Top Tier Indiana Battery Sales Reference

Internal Sales Team Resource — Q2 2026 Edition

Sales Architecture (Read First)

This section establishes the pitch architecture every IN rep uses — takeover-led lead, cohort-aware bridge (with NIPSCO FIT honest framing), hidden-costs bundle, ownership reframe. Read this FIRST. Utility-specific detail (rate cases, cohort cliffs, I&M TOU mechanics, IURC Cause 45506 progression) lives in the sections below and is referenced where it bears on the architecture.

Standing Rules (Do NOT Violate)

• ❌ NEVER pitch bill savings to a NIPSCO FIT (Rate 665) customer. FIT customers get paid ~17¢/kWh for exports while paying ~20¢/kWh for imports — battery installed under FIT REMOVES the export-rate income (every self-consumed kWh loses the 17¢ export payment). If they want a battery for resilience, pitch resilience-primary and be HONEST about the math.
• ❌ NEVER coach reps to disqualify based on home tenure. If a customer plans to sell in 3 years, the right move is the resale story (system raises home value; closing equity pays off loan; warranties carry over per their actual transfer rules) — not "walk away."
• ❌ NEVER claim "all warranties transfer." Workmanship transfers WITH WRITTEN CONSENT. Manufacturer warranties transfer per their own terms. The 5-year Align Solar Protection service contract is NON-TRANSFERABLE.
• ❌ NEVER fabricate inspection findings. The inspection is mostly about education + diagnosing the bill problem + future-failure prevention.
• ❌ NEVER apply EDG cohort math to a NM I, NM II, or NIPSCO FIT customer. Different cohorts get different conversations. Get the cohort wrong and the proposal math is wrong.
• ❌ NEVER pitch a TOU rate switch at AES / CenterPoint / Duke IN / NIPSCO. Only I&M has an open residential TOU (Tariff R.S.-TOD2). The other four either have no residential TOU or have pilots that aren't battery-arbitrage-friendly. I&M TOU stack is an I&M-only pitch.
• ❌ NEVER pitch a residential VPP / DR program at any IN IOU. None operate today. Adjacent-market programs (Duke NC EnergyWise, MD DRIVE Act pilots) are NOT available to IN customers.
• ❌ NEVER pitch the Section 25D federal battery-with-solar 2026 residual credit without tax-counsel review. Federal solar ITC expired 12/31/2025. IN has no state-level extension. (IN sales-tax and property-tax exemptions still apply — see Tax Landscape section.)

The LEAD: Takeover-Led Opening (use for all 5 IN utilities, ALL cohorts)

The customer booked the appointment because they're frustrated about their utility bill AND their installer is unreachable. Don't open with savings math. Don't open with rate-case statistics. Don't open with SEA 309. Open with:

1. The free system inspection. "I'm here to inspect your existing solar system at no cost. If it's running well, we'll confirm that. If anything's wrong, we'll surface it. Either way, you walk away with a clearer picture of what you own."
2. System takeover. "When your inverter fails — and inverters do fail, usually between year 8 and year 20 — you need someone to handle the warranty claim and the replacement. Top Tier becomes your single point of contact for the next 10 years on the entire system, not just on anything new we install."
3. Then bridge to the bill — AFTER cohort identification. "You're still seeing a [AES / CenterPoint / Duke IN / I&M / NIPSCO] bill after going solar. The reason depends on which cohort you're on — let me ask you a few questions to make sure we walk through the right numbers."

The battery is the upsell that makes the deal economic for Top Tier; takeover/inspection is the lead the customer agreed to. Reps get paid on battery sales. Don't lose the open by leading with the close.

IN-specific bridge to weather: Indiana state-wide rate increases (IURC Cause 45506 progression for I&M; phased Duke 11%; AES 2024 case +$30/mo; CenterPoint multi-rider climb) are the documented backdrop. Indiana storm history adds the resilience anchor (Easter 2023 derecho across central IN; March 2025 tornado outbreak across IN/KY/TN; 2024 winter storms). The architecture is: takeover + inspection FIRST, bridge AFTER cohort identification, then layer rate-trajectory + resilience as appropriate.

