Balcony Solar Calculator: Yield, Battery and Payback

PVGIS 5.3 DRcalc supplies horizontal global, direct and diffuse hourly monthly means for Berlin, Hamburg, Munich and Zurich (SARAH3, 2005–2023; sources s5–s8). The monthly irradiation table integrates those 24 hourly averages over a non-leap calendar. Each monthly mean day is repeated for its calendar day count: 8760 hourly energy balances, not a historical weather year.

NOAA fractional-year equations give declination and the equation of time at the representative mid-month day, evaluated at noon for the daily correction (source s12, page 1). The solar unit vector is projected onto a panel normal defined by tilt and clockwise-from-north bearing. Direct-horizontal irradiance is multiplied by the nonnegative incidence-to-zenith cosine ratio. The direct beam is omitted below a zenith cosine of 0.05 and below the selected obstruction elevation, avoiding unstable near-horizon projection.

Following the Sandia PVPMC isotropic model (https://pvpmc.sandia.gov/modeling-guide/1-weather-design-inputs/plane-of-array-poa-irradiance/calculating-poa-irradiance/poa-sky-diffuse/isotropic-sky-diffuse-model/), sky diffuse uses the factor $(1+\cos\beta)/2$; ground reflection uses $0.2(1-\cos\beta)/2$. The additional uniform shading loss acts on the sum. Module rating times irradiance divided by 1000 W/m² gives power before the selected constant conversion loss. Solar output is then clipped at the simulated AC operating cap. This cap is independent of the highest selectable inverter rating used for German regulatory guidance.

The illustrative household profile is normalized to the entered annual energy. Direct use is the hourly minimum of solar and demand. Storage is AC coupled: only solar surplus after clipping may charge it. With usable stored energy $S$, the controller limits charge by surplus, charger power and $(C-S)/\eta_c$, and discharge by demand, discharge power, remaining combined AC headroom and $S\eta_d$. Here $\eta_c=\eta_d=\sqrt{\eta_{rt}}$. Continuous standby is added to demand. Storage starts empty; unspent year-end energy is reported, with no cash credit. Generation plus import equals household demand, standby, export, battery losses and the stored-energy increase.

HTW Berlin provides the battery-system efficiency benchmark (documentation v3.0, attached s1, page 6): 82.5% AC round-trip utilization. A controlled 100 Wh solar-surplus pulse followed by 100 Wh AC demand runs through the production dispatch function, with zero standby, 100 Wh usable capacity, and 100 W charge, discharge and AC caps over 1 h intervals. The expected system response is 100 Wh accepted, 82.5 Wh delivered, 17.5 Wh grid top-up, and zero final stored energy. This checks charging, stored-energy updates, discharging and conversion losses against a published system-level result. HTW's annual simulator uses minute data and 41 household profiles; this tool uses hourly climate averages and illustrative loads. Its annual self-consumption and payback results are not validated against HTW.

Independent PVGIS PVcalc checks use Berlin, 880 Wp, south, free-standing crystalline silicon and 14% PVGIS system losses: 915.89 kWh/year at 30°, and 667.07 kWh/year at 90°. This tool's separate 20% total conversion-loss assumption includes temperature and other effects. Its isotropic transposition gives about 3.5% and 5.8% lower energy respectively; 8% benchmark tolerances reflect different models, not numerical solver error.

Annual savings equal avoided imports times the import tariff plus paid exports. Battery benefit is the difference from solar alone, after standby and lost export revenue. Simple payback divides initial cost by first-year savings and excludes replacements. Discounted cash flow repeats first-year savings in constant real money, includes battery replacements at the start of each new interval, and assumes no terminal resale value.

Zero initial investment and zero annual benefit are reported as break-even. Zero investment with positive benefit is immediate; zero investment with negative benefit is an annual loss. A positive investment with nonpositive benefit has no simple payback. For the battery decision, incremental discounted NPV rounded to the nearest cent is break-even at zero; only a positive value is described as repaying the extra cost.

