The rule includes readiness requirements, withdrawal consequences and cluster cost-allocation provisions.
- Run the cluster analysis. The provider tests the group of projects against base cases and contingencies, identifies overloads, voltage or stability concerns, and assigns impacts among participants. The Order No. 2023 explainer describes a 150-day cluster-study requirement, but implementation, restudies, data quality and project changes mean it is not a guaranteed end-to-end connection schedule.
- Specify facilities and network work. The study separates equipment at the POI from broader upgrades and states the assumptions used to calculate each project’s impact.
- Coordinate affected-system studies. If power flows could affect another transmission system, that provider can perform its own analysis and identify additional mitigation and costs.
- Negotiate the interconnection agreement. The agreement records the facilities, operating limits, milestones, security requirements, testing, ownership and cost responsibility that govern construction and operation.
- Construct, test and energize. The project must meet the agreement’s protection, controls, telemetry and commissioning requirements before commercial operation.
For a live project, the provider’s current tariff, transition rules, study status and executed documents take priority over a general description of the federal rule.
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Why a battery changes the engineering question
A co-located battery can charge when the grid is lightly loaded and discharge when solar production falls. That flexibility can change the project’s hourly injections and therefore the hours in which a constraint appears. DOE describes the general benefit this way: “One of the major benefits of energy storage is the flexibility to control when power is exported to (or drawn from) the grid.”
That capability does not automatically reduce upgrade costs. The provider must accept and model the proposed controls, verify that they can be enforced, and determine whether the remaining operating envelope satisfies reliability criteria. Important distinctions include:
- Shared POI versus separate POIs: Co-location behind one POI can be evaluated as a combined resource, but the provider still needs accurate models of simultaneous charging and discharging limits.
- Export limit: A battery may reduce the project’s maximum export, but a lower limit can reduce revenue or require curtailment during high-value hours.
- Charging source: Charging from solar, from the grid, or from both produces different flows and may create different study cases.
- Schedule enforceability: An hourly schedule or controller limit is useful only if metering, telemetry, control logic and contractual remedies make it dependable.
- Duration and state of charge: A battery cannot sustain an evening export profile indefinitely; the study must reflect its power and energy limits.
DOE’s 2024 account of the BATRIES project describes state-level efforts to let developers specify operating schedules when assessing whether an upgrade can be avoided. That is a dated California example, not a nationwide rule. State distribution procedures can omit storage or fail to credit its flexibility, while transmission providers apply their own tariffs and reliability criteria.
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Alternatives when the model finds a violation
The feasible response depends on the specific violation. Compare alternatives on reliability compliance, export capability, curtailment risk, capital cost, who pays, construction time, operating flexibility, enforceability and whether the solution benefits only one project or the wider network.
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|---|---|---|
| Build or reinforce infrastructure | Can preserve a higher firm export capability and address a persistent thermal, voltage or stability constraint. | Requires capital, permitting, outages, equipment lead times and a cost-allocation decision. |
| Downsize the request | Lower injections can reduce the project’s modeled impact and the scope of required work. | Reduces plant capacity and may undermine the project’s economics or contracted obligations. |
| Curtail exports | Can manage an occasional or time-specific constraint without immediate construction. | Creates lost production and must be measured, communicated and enforced under the agreement. |
| Use a battery operating envelope | Shifts exports away from constrained hours and can combine solar output with controlled storage dispatch. | Requires controls, telemetry and an enforceable schedule; battery duration and market operations limit flexibility. |
| Apply advanced transmission technology | Power-flow controls, advanced conductors, switching, converters, reactive-power devices or other technologies may solve a constraint with a different footprint or schedule. | Feasibility, procurement, maintenance, protection coordination and provider acceptance must be demonstrated for the specific system. |
The 2022 study by McLaren, Abraham, Darghouth and Forrester illustrates this comparison for distribution-connected photovoltaic systems. It defines an “Operating Envelope” of technical parameters and examines hourly maximum-export limits that could be written into an interconnection service agreement. Its methods are useful for understanding the infrastructure-versus-operating-flexibility trade-off, but they are not a guarantee for a utility-scale transmission interconnection.
Who pays for the upgrades?