Bridge — Multi-Cohort "Why You Still Have a Bill"

IN is the most cohort-rich market Top Tier serves. Routing the right Bridge template is critical. Cohort identification happens BEFORE the bridge — see the Cohort Screening Protocol below.

Template 1: EDG NET BILLING (AES / CenterPoint / Duke IN — post-July 2022 cohort)

Verbatim from the proposal copy (lib/why-bill-own-rent.ts, edg_net_billing cohort):

You went solar and still see a bill. Here's why.

[utility] doesn't pay you the same rate for the energy you export as the rate you pay when you import. They credit your exports at an export rate (their "EDG" or net-billing rate), but you buy electricity back at the full retail rate. The spread between the two is where your residual bill comes from. Every kWh your solar produces during the day that you don't use immediately gets credited at the lower export rate. Every kWh you import after sunset costs you retail. A battery stores your daytime production for nighttime use — closing the spread by self-consuming what you'd otherwise export.

Per-utility rate substitution:

• AES Indiana: EDG 5.4325¢/kWh (Jul 1, 2026); retail ~14¢/kWh blended → ~8.6¢ spread
• CenterPoint Indiana South: EDG 5.561¢/kWh (Mar 1, 2026); retail ~20¢/kWh all-in → widest IN spread at ~14.4¢
• Duke Indiana: EDG 4.1542¢/kWh (current per Rider 54); retail ~13¢/kWh → ~8.8¢ spread (lowest IN EDG = best spread on the low-retail side)

These are healthy EDG spreads — comparable to or better than the GA market's ~7¢ spread. The battery math works straightforwardly here.

Bridge in conversation (AES / CenterPoint / Duke IN):

"You're on [utility]'s EDG tariff because you went solar after SEA 309 closed retail net metering in July 2022. Your exports get credited at [rate]¢/kWh while imports cost you ~[retail]¢/kWh — that ~[spread]¢/kWh spread is why your bill isn't zero. The battery captures the spread on every kWh it shifts from exported to self-consumed. And IN retail rates aren't slowing down — [utility-specific rate-case anchor]. The spread the battery captures keeps widening."

Template 2: EDG NET BILLING + TOU STACK (I&M — Tariff R.S.-TOD2 overlay)

I&M is the only IN IOU with an open residential TOU rate eligible for battery arbitrage. The standard edg_net_billing bridge applies first, then layer the TOU savings stack as additional value.

Verbatim edg_net_billing bridge for I&M:

You went solar and still see a bill. Here's why.

I&M doesn't pay you the same rate for the energy you export as the rate you pay when you import. They credit your exports at an export rate (their "EDG" or net-billing rate), but you buy electricity back at the full retail rate. The spread between the two is where your residual bill comes from. Every kWh your solar produces during the day that you don't use immediately gets credited at the lower export rate. Every kWh you import after sunset costs you retail. A battery stores your daytime production for nighttime use — closing the spread by self-consuming what you'd otherwise export.

I&M-specific add-on after the bridge — TOU Stack:

"I&M is the only IN utility with an open residential TOU rate — Tariff R.S.-TOD2. On-peak runs 2-6 PM weekdays May-September at 24.746¢/kWh; off-peak runs at 10.764¢/kWh. With your battery installed, we can switch you onto TOU and discharge during the on-peak window — that's ~$10/mo of additional savings stacked on top of your EDG daily-cycle math. Modest add-on, but real. R.S.-TOD2 is available without the 12-month tenure requirement for existing R.S. customers."

