State analysis · source documents checked 2026-09-24
Solar payback in Indiana (IN) — 2026
In AES Indiana territory, a new solar system earns Rider 16 excess-generation credit, now 5.4325 cents per exported kWh, not net metering. Other Indiana utilities set their own rates.
What decides the answer in Indiana
Net metering is closed to new AES Indiana systems. The IURC order in cause 45504 (January 26, 2022, per the order's file name) applies Indiana Code 8-1-40-10: the net-metering tariff stays open until the earlier of a 1.5% capacity trigger or July 1, 2022, and AES expected it to stay available until July 1, 2022. Rider 16 lets eligible customers enroll from July 1, 2022 and excludes a facility operating under Rider 9 net metering. AES Indiana's solar FAQ gives the legacy dates: systems installed before January 1, 2018 may receive net-metering credits until July 1, 2047, and systems installed after December 31, 2017 and before July 1, 2022 until July 1, 2032. Those dates are the utility's own statement; the statute text was not retrieved in this check. A system installed in 2026 is an EDG system, and legacy status matters only for an array that was already operating before July 1, 2022. [1] [4] [2]
The EDG rate is the previous calendar year's average marginal price of energy multiplied by 1.25 (Indiana Code 8-1-40-17), updated by a compliance filing on or before March 1 each year. The order's initial calculation used a 2020 average hourly price of 22.37 dollars per MWh at the IPL.IPL load node, which gave 2.796 cents/kWh from July 1, 2022. The sheet effective July 1, 2024 listed 3.9350 cents. The current sheet (I.U.R.C. No. E-20, Original No. 172.2, issued under cause 46258, effective July 27, 2026) lists 5.4325 cents per kWh recorded on meter Channel 2. AES's solar FAQ page still showed 3.935 cents when checked on September 24, 2026; the tariff sheet is the governing document. Because the rate follows wholesale prices each year, no single figure holds for 25 years. [1] [3] [2] [4]
Rider 16 uses two meter channels. Channel 1 records energy the utility supplies to the home, billed at the normal rate schedule. Channel 2 records generation beyond what the home is using at that moment, and only that outflow earns the EDG rate. The order describes this as instantaneous measurement, so a month can include imports at the retail price and exports at the EDG rate even when the monthly totals look balanced. Credits cannot bring a bill below the Minimum Charge. Any excess carries forward indefinitely while the customer stays on the rider at that address. When service ends, unused credit goes to all customers through the fuel adjustment clause, and it cannot be moved to another account. [2] [1]
The AES figures do not apply elsewhere in Indiana. NIPSCO's Rider 589 (IURC cause 45505, order issued December 15, 2021, according to the state's Office of Utility Consumer Counselor) also bills inflow and outflow separately. The sheet in NIPSCO's current tariff library lists a Marginal DG Price of 3.8333 cents/kWh, effective March 31, 2025; no 2026 update was found in this check. Duke Energy Indiana files an annual EDG update under cause 45508 (its February 25, 2025 compliance filing proposed First Revised Tariff No. 54, pending Commission approval), but the rate in force in 2026 was not retrieved. Indiana Michigan Power's Rider EDG was approved in cause 45506, and CenterPoint's (then Vectren South) in cause 45378; their current rates were not retrieved. Rural electric cooperatives and municipal utilities are not covered here. [5] [6] [7] [8] [9]
For a quote, first confirm which utility serves the address and get its current EDG sheet. Then check that the installer's savings estimate separates self-used energy, valued at the import price, from Channel 2 exports, valued at the EDG rate. The household illustration below prints its own export-price input; compare that input with the published 2.796, 3.935 and 5.4325 cent rates above. Its self-use share is an assumption and needs interval load data before it can predict a bill. [2]
How Indiana pays for an exported kilowatt-hour
Export value differs from the full retail bill. The retail-value benchmark credits every kWh at the state-average import price. Under Rider 16 only Channel 2 outflow earns the EDG rate (5.4325 cents at AES Indiana from July 27, 2026), so the benchmark overstates export value. It is kept only for comparison across states, not as an Indiana estimate.
Document: Cause 45504; January 26, 2022 (file name ord_45504_012622); Indiana Code 8-1-40-10, -16, -17; Rider 16 rate calculation. Effective/source period: Initial Rider 16 rate from July 1, 2022; annual March 1 updates ordered.
