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Co-locating solar photovoltaic (PV) panels and battery energy storage means developing both systems at one physical site, often with shared land, access roads, electrical equipment, controls, construction mobilization, and an interconnection point. That arrangement can reduce duplicated work, but it does not automatically lower costs, secure grid approval, provide backup power, or improve financial returns.
The right design starts with the job the battery must perform, then works through site constraints, utility rules, AC-versus-DC architecture, permits, safety, and a project-specific financial model. Use current engineering studies, tariffs, equipment quotes, and local approvals rather than assuming that a configuration that worked elsewhere will work at your site.
What does co-located solar and battery storage mean?
A co-located project places a PV array and a battery energy storage system (BESS) behind the same general site boundary. They may share a point of interconnection (POI), substation or transformer capacity, switchgear, communications, monitoring, fencing, roads, security, operations staff, and maintenance access. The systems can still have separate inverters, controls, warranties, owners, or operating schedules.
Co-location is different from merely owning solar and storage in the same portfolio. Separately sited systems generally need separate land, construction mobilization, utility studies, interconnection facilities, and operating arrangements. A shared site can avoid some duplication, but every category must be checked against the electrical design and the utility tariff.
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| Planning issue | Shared-site project | Separately sited projects |
|---|---|---|
| Land and site work | May share leased or purchased land, grading, roads, drainage, fencing, and security; the battery may still require a dedicated pad and fire access. | Each site normally requires its own land, civil work, access, and security. |
| Electrical connection | May share a POI, substation, transformer, switchgear, metering, and communications, subject to utility approval and equipment ratings. | Each facility generally has its own interconnection facilities and studies. |
| Construction and permitting | Some mobilization, surveys, controls integration, and permit work can overlap, while battery-specific fire and building reviews remain. | Permitting, studies, and mobilization are usually duplicated. |
| Operations | One site can simplify access and staffing, but PV and BESS controls, maintenance windows, and safety procedures must be coordinated. | Sites can operate independently, which may simplify dispatch but increases travel and management overhead. |
| Constraints | Shared equipment can create export, charging, protection, or outage dependencies between the two systems. | Separate sites may provide more operational independence but lose shared infrastructure opportunities. |
The amount actually shared depends on the site layout, voltage level, existing PV equipment, ownership structure, tariff, and interconnection agreement. Treat co-location as a design option, not as a guaranteed saving.
Define the job before choosing equipment
Storage sizing follows the service the system must deliver. Write an operating brief before requesting battery prices or selecting an inverter. State which loads, meters, markets, and operating limits the battery will serve.
Shift solar into later hours
If the goal is to move midday PV production into evening consumption, the battery needs enough usable energy for the desired shift and enough power to discharge during the target hours. The schedule must account for charging limits, state-of-charge reserves, conversion losses, and any export cap.
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Reduce demand charges
A commercial facility may discharge during tariff-defined peak periods. That use case is governed by the utility’s demand calculation, interval length, seasonal schedule, and rules for battery charging. A battery that is large enough in energy terms may still lack the power rating needed to reduce a short, high demand peak.
Smooth short-term PV variation
Fast charge and discharge commands can soften brief changes caused by clouds or other generation variability. Smoothing is a different duty from moving energy for several hours, so the controls, power rating, usable energy, and cycling pattern must be modeled separately.
Participate in grid markets
Grid services can impose telemetry, response-time, minimum-size, availability, metering, and state-of-charge requirements. Confirm eligibility with the relevant market operator, utility, and project counsel; a co-located system is not automatically allowed to export or provide every service.
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Provide resilience or microgrid capability
Ordinary grid-connected storage does not become backup power simply because it is installed beside PV. Islanding, critical-load panels, black-start capability, protection, controls, fuel or charging strategy, and utility operating permissions must be deliberately engineered. Define which loads must remain energized, for how long, and under what outage conditions.
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Screen the site and point of interconnection early
Physical and land-use checks
- Confirm enough area for PV rows, battery enclosures, transformers, inverters, drainage, setbacks required by local authorities, and future maintenance.
- Verify construction access for heavy vehicles, cranes, replacement batteries, and emergency responders.
- Lay out fire lanes, turning radii, equipment clearances, fencing, security, and separation between combustible or high-voltage equipment.
