PV and Home Battery Payback Calculator

This is an hourly screening calculation, following the energy-flow structure of Weniger, Tjaden and Quaschning (HTW Berlin, manuscript pp.3–4). It is not a reproduction of their weather record, VDI load data or annual self-consumption results. PV size is held fixed while nominal battery sizes 0, 2, …, 20 kWh and the selected size are compared.

For each month, two analytical 24-hour days represent bright and dull weather. Each receives half the calendar days of that month, giving 576 hourly bins weighted to 8760 hours. Daylight follows latitude and solar declination. A seasonal cosine and 1.7/0.3 brightness multipliers form the PV shape; demand uses transparent Gaussian morning/evening peaks or a flat shape. Both profiles are normalised to the user's annual totals. These are author-defined scenarios, not measured catalogue data.

At every hour, direct use is the smaller of PV energy and household demand. The battery charges only from surplus PV, up to AC power and available usable energy; it discharges against the remaining load. With $\eta_{AC}=\eta_{cell}\eta_{inv}^2$ and $\eta=\sqrt{\eta_{AC}}$, the state update is $S_{t+1}=S_t+\eta E_{charge}-E_{discharge}/\eta$. Each day starts from the fixed point of its clipped charge/discharge map. A separate closure residual verifies periodic SOC. Export is limited at the connection point after household use and battery charging; excess becomes curtailment.

Optional peak shaving discharges only above the entered import target. This is an author-derived solar-only threshold controller, informed by the application structure in SimSES; it is not the full SimSES cell, thermal or aging model. No forecast, grid recharging or demand-charge revenue is assumed. A target may remain unmet.

Cash flow is grid-only avoidable cost minus the system's import bill plus export value, less operating costs, initial investment and scheduled battery replacements. NPV discounts each year-end cash flow. Added battery NPV subtracts the same PV system without storage. The best tested size maximises NPV, including zero storage. Payback means the first interpolated crossing of cumulative undiscounted cash flow; later replacement can reverse it, so inspect the cash-flow curve.

Rules reviewed 25 October 2026: German 2026 surplus bands are 7.70 ct/kWh through 10 kW and 6.66 ct/kWh above 10 kW here. The current German preset covers 2–24.9 kW commissioned during August–December 2026. Its first full study year is 2027 or later: the commissioning-year remainder contributes no energy or cash flow, and the entered initial investment is charged at the study start. The 60% cap ends in the entered successfully tested control year. Within this supported size range, negative-price suspension begins the year after smart-meter installation under EEG §51(2)(1). Systems below 2 kW have a separate determination-based exemption under §51(2)(2); they are excluded from the current preset rather than assigned an unverified determination date. The unpassed EEG 2027 scenario uses a permanent 50% export cap. Draft §21 eligibility follows commissioning: below 50 kW before 2028, below 25 kW before 2029, and below 7 kW before 2031; commissioning from 2031 has no transitional payment. At the scenario's 5.2 ct/kWh payment, entitlement ends with the 36th calendar month following commissioning (draft §25(2)), regardless of study start. Candidate-specific monthly export totals apply the remaining term, including a partial final calendar year. The draft §51 smart-meter exemption also lasts through the installation calendar year for eligible network-operator acceptance. Other exports use the entered merchant assumption; this does not assume that a merchant contract or further bonus is available. Dutch imports and exports net annually only through 2026; export fees are separate. France uses 1.1 c€/kWh for eligible new June-2026 contracts, 2% anniversary indexation, a 1600 kWh/kW annual export payment ceiling and a 20-year term. Poland values positive and negative RCE exposure separately for the 15-year net-billing term. For each battery candidate, raw RCE value V gives positive credit D = max(1.23 V, 0). Eligible electricity purchases I exclude network charges. Import use is U = min(D, I), and refundable surplus is R = min(D − U, 0.30 max(V, 0)). Realised positive value is min(requested share × D, U + R). Thus zero imports cannot realise more than 30% of pre-uplift RCE value. Any negative net liability is retained in full. The chosen negative-price floor is applied before these operations. Thereafter entered merchant assumptions apply. The German current preset keeps a 2026 commissioning entitlement through 2046. No future law or merchant price is predicted.

