Indiana Net Metering Policy Explained

Indiana's net metering framework governs how residential and commercial solar customers receive credit for surplus electricity exported to the grid, directly affecting the financial return on every solar installation in the state. This page covers the statutory definition, billing mechanics, utility-specific variations, classification rules, contested policy tensions, and common misconceptions surrounding Indiana net metering. Understanding these rules is essential context for evaluating solar system sizing, utility compatibility, and long-term energy economics under Indiana law.

• Definition and Scope
• Core Mechanics or Structure
• Causal Relationships or Drivers
• Classification Boundaries
• Tradeoffs and Tensions
• Common Misconceptions
• Checklist or Steps
• Reference Table or Matrix

Definition and scope

Net metering in Indiana is the billing arrangement under which an eligible customer-generator's electricity meter measures the difference between electricity consumed from the grid and electricity supplied to the grid by the customer's qualifying generation system. When generation exceeds consumption during a billing period, the net surplus flows to the utility, and the customer receives a credit.

Indiana's net metering statute is codified at Indiana Code § 8-1-40, enacted in 2017 as part of Senate Enrolled Act 309. The Indiana Utility Regulatory Commission (IURC) has jurisdiction over net metering rules as they apply to investor-owned utilities (IOUs) such as Indiana Michigan Power, Duke Energy Indiana, and Indianapolis Power & Light (now AES Indiana). The statute set a phased transition timeline that effectively changed the compensation structure starting in 2022 for new applicants at those IOUs.

Scope and geographic coverage: This page applies exclusively to Indiana-jurisdictional utilities and customers subject to IURC authority. Municipal utilities and rural electric cooperatives (RECs) operate under different governance structures — they are not required by state statute to offer net metering under the same terms as IOUs, though some do. Federal interconnection rules under FERC jurisdiction (such as FERC Order 2222 and PURPA) operate in parallel but are not covered here. Policies in Ohio, Illinois, Michigan, or Kentucky — even for Indiana residents near state borders — are outside this page's scope. Commercial and industrial net metering above 1 megawatt (MW) nameplate capacity involves additional IURC proceedings not detailed here.

For a broader view of how solar generation physically connects with utility infrastructure, see How Indiana Solar Energy Systems Works: Conceptual Overview. For the full regulatory landscape governing these interactions, see Regulatory Context for Indiana Solar Energy Systems.

Core mechanics or structure

Under the pre-2022 legacy net metering structure, Indiana IOUs credited surplus generation at the full retail electricity rate — meaning each kilowatt-hour (kWh) exported offset one kWh of consumption at the same price the customer paid to purchase electricity.

Senate Enrolled Act 309 introduced a phased compensation reduction. Customers who applied for interconnection before July 1, 2022, are grandfathered at full retail net metering for 30 years from their approval date. Customers who applied on or after July 1, 2022, receive credits at a "transitional" rate — not the full retail rate — for surplus generation. The transitional rate is set by each utility through IURC rate cases and is generally lower than the retail rate, reflecting the utility's avoided cost or a negotiated value-of-solar calculation.

Billing cycle mechanics:
1. A bidirectional meter records both imported and exported energy in kWh.
2. At the end of each monthly billing cycle, the utility calculates net consumption (imported kWh minus exported kWh).
3. If net consumption is positive, the customer pays for net kWh at the applicable retail rate.
4. If net consumption is negative (net surplus), the credit is calculated at the applicable compensation rate — retail for grandfathered customers, transitional rate for post-July 2022 applicants.
5. Monthly surplus credits roll forward to the next billing period.
6. At the annual true-up (typically the customer's anniversary month), any remaining annual surplus is compensated — the terms vary by utility and rate case.

The Indiana Utility Regulatory Commission (IURC) publishes rate case orders that set the transitional compensation rates for each IOU. Customers should consult their utility's current tariff schedule, filed with the IURC, for the specific per-kWh credit value.

For customers considering battery storage integration alongside net metering, the interaction between storage dispatch and metered export introduces additional complexity covered at Indiana Solar Battery Storage Integration.

Causal relationships or drivers

Three forces shaped Indiana's transition away from full retail net metering.

1. Cost-shift argument: Investor-owned utilities argued before the IURC that full retail net metering caused non-solar customers to subsidize the fixed grid costs of solar customers. The utilities contended that solar customers, by reducing their net consumption, contribute less to recovering fixed transmission and distribution infrastructure costs while still relying on that infrastructure for backup power.

2. Solar adoption growth: Indiana's installed solar capacity grew from under 100 MW in 2015 to over 1,800 MW by 2023 (U.S. Energy Information Administration, Indiana State Profile), increasing the financial significance of net metering credits on utility revenue requirements.

3. Legislative compromise: Senate Enrolled Act 309 represented a negotiated outcome between solar industry stakeholders and investor-owned utilities. The 30-year grandfather provision was a concession to existing and near-term solar adopters; the post-2022 transition to lower rates was a concession to utility cost-recovery arguments.

Rural electric cooperatives were largely outside this legislative battle, which is why their net metering policies vary considerably — a factor examined further at Indiana Rural Electric Cooperative Solar Policies.

Classification boundaries

Indiana net metering rules create distinct customer classes with different rights:

Systems larger than 1 MW nameplate capacity are generally classified as wholesale generators and interact with PJM Interconnection's wholesale market rules rather than retail net metering tariffs.

The nameplate capacity cap of 1 MW applies to the generating equipment installed, not to projected annual output. A 999 kW rooftop array qualifies; a 1.1 MW ground-mount system at a commercial facility would not qualify under standard net metering and requires a separate interconnection agreement. For sizing methodology relevant to staying within these thresholds, see Indiana Solar System Sizing Methodology.

