Unit economics to capital stack

Battery debt financing

How much a lender could lend against one generic leased home battery, and against a fleet, from the cash the battery earns, after the member's payment and the federal storage tax credit, and whether the battery pays back at all. Change any input. The page redoes the math as you type.

A generic model, not any company's books. This site is not affiliated with Base Power or any battery company. The defaults are generic: installed cost from NREL's public cost benchmark, statewide retail and delivery prices from EIA, ERCOT prices, and labeled assumptions for the lease terms, lender terms, the toll and operating cost. One company's published figures are available as an optional preset, labeled as that company's public claims, not its economics.

What drives the default answer: a retail energy margin (derived from EIA and ERCOT data with one labeled cost assumption), ERCOT energy arbitrage (derived from public prices with assumptions) and member fees (an assumption) carry the loan, and the 30% tax credit, sold at a market discount, cuts what must be funded. The default assumes the battery's owner is also the home's retail provider, which only exists in zones with retail choice; a third-party owner should set the retail margin to 0. The default case is merchant, so the utility toll placeholder does not count. On the generic defaults the battery does not pay back; "Does it pay?" says by how much and what is left out.

Each input says Sourced (public number with a link, sometimes with our stated math), Assumption (our placeholder, or our math with a labeled assumption) or, after you load the preset, Company claim (a figure a company published about itself).

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Inputs, per battery

What earns the cash

Revenue case Assumption

A toll is a contract in which a utility pays the battery owner for the right to dispatch the battery, usually on a pay-for-performance basis. Whoever holds the toll usually controls dispatch, so toll and arbitrage rarely both go to the owner. In a city-utility or co-op zone (no retail choice) a utility contract like this is the only way a battery company shares the battery's value.

Energy arbitrage zone Derived from public prices with assumptions

Energy arbitrage only, 12 real ERCOT months, from our zone value file.

The arbitrage value is derived from public ERCOT prices with assumptions, not a published number: a fixed charge and discharge clock (10 AM to 2 PM in, 7 to 9 PM out), 88% round trip efficiency and a 20% backup reserve.

Zones without retail choice. LZ_AEN (Austin Energy), LZ_CPS (CPS Energy, San Antonio), LZ_LCRA (LCRA's wholesale customers, mostly cities and co-ops) and LZ_RAYBN (Rayburn Country Electric Cooperative) are what ERCOT calls Non-Opt-In Entity load zones (Protocols 3.4.3; ERCOT board item 13.2, December 2025). Texas law leaves retail choice to each city utility (PURA 40.051) and co-op board (PURA 41.051), and these have not opted in. No retail provider exists there to keep the arbitrage or a retail margin: the value goes to the utility, so the model counts neither and points to the toll case. The other four zones are mostly retail choice, with some city and co-op pockets.

Who keeps the export value. At up to 20 kW from 7 to 9 PM, most of the discharge is more than a home uses, so it flows out through the meter. In ERCOT, a home battery of 1 MW or less that is not registered with ERCOT is an Unregistered Distributed Generator (the Nodal Protocols' Section 2 counts energy storage as distributed generation). Its metered outflow is subtracted from the settlement load of the home's retail provider (Nodal Protocols 11.4.4.3), and the provider pays for that load at the real-time load-zone price (6.6.3.2). So:

(a) The owner is the home's retail provider (its REP and load-serving entity). Every kWh the battery discharges, used at home or exported, cuts that provider's load-zone purchases at the load-zone price, and every kWh it charges adds to them. The arbitrage line is kept through the provider's own settlement. No ADER aggregation is needed for it.
(b) The owner is a third party, not the retail provider. The same cut lands on whichever provider serves the home. The owner gets the value only by contract with that provider, or by registering the battery with ERCOT as a settlement-only resource through a QSE. Texas rule 16 TAC 25.217(f)(2) lets owners of renewable distributed generation sell outflow to their REP "at a value to which both parties agree"; we found no rule that makes a REP buy battery outflow at any price.
(c) ERCOT's ADER pilot is the route to ancillary services (Non-Spin and ECRS so far) and to dispatch as an aggregated resource. It is not needed for the energy value in (a).

Not settled by these sources: the reduction in 11.4.4.3 is written for premises the wires utility has flagged as having distributed generation (a DG profile segment), so it depends on the battery being reported at interconnection; and distribution loss factors shift the value by a few percent. Not modeled.

Per battery

Does it pay?

The whole battery (unlevered): pay the net cost in year 0, get CFADS every year of life. Equity: put in the equity, get CFADS after loan payments. NPV at the discount rate input. No taxes, depreciation, residual value or escalators.

What this means

Cash flow available for debt service

CFADS = revenue minus operating cost, before the loan. Year 1, per battery.

Bars: CFADS each year of life. Line: yearly loan payment. Gap between them is the cushion.

