Solar + Storage Design Guide: How to Size and Design Battery-Backed Solar Systems

Storage has moved from an optional upsell to a core part of solar design. In California, the net billing tariff makes a battery almost mandatory for acceptable project economics. Across the rest of the US, time-of-use rates and falling export compensation are pushing the same direction.

The residential Investment Tax Credit under Section 25D expired on December 31, 2025. Homeowner economics now stand on bill savings and resilience, not a 30% federal credit. That makes correct sizing and honest payback math more important, not less.

We wrote this solar storage design guide for installers and EPCs who design battery-backed systems every week. It covers architecture, sizing, backup panels, code, inverters, modeling, and economics — the same workflow we use on real projects.

This guide assumes grid-tied residential and light commercial projects, which is where most storage volume sits. Off-grid systems share the same math but change the targets. Where the two diverge, we say so.

In this guide:

• Why storage design is now a core installer skill in 2026
• AC vs DC coupling tradeoffs, with a decision framework
• Battery sizing math with a worked residential example
• Backup load panel design and transfer equipment
• NEC 706 and 705 compliance essentials for energy storage
• Inverter selection for hybrid new builds and AC-coupled retrofits
• Production and consumption modeling with interval data
• Storage economics — including when a battery does not pay
• 7 common storage design mistakes and how to avoid them

Why Solar + Storage Design Matters in 2026

US battery storage installations reached a record 12.3 GW in 2024, up roughly a third from the prior year, per the SEIA and Wood Mackenzie U.S. Solar Market Insight report. Residential storage grew alongside grid-scale projects. Attach rates on new residential systems keep climbing in every major market.

Policy is the biggest driver. California’s NEM 3.0, formally the net billing tariff from the CPUC, cut average export compensation by roughly 75% compared with retail rates. A solar-only system now exports midday energy for a few cents per kWh. A battery shifts that same energy to evening use at full retail value.

The second driver is the expired tax credit. The residential ITC under Section 25D ended on December 31, 2025. There is no 30% homeowner credit to soften the price of a battery anymore. Project value must come from self-consumption, peak shaving, and backup capability.

The third driver is resilience. Outage frequency keeps rising in several US regions, and homeowners now ask for backup by name. A battery is no longer a bill-savings device alone. It is also a reliability product, and it gets sold that way.

In California, the shift is already visible in attach rates. Industry trackers put storage attachment on new residential systems well above half under the net billing tariff. The rest of the country sits lower, but the direction is identical.

Outage data backs the resilience case. US electricity customers averaged just over 7 hours of interruptions in 2020, per EIA reliability data, with major storms pushing regional figures far higher. Customers remember those hours when they compare quotes.

The trend extends well beyond California. Utilities in Arizona, Colorado, and the Northeast keep cutting export rates and widening time-of-use spreads. Every rate redesign moves value from exporting energy to storing it.

International markets show the same pattern at a more mature stage. In Germany and Australia, where feed-in tariffs fell years ago, most new residential systems now ship with batteries. The US market is following that curve with a delay.

Financing partners have noticed. Lenders and lease providers increasingly model storage in their default cash flows. A design that cannot justify its battery in plain numbers will struggle to get funded.

For installers, this changes the job profile. Storage projects carry larger tickets and better margins than solar-only work. They also carry more design risk — a mis-sized battery or a rejected permit plan set can erase the margin on an otherwise clean install.

Customers have changed as well. Homeowners now arrive with outage stories and neighbor referrals. Commercial clients arrive with demand charge printouts. Both expect a designed answer, not a catalog page.

Good storage design is a repeatable process, not a talent. You audit loads, pick an architecture, size energy and power, design the backup panel, check code clearances, and model the economics. The right solar design software makes each step faster, but the process itself is what protects your margin.

If you are building out a storage offering, start with our /for-solar-installers page and the /glossary/battery-storage reference. Then work through the sections below in order. Each one maps to a decision you will make on your next storage quote.