Tradeoffs and tensions

Value gap: The transitional rate paid to post-2022 customers is typically set below the retail rate, which lengthens the payback period for new solar installations. A system sized to maximize self-consumption (keeping exports low) performs better financially under the new structure than a system sized to maximize generation without regard to on-site load.

Grandfathering asymmetry: Two identical homes on the same street may receive radically different credit rates — one at the full retail rate for decades, the other at a substantially reduced rate — based solely on application date. This creates a time-sensitive decision dynamic that distorts market behavior and can appear arbitrary to affected customers.

Cooperative and municipal opacity: Because RECs and municipal utilities are not required to file standardized net metering tariffs with the IURC, their policies are less transparent and less uniform. A customer served by Wabash Valley Power Alliance or Tipmont REMC may face policies with no public comparable benchmark.

Storage interaction: Customers who add battery storage after receiving a grandfathered net metering approval risk losing that grandfathered status if the storage addition is treated as a system modification requiring a new interconnection application. The IURC has not issued a uniform statewide rule on this question as of the most recent published orders; it remains a utility-specific determination.

For broader financing implications of the transitional rate structure, the analysis at Indiana Solar Financing Options addresses how lenders and lease providers model post-2022 credit values.

Common misconceptions

Misconception 1: Net metering means the utility pays cash for exported solar.
Indiana net metering generates billing credits, not cash payments. Surplus credits reduce future bills; they do not result in a check from the utility. At annual true-up, any remaining credit balance may be forfeited or paid out at a wholesale rate substantially below retail — specific terms depend on the utility's IURC-approved tariff.

Misconception 2: All Indiana solar customers receive the same rate.
The three-tier structure (grandfathered, post-2022 IOU, cooperative/municipal) produces materially different outcomes. Customers of Duke Energy Indiana receive a different transitional rate than customers of AES Indiana, and both differ from cooperative members who may have no formal net metering tariff at all.

Misconception 3: Net metering is the same as the SREC market.
Net metering governs the billing credit for exported electricity. Solar Renewable Energy Credits (SRECs) are a separate instrument representing the environmental attribute of each MWh generated, entirely independent of net metering credits. Indiana does not have an active mandatory SREC market; these are distinct topics. The SREC distinction is explored further at Indiana SREC Market and Renewable Energy Credits.

Misconception 4: Grandfathered status transfers automatically with a home sale.
Grandfathered net metering status is tied to the interconnection agreement, not the property deed. Whether grandfathered status survives a property transfer depends on the utility's tariff language. Buyers of homes with existing solar should request written confirmation from the utility before assuming continued full retail credits.

Misconception 5: A larger system always produces better financial outcomes.
Under post-2022 transitional rates, oversizing a system to maximize exports can reduce overall financial return because surplus kWh are credited at the lower transitional rate. Optimizing system size to match consumption patterns is more financially efficient for post-2022 applicants than maximizing installed capacity.

Checklist or steps

The following sequence describes the procedural stages involved in establishing net metering service with an Indiana investor-owned utility. This is a descriptive process outline, not professional guidance.

1. Confirm utility jurisdiction — Identify whether the property is served by an IURC-regulated IOU, a municipal utility, or a rural electric cooperative. The applicable net metering rules differ for each category.
2. Review applicable tariff — Obtain the current net metering tariff schedule from the utility's IURC-filed rate cases or the utility's published tariff documents. Note the transitional compensation rate applicable to new applicants.
3. Submit interconnection application — File the utility's interconnection application form, which includes system specifications: inverter type, nameplate capacity (kW DC and AC), proposed point of interconnection, and equipment documentation. Interconnection requirements are detailed at Indiana Utility Interconnection Requirements.
4. Receive technical review determination — The utility performs a screens-based technical review (simplified process for systems under 25 kW) or a full supplemental review for larger systems. The utility has defined review windows per IURC rules.
5. Execute interconnection agreement — Upon approval, sign the interconnection agreement. The date of execution establishes whether grandfathered or transitional net metering rates apply.
6. Schedule inspection and meter installation — Coordinate the electrical inspection (local AHJ) and the utility's installation of a bidirectional meter. Permitting concepts are covered at Permitting and Inspection Concepts for Indiana Solar Energy Systems.
7. Receive permission to operate (PTO) — The utility issues written PTO before the system is energized and export begins. Operating prior to PTO may void interconnection approval.
8. Monitor billing credits — Review monthly utility bills to confirm net metering credits are applied at the correct rate and that rollover credits are accumulating accurately.
9. Track annual true-up date — Note the anniversary month when any accumulated annual surplus is settled. Understand the utility's specific settlement terms from the executed agreement.

For a broader timeline context, Indiana Solar Installation Timeline: What to Expect maps these steps within the full project schedule.

The site's homepage provides orientation to the full range of Indiana solar reference topics covered across these interconnected subjects.

Reference table or matrix

Indiana Net Metering Compensation Structure by Customer Segment

Key Indiana IOU Net Metering Parties

References

• Indiana Code § 8-1-40 — Net Metering — Primary statutory authority for Indiana net metering, enacted via Senate Enrolled Act 309 (2017)
• Indiana Utility Regulatory Commission (IURC) — State agency with jurisdiction over investor-owned utility net metering tariffs and interconnection rules
• U.S. Energy Information Administration — Indiana State Profile — Source for Indiana installed solar capacity data
• FERC Order 2222 — Federal Energy Regulatory Commission rule governing distributed energy resource aggregation, applicable to systems interacting with wholesale markets
• PJM Interconnection — Regional transmission organization operating the wholesale electricity market covering Indiana IOUs
• Indiana General Assembly — Senate Enrolled Act 309 (2017) — Legislative source document establishing the net metering transition timeline and grandfathering provisions