Applies to: AES Indiana customers with new distributed generation after net metering closes. Relevant passage: “net metering tariff will remain available until July 1, 2022”.
Document: I.U.R.C. No. E-20, Original Nos. 172–172.3; Cause 46258. Effective/source period: July 27, 2026.
Applies to: AES Indiana customers with an eligible generator up to the lesser of 1 MW or average annual use; not Rider 9 net metering. Relevant passage: “5.4325¢ per KWH recorded on meter Channel 2.”.
Document: I.U.R.C. No. E-18, 3rd Revised No. 172.2. Effective/source period: July 1, 2024 rate sheet; replaced by the July 27, 2026 sheet.
Applies to: AES Indiana Rider 16 customers. Relevant passage: “3.9350¢ per KWH recorded on meter Channel 2.”.
AES Indiana solar FAQs — Utility's statement of legacy net-metering end dates (2032, 2047).
Document: Net metering and Rate EDG questions. Effective/source period: Retrieved September 24, 2026; its 3.935-cent rate is out of date.
Applies to: AES Indiana net-metering and Rate EDG customers. Relevant passage: “Eligible distributed generation systems after 6/30/2022 will not be eligible for net metering but will be eligible for Rate EDG”.
Document: IURC Electric Service Tariff, Original Volume No. 15, Rider 589; Second Revised Sheet No. 209. Effective/source period: Sheet No. 209 effective March 31, 2025; later updates not verified.
Applies to: NIPSCO excess distributed generation customers. Relevant passage: “Marginal DG Price: $0.038333/kwh for all Outflow”.
Document: Annual EDG Rate Update Compliance Filing; First Revised Tariff No. 54. Effective/source period: Filed February 25, 2025, pending approval when filed; the 2026 rate was not retrieved.
Applies to: Duke Energy Indiana EDG customers. Relevant passage: “First Revised Tariff No. 54”.
Document: Cause 45506 order. Effective/source period: Order January 26, 2022 (per file name ord_45506_012622; the order's APPROVED date line is blank); current rate not retrieved.
Applies to: Indiana Michigan Power customers in Indiana. Relevant passage: “CAUSE NO. 45506”.
Document: Cause 45378 order. Effective/source period: Historical order; current rate not retrieved.
Applies to: CenterPoint Energy Indiana South customers. Relevant passage: “CAUSE NO. 45378”.
“Source documents checked 2026-09-24” means each linked document was retrieved on that date and the passage quoted under it is the text the claims in this section rely on. The date covers only those claims. It is not a household eligibility decision or a guarantee that a tariff is still current, so check the linked live documents before signing a contract, and report corrections via the contact page.
Common retail-value benchmark — not a household forecast
No incentives; every modeled kWh is valued at the historical state-average retail price. The household scenarios below separate assumed import/export prices, consumption share, cash cost and receipt timing.
How Indiana compares with the other 50 records in this dataset
Measure
Indiana
Dataset median
Rank of 51
Avg residential rate
14.77¢/kWh
14.91¢/kWh
27th highest
NSRDB daily sunlight (one location per state)
4.8 kWh/m²/day
4.9 kWh/m²/day
32nd highest
Retail benchmark payback
13.7 years
13.0 years
33rd fastest on this benchmark
Household scenarios below (range)
16.0 years to 22.6 years
—
Not ranked across states
The rank compares every state on the same full-retail basis; it is a benchmark, not a forecast for a new Indiana customer. The household scenarios below, each with its own stated import price, export credit, cost and incentive timing, give 16.0 years to 22.6 years.
Rate: Calendar year 2024 annual average, from the EIA. Sunlight is NSRDB data via NLR PVWatts v8 at each state's 2020 Census center of population, one location per state (request settings and the values PVWatts returned are in state-insolation-pvwatts.json). Ranks and medians are computed across the 50 states and DC in this dataset. Every input behind the payback figure is printed in the assumptions block below, and the full 51-row table is at /states.
Reproduce the Indiana household comparisons
These are hypothetical households, not customer results or offers. All start from an assumed 7 kW array producing 9466.27 kWh in year one; any row that changes production (a battery or a production-stress row) says so. The sunlight input is NSRDB data via PVWatts v8 for one location per state (request and response in state-insolation-pvwatts.json; see the methodology), not a production estimate for your roof. No federal credit is applied. No loan, income-tax effect on incentive revenue, battery replacement or future tariff change is modeled.
