Solar Design Studio — Model & Methodology

Methodology as of July 17, 2026. This document describes every model, data source, and default assumption behind the numbers the Design Studio shows you. We publish it because our core belief is that transparency is knowledge, and knowledge is power: you should never have to take an energy model's word for anything. Everything below is an informational estimate, not an engineering design or an installation quote.

1. Roof model & solar resource

When you enter an address, we request the building's 3-D roof model and solar irradiance data from the Google Solar API (buildingInsights and dataLayers endpoints). Google derives roof geometry from high-resolution aerial imagery and computes an annual flux map — the solar energy each point of the roof receives, in kWh per kW of installed capacity per year — that accounts for roof pitch, azimuth, and shading from trees, chimneys, and neighboring structures. Panel positions come from Google's per-panel layout, and when you size the system with the slider, panels are added in descending order of their individual shading-aware annual output.

Honesty note: these are theoretical-maximum placements from aerial imagery. They do not model fire-access setbacks, vents, or structural obstructions — a final engineered layout after a site survey may fit fewer panels (we repeat this caveat in every proposal we generate).

2. Energy production simulation

Annual and monthly AC production is simulated with PVWatts® v8 from the National Laboratory of the Rockies (formerly NREL), using each roof segment's actual tilt and azimuth and PVWatts' standard ~14% system-loss assumption (soiling, wiring, inverter conversion, availability — see the PVWatts technical reference). The shading-aware DC estimate from the flux map is reconciled with the PVWatts simulation so both the heatmap and the financial model describe the same system. If PVWatts is unreachable, we fall back to the flux-derived DC estimate derated by a standard 0.85 DC→AC factor and label the result accordingly in the UI.

3. Household load profiles

Hourly household consumption uses the NLR ResStock 2025.1 dataset (End-Use Load Profiles for the U.S. Building Stock, calibrated AMY-2018 simulations, distributed through the DOE Open Energy Data Initiative). For each of 49 states we reduce the state-level aggregate for single-family detached homes (the building class that hosts nearly all residential rooftop solar) to normalized month-by-hour load shapes, kept separately for weekdays and weekends, then scale the shape to your annual kWh. ResStock's published timeseries use Eastern Standard Time for every state; we shift each state to its local standard time before use so load, solar, and time-of-use rate windows line up. Alaska and Hawaii (absent from the state aggregates) fall back to a building-stock-weighted national average. The UI always cites which shape is in use (e.g., "NLR ResStock (CA single-family homes)").

Your actual meter data will differ from a state-typical shape. When your utility bill shows annual kWh, enter it directly — the studio warns you when a bill-derived estimate looks implausibly low, because an understated load makes batteries look worthless (there is no nighttime load to shift into) and an overstated one exaggerates savings.

4. Utility rates & tariffs

Rate prefills follow a hierarchy. Where we can identify your serving utility (one cached lookup against the NLR Utility Rates API), we use that utility's standard residential rate from our snapshot of the DOE/OpenEI Utility Rate Database (URDB) — the bulk download of utility-submitted tariffs, filtered to active residential rates. Because URDB's "default" flag is sparsely populated, we select each utility's representative rate by name scoring (preferring standard residential service, excluding EV/senior/low-income/closed riders). We also identify each utility's best opt-in time-of-use candidate — the active residential TOU rate with the largest defensible peak/off-peak spread — including its full 12-month × 24-hour weekday and weekend schedule grids. Where no utility match exists, we prefill the state residential average from the EIA's Electric Power Monthly, Table 5.6.A. Every prefiled rate shows its source and as-of date in the UI, and you can override any of them.

5. Whole-bill hourly valuation

Solar savings are not computed as generation × a flat rate. We simulate all 8,760 hours of a year: your load shape (§3) against your solar production shape, valued under your tariff's hourly rate grid (§4). Self-consumed energy is credited at the rate in effect that hour; exports are credited at your export-credit ratio × that hour's rate. This matters most under net-billing regimes like California's NEM 3.0 (CPUC D.22-12-056), where midday exports earn far less than retail — a flat model flatters solar-only systems and unfairly punishes batteries. Export-credit defaults per state are derived from the net-metering policy summaries in the DSIRE database (§9) — for example ~25% of retail for California net billing, 75% for Nevada — and are shown, sourced, and editable in the Advanced panel. Both the solar-only and solar-plus-battery cases run through the same hourly engine, so comparisons between them are apples-to-apples.