- Check zoning, conditional-use approvals, neighboring notices, glare concerns, environmental resources, wetlands, endangered species, and historic-preservation obligations where applicable.
- Identify grading, geotechnical, flood, stormwater, noise, and temperature conditions that can affect equipment selection or civil cost.
Electrical and utility screening
Ask the utility for a preliminary view of available capacity at the proposed POI and whether the circuit is a network distribution system or another topology with special operating rules. Establish whether adding the battery changes the export profile, import requirements, protection scheme, metering, or study scope.
- What interconnection capacity is available today, and what upgrades or new lines could be required?
- Can PV and the BESS share the proposed POI, transformer, switchgear, and revenue meter?
- Where may the PV inverter, battery inverter, transformer, and protection equipment be located?
- Will a supplemental review, system impact study, facilities study, or transmission study be required?
- How will simultaneous PV export, battery charging, and battery discharge be limited?
- Are there limits on importing from the grid to charge the battery?
- What telemetry, controls, power-factor, ride-through, protection, and remote-dispatch functions are required?
- What tariff, standby charge, demand rule, net-metering provision, or export-credit rule applies?
- If resilience is planned, what islanding, reconnection, and microgrid approvals are necessary?
What FERC Order No. 2023 changes—and what it does not
For transmission-connected projects, the Federal Energy Regulatory Commission issued Order No. 2023 on July 28, 2023; it became effective November 6, 2023. FERC’s explainer says the final rule requires transmission providers to allow projects to co-locate on a shared site behind a single point of interconnection and share a single interconnection request. The reform also uses cluster studies and readiness and site-control requirements.
“The final rule requires transmission providers to allow projects to co-locate on a shared site behind a single point of interconnection and share a single interconnection request, thereby removing barriers for co-located resources by creating a more efficient standardized procedure for these types of configurations.”
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This is a transmission-provider interconnection rule, not a universal approval. Provider compliance filings, the applicable tariff, state commission rules, local distribution procedures, and project-specific studies still control what an applicant must submit. Confirm the process with the relevant transmission provider or utility before relying on a shared request or POI.
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Should solar and battery storage be AC-coupled or DC-coupled?
The coupling choice determines where conversion occurs, which equipment can be shared, how the battery charges, and how controls enforce export limits.
AC-coupled arrangement
In an AC-coupled design, the PV array feeds a PV inverter, while the battery uses a separate bidirectional battery inverter. Both connect on the AC side through switchgear, transformers, and controls. This arrangement is often easier to add to an operating PV plant because the battery can be engineered as a distinct AC resource, subject to the existing POI and protection limits.
DC-coupled arrangement
In a DC-coupled design, PV and battery connect on the DC side and can share a bidirectional inverter, with DC-to-DC conversion and control equipment managing charging. PV energy can charge the battery before passing through the main inverter, which may capture energy that would otherwise be clipped when PV output exceeds inverter capacity. Fewer shared inverter components and avoiding an additional conversion for some charging paths are potential advantages described in NREL’s first-quarter 2021 cost benchmark.
DC coupling can also require more specialized controls, operating logic, protection coordination, and integration with the PV inverter. The benchmark notes that efficiency differences depend on the equipment and that advances in power electronics have narrowed some historical gaps. Do not treat a coupling label as a guaranteed efficiency or cost result.
| Decision factor | AC coupling | DC coupling |
|---|---|---|
| Basic topology | Separate PV and battery inverters connect on the AC side. | PV and battery connect on the DC side, with shared inverter potential and DC-to-DC controls. |
| Adding storage to existing PV | Often accommodates a standalone battery inverter and AC interconnection equipment. | May require compatible PV inverter, DC collection, controls, and equipment replacement or redesign. |
| Clipped-energy opportunity | Usually requires AC-side charging after PV conversion. | Can capture some PV energy that would otherwise be clipped at the inverter, subject to ratings and controls. |
| Grid charging flexibility | Separate battery inverter can generally be configured for grid charging if the tariff and interconnection permit it. | Grid-charging paths depend on the DC architecture, inverter controls, and approved operating modes. |
| Controls and integration | Separate resources need coordinated plant controls and export management. | Shared conversion can reduce some hardware but adds DC-side integration and control complexity. |
| Efficiency and cost | Depends on the number of conversion steps, equipment ratings, and operating profile. | Potentially fewer conversion steps for selected paths; actual efficiency and cost require project-specific modeling. |
Compare both architectures against the existing PV inverter and warranty, whether the battery must charge from the grid, clipping opportunity, import and export limits, expansion plans, control requirements, service support, and financing structure. Require the engineer and equipment suppliers to document round-trip efficiency by operating path rather than quoting one headline number.