Additional regional rules — reviewed 25 October 2026

India (INR): MNRE residential CFA guidelines of 7 June 2024, with July 2025 amendment (attached s15, PDF pp.5, 8–9 and 13), set general-state assistance at INR 30000/kW for the first 2 kW and INR 18000/kW for the next 1 kW. Special-category rates are 10% higher. Capacity above 3 kW receives no extra CFA. Only confirmed eligibility is counted; the date window ends 31 March 2027. The grant, capped here at gross PV cost, reduces PV initial investment once and never reduces battery cost. Annual net-metering mode offsets min(annual imports, annual exports); monthly mode instead sums that minimum by month without carry. Remaining exports receive the entered state tariff. These are selectable contract assumptions, not a single nationwide settlement rule.

Pakistan (PKR): NEPRA regulation 14, SRO 251(I)/2026 of 9 February 2026 (attached s14, PDF p.6), prices imports at the applicable consumer tariff and exports at NAEPP. It does not set a fixed 10 or 11 rupees. The separate CY2026 decision of 7 January 2026 (s18, PDF p.17) gives NAEPP = PKR 8.13/kWh, distinct from NAPPP = 25.32. The editable rate starts at 8.13; regulation 14(3) permits revision. The first year after the entered five-year agreement uses a separate user renewal price. New-prosumer connections only; protected older contracts are excluded. Monthly/quarterly credit-payment timing is approximated by year-end cash flow.

Brazil (BRL): New local residential GD II only, excluding grandfathered art.26 systems. Law 14300 art.27 charges 60%, 75% and 90% of the entered full Fio B component on compensated kWh in 2026, 2027 and 2028. From 2029 the separately entered charge is a scenario under art.17, not a legislated 100% step. The monthly FIFO bank starts empty, receives each month's exports and expires unused vintages after 60 months under art.13. REN 1059 group B billing constrains compensated kWh to grid imports, available credits and the amount that leaves the bill at or above the monthly availability floor. For import I, compensated Q, import price p and compensation charge c: bill = max(floor, (I − Q)p + Qc). The grid-only baseline uses the same floor. Unused credits have no cash or terminal value. Local taxes, tariff flags, low-income concessions, remote sharing and injection-demand charges are outside this simplified conventional group B case.

German section 14a credit eligibility

A fixed Module 1 or Module 1+3 credit is counted only when confirmed additional annual credit is entered and the battery has verified technical grid-charging demand strictly above 4.2 kW. BNetzA bases battery eligibility on technical public-grid charging capability; software settings that currently allow only PV charging do not remove that capability. The new capability input is independent of the simulated PV-only charge/discharge limit. Enter zero for unavailable or unconfirmed capability. An incompatible positive credit claim produces an input error and contributes zero to every candidate cash flow. Every positive size in the comparison must have compatible hardware, operator eligibility and costs; the zero-battery candidate receives no credit. Module 2 savings remain zero because no grid charging is dispatched, and Module 3 time shifting is outside the flat-tariff model. Source: BNetzA affected installations and battery FAQ, attached s20; rules reviewed 25 October 2026.