6. Battery storage modeling

Battery choices are limited to a discrete catalog of real, UL 9540-listed residential systems shipping in 2026 (Enphase IQ Battery 5P, Tesla Powerwall 3 and expansion, FranklinWH aPower 2), priced at typical installed market prices before incentives (the residential market spans roughly $850–$1,700 per usable kWh installed; each catalog entry carries its own price note). We deliberately do not offer a continuous "battery size" slider — you can only buy hardware that exists.

Battery bill value is computed by a deterministic daily-cycling dispatch simulation: charge from solar surplus, discharge into the highest-priced hours in which the home needs grid power, at 92% round-trip efficiency (typical for LFP AC-coupled systems) and 330 equivalent full cycles per year. Value is capped by physics — a battery cannot shift more than your overnight load actually absorbs. The "typical day" operation chart uses a companion chronological self-consumption simulation (state of charge carries across midnight, as shipped residential batteries behave in self-powered mode). Capacity fade is modeled at 2%/yr (consistent with LFP warranties guaranteeing ~70% at 10 years), with one replacement at year 16 costed at 60% of today's installed price.

Accuracy honesty: for flat-rate homes this heuristic lands within roughly ±10–15% of a full optimization; under time-of-use rates the spread can be ±30–60% for demand-charge-like situations. We surface both a current-rate and an opt-in TOU valuation when your utility files a TOU tariff, and we only advertise "TOU upside" when the modeled TOU value meaningfully exceeds the flat value. A full optimizer (NLR REopt) is integrated but dormant: this is an exploratory tool, and REopt's job latency and API quotas are not compatible with an interactive slider. If we ever produce quotable dispatch numbers, they will come from it.

7. Ownership financial model (cash / loan)

The cash and loan models compute year-by-year cash flows over your analysis horizon: hourly-valued bill savings (§5) escalated by your utility-inflation assumption and degraded by panel degradation (default 0.5%/yr, per typical module warranties), minus O&M, plus SRECs where you enter them, discounted at your chosen rate (default 5%) for NPV, with IRR, payback, and LCOE reported alongside. Loan mode adds amortized payments at your APR/term/down-payment.

Cost defaults are benchmarks, not quotes: the installed-cost prefill is the DOE Photovoltaics & Storage Cost Benchmark's Q1-2025 modeled minimum sustainable price for residential PV (~$2.95/W national; see PVSCB data), adjusted per state by scaling its ~41% labor share with Bureau of Labor Statistics mean electrician wages (OES 47-2111). For context we also display the market median from Lawrence Berkeley National Laboratory's Tracking the Sun (2025 release, 2023–24 host-owned installs). Both figures and their sources appear next to the input.

Federal credit status: the Section 25D residential clean-energy credit expired for expenditures after December 31, 2025. The studio's federal-credit default is therefore 0% for purchased systems; third-party-owned systems can still monetize the commercial Section 48E credit (§8). We would rather show you a smaller, correct number.

8. Third-party ownership (lease / PPA) — the dual-ledger model

The lease/PPA engine computes both sides of the transaction from identical inputs and lets you flip between them: the homeowner ledger (contract payments vs. hourly-valued bill offset) and the asset-owner ledger (the fund's actual economics). We built it this way because TPO customers are routinely told the corporate math "doesn't concern them." It does: the fund on your roof monetizes tax benefits you sign away.