Payment responsibility follows the applicable tariff and the study’s allocation rules, not a universal “generator pays” formula. FERC Order No. 2023 uses a proportional-impact approach for allocating specific network-upgrade costs among customers in a cluster. A project that withdraws, changes its request or fails a readiness requirement can face consequences specified in the tariff, including reallocation of costs.
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An affected-system study can create additional obligations outside the host provider’s initial estimate. The neighboring provider’s tariff and agreement determine how those costs are assigned.
Regional planning is a separate layer. FERC issued Order No. 1920 on May 13, 2024, followed by Order No. 1920-A on November 21, 2024, and Order No. 1920-B on April 11, 2025. These orders address long-term regional planning, state consultation, right-sized replacement facilities and interregional coordination. A regional facility selected through that process may have its own allocation method, but regional planning does not decide the project’s point-to-point interconnection requirements.
What costs and delays look like in practice
There is no reliable nationwide price range for connecting a large solar-and-battery project. Costs depend on voltage level, POI design, network conditions, scope of affected-system work, permitting, equipment availability and the project’s requested export capability. DOE and NREL’s 2023 discussion of Lawrence Berkeley National Laboratory findings reported that interconnection costs rose in PJM and MISO and that proposed wind, solar and storage projects in those territories had higher average network-upgrade costs than gas projects applying there. The cited summary does not establish a national dollar figure.
Queue conditions also affect schedule risk. The Council of Economic Advisers’ Economic Report of the President 2026, citing Rand et al. (2024), reports a median interconnection-queue wait of three years. It also reports that more than 80% of queued generation projects were solar and storage at the end of 2024, compared with about 14% in 2014. Those are shares of queued projects, not shares of generation or completed projects. The same report attributes an approximately 14% completion rate by capacity to Rand et al. (2024).
DOE’s 2024 BATRIES account says the project examined nearly 40 improvement areas and narrowed them to eight barriers affecting storage interconnection on the distribution grid. DOE also reported a $1.3 million 2019 award to the Interstate Renewable Energy Council for work on standalone-storage and solar-plus-storage distribution interconnection challenges. Neither figure is a forecast of a particular project’s cost or schedule.
A developer’s checklist before relying on an upgrade estimate
- Confirm the POI, voltage, ownership boundary and the transmission provider’s current tariff.
- Document solar inverter ratings, battery power and energy ratings, charging source, state-of-charge limits and simultaneous-output assumptions.
- State the requested firm export, any non-firm service, and the hours or conditions in which curtailment would be acceptable.
- Ask whether co-location behind one POI is permitted and how the provider models each resource.
- Identify every possible affected system and request the status and assumptions of coordinated studies.
- Separate POI facilities, network upgrades and regional-planning projects in the financial model.
- Compare construction, downsizing, curtailment and operating-envelope options using the same reliability and revenue assumptions.
- Check milestone dates, security postings, restudy triggers and withdrawal consequences before committing equipment orders.
- Verify that control, telemetry and metering systems can enforce any export schedule written into the agreement.
- Recheck the tariff and current filings before treating an older study, state rule or federal explainer as controlling.
Geographic and regulatory limits
The framework described here is based on U.S. federal sources. FERC jurisdiction covers relevant transmission-provider processes, while state distribution-interconnection rules vary. A state may use different screening methods, terminology or storage provisions. Order No. 1920 implementation and regional tariffs can also evolve, so a project team should rely on the current provider documents and filings.
DOE’s National Transmission Planning Study evaluates transmission, generation and storage across multiple scenarios. Its scenarios test a range of possible futures; they do not declare which future is most likely and do not prove that a particular line or substation has been approved or is required for one project.
Bottom line
The needed upgrades are whatever the project-specific interconnection, facilities and affected-system studies identify. A large solar-and-battery project may need POI equipment, broader network reinforcement, operating limits, curtailment, downsizing, advanced transmission technology, or a combination. Storage can change when the project exports and may reduce or defer some work, but only a provider-approved, enforceable operating model can earn that treatment. The tariff and executed interconnection agreement—not the project’s nameplate capacity or a nearby line on a map—establish the final scope, schedule and cost responsibility.
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