AC vs DC Coupling: Which Architecture to Choose

Every battery-backed system stores DC energy and serves AC loads. The design question is where the battery connects. AC coupling places a battery with its own inverter on the AC side of the system. DC coupling connects the battery to the DC bus of a hybrid inverter that also serves the PV array.

The difference comes down to conversion count. In a DC-coupled system, PV energy passes through 1 inversion before reaching the home or the battery. In an AC-coupled system, PV energy is inverted to AC, rectified back to DC for storage, then inverted again for use. Each conversion costs efficiency.

That extra conversion shows up in round-trip efficiency (RTE). DC-coupled systems typically achieve 95–98%. AC-coupled systems typically land at 90–94%, according to EnergySage’s storage comparison data. Over a 10-year life, the gap is real but rarely decisive on its own.

Retrofits flip the math. An AC-coupled battery connects without touching the existing PV inverter or array wiring. It works with string inverters and microinverters alike. For the installed base of grid-tied systems, AC coupling is usually the only sensible option.

New builds tilt the other way. DC coupling means 1 inverter instead of 2, which cuts hardware cost, wall space, and conduit runs. It also captures clipped energy on high DC-to-AC ratio designs, which an AC-coupled system would lose. For most ground-up residential projects, DC coupling is the cleaner design.

Our rule of thumb is simple. Retrofit — AC couple. New build with a single inverter location — DC couple. New build with microinverters already specified — AC couple. The architecture should follow the project, not the other way around.

Outage behavior deserves a closer look. An AC-coupled battery must island the existing PV inverter and manage its output through frequency shifting. That coordination is proven, but it adds a control dependency that a hybrid system handles natively on the DC bus.

DC coupling also gives you more room on array sizing. Because clipped energy can flow straight into the battery, you can push the DC-to-AC ratio harder without wasting production. On tight roofs where every module counts, that flexibility has real value.

Service and monitoring differ as well. A hybrid system reports PV and battery through 1 app and 1 support channel. An AC-coupled system splits that across 2 manufacturers, which matters on year 7 when the homeowner calls you first.

AC coupling also scales cleanly for whole-home retrofits. Because the battery inverter is independent, you can stack units over time as the budget allows. Many homeowners start with 1 battery for critical loads and add a second unit a year later.

One more tradeoff rarely mentioned in spec sheets: fault isolation. With 2 inverters, a battery failure does not take down PV production, and vice versa. With a hybrid unit, 1 failure can idle the whole system until the replacement arrives. For a deeper technical walkthrough, read our AC vs DC coupled storage comparison.

Battery Sizing: Critical Loads, Autonomy, and Daily Usage

Battery sizing starts with 3 numbers: critical load energy per day, desired autonomy, and system losses. Get those right and the capacity picks itself. Get them wrong and no inverter setting will save the design.

The core formula is:

Usable capacity (kWh) = Daily critical loads (kWh) × Autonomy (days) ÷ (Depth of discharge × Round-trip efficiency)

Work through it in 6 steps:

1. Audit the critical loads with the homeowner. List every circuit the battery must serve during an outage.
2. Convert each load to daily energy. Running watts multiplied by realistic hours per day gives Wh per day.
3. Choose an autonomy target. One day is typical for grid-tied backup; 2–3 days suits outage-prone regions.
4. Adjust for depth of discharge (DoD) and round-trip efficiency. LFP batteries typically allow 90–100% DoD.
5. Check power, not just energy. The inverter’s continuous kW rating must exceed the largest coincident load.
6. Check surge. Motors draw 3–5× their running watts for the first seconds after start.

Here is a worked audit for a typical US home on partial backup:

Apply the formula. A 1-day autonomy target with a 90% DoD battery at 95% RTE gives 6.0 ÷ (0.90 × 0.95) = 7.0 kWh of nameplate capacity. A single 13.5 kWh unit covers this home with margin for degradation and cloudy stretches.

