Battery storage ROI methodology

Time-of-use arbitrage

The dominant economic use case for residential battery storage in most U.S. markets is time-of-use (TOU) rate arbitrage: charging the battery during off-peak periods when electricity is cheap and discharging it during peak periods when electricity is expensive. The value of arbitrage depends entirely on the rate spread between peak and off-peak tariffs at the homeowner's specific utility — a variable the calculator requires as direct input because it varies by utility, state, and rate plan.

Representative TOU spreads from major utilities as of 2025:

• PG&E (California) E-TOU-C plan: off-peak ~$0.34/kWh, peak ~$0.56/kWh — spread ~$0.22/kWh. A 10 kWh daily discharge cycle generates approximately $800/year in arbitrage value on this plan alone.
• SDG&E (California) TOU-DR1: one of the widest spreads in the country at ~$0.30/kWh peak-to-off-peak. San Diego homeowners with batteries routinely see the fastest storage paybacks in the nation.
• ERCOT (Texas) GRIDDY-type variable: real-time market prices can reach $5–$9/kWh during grid stress events (the February 2021 winter storm being the extreme case). However, most Texas residential customers are on fixed-rate retail plans with minimal TOU spread; the arbitrage case in Texas is primarily backup value, not rate arbitrage.
• Con Edison (New York): approximately $0.12/kWh peak-to-off-peak spread — lower than California but meaningful given high absolute electricity rates.

The calculator computes annual arbitrage value as:

Annual TOU arbitrage value =
  Daily discharge capacity (kWh)
  × TOU spread ($/kWh, peak minus off-peak)
  × Annual cycle days (default 250, adjustable)
  × Round-trip efficiency (default 90% for LFP batteries)
  × Degradation factor (year-specific, see below)

Virtual net metering

In some states and utility territories, homeowners can be credited for discharging battery storage to the grid at retail rates — a policy known as virtual net metering (VNM) or battery net metering. California, Massachusetts, and New Jersey have the most developed VNM frameworks. The economic value here is that stored solar energy exported during peak hours earns retail-rate compensation rather than the reduced avoided-cost rate that governs solar exports under NEM 3.0 in California or flat avoided-cost programs in other states.

The calculator flags whether VNM is available in the user's utility territory and, if so, models the VNM export credit as an additional annual cash flow line item on top of TOU arbitrage value. VNM is an either/or with TOU arbitrage in practice — a battery cannot simultaneously earn TOU arbitrage by discharging to the home and VNM credit by discharging to the grid — so the calculator uses the higher of the two values for each dispatch window.

Backup value: insurance framing

The U.S. electric grid achieves approximately 99.97% reliability (EIA data) — meaning the average home experiences roughly 2.6 hours of outage time per year. For most households, that statistic is reassuring. But it masks wide geographic variation: homes in wildfire-prone California utility territories subject to Public Safety Power Shutoffs (PSPS) may experience 40–200 hours of planned outages per year, while Gulf Coast homes face hurricane-related outages that can last days to weeks.

The economic value of backup power is highly user-specific and resists general modeling. The calculator handles it in two ways:

• Direct cost approach: the user enters an estimated annual outage cost (spoiled food, lost productivity, generator rental, hotel stays) and the calculator discounts that avoided-cost stream over the battery's useful life.
• Insurance premium approach: the user enters what they would pay annually for equivalent backup coverage (e.g., a whole-home generator costs $5,000–$15,000 installed plus $200–$500/yr in maintenance); the battery's backup value equals the generator alternative cost if the battery provides comparable coverage.

Backup value is never included in the base calculation — only when the user explicitly enters a value. It is presented separately from TOU/VNM arbitrage to prevent conflation of financial return with insurance value.

IRC §48E — Clean Electricity Investment Credit (important caveat)

A critical distinction applies here. The residential solar credit (§25D) expired December 31, 2025. IRC §48E is the Clean Electricity Investment Credit that applies to commercial and utility-scale projects — it is not a residential homeowner credit. Homeowners who installed battery storage as part of a solar system before December 31, 2025 may have claimed the §25D residential credit for qualified battery storage (≥3 kWh capacity), which provided a 30% credit. That credit is now expired.

For standalone battery storage installed after January 1, 2026, no federal residential tax credit is currently available. Homeowners should verify with their tax advisor whether any applicable legislation has been enacted after this page's review date. The calculator does not apply a federal credit to battery storage installed after December 31, 2025 unless the user confirms eligibility under a newly enacted provision.

State-level battery storage incentives — notably California's SGIP rebate ($0.15–$0.85/Wh depending on equity tier and program availability) and Massachusetts's SMART battery adder — remain active and are modeled separately in the State Incentive Stacker.

Common battery systems and cost benchmarks

The NREL Tracking the Sun 2024 dataset (Lawrence Berkeley National Laboratory) establishes a median residential battery add-on cost of $1,200 per kWh installed, with 23% of new residential solar systems including battery storage. Representative installed costs for the most common residential batteries:

• Tesla Powerwall 3 — 13.5 kWh usable capacity; $9,000–$11,000 installed (single unit); LFP chemistry.
• Enphase IQ Battery 5P — 5 kWh per module (stackable); $5,500–$7,000 per module installed; LFP chemistry; native microinverter integration.
• Franklin WH — 13.6 kWh usable; $8,500–$10,000 installed; LFP chemistry; 10-year warranty.

Break-even formula and degradation

Simple break-even (years) =
  Total installed cost ÷ Annual TOU arbitrage savings

NPV break-even applies degradation and discounting:
  Annual value(t) = Base annual value × Degradation(t) / (1 + r)^t

Degradation by chemistry:
  LFP (lithium iron phosphate): 80% capacity retained at Year 10
    → linear: ~2%/yr capacity loss
  NMC (nickel manganese cobalt): 70% capacity retained at Year 10
    → linear: ~3%/yr capacity loss

Example (10 kWh LFP battery, $0.22/kWh TOU spread, 250 cycle-days/yr):
  Year 1 annual value = 10 kWh × $0.22 × 250 × 90% = $495
  Year 5 annual value = $495 × (1 − 0.02)^4 = ~$457
  Year 10 annual value = $495 × 0.80 = $396

Named-expert guidance

Limitations

• TOU rate spreads change when utilities file new tariffs; the calculator uses the most recent available rate schedule but should be verified against your current utility bill.
• Cycle count assumptions (250 days/yr) are conservative for primary TOU arbitrage use; actual dispatch frequency depends on your home energy management system and battery firmware settings.
• Backup value is inherently subjective and user-specific; the calculator's backup value field accepts any figure the user enters without validation — confirm the estimate is reasonable before using it in a purchase decision.
• No federal residential battery credit is included for systems installed after December 31, 2025.

Primary sources

• Lawrence Berkeley National Laboratory, Tracking the Sun 2024 (trackingthesun.lbl.gov) — median battery cost $1,200/kWh installed; 23% storage attachment rate
• IRC §48E — Clean Electricity Investment Credit (commercial/utility; not residential)
• EIA Form EIA-861 — residential electricity rates by state and utility
• California SGIP (Self-Generation Incentive Program) — battery storage rebates, selfgenca.com
• Tesla, Enphase, and Franklin Energy — manufacturer battery specification sheets for capacity, warranty, and degradation curves