Per-utility rate substitution (I&M):

• I&M EDG 5.466¢/kWh (Cause 45506, effective billing month March 2026); retail ~16.67¢/kWh → ~11¢ spread
• Plus $10/mo TOU switch stack ($120/yr) on top of EDG daily-cycle savings

Important context for I&M reps: the historical "I&M is the outlier high-EDG utility / smallest spread in IN / 2× peers" framing in older materials is OBSOLETE. The 2023 reference rate of 8.482¢/kWh has been superseded by the 2026 rate of 5.466¢/kWh (~35% reduction tracking PJM LMP softening). I&M is now a STANDARD EDG pitch + 22% rate-hike petition + AEP parent posture hedge + TOU stack.

Template 3: SPECIAL HANDLING — NIPSCO FIT (Rate 665) — HONEST FRAMING REQUIRED

This is the critical IN cohort guardrail. NIPSCO Rate 665 FIT customers are economically better off keeping FIT than installing a battery for bill-savings reasons. Reps MUST screen for FIT and pitch differently.

The math (honest): NIPSCO Rate 665 (Phase II Micro Solar ≤10 kW) pays ~17¢/kWh for ALL exports with a 1.0-1.5% annual escalator, 20-year contract term. Customer pays NIPSCO retail rate (~20.5¢/kWh flat for Rate 611) for ALL imports. The customer is on a long-term contract where every exported kWh is worth ~17¢ to them. A battery installed under FIT REMOVES that ~17¢ export-rate income for every kWh it shifts from "exported" to "self-consumed" — replacing it with a ~3¢ avoided-cost-of-imports gain (the difference between retail rate and FIT rate). The battery destroys bill economics for FIT customers.

What to say verbatim (REQUIRED honest framing):

"You're on NIPSCO Rate 665, which is genuinely good for you economically. NIPSCO is paying you ~17¢/kWh for every kWh you export, locked in for 20 years from your contract start with a small annual escalator. The honest answer about a battery: a battery for bill savings does NOT pencil out for you. Every kWh your battery shifts from exported to self-consumed costs you the 17¢ export payment in exchange for ~3¢ of avoided retail import. The math is upside-down vs the EDG customers we typically work with."

"That said — if you want a battery for RESILIENCE — backup power during outages, peace of mind during the next winter storm or summer derecho — the resilience value stands on its own. We can do that conversation. But I'm not going to pretend the bill math works for you. It doesn't."

When to pitch a battery to a FIT customer:

• Customer explicitly wants backup power for resilience (medical equipment, work-from-home, food preservation, sump pump in flood-prone area)
• Customer's FIT contract is in its final 3-5 years and they want to be positioned for the post-FIT EDG world
• Customer is selling within 5 years and wants the home-value boost (Berkeley Lab $3-10K incremental battery premium)

When NOT to pitch a battery to a FIT customer:

• Customer's primary motivation is bill savings → respect the math; recommend they stay on FIT pure-export
• Customer is mid-FIT-contract (years 5-15 of 20) → economics most negative; resilience case must be very clear

Documentation: All FIT-customer conversations should be documented in the rep notes (customer name + FIT contract year + reason for battery purchase if pursued). Todd reviews FIT conversions monthly to confirm the honest-framing rule is being followed.

Hidden Costs Avoided: The $11K System Takeover Bundle

Pillar 3 of the pitch (after Bridge and Takeover/Inspection lead). When Top Tier takes over the system, you bundle in services the customer would otherwise pay out of pocket over the 25-year horizon. These are estimates, not firm line-item quotes — but they total over $11K of value the customer doesn't see on the proposal's headline savings number. Applies to all 5 IN IOUs equally (including FIT customers — the takeover bundle is real value separate from bill math).

Verbatim from the proposal copy (components/multistate/sections/HiddenCostsAvoided.tsx):

The pitch: "On top of the bill math we walked through, you're picking up over $11K of bundled services that aren't sold separately. We don't quote them as line items because they're built into the takeover. If your inverter fails in year 12, the manufacturer warranty handling alone is worth a few hundred dollars. The replacement coordination saves you another $3-5K. The 5-year Align contract on your existing system is $1,500 you'd otherwise pay if you went looking for it. It adds up."