Day playback: the selected month uses the same representative mid-month solar geometry and the actual state at the start of day 15 from the chronological battery dispatch. The 0–24 h UTC clock moves the sun along a schematic sunrise-to-sunset path; path height follows the calculated elevation while horizontal distance shows progress through daylight, not compass azimuth. The sun is hidden below the horizon. Solar, load, discharge and import power are held over each hourly interval. Battery energy is interpolated linearly between the recorded hour boundaries, consistent with those constant hourly average powers. The 24:00 marker is the left-hand limit of the last interval and the final stored energy. Only selected-hour values, labels and drawings read the playing hour; the yearly dispatch, generation, savings and payback do not.

• One unobstructed panel plane, no bifacial gain, no snow cover and ground albedo 0.2. PVGIS terrain-horizon effects are already in the climate data. The obstruction input removes direct light only; it does not model a reduced diffuse-sky view.
• The three load curves are author-defined scenarios, not measured loads or BDEW standard profiles. They contain smooth morning, midday and evening components with a persistent base load. Local clock time is approximated by UTC+1 in November–March and UTC+2 in April–October; exact daylight-saving transition days are omitted.
• Monthly averaged weather smooths cloud variability and hourly loads smooth appliance peaks. Consequently solar clipping and grid imports can be understated, and direct use and battery benefit can be overstated. Results are planning scenarios, not a savings guarantee.
• Battery usable capacity and efficiency remain constant until replacement. There is no grid charging, tariff arbitrage, battery export or recovery of solar-inverter clipping. The shared AC cap is an operating assumption; it does not establish that a particular inverter arrangement complies with connection rules.
• Example prices are editable assumptions, not surveyed October 2026 market quotations. All monetary entries use EUR, including Swiss cases after consistent currency conversion. Real tariffs, output and annual demand stay constant; degradation, inflation, tax, financing, maintenance, inverter replacement and capacity fade are excluded.
• No additional numerical storage-capacity limit is imposed. This does not imply that storage is exempt from electrical safety, registration or grid-connection requirements.

Rule snapshot: checked 25 October 2026. Germany follows the VDE FAQ dated 6 July 2026 (https://www.vde.com/topics-de/energy/steckersolargeraete-faq), DKE's explanation of DIN VDE V 0126-95:2025-12 (https://www.dke.de/de/arbeitsfelder/energy/normenhinweise/faq-zur-dinvdev012695), the Bundesnetzagentur balcony-PV FAQ (https://www.bundesnetzagentur.de/DE/Fachthemen/ElektrizitaetundGas/ErneuerbareEnergien/Solaranlagen/Balkon_table.html) and VDE FNN's connection FAQ, question 10, dated 3 March 2026 (https://www.vde.com/de/fnn/themen/tar/tar-niederspannung/erzeugungsanlagen-steckdose). The simplified route has an 800 VA inverter limit and a 2000 Wp module limit. The inverter limit applies to the applicable summed highest selectable PV-inverter rating, not the simulated operating cap. A 900 VA inverter set to 600 W does not qualify; selecting a lower operating mode does not change eligibility.

Household-plug (Schuko) configurations are limited to 960 Wp and require the specified product safeguards. Above 960 Wp, select an appropriate dedicated energy connector and have the circuit assessed. These are household totals, not a separate allowance per socket. MaStR-only registration is conditional on unpaid exports and all other simplified-route requirements. Register the qualifying solar installation within one month of commissioning. For paid exports, follow the applicable grid-connection procedure and register with both the network operator and MaStR; do not rely on the unpaid-export simplifications. Check against the standard in force.

Switzerland follows the Federal Office of Energy / EnergySwitzerland FAQ, December 2024 (https://pubdb.bfe.admin.ch/de/publication/download/11259): maximum 600 W AC per household meter. Notify the distribution operator and supply the set's conformity declaration. The supplier must verify the combined module ratings against inverter input limits.

Storage scope: DIN VDE V 0126-95:2025-12 excludes plug-in systems with energy storage; DKE explicitly says additional requirements must be fulfilled. This tool imposes no invented storage-size rule and does not approve a storage connection. Have a qualified person check the actual system, protection, combined inverter ratings and applicable registrations.

For preliminary energy and economic comparisons in the four represented climates. No string-voltage/current sizing, cable or protection design, structural/wind checks, detailed near-field shading, backup-power design or installation approval is included. Installation work and circuit modifications belong to a qualified person. Assess secure mounting and permissions separately. Use site-specific hourly weather and measured demand before a major purchase.