Now the power check. The coincident running load is about 2.9 kW if the blower, well pump, and refrigerator overlap. The battery inverter must exceed that continuously. It must also start the well pump, which can pull 3.6–6 kW for a moment.

Most residential batteries cluster around a few standard sizes. Use this table as a first-pass filter:

Most homes need 10–20 kWh for partial backup and 20–40 kWh for whole-home backup. Off-grid designs are a different problem entirely. They often need 2–3 days of autonomy plus generator support, which pushes capacity far higher.

Do not forget the recharge side. The PV array must serve daytime loads and refill the battery on a typical day. A useful rule: daily PV production should exceed daily consumption plus planned battery charging. A 10 kW array producing 40 kWh per day can refill a 20 kWh battery in most climates.

A whole-home example shows how fast the numbers scale. Take a home using 30 kWh per day with 18 kWh of overnight and outage-critical consumption. At 1 day of autonomy, 90% DoD, and 95% RTE, the nameplate requirement is 18 ÷ 0.855 = 21 kWh. That points to a 27 kWh stack, with power ratings checked against the coincident load as before.

Stretch the same home to 2 days of autonomy and the requirement doubles to 42 kWh nameplate. That is 3 stacked 13.5 kWh units, or a different product class entirely. Autonomy is the cheapest number to change and the most expensive to underestimate.

Battery chemistry belongs in the sizing conversation, too. LFP packs tolerate deeper daily discharge and higher cycle counts, which supports using the full nameplate figure in the formula. NMC packs often carry lower recommended DoD, so the same nominal size delivers less usable energy per day.

Seasonal drift is the last check. Winter production can fall 30–50% below summer output in northern climates. If the design depends on daily recharging in December, verify it against winter-specific yield, not the annual average.

From the field: most undersizing failures we see are power failures, not energy failures. The battery had enough kWh. It could not start the air conditioner. Always run the surge check before you run the payback check.

Backup Load Panel Design and Transfer Equipment

The critical loads panel is where backup design becomes physical. You move the circuits the battery will serve into a dedicated subpanel. Everything else stays on the main panel and goes dark during an outage.

Partial backup is the cheapest clean design. A 60–125 A subpanel feeds refrigeration, lighting, a furnace blower, and a few convenience circuits. One battery handles it in most homes, and the install stays simple.

Whole-home backup is a power problem, not an energy problem. A 200 A service can draw 48 kW at the bus. No residential battery stack covers that continuously. Realistic whole-home designs pair 2–3 batteries with smart load management that sheds the air conditioner, water heater, and EV charger when the battery runs low.

Transfer equipment isolates the home from the grid during an outage. Modern battery systems use an integrated gateway or an automatic transfer switch (ATS) rated for the backed-up load. NEC Article 702 covers these optional standby systems. Grid isolation must be positive and listed — a generator-style manual interlock is not a substitute for a listed transfer device.

Meter-main combination services complicate the layout. When the meter and main breaker share 1 enclosure, the transfer device usually goes between that unit and a new backed-up panel. Plan the physical stack-up on the wall before quoting, not during rough-in.

Generator pairing is the other common request. Most modern battery systems accept a generator input or coexist with one on a separate transfer switch. Confirm the exact topology with the battery manufacturer — 3 wrong topologies exist for every right 1.

A smart electrical panel can replace the subpanel entirely. It gives per-circuit control, monitoring, and automated load shedding. The tradeoffs are cost, a longer install day, and a homeowner app that someone has to explain.

Load selection deserves a real conversation, not a checkbox. Ask the homeowner what they actually need during an 8-hour outage. Most pick the refrigerator, some lights, the furnace blower, and Wi-Fi. Almost none pick the second freezer in the garage — until the first outage.

Panel placement affects cost more than most quotes admit. Every circuit moved to the critical loads panel needs its conductors rerouted or spliced. A subpanel placed beside the main panel keeps those runs short; a battery location 2 floors away turns the same job into a day of fishing wire.