IN-specific tie-ins:

• Winter resilience emphasis — IN winter storms recurring; service-call wait times spike after major weather events (March 2025 tornado outbreak across IN/KY/TN; Easter 2023 derecho; recurring winter storms). Pre-paid service contract = no 90-day waitlist for post-storm diagnostics.
• NO-VPP context — Unlike Duke NC (EnergyWise) or MD (DRIVE Act pilots), IN has no utility-paid VPP. The $11K hidden-costs bundle is the structural value Top Tier brings; there's no incentive-program stacking to lean on.

What NOT to say:

• ❌ Don't promise the line items as standalone products.
• ❌ Don't pitch the headline as a guarantee. "Over $11K" is the estimated typical bundle value.
• ❌ Don't confuse Align (non-transferable) with the manufacturer warranty (transferable per its own terms).

What You Own vs What You Rent — Cohort-Routed Reframe

Pillar 4 of the pitch. IN's cohort split routes to different OwnVsRent templates per cohort.

DOLLAR-COMPARISON template (AES / CenterPoint / Duke IN / I&M — standard EDG cohorts)

Verbatim from the proposal copy (components/multistate/sections/OwnVsRent.tsx, DOLLAR-COMPARISON branch):

Over 25 years: are you renting power or owning it?

The 25-year horizon isn't about which line is lower on the chart — it's about whether you walk out with an asset.

For IN EDG customers, the dollar math is meaningful — EDG spreads are 8-14¢/kWh and IN retail rates have an active IURC rate-case progression (I&M 22% petition; Duke phased 11%; AES 2024 +$30/mo; CenterPoint multi-rider climb). The "rent" line compounds; the battery captures the spread today and hedges the trajectory.

The pitch (standard EDG):

"Over 25 years, the question is whether you're renting power or owning it. Your IN rent number compounds — and the documented IURC rate-case progression means the retail side keeps climbing. The battery captures the EDG spread today on every kWh it shifts. What ~$33K over 15 years buys you is ownership of the asset, $3-10K of incremental home value Berkeley Lab attributes to battery, outage protection for the next severe weather event, and 10+ years of service-path coverage."

DOLLAR-COMPARISON + TOU OVERLAY (I&M-specific)

Same dollar-comparison template as the other EDG utilities; I&M adds the $120/yr TOU switch stack as additional value on top. Frame the TOU savings as compounding additional value over the 25-year horizon ($3,000 cumulative if maintained, modest but real).

QUALITATIVE-LEANING template (NIPSCO FIT — bill math doesn't favor battery)

For FIT customers, the dollar-comparison reframe gives the wrong answer (FIT economics + battery math = battery costs the customer money). Use the qualitative reframe instead — emphasize ownership / control / resilience / home value rather than dollar comparisons.

Verbatim from the proposal copy (components/multistate/sections/OwnVsRent.tsx, QUALITATIVE branch — adapt for FIT context):

Your bill is small today — your solar's doing what it should. (For FIT customers: "Your bill is small today because Rate 665 is paying you above retail for exports.")

That depends on net metering rules continuing as-is. The 25-year horizon for you isn't about a dollar gap on the chart — it's about what your monthly loan payment actually buys you that your current bill doesn't.

What ~$33K over 15 years buys the IN FIT customer:

• Ownership of generation + storage. System is yours.
• Incremental home value: $3K-$10K per Berkeley Lab.
• Resilience for IN severe-weather pattern. Solar shuts off during grid outages today (anti-islanding). Battery keeps critical loads running.
• Post-FIT positioning. When the 20-year Rate 665 contract expires, the customer transitions to whatever the prevailing EDG / NM regime is at that point. Battery installed during FIT positions for the post-FIT economics.
• 10-year Top Tier workmanship warranty + service path.