Model battery size, export limits, and operating rules
Start with an hourly or sub-hourly profile of PV production, facility load, tariff periods, and permitted grid exchanges. Test the battery’s usable energy, charge and discharge power, state-of-charge reserve, degradation assumptions, temperature limits, and outage strategy. The same nameplate battery can produce different value depending on whether it cycles for demand management, solar shifting, smoothing, or market dispatch.
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Check whether the POI, transformer, and inverter ratings permit simultaneous PV export and battery discharge. A controller may need to curtail PV, limit battery discharge, or charge from the grid to stay within the approved envelope. Document these rules in the plant controller specification and interconnection application.
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Do not use the 100-megawatt-hour battery paired with PV at the AES Lawai Solar Project in Kauai, Hawaii, as a sizing template. It is a specific DOE project example, not a general recommendation or typical duration.
Build an economics model with local inputs
Co-location can reduce duplicated capital and operating work, but the value must be quantified for the actual design. NREL’s 2021 benchmark identifies potential shared-cost categories; it is useful for understanding architecture, not for quoting present-day prices.
| Cost or value item | What may be shared or affected | What must still be verified |
|---|---|---|
| Land and civil work | Land acquisition or lease, grading, roads, drainage, fencing, and security may serve both systems. | Battery pads, fire lanes, enclosure clearances, geotechnical work, and drainage capacity may add new cost. |
| Electrical equipment | Transformers, switchgear, metering, communications, and substation facilities may be shared if ratings and protection permit. | New breakers, protection relays, bus upgrades, controls, or a larger transformer may be required. |
| Construction and permitting | Mobilization, surveys, engineering coordination, and some permit work can overlap. | Battery-specific fire, building, electrical, environmental, and utility reviews remain. |
| Operations and maintenance | Site staff, access, monitoring, vegetation management, and security may be consolidated. | Battery inspections, augmentation or replacement, software support, warranty conditions, and emergency response need separate allowances. |
| Revenue and savings | Solar energy, demand savings, avoided purchases, capacity value, or market services may complement one another. | Tariffs, export credits, net-metering rules, standby charges, incentives, SREC markets where applicable, and market eligibility determine actual value. |
Use current vendor quotes and local engineering for capital cost, interconnection upgrades, O&M, degradation, replacement, insurance, taxes, financing, and decommissioning. DOE’s PV procurement guidance recommends reviewing tariffs and net-metering policy, incentives, SREC markets where applicable, existing electrical infrastructure, state and utility rules, project-size definitions, standby charges, and project agreements.
PVWatts, the System Advisor Model (SAM), and REopt can help estimate solar production, dispatch, and project economics. They do not replace a site survey, utility study, tariff interpretation, or binding equipment quote.
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There is no single national permit checklist or universal battery setback rule established for every U.S. project. Build an approvals matrix for the exact jurisdiction and technology, then confirm each item with the authority having jurisdiction.
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Authorities and reviews to identify
- Local planning or zoning authority for land use, conditional-use approval, setbacks, visual concerns, and public notices.
- Building and electrical officials for foundations, wiring, grounding, equipment clearances, and code compliance.
- Fire marshal or emergency-management officials for access, detection, suppression, emergency shutdown, labeling, and response plans.
- Environmental reviewers for wetlands, stormwater, habitat, hazardous materials, noise, and other site-specific constraints.
- Historic-preservation authorities where listed properties, districts, or archaeological resources may be affected.
- Utility and transmission-provider engineering teams for studies, protection, metering, telemetry, operating limits, and commissioning.
The 2025 National Renewable Energy Laboratory report on solar-plus-storage permitting describes a process spanning local zoning, state permitting, and federal bottlenecks across commercial-and-industrial, community, and utility-scale projects. Use its findings as context, but obtain the current requirements from the authorities for your site and project size.