Commissioning closes the loop. Before you leave, simulate an outage with the homeowner watching. Confirm the transfer happens in the specified time, the critical circuits stay live, and the large loads shed in the right order.

Keep 1 spare breaker space in the critical loads panel. Homeowners add loads, and a full panel turns a 30-minute circuit addition into a panel replacement. Future-proofing costs almost nothing at install time.

Field note: label every circuit in the critical loads panel with its backed-up status and measured draw. The next service call goes faster. The homeowner also stops plugging a space heater into the backed-up bedroom circuit.

NEC 706 and 705 Compliance for Energy Storage

NEC Article 706 governs energy storage systems of every chemistry and size. It sits alongside Article 690 for PV and Article 705 for interconnection. Storage plan sets fail review most often on 3 items: disconnects, signage, and working space.

The article requires a listed disconnecting means within sight of the equipment, per Section 706.15. It requires overcurrent protection matched to the listing. It also requires a permanent directory identifying every power source on the premises, and working space per Article 110.

Equipment listing is the foundation. UL 9540 is the listing standard for complete energy storage systems. UL 9540A is the test method that produces thermal runaway propagation data. AHJs increasingly ask for 9540A reports during plan review, so collect them before you submit.

NFPA 855 adds installation rules on top of the NEC. For residential lithium-ion systems, individual units are limited to 20 kWh each. Aggregate capacity per location is limited to 40 kWh, with at least 3 ft of separation between units. Garages need vehicle impact protection, and several locations — sleeping rooms among them — are off-limits.

NEC Article 705 covers the interconnection side. Load-side connections under Section 705.12 must respect busbar limits — the familiar 120% rule on dwelling panels. A battery and a PV inverter sharing 1 panel can exceed that allowance fast.

A power control system (PCS) under Section 705.13 offers a way out. A listed PCS monitors currents and caps backfeed, which allows a larger PV-plus-storage system on an existing service. It is often the difference between a clean permit and a service upgrade.

A concrete busbar example shows why this matters. On a 200 A panel with a 200 A main breaker, the 120% rule leaves 40 A of headroom for all load-side power sources combined. A 60 A battery breaker plus a 40 A PV breaker does not fit — a PCS or a supply-side tap becomes the answer.

PV rapid shutdown under Section 690.12 still applies with storage attached. The battery must not keep array conductors energized beyond the shutdown boundary. Coordinate the ESS shutdown scheme with the PV rapid shutdown initiator during design, not on the roof.

Code editions vary by jurisdiction. One AHJ works from NEC 2020, the next county from NEC 2023, and the utility adds its own interconnection handbook on top. Check which edition applies before you draw the single-line diagram.

The utility side adds a second layer. Many utilities require an updated interconnection agreement when storage joins an existing PV system, even if nothing about the array changes. Some also require export control settings or a non-export relay for systems above a size threshold.

Commercial storage raises the stakes further. Larger systems trigger NFPA 855 provisions for fire department access, signage, and sometimes dedicated ESS rooms. Budget the permitting timeline accordingly — C&I storage reviews routinely take twice as long as residential ones.

Signage is cheap and frequently wrong. The directory must identify every power source, its location, and its disconnect. Print it, laminate it, and mount it where the inspector stands, not where it fits aesthetically.

From the field: call the AHJ before design freeze on any storage project. A 10-minute call about placement and clearances has saved us more redesigns than any checklist. Both the NFPA 70 (NEC) and NFPA 855 standards are free to read online — use them.

Inverter Selection: Hybrid vs AC-Coupled Retrofits

The inverter decision follows the architecture decision. A hybrid inverter serves the PV array and the battery from 1 chassis in a DC-coupled design. An AC-coupled battery brings its own inverter and leaves the existing PV inverter alone.

Read 3 ratings on every datasheet, not 1. The grid-tied rating sets normal operation. The backup port rating sets what the unit can serve while islanded — often well below the grid-tied number. The surge rating sets what it can start.