The pitch (FIT-honest):

"Your bill math under Rate 665 already works in your favor — NIPSCO is paying you ~17¢/kWh for exports for the next [N] years. The battery doesn't improve your bill math; it actually costs you a little. What ~$33K over 15 years buys you is ownership of the system, $3-10K of incremental home value, real resilience for the next derecho or winter storm, and positioning for when your FIT contract expires. If those values matter to you, the battery makes sense. If your only goal is bill savings — stay on FIT."

Cohort Screening Protocol — REQUIRED First 60 Seconds

Reps MUST identify cohort before bridging. IN's cohort architecture is the most complex Top Tier serves; getting it wrong produces wrong proposal math.

Step 1: Identify utility

"Which utility serves your address?" → AES Indiana / CenterPoint Indiana South / Duke Indiana / Indiana Michigan Power / NIPSCO

Step 2: Identify cohort (utility-dependent)

For AES / CenterPoint / Duke IN / I&M: Ask "When did your solar system get interconnected?"

• Pre-2018: NM I cohort (grandfathered through July 1, 2047) — RARE; pitch resilience + takeover + cliff-positioning (battery prepares them for 2047 cliff)
• 2018-July 2022: NM II cohort (grandfathered through July 1, 2032) — pitch cliff-positioning + resilience + takeover
• Post-July 2022: EDG cohort (default calculator math; standard pitch)

For NIPSCO: Ask the NIPSCO FIT screening question first:

"Did you enroll in NIPSCO's Rate 665 Feed-in Tariff when you went solar? Sometimes called 'FIT' or 'Phase II Micro Solar' — it pays you about 17 cents per kWh for everything you export."

• If YES → FIT cohort (Template 3 special handling; resilience-only pitch; honest "Rate 665 is genuinely good for you" framing)
• If NO + interconnected post-July 2022 → standard EDG cohort
• If NO + interconnected 2018-July 2022 → NM II cohort
• If NO + interconnected pre-2018 → NM I cohort

Step 3: Verify with interconnection paperwork

"Do you have a copy of your interconnection paperwork or your most recent utility bill? Either one will confirm the cohort." Document the cohort in your notes.

What happens if you skip cohort screening

• EDG math quoted to NM II customer: Wrong math; customer realizes after the close; rep credibility destroyed.
• EDG math quoted to FIT customer: Customer signs up; first bill comes in WORSE than before because of the lost FIT export income; refund + lawsuit risk.
• NM II math quoted to EDG customer: Cliff urgency doesn't apply; customer either disengages or signs up under false framing.

The cohort screening is non-negotiable. Five minutes of questions saves five years of regret.

What NOT To Say · IN-specific Quick Reference

Quick Orientation

This guide covers the five investor-owned utilities most likely to appear in your Indiana sales conversations: AES Indiana (Indianapolis Power & Light), CenterPoint Energy Indiana South (CEI South, formerly Vectren Southern), Duke Energy Indiana, Indiana Michigan Power (I&M, an AEP subsidiary), and the Northern Indiana Public Service Company (NIPSCO, a NiSource subsidiary). These five IOUs serve the overwhelming majority of Indiana residential solar customers; Indiana also has many municipal utilities (Indianapolis Power & Light's Indianapolis-only customers, Anderson Municipal Light & Power, Bedford, etc.) and electric cooperatives (Wabash Valley Power, NineStar Connect, etc.) — this guide is for IOU customers only.

Top Tier sells batteries and service plans to customers who already have solar. This guide assumes every customer in your conversation already has an existing solar system. If a prospect doesn't have solar, they're not our customer — refer them out and move on.

Indiana is a regulated electric market. Customers buy distribution AND generation from their assigned utility — there is no retail-choice REP layer the way Ohio, Pennsylvania, or Texas have. This makes the bill structure simpler than those markets but it also means the rep guide is utility-specific in the same way GA Power's is for Georgia.