How the loan is sized

Lenders take the lower of two limits: what cash flow can repay, and a share of what the asset cost.

Fleet scale

Same unit math, multiplied. Assumes every battery looks like the average one.

100 MW view: 100,000 kW divided by the power input per battery. Nameplate power, before availability.

Sensitivity: debt per battery

Rows: utility toll. Columns: interest rate. All other inputs as set.

cash flow limits the loan advance cap limits it no debt

Real vs assumed

Every default on this page, and where it comes from.

Method and what is left out

Debt sizing. Level yearly payment over the loan term. The payment is the weakest year's CFADS inside the term, divided by the target DSCR. Debt is the present value of that payment at the interest rate. Then the loan is capped at the advance rate times installed cost, and never above cost minus the member's upfront payment.
Tax credit. The federal investment tax credit for energy storage (IRC 48E) goes to the owner of a leased battery. The model treats it the simplest standard way: the owner sells the credit for cash when the battery goes into service (a transfer under IRC 6418), at the credit sale price (default 89.5 cents per dollar, Crux's 2026-vintage ITC average), and that cash lowers the net cost that debt and equity must fund. That is a simplification. Real lenders usually fund the credit separately, with a bridge loan sized on the credit and repaid when it sells, and size the term loan on cash flow and an advance rate on the full installed cost. The advance cap here already applies to the full cost, so the credit only changes the debt when the net-cost cap binds; when it does, equity shows $0 and the page says why. Left out: the months between paying for the battery and getting paid for the credit, bridge loan interest, five-year recapture risk and the insurance buyers ask for, the depreciation basis cut, bonus adders, and tax equity partnerships.
Equity per battery = installed cost minus member upfront payment minus tax credit minus debt.
Does it pay? The whole battery: pay the net cost (installed cost minus the member payment and the tax-credit cash) in year 0, get CFADS each year of its life. Unlevered IRR, NPV at the discount rate input (10% by default, a placeholder) and the payback year. Equity: put in the equity, get CFADS minus the loan payment. When the cash never covers the net cost the page says so plainly. Left out, any of which could change the answer: price spikes outside the fixed 7 to 9 PM window, ancillary services ($0 by default), depreciation, the battery's value after its useful life, fee escalators and a utility toll. We do not tune inputs to make it pay.
Tax credit size risk. The 30% rate without the wage and apprenticeship tests rests on each battery being a facility under 1 MW. Treas. Reg. 1.48E-3(c)(4)(ii) counts storage units as one facility for this test when they have the same or related owners, the same placed-in-service year and a shared point of interconnection or end user. Batteries at separate homes usually share neither, but common ownership, financing and aggregated dispatch are a risk to check with tax counsel, not a conclusion.
Fade cuts toll and arbitrage each year. Member fees stay flat. No inflation on anything.
Energy arbitrage is derived from public prices with assumptions, not a published number. It uses a fixed daily clock, 88% round trip efficiency and a 20% backup reserve: charge 10 AM to 2 PM, discharge 7 to 9 PM, Central time, every day, settled at the load zone real-time price. The value comes from the zone value file, which shows the schedule and method. Most of that discharge is export. For an unregistered battery of 1 MW or less, ERCOT settles outflow as a cut to the settlement load of the home's retail provider at the real-time load-zone price (Nodal Protocols Section 2, definitions of Distributed Generator and Unregistered Distributed Generator; 11.4.4.3, load reduction for excess from other distributed generators; 6.6.3.2(1)(g), Adjusted Metered Load charged at the load-zone price). So the full line belongs to an owner that is the home's retail provider (case a above). A third-party owner (case b) earns it only through a contract with that provider or by registering the battery with ERCOT (a Settlement Only Distribution Generator, 6.6.3.8, whose storage-majority sites keep load-zone pricing under 6.6.3.2(1)(j)). ADER (case c) adds ancillary services, not this energy value. No capacity value. It is not any company's revenue.
Retail energy margin defaults to $63 a month: (16.66 cents, what retail providers billed ERCOT homes in 2024 - 5.21 cents delivery charges billed by the wires utilities - 3.70 cents load-weighted LZ_NORTH wholesale price - 2.0 cents other supply cost, an assumption) x 1,097 kWh a month, all from EIA-861 except the wholesale price (our math on ERCOT data). It is a gross margin, before the provider's own cost to serve, so treat it as the high end. It uses the home's whole usage before the battery, and the arbitrage line values the battery's own charge and discharge at the same load-zone price, so the two add up without counting a kWh twice. It belongs only to an owner that is the home's retail provider, and only where retail choice exists; set it to 0 for a third-party owner.
Ancillary services (ERCOT reserves such as Non-Spin and ECRS, reached by home batteries only through the ADER pilot, where ECRS was fully subscribed in September 2026) are one input in $ per kW-year, $0 by default because no public number gives what an aggregated home battery nets. A battery cannot sell the same kWh twice: a kW held as reserve in an hour cannot also discharge for arbitrage that hour. So the input is the extra value after the arbitrage it displaces (for example, reserve sold in the 22 hours outside the discharge window), and the model adds it to arbitrage. It counts in the merchant and stacked cases, not the toll case, with availability and fade applied.
Inputs are checked the same way on this page and in the API: plain decimal numbers within each field's limits. A blank field keeps its default. An invalid field shows an error and the results wait until it is fixed.
Depreciation is not modeled. It is a tax deduction, not cash the battery earns, so it does not change CFADS or the debt sized on CFADS; it changes the owner's taxes and so the equity return, which "Does it pay?" shows before taxes.
Not modeled: income taxes, tax equity, member churn and defaults, reserve accounts, fees on the loan, sculpted payments, refinancing, and the value of the battery after the loan ends. Each of these can move the answer a lot.
Fleet is the unit result times a count. Real lenders look at the whole pool, with concentration limits and performance history.