A practical planning sequence
- Write the operating brief. Define the loads or market services, target hours, required power, usable energy, reserve level, export and import limits, and whether resilience is included.
- Collect site data. Assemble surveys, parcel and zoning information, geotechnical and flood data, access constraints, environmental records, existing one-line diagrams, equipment ratings, and PV production and load profiles.
- Hold a utility pre-application meeting. Ask the questions listed above and obtain the governing tariff, study path, metering rules, protection requirements, and data format.
- Compare AC and DC layouts. Have the engineer draw both one-line options, including conversion paths, clipping capture, grid charging, export controls, expansion space, and warranty boundaries.
- Run dispatch and financial cases. Model solar shifting, demand management, smoothing, market participation, and outage operation separately. Include losses, degradation, replacement, interconnection upgrades, and tariff changes.
- Create the approvals matrix. Assign an owner and target date to zoning, building, electrical, fire, environmental, historic, utility, and market approvals. Record the code edition and tariff version used.
- Specify safety and controls. Define emergency access, shutdown logic, detection and suppression interfaces, communications, cybersecurity responsibilities, operating envelopes, and coordination with first responders.
- Procure and commission in stages. Require vendor drawings, protection studies, factory and site acceptance tests, controller demonstrations, metering validation, and utility witness testing before commercial operation.
Common planning failures and how to correct them
| Failure mode | Why it happens | Corrective action |
|---|---|---|
| Assuming co-location guarantees approval | The project treats a shared parcel as a substitute for an interconnection study. | Confirm the POI, tariff, study process, protection, metering, and upgrade responsibility with the utility before final design. |
| Choosing a battery by energy capacity alone | The owner specifies a desired number of hours without defining peak power or dispatch speed. | State both usable energy and power requirements for each service, then test reserve and degradation assumptions. |
| Calling grid-connected storage backup power | Islanded operation, critical-load wiring, and reconnection controls were never designed. | Define critical loads and outage duration, then engineer islanding, protection, controls, and utility permissions explicitly. |
| Using an old cost benchmark as a quote | A historical architecture study is treated as a current market price. | Use the NREL 2021 benchmark for structural comparisons only and replace every price with current quotes and local engineering. |
| Ignoring charging and export interactions | PV, battery, and load are modeled independently even though they share a POI. | Simulate simultaneous PV export, battery charging, battery discharge, curtailment, and grid imports under the approved limits. |
| Leaving fire and access review until late design | The layout reserves every available area for modules and containers. | Place emergency access, equipment clearances, drainage, and responder requirements on the first site plan. |
| Assuming all shared equipment is interchangeable | Existing PV warranties, inverter controls, protection settings, or transformer ratings are overlooked. | Obtain compatibility statements, updated one-lines, protection studies, and warranty confirmations before selecting the coupling scheme. |
Documents and checklists to use
Use the U.S. Department of Energy Federal Energy Management Program’s Distributed Energy Interconnection Checklist as a question-by-question discussion aid with the utility. It was published September 7, 2021. DOE also provides a separate battery procurement checklist for early BESS planning. Verify the current version and confirm which questions apply to your utility, jurisdiction, and project scale.
Maintain a controlled document set containing the site plan, electrical one-line, equipment data sheets, protection and controls narrative, tariff and interconnection correspondence, dispatch model, financial assumptions, permit matrix, emergency-response plan, and commissioning test records. Version-control these documents so that the utility, authorities, lenders, owner, and integrator are reviewing the same design.
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Proceed when the battery’s operating purpose is explicit, the site can accommodate safe construction and maintenance, the utility has identified a feasible interconnection path, and the economics remain viable after upgrades, tariffs, losses, degradation, and replacement are included. Choose AC or DC coupling only after comparing the existing PV assets, clipping opportunity, charging flexibility, controls, warranties, expansion plan, and total installed cost.
Pause or redesign if the shared POI cannot support the proposed export and charging behavior, required fire access does not fit, approvals conflict with the site layout, or the value case depends on an incentive or market rule that has not been confirmed. A disciplined co-location plan is a coordinated electrical, civil, regulatory, safety, and financial project—not simply a solar array with containers placed beside it.
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