The Big Indiana Story: SEA 309 + the EDG Cohort

Indiana's residential battery pitch lives or dies on one regulatory fact: Senate Enrolled Act 309 (2017) phased out retail net metering. By July 1, 2022, all five IOUs were closed to new net-metering enrollment.

Today, every Indiana solar customer falls into one of three statewide cohorts (NIPSCO has a fourth — see the NIPSCO section):

1. NM I (pre-2018 enrollment) — Monthly netting at full retail; grandfathered through July 1, 2047. Rare; older installs.
2. NM II (2018 – July 2022 enrollment) — Monthly netting at full retail; grandfathered through July 1, 2032. The "2032 cliff" cohort — this is the cohort with the most forward-pressure exposure.
3. EDG (post-July 2022 / all new installs) — Instantaneous netting; imports billed at retail; exports credited at the utility's EDG rate (statutorily set at 1.25× MISO marginal LMP per IC 8-1-40-17, updated annually). This is the cohort the proposal calculator models by default.

Important architecture decision: The proposal calculator assumes the customer is on the EDG cohort. NM I, NM II, and NIPSCO FIT cohorts get a different conversation — see the "Cohort Screening Protocol" section below. Don't put a NM I or NM II customer in front of the EDG calculator and expect the bill math to make sense. The math will be wrong; the rep guide is the source of truth for those cohort conversations.

The Indiana Pitch (3 Pillars)

The Indiana pitch centers on three things, in this order:

1. Self-consumption spread capture — the EDG rate is 4-6¢/kWh across all 5 IN IOUs (Duke lowest at 4.15¢, CenterPoint highest at 5.56¢) against retail rates of 13-20¢/kWh. A battery converts exported kWh into self-consumed kWh, capturing that 8-15¢/kWh spread.
2. Cohort-cliff hedge for NM II customers — every customer who interconnected between 2018 and July 2022 loses retail net metering on July 1, 2032. Battery makes that cliff a non-event for the customer's own consumption.
3. Rate-trajectory hedge — Indiana has an active IURC rate-case cycle. I&M filed a 22% rate-hike petition; Duke phased 11% through 2025-2026; AES 2024 case raised bills ~$30/mo; the Indiana governor and IURC pushed back publicly in March 2026 but the underlying capital-recovery drivers don't pause.

Notably absent from the IN pitch:

• No battery rebates. No IN utility offers a residential battery-specific rebate in 2026.
• No VPP / DR programs. No IN utility runs a residential battery virtual power plant or demand-response program with cash-stacked enrollment.
• No federal ITC. The 30% federal Investment Tax Credit expired December 31, 2025. New residential battery installations in 2026 do not qualify for the federal credit. (Indiana sales-tax and property-tax exemptions still apply — see the Tax Landscape section.)

This is why the IN pitch leans harder on the structural story than the FL/GA pitch does. There are no sweeteners; there is the math, the cliff, and the trajectory.

Default Configuration: SELF-CONSUMPTION

Indiana is primarily a self-consumption battery market. The EDG spread does most of the work in the bill math, and Indiana's winter outage risk (while real) is less acute than Ohio's. Pitch leads with self-consumption + rate-trajectory hedge; resilience is layered in if the customer asks. Backup-capable upgrades are available; they're not the default offer.

Pricing reflects this: Indiana's standard quote is $17,000 cash / $20,500 financed (Service Finance, 7.95%, 15 yr) for the self-consumption configuration, with a monthly payment of approximately $210.

The Five Utilities at a Glance

EDG verification status (all 5 utilities verified May 2026):

• AES, CenterPoint, NIPSCO: 2026 EDG rates confirmed against IURC compliance filings.
• Duke Indiana: 4.1542¢/kWh current per duke-energy.com customer-facing Rider 54 PDF (Third Revised Sheet No. 54, Issued March 13, 2024). The rate has held through the 2025 and 2026 annual compliance filing cycles — no rate change propagated to Duke's customer-facing Rider 54 document.
• I&M: 5.466¢/kWh effective billing month March 2026 per Cause 45506, Second Revised Sheet No. 41.8 dated Feb 17, 2026 (extracted from IM_IN_TB_20_04-30-2026.pdf at indianamichiganpower.com).