Math lives in finance-core.js, tested in Node. Defaults live in finance-defaults.json.

Sources

NREL, U.S. Solar Photovoltaic System and Energy Storage Cost Benchmarks, Q1 2023 (Ramasamy et al., NREL/TP-7A40-87303, September 2023; mirror copy, retrieved 2026-11-04). Table 3, modeled market price, 2022 dollars: 8 kW rooftop PV $2.68/W; with a 5 kW / 12.5 kWh battery $4.70/W. Our math: ($4.70 - $2.68) x 8,000 W / 12.5 kWh = $1,293/kWh, the generic installed cost default.
Lawrence Berkeley National Laboratory, U.S. Distributed Solar and Storage, 2026 Data Update (August 2026). Median residential battery 13.5 kWh in 2025; among cash-purchase homes, paired PV plus storage priced $2.1/W above PV alone (mostly California data). A cross-check, not used in the math.
EIA-861, 2024 data (retrieved 2026-11-04). Sales to ultimate customers, Texas, ERCOT, retail power marketers, residential: $15.27 billion, 91.6 million MWh, 6.96 million customers (16.66 cents/kWh, 1,097 kWh a month). Delivery companies, Texas, residential: 5.21 cents/kWh.
Solar Power World, "Texas homeowners can lease Tesla Powerwall batteries straight from company" (2026-08-13, retrieved 2026-11-04): two Powerwall units for $35 a month with $0 installation, in areas of Texas with retail choice, with a Tesla Electric fixed plan. One published lease, used as the generic member fee and upfront assumption.
Battery size, and the optional preset: Base Power, utilities page (retrieved 2026-10-29). Base Core 20 kW / 39.2 kWh, the size the zone arbitrage values were simulated for ("Our proprietary residential BESS (20 kW / 39.2 kWh)"). "Landed cost of storage": Base about $300 to $400 per kWh (used here as a cost basis; as a cost shown to utilities it may include Base's margin), utility-scale about $200 to $400 per kWh, traditional battery VPPs about $1,100 per kWh (Base cites EnergySage, Lazard, Wood Mac). "24/7 dispatchable up to 500 cycles a year", "96% fleet availability", "Field-demonstrated <5% forced outage rate". Tolling and build-transfer structures.
Optional preset only: Base Power, Base Core page (retrieved 2026-10-29, rechecked 2026-11-04). "Whole home backup for only $695 and then $19/mo.", shown with an Oncor-territory plan. The same site says "Base availability, pricing, and offers vary by address" and "Product availability, system configurations, and pricing vary by state."
Crux, 1Q2026 market update Q&A (updated 2026-05-04, retrieved 2026-11-04). "For 2025 ITCs, pricing averaged $0.909"; for 2026, "ITC pricing dropped slightly, by 0.6% to $0.895".
ERCOT, Aggregate Distributed Energy Resource (ADER) pilot project (PUCT Project No. 53911, retrieved 2026-11-04). An ADER is a resource made of many metered premises on the distribution system that responds to ERCOT dispatch as one. ERCOT board item 10.1, Phase 3.3 (May 22, 2026): "Increases to the limits of participation were enacted in Phase 3.2 on February 27, 2026"; ADERs registered "must be no greater than 500 MW system wide" and are limited to "no more than 100 MW of Non-Spinning Reserve (Non-Spin) system-wide and no more than 100 MW of ERCOT Contingency Reserve Service (ECRS) system-wide". ADER Pilot Program Update (April 1, 2026): energy limit 500 MW, ancillary services limit (Non-Spin and ECRS) 100 MW. ADER Phase 4, WMWG (September 25, 2026): "ECRS fully subscribed", "Non-Spin ~68% utilized", "293 MW of the 500 MW energy capacity limit". ADER Phase 4, WMS (October 7, 2026): Phase 4 adds the Aggregate Distributed Energy Storage Resource (ADESR), dispatched with nodal shift factors and settled zonally, "Ineligible" for ancillary services, timing "December 2026 (proposed)", with WMS endorsement November 4, TAC November 18 and ERCOT board approval December 7.
26 U.S.C. 48E, clean electricity investment credit, as amended by P.L. 119-21 (July 4, 2025) (retrieved 2026-11-03). 48E(a)(2)(B): 6% base, 30% for storage under 1 MW or meeting wage and apprenticeship rules. 48E(e): phase-down by construction start year, with the applicable year set to 2032 in 26 U.S.C. 45Y(d)(3). 48E(c)(3): no credit for storage starting construction after 2025 with material assistance from a prohibited foreign entity. 48E(i): no credit for leased property described in 25D(d)(1) or (4) (solar water heating, small wind).
