Indiana Solar in 2026: The SEA 309 Avoided-Cost Trap & the Self-Consumption Case

For most Indiana homeowners, yes - but the case rests almost entirely on self-consumption. An 8 kW rooftop system costs about $22,400 (2.80/W - below the national average) and pays back in roughly 13.8 years on the strength of cheap hardware, a solid $0.179/kWh retail rate, and a property tax exemption. Indiana's 25-year ROI of approximately 143% is actually strong - better than several states with richer export terms - precisely because the low cost-per-watt compounds over the system life and the self-consumed portion of production earns full retail. The catch is that exported surplus earns only $0.03-0.05/kWh under the EDG tariff, so the math depends on sizing the array to consume, not to export.

Senate Enrolled Act 309 (2017) is the Indiana legislation that transitioned the state from full-retail net metering to the Excess Distributed Generation (EDG) framework. Under EDG, exported surplus is credited at each utility's avoided cost - roughly $0.03-0.05/kWh depending on utility and period - rather than at the full retail rate. The transition was phased in through 2022 for residential systems, with earlier NEM customers grandfathered for 15 years. The Indiana Utility Regulatory Commission (IURC) oversees each utility's avoided-cost filing. SEA 309 is the single most important Indiana solar policy of the last decade: it made self-consumption the value driver and turned oversized arrays into a slower-payback proposition.

Indiana runs a two-tier export system (with a third, legacy tier for grandfathered customers). <strong>Tier 1 - Self-consumption:</strong> every kilowatt-hour you use on-site offsets the full retail purchase price ($0.15-0.18/kWh), entirely unaffected by SEA 309. This is the economic backbone. <strong>Tier 2 - EDG export:</strong> surplus exported to the grid is credited at each utility's avoided cost under the EDG framework, roughly $0.03-0.05/kWh - the NemRate of $0.06/kWh in our policy database is a representative midpoint. This is 4-6x less than the value of self-consumed energy. <strong>Tier 3 - Grandfathered full retail:</strong> only for systems interconnected before the SEA 309 transition; this cohort is shrinking as legacy terms expire.

Size to consume, not to export. Because Tier 1 self-consumption is worth $0.15-0.18/kWh while Tier 2 EDG exports are worth only $0.03-0.05/kWh, every kilowatt-hour you use yourself is worth roughly 4-6x what you export. The optimal Indiana system covers your daytime and annual consumption as closely as possible, minimizing surplus sent to the grid. West- and southwest-facing arrays that extend production into the late-afternoon air-conditioning peak can outperform pure south-facing designs on dollars - even though they produce fewer total kilowatt-hours - because they shift generation into high-value self-consumption windows. Use our <a href="/tools/system-size-calculator/">System Size Calculator</a> with your actual annual usage, and aim for 70-100% offset of consumption rather than over-sizing for export surplus.

For most homeowners, a battery is a marginal-ROI purchase in Indiana - not as clearly negative as in full-retail-NEM states, but rarely justified on economics alone. With EDG exports already low-valued at $0.03-0.05/kWh, a battery's incremental value comes from shifting consumption to avoid exporting at a few cents per kilowatt-hour - which can be worth doing but rarely covers the battery's cost over its life. Batteries in Indiana are justified for <strong>resilience</strong>: severe thunderstorm outages (especially in spring and summer), households with medical equipment dependencies, or rural areas with less reliable distribution. Indiana's severe-weather season is a real factor. If resilience is not a hard requirement for your household, skip the battery and put the savings into a slightly larger array sized to your consumption - or into higher-efficiency panels that extract more from constrained roof space.

A typical 8 kW rooftop system in Indiana runs about $22,400 (2.80/W) before incentives - below the national average, reflecting strong installer competition in the Midwest. The 30% federal residential credit (Section 25D) expired December 31, 2025, so owned systems placed in service in 2026 receive $0 federal credit. Leased/PPA systems may still capture Section 48E for projects that began construction before July 4, 2026. Indiana offers a property-tax exemption (IC 6-1.1-6-3.3) but, importantly, NO state sales-tax exemption - the 7% state rate applies (budget roughly $1,570 on an 8 kW purchase). The economic case rests on cheap hardware, the $0.179/kWh retail rate, and the property tax exemption.