Oversizing the battery and undersizing the inverter is the classic rookie error. A 27 kWh battery behind a 5 kW inverter serves lights and a refrigerator. It will not serve a cooktop and a well pump at dinner time.

For retrofits, confirm compatibility with the existing PV inverter before quoting. Most AC-coupled batteries island the PV inverter and manage its output through frequency shifting. That coordination works with most string inverters and microinverters, but verify the pairing on the battery manufacturer’s compatibility list.

On new builds, compare the hybrid unit’s backup port rating against the critical loads sum before price enters the conversation. The cheapest hybrid inverter often has the weakest islanded output. That gap only shows up during the first outage — on your warranty ticket.

Frequency-shift control deserves a compatibility check of its own. When the battery is full during an outage, the AC-coupled battery raises grid frequency to curtail the PV inverter. Most modern inverters ride through this gracefully, but older units can trip offline and stay there.

Three-phase service changes the selection entirely, mainly on C&I projects. Many residential-class batteries are single-phase only, and mixing them onto a 3-phase service creates imbalance problems. Confirm phase configuration before shortlisting equipment.

Firmware matters more than brochures admit. Backup behavior, surge response, and generator coordination all live in software. Check the manufacturer’s release history — a unit with active firmware support ages far better than one abandoned after launch.

Warranty length tracks architecture, too. Hybrid inverters typically carry 10-year warranties with paid extensions, while integrated AC-coupled batteries often bundle 10–15 years. Match warranty terms across the stack so 1 component does not become the weak link in year 11.

One spec worth asking about directly: pass-through current. Some gateways limit the backed-up panel to 60 A even when the inverter can supply more. Match the transfer equipment rating to the design, or the bottleneck moves to a box you already sold.

Production and Consumption Modeling for Storage

Monthly kWh averages hide the information that sizes batteries. A home using 30 kWh per day with a flat profile needs a different battery than the same home with a 6 kW evening peak. Use interval data — 15-minute or hourly — whenever you can get it.

A useful storage model outputs 4 curves: PV production, household consumption, battery state of charge, and grid import/export. From those curves you get self-consumption rate, cycles per year, and export volume. Those 3 numbers drive the economics.

If you want help interpreting a tariff sheet or a modeling result, Clara AI can walk through the logic step by step. It reads the same project data your design uses, so the answers stay grounded in the actual system.

We model this in SurgePV. Our solar shadow analysis software produces the hour-by-hour production profile for the actual roof, accounting for shading losses across the year. The /generation-financial-tool layers the load profile and rate tariff on top, then computes self-consumption, savings, and payback with and without storage.

Tariff structure drives the cycling strategy. On time-of-use rates, the battery discharges through the evening peak — typically 4–9 PM — and recharges from midday solar. On flat rates with low export compensation, it simply absorbs surplus production for evening use.

Under California’s net billing tariff, export timing matters as much as export volume. Avoided-cost rates change by hour and by month. A model that assumes flat export prices will misstate storage savings by a wide margin in either direction.

Rate escalation assumptions matter just as much. A 3% annual utility escalation versus a flat rate changes the 20-year savings figure by tens of thousands of dollars. Document your escalation assumption in every proposal — it is the number competitors inflate.

Include degradation in the model. A battery cycling daily will lose roughly 10–15% of usable capacity over 10 years, within its warranty terms. Model year 1 and year 10 side by side. If the design only works at year-1 capacity, it does not work.

Getting interval data is easier than it used to be. Most US utilities offer Green Button downloads from the customer portal, and many smart meters expose 15-minute data. Ask for 12 months — a single summer bill can mislead the whole design.

When real data does not exist, synthesize the profile from known anchors. Start with the monthly kWh from bills, then apply a load shape matched to the home type: EV charging overnight, cooking peaks in the evening, cooling peaks in the afternoon. Flag the model as estimated in the proposal so everyone knows its limits.