• Consumer contract defaults: 2026 residential PPA rates typically run 15–21¢/kWh, pitched 10–30% below the local utility rate, with compounding annual escalators of 0–3.99% (2.9% is the market mode) — see Solar.com's PPA rate guide. Our defaults: 85% of your utility rate, 2.9% escalator, $55/mo battery add-on (or a +4¢/kWh hybrid uplift), all editable.
• Section 48E ITC: fund-owned residential systems claim the tech-neutral commercial credit (26 U.S.C. §48E): 30% base for systems under 1 MWac (exempt from prevailing-wage requirements), stackable with +10% domestic-content, +10% energy-community, and +10% low-income-community adders — the last is a capacity-capped allocation program, not an entitlement, and the UI labels it as such.
• FMV step-up: the fund's credit basis is an appraised fair market value, not the build cost — market-standard multipliers run ~1.1–1.35× (default 1.25×). Aggressive step-ups have drawn IRS challenge; see SEIA's cost-basis guidance and the Treasury's 1603 cost-basis evaluation memo.
• MACRS: 5-year accelerated depreciation (200% declining balance, half-year convention: 20 / 32 / 19.2 / 11.52 / 11.52 / 5.76%) per IRS Publication 946, on a basis reduced by half the ITC claimed (26 U.S.C. §50(c)), at the 21% federal corporate rate.
• Buy rate & margin spread: we solve for the minimum customer rate at which the fund's NPV is zero at its target discount (default 7%, the typical unlevered return for residential portfolios in appraisal DCF practice — see tax-equity structure overviews). Everything between that "buy rate" and your quoted rate is margin available for dealer fees and commissions — and we display it, because knowing the floor is negotiating leverage.
• Consumer protections modeled: lease production guarantees (default: 90% of modeled year-1 output, degrading at the contract's assumed 0.5%/yr) generate true-up credits at the utility rate when modeled output underruns; battery capacity guarantees (70% floor) prorate the battery fee. Prepaid contracts convert the payment stream to a single upfront sum discounted at the fund's rate. Buyout estimates for home resale are the value of remaining payments at the fund's discount rate — contracts often charge the greater of this or appraised value.

9. Incentive programs

The "Programs at this address" panel and Advisor chat draw from SIA's snapshot of the DSIRE database (N.C. Clean Energy Technology Center, CC-BY-SA 4.0), refreshed monthly and filtered to currently active programs only — expired and unpublished programs are excluded rather than shown with fine print. Amounts are never auto-applied: you review each program's terms and enter what you qualify for. California battery buyers are pointed to SGIP, whose rebates vary by utility and equity eligibility.

10. Building & electrical code context

The "Codes at this address" card shows each state's adopted editions of the NEC (NFPA 70), IRC, and IFC, compiled from the ICC code-adoption resources and NEC adoption trackers, refreshed periodically (the as-of date is shown). From the editions we derive plain-English requirements: rapid shutdown (NEC 690.12, 2017+), the NEC 705.12 "120% rule" back-feed check (we compute your specific limit from your main-panel rating and flag designs that exceed it, including AC-coupled battery output), roof fire-access pathways (IRC R324/IFC, including the stricter setbacks when panels exceed one-third of the roof), and energy-storage rules (NEC 706, UL 9540 listing, IRC R328 placement limits) when a battery is selected. This is educational context about statewide minimums — local amendments apply, and your installer confirms requirements with the authority having jurisdiction.

11. Neighborhood adoption data

Where shown, "solar homes near you" counts come from a cascade of public records: live permit data where available (e.g., Austin's open permit dataset), state interconnection aggregates (e.g., California DG Stats), and otherwise the zip-level baseline from LBL's Tracking the Sun. Dated sources are phrased honestly ("at least N as of YEAR"), and when no source reports a meaningful count we show nothing at all rather than a zero.

12. Data refresh cadence

13. Known limitations

• Panel layouts are theoretical maximums from aerial imagery; engineered layouts after site survey typically fit fewer panels.
• Load shapes are state-typical, not your meter. Direct annual-kWh entry improves battery math substantially; interval-meter import is not yet supported.
• Tariff data is a snapshot; utilities file changes continuously. Verify the current rate on your bill.
• Battery valuation is a heuristic with the accuracy bands stated in §6, not an optimized dispatch guarantee.
• TPO corporate figures model a typical fund structure; an actual fund's leverage, tax appetite, and appraisals will differ. The buy rate is a modeling floor, not an offer.
• Incentive eligibility is determined by program administrators, not by SIA.
• Nothing here is engineering, tax, or investment advice. Estimates are informational only, and are not an installation quote.

Attribution & licenses

DSIRE data © N.C. Clean Energy Technology Center, used under CC-BY-SA 4.0. ResStock, PVWatts®, and REopt are products of the National Laboratory of the Rockies and the U.S. Department of Energy. Tracking the Sun is a product of Lawrence Berkeley National Laboratory. URDB is maintained by NLR for the DOE. Google Solar API imagery and derived data © Google. PVWatts® is a registered trademark. Their appearance here is attribution, not endorsement of SIA.