Indiana's tax posture is thin on the incentive side but stable on property tax. There IS a property-tax exemption: solar energy systems are exempt from the property-tax assessment increase they would otherwise trigger, under Indiana Code 6-1.1-6-3.3 - your system will not raise your tax bill. However, Indiana does NOT exempt solar equipment from sales tax: the 7% state rate applies to the equipment purchase. There is no state solar income-tax credit, and Indiana has no SREC market. The contrast with neighboring Illinois, which stacks Illinois Shines REC income on more favorable export terms, is notable - cross-link to our <a href="/solar-by-state/illinois-comprehensive-guide/">Illinois comprehensive guide</a> for the comparison. Indiana's case rests on cheap hardware, a solid retail rate, and high self-consumption value.

Indiana's five investor-owned utilities divide the state. <strong>Duke Energy Indiana</strong> serves the south-central and central tier including Bloomington and the Carmel area; <strong>AES Indiana</strong> (formerly Indianapolis Power & Light) serves the Indianapolis metro; <strong>NIPSCO</strong> serves the northern tier including the South Bend-Elkhart-Gary corridor; <strong>CenterPoint Energy Indiana</strong> (formerly Vectren) serves the Evansville area and the southwest; and <strong>Indiana Michigan Power</strong> (I&M, an AEP subsidiary) serves Fort Wayne, South Bend, and the eastern tier. Check your electric bill to confirm your utility. Each utility files its own avoided-cost rate under the EDG framework, so the value of your exports depends on which utility serves you - this is the detail that most affects a correct sizing decision.

After the 2026 expiration of the Section 25D residential credit, the structure carries real federal-tax consequences. A cash purchase or low-interest loan keeps the full long-term savings but receives $0 federal credit - Indiana's thin state incentive menu means there is little offsetting state value either way. A lease or PPA eliminates upfront cost and can still capture Section 48E (the developer claims the 30% credit and passes value through as lower payments) on projects that began construction before July 4, 2026. In Indiana's EDG environment, pay particular attention to how a lease interacts with your utility's avoided-cost export terms - some third-party-owned systems may be treated differently under EDG. Compare both paths with your actual utility and consumption profile.

Indiana averages about 4.5 peak sun hours per day statewide - the Midwestern norm, with productive summers offset by shorter, often cloudy winter days. A south-facing 8 kW array tilted near latitude (~40°) typically produces on the order of $11,300 kWh per year (the state-database figure is 11,300 kWh). Production varies modestly by region: southern Indiana (Evansville, the Ohio River valley) runs marginally higher, while the lake-effect snowbelt around South Bend and Fort Wayne compresses winter output. Cold, clear winter days actually improve panel efficiency, partially offsetting shorter daylight. Because EDG export value is so low, the optimal strategy is to maximize self-consumption - align production with your daytime usage rather than maximizing raw export.

It depends on your interconnection date. Systems interconnected before SEA 309's residential transition (phased through 2022) were grandfathered at full-retail export terms for 15 years. If you interconnected before that window, you may still be on full-retail exports - check your interconnection paperwork or contact your utility. If you interconnected after the SEA 309 transition, you are on the EDG avoided-cost tariff (Tier 2). The grandfathering cohort is shrinking as the 15-year terms elapse, so the value of pre-SEA 309 systems as a transferable asset has declined. Track your utility's current terms with our <a href="/tools/nem-grandfathering-calculator/">NEM Grandfathering Calculator</a>.

Because export value is so low under EDG, total kilowatt-hours matter less than the timing of those kilowatt-hours. A pure south-facing array produces the most annual energy but peaks at midday - when many households are unoccupied and a larger share of generation is exported at the avoided-cost rate ($0.03-0.05/kWh). A west- or southwest-facing array produces 10-15% fewer total kilowatt-hours but shifts production into the late-afternoon air-conditioning peak, when occupancy and consumption are high - so a larger share of generation is self-consumed at the full retail rate ($0.15-0.18/kWh). On dollars, the west-facing array can come out ahead. This is the Indiana sizing lesson: optimize for self-consumption value, not raw production.