Cycle-throughput warranties also belong in the model. Many batteries warrant energy throughput alongside years and cycles. A design that cycles aggressively twice a day can hit the throughput cap before the calendar limit, which changes the real warranty end date.

From the field: on a recent 8 kW project, monthly-average modeling said a 13.5 kWh battery was enough. Interval data showed a sharp evening peak that needed 18 kWh to cover. We sized to the data — no callback and no awkward second battery sale a year later.

Economic Analysis: When Storage Pays and When It Doesn’t

Here is the part most storage marketing skips. A battery is not automatically a good investment. Standalone battery payback often runs 10–20 years, which sits at or beyond the warranty period. Pairing with solar shortens it, and market conditions decide the rest.

Storage pays fastest under 4 conditions. California’s net billing tariff, where exports are worth roughly 75% less than retail energy. Time-of-use rates with spreads of $0.20 per kWh or more. C&I tariffs with meaningful demand charges. And outage-prone grids where resilience carries real dollar value for the customer.

Storage pays slowest where the grid already acts like a free battery. In markets with 1:1 retail /glossary/net-metering, exported energy comes back at full value, so a battery saves little on the bill. Flat low rates and rare outages weaken the case further.

The expired residential ITC changed the math honestly. With Section 25D gone since December 31, 2025, homeowners cannot count a 30% credit in payback projections. Commercial projects may still qualify under Section 48E, subject to construction-start deadlines — confirm current eligibility with a tax professional. Model every residential case without any federal credit.

Under California’s net billing tariff, the no-credit math still favors storage, because the export-versus-retail spread does the work. In flat-rate net metering states, the same math often says wait. That regional split is the single most important economic fact in storage design right now.

On cost: installed residential storage runs roughly $1,000–$1,500 per kWh, per EnergySage marketplace data. A 13.5 kWh unit lands around $15,000–$18,000 installed as a standalone job. Adding the same battery to a new solar install costs less because labor, permitting, and truck rolls are shared.

These are directional ranges, not quotes. Rate structures, usage patterns, and installed cost move every project. The discipline that matters: present the with-and-without-storage cases side by side and let the customer see both.

Our solar proposal software shows exactly that comparison in the customer-facing proposal, which builds more trust than a single optimistic payback line. For full installed-cost context, see /blog/solar-installation-cost-breakdown and our battery payback guide.

Levelized cost of storage is the cleaner metric for skeptical customers. Divide total installed cost by lifetime discharged energy. At $1,200 per kWh installed and 4,000 full cycles, a battery delivers energy at roughly $0.30 per kWh — which beats peak TOU rates in some markets and loses badly in others.

C&I projects stack value differently. A commercial battery can shave demand charges, arbitrage energy prices, and provide backup in the same day. That stacking is why commercial storage paybacks often land at half the residential figure.

Financing changes the customer’s math more than any tariff. A battery rolled into a 25-year solar loan costs less per month but more in total interest. Show both the cash price and the financed payment, and let the customer pick the honest tradeoff.

Watch the dealer fee on financed storage. Fees of 10–20% on the loan amount are common, and they belong in the customer’s cost comparison — not in the fine print.

One honest note on resilience value: it is real, but it is not a spreadsheet number. Some customers will pay for backup the way they pay for insurance. Others will not. Offer the option, price it correctly, and never pad the bill-savings case to sell it.

Common Storage Design Mistakes

We review a lot of storage designs, and the same errors keep appearing. None of them are exotic. All of them are avoidable at the design stage.

1. Sizing on energy and ignoring power. A 13.5 kWh battery with a 5 kW inverter cannot start a 4-ton air conditioner. Check continuous and surge ratings against coincident loads before anything else.

2. Promising whole-home backup with 1 battery. One unit backs up a critical loads panel well. Whole-home coverage needs 2–3 units plus load management, and the proposal should say so.