The benchmark row prices every kWh at the EIA average cited above. Where another row applies a published figure (for example a tariff or rider rate or charge, a program incentive rate, a statutory fee schedule, or a tax credit's rate, cap or carryforward period), that figure comes from a document in the sources list above. Every other price, consumption share, cost, fee, receipt date and amount of tax a household can use in a year is assumed. Eligibility remains conditional. The annual split does not reproduce monthly netting, time-of-use periods, credit caps, curtailment or minimum bills. Annual fees represent incremental solar costs, not charges you would pay with or without solar.
Production degrades by assumed 0.5% per year. The main result increases both import and export prices by assumed 3% per year; the flat-price column sets that to zero. Neither escalation is a tariff forecast. Fixed fees and scheduled receipts do not escalate. Energy savings accrue uniformly within a year for interpolation; incentives arrive only at year end.
Modeled results, not guarantees. No break-even means no crossing inside 25 years, not a calculated date beyond year 25.
Scenario
Initial cash cost
Year 1 energy value
Year 1 net cash incl. receipts
Payback
Flat-price payback
25-year net cash after cost
Common retail-value benchmark — no incentives
$22,400.00
$1,398.17
$1,398.17
13.7 years
16.7 years
Modeled $25,265.64
Hypothetical household — no incentives
$22,400.00
$899.30
$899.30
19.6 years
no break-even inside 25 years
Modeled $8,258.34
Illustrative higher cash price — no incentives
$26,880.00
$899.30
$899.30
22.6 years
no break-even inside 25 years
Modeled $3,778.34
Illustrative 75% self-use — no incentives
$22,400.00
$1,159.62
$1,159.62
16.0 years
20.3 years
Modeled $17,133.12
AES Indiana: published Rider 16 excess-generation rate — no incentives
$22,400.00
$967.10
$967.10
18.5 years
24.6 years
Modeled $10,569.81
Inputs, receipts and annual arithmetic: Common retail-value benchmark — no incentives
Historical state-average import value for ALL production; only a comparison, not an address-specific tariff.
Assumed initial cash cost $22,400.00, not reduced by any upfront credit or rebate; any receipt is listed below and arrives at year end. Import 14.770¢/kWh; export 14.770¢/kWh; self-use 100%; incremental fixed annual cost $0.00.
Year-one modeled energy value = 9466.27 × [(100/100 × 14.77/100) + ((1 − 100/100) × 14.77/100)] = $1,398.17. Subtract the annual fixed cost and add only that year's receipts for net cash. Display rounds cents; the downloadable calculation retains full precision.
Incentive basis: None; no eligibility or benefit assumed. Modeled total receipts inside 25 years: $0.00. These are not subtracted from initial cash cost.
The exact input fields and all 25 modelled years for this row are in the JSON download above.
Inputs, receipts and annual arithmetic: Hypothetical household — no incentives
Assumed round 15-cent import price, rounded up from the 14.77-cent EIA 2024 Indiana average, and an assumed round 4-cent export price. It is not any utility's rate: it sits between NIPSCO's 3.8333-cent Marginal DG Price (Rider 589, sheet effective March 31, 2025) and AES Indiana's 5.4325-cent Rider 16 rate (row below). Other Indiana utilities' current rates were not retrieved here, and actual instantaneous netting needs interval data.
Assumed initial cash cost $22,400.00, not reduced by any upfront credit or rebate; any receipt is listed below and arrives at year end. Import 15.000¢/kWh; export 4.000¢/kWh; self-use 50%; incremental fixed annual cost $0.00.
Year-one modeled energy value = 9466.27 × [(50/100 × 15/100) + ((1 − 50/100) × 4/100)] = $899.30. Subtract the annual fixed cost and add only that year's receipts for net cash. Display rounds cents; the downloadable calculation retains full precision.
Incentive basis: None; no eligibility or benefit assumed. Modeled total receipts inside 25 years: $0.00. These are not subtracted from initial cash cost.
The exact input fields and all 25 modelled years for this row are in the JSON download above.
Inputs, receipts and annual arithmetic: Illustrative higher cash price — no incentives
Same production, prices, consumption share and fees, but cash cost is 20% higher; not a market-price estimate.