26 U.S.C. 25D(h) (retrieved 2026-11-03). The homeowner credit ends for expenditures after December 31, 2025.
IRS Notice 2026-15 and IR-2026-23 (February 12, 2026). Interim rules for the material assistance cost ratio for energy storage starting construction after December 31, 2025; the storage threshold is 55% for 2026, rising to 75% for 2030 and later (IRC 7701(a)(52)).
26 CFR 1.48E-3 (T.D. 10024, January 15, 2025; retrieved 2026-11-04). (c)(4)(ii), EST One Megawatt Exception: storage units are "treated as having integrated operations" when "(A) Owned by the same or related taxpayers; (B) Placed in service in the same taxable year; and (C) Transmit energy through the same point of interconnection or ... are able to support the same end user." Cited as a risk to check, not a conclusion.
IRS, Clean Electricity Investment Credit (page updated 2026-01-05, retrieved 2026-11-03). Applies to storage placed in service after 2024; 6% base, up to 30%, plus 10-point domestic content and energy community bonuses.
ERCOT Nodal Protocols, current (read 2026-11-04). Section 2 (Oct 29, 2026 version): "Distributed Generator (DG): An electrical generator, including an Energy Storage System (ESS), that is connected ... through the Distribution System"; "Unregistered Distributed Generator (UDG): A generator with a nameplate capacity of one MW or less that is connected to the Distribution System, and which is not registered with ERCOT for the purpose of Settlement." Section 11.4.4.3 (Jun 1, 2026 version), Load Reduction for Excess from Other Distributed Generators: Adjusted Metered Load "shall be reduced for excess generation from ESI IDs with UDGs behind the meter", using "the actual 15-minute interval data" from an AMS meter when available. Section 6.6.3.2(1)(g), Real-Time Energy Imbalance Payment or Charge at a Load Zone: each QSE settles "its AML at the Settlement Point" at the Load Zone price. Section 6.6.3.8: settlement for a registered Settlement Only Distribution Generator.
ERCOT, Distributed Generation (retrieved 2026-11-04): "DG energy injections into a TDSP Distribution System will reduce the settlement Load of the Retail Electric Provider."
16 TAC 25.217(f)(2) (PUCT, Distributed Renewable Generation, retrieved 2026-11-04): in areas with customer choice, owners of renewable distributed generation "who choose to sell out-flows shall sell their out-flows to the REP that serves the premises ... at a value to which both parties agree." It covers renewable generation, not a grid-charged battery.
Optional preset only: Base Texas REP, Electricity Facts Label, Base Battery Plan, ONCOR (dated 10/07/2026, retrieved 2026-11-04). "Base Charge: $0 per month", "Energy Charge: 7.7¢ per kWh", "ONCOR Delivery Charge: 6.8673¢ per kWh and $4.06 per month", passed through "without-mark-up"; 15.0¢ per kWh at 1,000 kWh; 36-month fixed term; "Base will purchase solar energy generated by the customer's system at $0.04 / kWh."
ERCOT NPRR 932 PRS report (June 2019), Protocols 3.4.3 NOIE Load Zones: "There are four NOIE Load Zones that were approved prior to the Texas Nodal Market Implementation Date: Austin Energy, City Public Service, Rayburn Country Electric Cooperative, and Lower Colorado River Authority (LCRA)". ERCOT board item 13.2 (December 2025) names "Competitive Load Zones and NOIE Load Zones". PURA 40.051: a city's governing body "has the discretion to decide when or if the municipally owned utility will provide customer choice"; PURA 41.051: a co-op's board "has the discretion to decide when or if the electric cooperative will provide customer choice."
ERCOT hourly load data archives (2025 and 2026 native load by weather zone, retrieved 2026-11-04), used with our LZ_NORTH prices to weight the wholesale price by load. EIA Table 5A (2024): Texas residential average 1,096 kWh a month.
megawatt.fun zone value file, built from ERCOT market prices. Energy arbitrage per battery per zone, 12 months.