3. Ignoring PV recharge capacity. A battery paired with an undersized array sits empty through winter. Verify that daily production exceeds daily consumption plus planned charging.

4. Defaulting to 1 architecture. AC coupling on every new build wastes the customer’s money. DC coupling on every retrofit wastes more. Match the architecture to the project in front of you.

5. Treating code clearances as an install-day problem. NFPA 855 spacing and location rules decide where batteries can physically go. Solve placement in design — not on the wall with the inspector watching.

6. Modeling on monthly averages. Averages hide peaks, and peaks size the equipment. Interval data costs almost nothing to obtain and prevents the most expensive sizing errors.

7. Forgetting degradation. Design for year-10 capacity, not day-1 capacity. The warranty already expects fade, and so should your autonomy calculation.

The pattern across all 7: storage punishes assumptions. Every mistake on this list is a number someone did not measure or a rating someone did not read. The fix is process, not talent.

Our internal checklist catches these before the quote goes out. It has 12 items, takes about 10 minutes, and has paid for itself many times over. Build your own version and require it on every storage design — no exceptions for experienced designers.

Conclusion

Storage design is now a core installer skill, and the market rewards the teams that treat it as a process. Match the architecture to the project. Size energy and power separately. Design the backup panel before you price the job.

The market will keep moving in this direction. Export rates are falling, rate structures are getting more complex, and customers are asking for backup by name. Installers who master storage design now will own the next 5 years of residential and C&I work.

None of this requires new hardware or exotic tools. It requires discipline: measure the loads, respect the code, model the real tariff. The teams that do those 3 things will out-sell and out-last the teams still quoting batteries from a brochure.

Code compliance belongs in the design phase, too. NEC 706, NFPA 855, and Article 705 decide placement, disconnects, and interconnection limits. A 10-minute AHJ call before design freeze is the cheapest insurance on the project.

Model the economics honestly. Interval data, real tariffs, and year-10 degradation produce payback numbers that survive the first utility bill. That honesty is what turns a storage customer into a referral source.

Storage done well is also the best marketing you can buy. A battery that performs exactly as promised generates referrals for years, and a battery that underperforms generates the opposite. Design is where that outcome gets decided.

Your action items from this guide:

• Audit critical loads with interval data before quoting any battery.
• Match the coupling architecture to the project — AC for retrofits, DC for most new builds.
• Design to NEC 706, NFPA 855, and Article 705 from day 1, and call the AHJ early.

We build solar software for exactly this workflow — design, shadow analysis, financial modeling, and proposals in 1 platform. If storage is becoming your core offering, the design process above is where the margin lives.

Frequently Asked Questions

What is the difference between AC and DC coupled solar storage?

AC-coupled systems use a separate battery inverter and are easier to retrofit. DC-coupled systems connect the battery to the solar inverter’s DC bus and are slightly more efficient. AC coupling is more flexible for existing systems; DC coupling is better for new installations.

How do you size a solar battery?

Size the battery by matching critical backup loads, desired autonomy hours, and daily energy usage. Most residential systems need 10–20 kWh for partial backup and 20–40 kWh for whole-home backup.

What is NEC 706 in solar storage?

NEC Article 706 covers energy storage systems. It requires proper disconnects, overcurrent protection, signage, and working space around battery equipment. It also addresses rapid shutdown and emergency power system integration.

Can any solar system be retrofitted with a battery?

Most grid-tied systems can be retrofitted with AC-coupled batteries. DC coupling usually requires a hybrid inverter replacement. Retrofits add cost but can be done without replacing the solar array.

How long does a solar battery last?

Most lithium-ion solar batteries are warranted for 10–15 years or 4,000–6,000 cycles. Actual lifespan depends on depth of discharge, temperature, and usage patterns.

Is battery storage worth it with net metering?

In markets with full retail net metering, batteries often lengthen payback. In markets with low export rates or time-of-use pricing, batteries improve self-consumption and can shorten payback.