Assumed initial cash cost $26,880.00, not reduced by any upfront credit or rebate; any receipt is listed below and arrives at year end. Import 15.000¢/kWh; export 4.000¢/kWh; self-use 50%; incremental fixed annual cost $0.00.
Year-one modeled energy value = 9466.27 × [(50/100 × 15/100) + ((1 − 50/100) × 4/100)] = $899.30. Subtract the annual fixed cost and add only that year's receipts for net cash. Display rounds cents; the downloadable calculation retains full precision.
Incentive basis: None; no eligibility or benefit assumed. Modeled total receipts inside 25 years: $0.00. These are not subtracted from initial cash cost.
The exact input fields and all 25 modelled years for this row are in the JSON download above.
Inputs, receipts and annual arithmetic: Illustrative 75% self-use — no incentives
Assumes a different load profile serves 75% of production on site without added equipment cost. This is a sensitivity, not a promised behavioral saving.
Assumed initial cash cost $22,400.00, not reduced by any upfront credit or rebate; any receipt is listed below and arrives at year end. Import 15.000¢/kWh; export 4.000¢/kWh; self-use 75%; incremental fixed annual cost $0.00.
Year-one modeled energy value = 9466.27 × [(75/100 × 15/100) + ((1 − 75/100) × 4/100)] = $1,159.62. Subtract the annual fixed cost and add only that year's receipts for net cash. Display rounds cents; the downloadable calculation retains full precision.
Incentive basis: None; no eligibility or benefit assumed. Modeled total receipts inside 25 years: $0.00. These are not subtracted from initial cash cost.
The exact input fields and all 25 modelled years for this row are in the JSON download above.
Inputs, receipts and annual arithmetic: AES Indiana: published Rider 16 excess-generation rate — no incentives
AES Indiana's Rider 16 (I.U.R.C. No. E-20, Original No. 172.2, Cause No. 46258, effective July 27, 2026) sets the excess distributed generation rate at 5.4325 cents per kWh recorded on meter Channel 2 (net outflow). This row applies 5.4325 cents to every exported kWh, with the same assumed 15-cent import price and 50% self-use. The rate is updated periodically and, like every price here, escalates in the main column only as an assumption. AES Indiana territory only.
Assumed initial cash cost $22,400.00, not reduced by any upfront credit or rebate; any receipt is listed below and arrives at year end. Import 15.000¢/kWh; export 5.433¢/kWh; self-use 50%; incremental fixed annual cost $0.00.
Year-one modeled energy value = 9466.27 × [(50/100 × 15/100) + ((1 − 50/100) × 5.4325/100)] = $967.10. Subtract the annual fixed cost and add only that year's receipts for net cash. Display rounds cents; the downloadable calculation retains full precision.
Incentive basis: None; no eligibility or benefit assumed. Modeled total receipts inside 25 years: $0.00. These are not subtracted from initial cash cost.
The exact input fields and all 25 modelled years for this row are in the JSON download above.
Formula and modeling limitations · Use the editable calculator below to test your own cash price and energy split. It cannot confirm utility enrollment or tax eligibility.
Assumptions behind the Indiana retail-value benchmark
A common full-retail comparison, not an address-specific forecast. Size alone does not change payback when cash cost and production both scale proportionally. Use the worksheet to vary cash price, production, self-consumption, export value and recurring costs.
System modeled
7 kW DC
Assumed installed cost
$22,400 (assumed $3.20/W DC)
Annual production, year 1
9,466 kWh
Production basis
NSRDB daily sunlight on a 20° south-facing panel at Indiana's 2020 Census population center (4.75 kWh/m²/day, via PVWatts v8). Annual production = system kW × this input × 365 × assumed performance ratio. PVWatts' own modelled AC output for the same request is 1,353.8 kWh per kW, or 9,477 kWh for 7 kW, so this shortcut runs 0.1% below it; on the PVWatts figure the benchmark payback would be 13.6 years.
Performance ratio (system losses)
0.78
EIA state-average retail rate
14.77¢/kWh — Calendar year 2024 annual average
Panel degradation
0.5%/yr
Assumed electricity price escalation
3.0%/yr, not a forecast
Model horizon
25 years
Federal tax credit applied
None included in this benchmark
State or utility incentives applied
None deducted in this benchmark. Where a household scenario above applies a published tariff rate or a conditional receipt, its row says so; this benchmark applies none of them
Assumed value of all production
Full retail rate, including exports; not a utility tariff lookup
Recurring operating costs applied
None in this benchmark; editable in worksheet
How the payback figure reconciles
Modelled $22,400 ÷ modelled $1,398 of year-one savings = 16.0 years — the straight division, if electricity prices never move and the panels never age.