• Demand, yield, prices and installed costs are user assumptions. Defaults are illustrative, not local quotes or national average prices. Use lifetime-average PV yield and usable capacity to allow for degradation. Default usable fraction is 0.90 SOC window × 0.90 average retained capacity = 0.81.
• Bright and dull days have equal weight. Weather does not persist across days; holidays, measured appliance diversity, shading, tilt, azimuth and PV inverter clipping are not simulated. Consecutive dull days and hourly averaging can materially change storage value. The same synthetic profile construction is used for all seven country presets; seasonal PV amplitude scales with latitude and reverses in the southern hemisphere.
• Efficiencies are constant and symmetric by path. Standby loss, battery self-discharge, temperature derating, capacity-dependent power and cycle-dependent replacement are excluded. Enter extra recurring costs and a realistic replacement interval; battery fixed and per-kWh costs recur together.
• Prices are constant except the French statutory 2% export indexation. European figures use EUR, India INR, Pakistan PKR and Brazil BRL, with a consistent quote/tax basis and no currency conversion. Unavoidable grid subscriptions remain payable and cancel between alternatives.
• Negative-price hours are a user sensitivity: an equal fraction of each 10:00–14:00 interval, with 1460 potential hours per year. No historical price series, quarterly settlement or future price forecast is implied. German §51a compensation after the normal support period is excluded.
• The Polish requested share is an expiry/use haircut. A separate annual ceiling for EVERY battery size enforces eligible electricity purchases and the RCE 30% cash-refund cap; distribution charges are ineligible. This annual envelope is not a monthly vintage ledger: 12-month expiry, attribution of purchases across vintages, first-year credit availability and refund delays can reduce value further. Refunds are included in the representative year's value without their actual delay, so detailed financial settlement still requires an invoice-level study. The displayed Polish positive export rate is credited value before the ceiling, not guaranteed cash income.
• §14a Module 1 and Module 1+3 use only a confirmed additional annual credit caused by this battery, with verified technical grid-charging demand strictly above 4.2 kW. The capability input is separate from the PV-only operating limit and must apply to every positive battery candidate. No capability confirmation means zero credited benefit. Confirm control, registration and applicable metering requirements with the network operator. Module 2 import savings and Module 3 time-varying savings remain zero.
• Current German metering/control changes use whole calendar years. For the Aug–Dec 2026 commissioning preset, the first full study year must be 2027 or later; commissioning-year operation and cash flows are excluded, not extrapolated to a full year. The draft additionally takes commissioning year and month, assumes commissioning on that month's first day, and applies its final supported month to monthly energy. The study starts on 1 January of a full operating year, with initial investment charged then; pre-study cash flows are excluded and delaying the study never renews support. No residual asset value, financing, income tax, market services or backup premium is included. Only explicitly confirmed Indian PV CFA is deducted.
• India: the capex case assumes compliant domestic cells/modules, approved residential eligibility and no prior subsidy double count. Study years begin after commissioning; the initial grant is netted at the study start without financing or payment delay. State tariffs, settlement periods and surplus compensation must match the local DISCOM contract. Monthly mode discards credits at each month's settlement; annual mode allows within-year netting. No indefinite Indian credit bank is assumed.
• Pakistan: the new-prosumer regime and applicable utility approval are assumed. The initial tariff remains constant until the entered agreement end; renewal compensation is a separate scenario. Import slab changes, time-of-use prices, outages and interest on delayed credits are excluded. No automatic licensing fee is invented.
• Brazil: each candidate has its own monthly import totals and 60-month credit bank. The conventional residential availability floor is an entered BRL amount. No export cash sale, annual reset of unused credits or Fio B charge on immediate self-consumption is assumed. Post-2028 charges, prices and minimum bills remain constant as entered. The selected regional rules card and all monetary result cards identify the currency; chart values use that same currency.

Use for early comparison of rooftop surplus-export PV from 0.5 to 24.9 kW, 100–30000 kWh/year household demand, 0–30 kWh nominal batteries and European latitudes 42–55°N and regional preset latitudes −40° to +55°. The German current preset is restricted to PV ratings of 2–24.9 kW commissioned during August–December 2026, after the 25 February 2025 Solarspitzengesetz change, and full study years from 2027 onward. Below-2-kW systems need a separate assessment of the EEG §51(2)(2) determination-based exemption. Installation-year partial operation is outside this full-year model. Select custom terms for older German contracts; the French preset covers eligible new requests from 5 June 2026 only. The Dutch and Polish presets are simplified contract scenarios, not invoice generators.

Results depend strongly on synthetic profile matching. The size optimum is discrete and conditional on the entered fixed PV capacity, inverter power, controller, cost and tariff assumptions; it is not a global design or dispatch optimum. Test your own measured hourly or quarter-hourly data in a detailed study before purchase. Representative hourly peak power is not an instantaneous protection or connection rating. Installation work belongs to a qualified person. Check tariffs, battery export eligibility, §14a treatment and connection requirements against the contract and rules or standards in force. The metric/US display switch may convert kW to horsepower; kWh and the selected currency remain the settlement basis and calculations retain their original units.

The schematic labels PV as available power and shows curtailment explicitly; its supply/demand check includes that unused power. Power traces are indexed by hour beginning, while stored energy is the interval-end state and is plotted at hours 1–24. Initial operation and the statutory end of the draft payment follow commissioning, even if the study starts later.

India, Pakistan and Brazil are dated rule scenarios, not tax or invoice engines. Indian state settlement terms must be verified; future CFA after 31 March 2027 is not assumed. Pakistan applies to new agreements under the 2026 regulations, with PV at least 1 kW; verify sanctioned load, connection and approval with the utility. Brazil applies to new local GD II conventional group B residential connections, with full Fio B and future compensation charges below the import price on a consistent tax basis. Systems protected by Law 14300 art.26 need a separate contract model. The regional profiles are analytical examples, not local climate forecasts.

German §14a fixed-credit claims require verified technical public-grid charging demand above 4.2 kW and operator-confirmed additional eligibility. A 3.6 kW simulated operating limit alone establishes no such eligibility; enter the separate hardware capability only when documented. The current operation remains solar-only even when that technical grid-charging capability exists.