With 0.5%/yr degradation and prices held flat: 16.7 years.
With the same degradation and electricity prices rising 3.0%/yr: 13.7 years — the retail-value benchmark, not a household forecast.
Production stress test, same assumed prices: 20% less production (shading, a poorer roof angle) gives 16.5 years; 20% more production gives 11.7 years. This is a what-if range, not a confidence interval.
These price-growth rates are assumptions, not forecasts of your utility's tariff. None of these cases models financing, taxes, battery dispatch or actual utility settlement. No crossing within 25 years does not establish a crossing later. Full wording on the methodology.
Solar cash-flow worksheet
Compare assumed cash flows, not an address-specific forecast. No tariff, roof or incentive eligibility is looked up. Your worksheet entries are calculated in this browser; the worksheet does not send them anywhere or save them between visits. The site also loads Google advertising code; the privacy page explains what that code may collect and your choices.
Starting retail rate: 14.77¢/kWh — Calendar year 2024 annual average (Indiana), from EIA Table 2.10. It is not your current tariff. All cost, export, usage, escalation and incentive entries are assumptions.
With no incentives or recurring costs, fixed cost/W and proportional generation mean that increasing size scales cost and savings equally: payback years cancel out. Unedited price and production follow that rule here. Once you edit either, it stays fixed when size changes; update it deliberately. Different cash prices, shading/production and export shares can change payback.
Optional assumed cash incentives — zero by default
No federal, state or utility incentive is inferred. Check eligibility and actual receipt timing. Recurring and delayed incentives arrive at year end; do not enter the same benefit in multiple fields. Operating cash is approximated uniformly within each year.
Your entered scenario — modelled, not a quote
Modelled installed cash price
$22,400
Modelled initial outlay after upfront rebate
$22,400
Modelled year-one net cash, including receipts/costs
$1,398
Modelled first cash-flow break-even
13.7 years
Modelled 25-year net cash after initial outlay
$25,266
Modelled production in year one
9,466 kWh
Modelled year-one energy value before costs/incentives: $1,398.
No break-even inside 25 years means the model never crosses within its horizon; it does not predict a later crossing. This is undiscounted cash flow, not investment return. A first crossing can reverse if later operating costs exceed cash benefits. Financing, taxes, changing export rules, time-of-use settlement, credit expiry and battery dispatch are not simulated.
Assumed price-escalation sensitivity
Same entered inputs, degradation and nominal fixed costs; only import/export price escalation changes. These are scenarios, not forecasts.
0%/year: 16.7 years
3%/year: 13.7 years
6%/year: 11.8 years
Separate common retail-value benchmark
This comparison uses 7 kW, assumed $3.20/W, production from the state's one-location NSRDB sunlight input and 14.77¢/kWh (Calendar year 2024 annual average) for every kWh. It ignores your entered cash price, production, tariff, costs and incentives; assumes 0.5% degradation and 3% escalation. It is not an address forecast.
Benchmark assumed cash price
$22,400
Benchmark modelled year-one value
$1,398
Benchmark modelled break-even
13.7 years
Reproduce the 25-year modelled cash flows for your entered scenario
Annual cash = degraded production × weighted import/export price × price-escalation factor − annual fixed cost + eligible year-end receipts. Cumulative cash starts at negative initial outlay. Incentives after year 25 are excluded.
Use your utility tariff and a site-specific production assessment to refine inputs. Methodology and limitations.
Estimate only. State comparisons are common retail-value benchmarks, not forecasts for your roof. Custom scenarios depend on the cash price, production, import/export prices, self-consumption and other assumptions entered. They are not quotes or guarantees. Listed incentives do not establish eligibility or a payment date. The Residential Clean Energy Credit (Section 25D, the 30% federal tax credit) expired for systems placed in service after December 31, 2025. Verify all numbers with a licensed installer and your utility before making a purchase decision. See full disclaimer.
Compare every state
Indiana is one of 17 jurisdictions with a written analysis on this site: 16 states and the District of Columbia. The rate, sunlight, modeled payback and recorded incentives for all 50 states and DC — including those without a page — are in one sortable table.