Important I&M update: The previously circulated reference rate of 8.482¢/kWh (2023, based on 2022 MISO LMP) has been SUPERSEDED. The 2026 rate of 5.466¢/kWh is materially DOWN — a ~35% reduction over three cycles tracking PJM LMP softening at the I&M load zone (the same PJM softening that drove the June 2026 ~3.6% bill DECREASE from the PJM/Off-System Sales rider). Consequence: I&M is no longer the outlier high-EDG utility in IN; the rate is now in line with AES (5.43¢), CenterPoint (5.56¢), and NIPSCO (4.97¢). The "smallest spread in IN / Fort Wayne LMP premium / 2× peers" framing in older materials is obsolete. I&M is now a standard EDG pitch + the 22% rate-hike petition + AEP parent posture hedge.

Note on coop/muni customers: This guide is for investor-owned utility (IOU) customers only. Indiana has 38 electric cooperatives and several municipal utilities (Indianapolis Power & Light city customers, Anderson, Bedford, Crawfordsville, etc.) — these are NOT covered by this guide and have different rules. Don't apply this guide to coop or muni customers without verification.

The Pitch Framework

The five Indiana customer archetypes

Reps should identify which archetype they're talking to within the first 5 minutes of conversation. The pitch differs significantly for each. Indiana's cohort architecture adds a layer Ohio doesn't have: TWO archetypes are cohort-screened before pitch.

Archetype 1: The EDG Customer (Most Common)

• Has solar installed after July 1, 2022
• On Excess Distributed Generation (EDG) tariff at their utility
• Exports earn the EDG rate (4-6¢/kWh depending on utility); imports cost full retail
• The proposal calculator's default scenario.
• Strongest fit for standard self-consumption pitch. Lead with spread capture + rate-trajectory hedge.

Archetype 2: The NM II Customer (Cohort-Specific)

• Has solar installed between 2018 and July 1, 2022
• On retail-rate net metering; cliff is July 1, 2032
• Today's bill economics are EXCELLENT; battery's day-to-day bill impact is small to zero
• The pitch is HEDGE THE CLIFF, not save-on-bill-today. Battery makes 2032 a non-event for self-consumption.
• Bill calculator output is misleading for this customer. Use the cliff-conversation framing in the rep guide.

Archetype 3: The NM I Customer (Rare, Cohort-Specific)

• Has solar installed before 2018
• On retail-rate net metering; cliff is July 1, 2047
• 20+ years of grandfathering remaining
• Battery's bill case is weakest of any IN cohort
• Pitch is RESILIENCE-ONLY OR system rescue value (orphaned installer). Don't pitch bill savings.

Archetype 4: The NIPSCO FIT Customer (NIPSCO-Specific, Rare)

• Has solar on NIPSCO; participated in Rate 665 Renewable Feed-In Tariff (closed to new applicants)
• Phase II Micro Solar (≤10 kW) earns ~$0.17/kWh per export with 1-1.5%/yr escalator
• Legacy contracts run 20 years
• Pitch is RESILIENCE-ONLY, not self-consumption. Self-consumption REDUCES the customer's revenue because exports earn ~17¢/kWh and self-consumed kWh only avoid ~20¢/kWh — a 3¢/kWh net positive, but tiny, and trading guaranteed contract revenue for marginal bill reduction.
• The NIPSCO FIT customer should not be converted to EDG. Screen for this first at NIPSCO.

Archetype 5: The Orphaned Solar Customer

• Original installer is out of business
• System is 5+ years old, approaching inverter failure window
• No service path, no warranty recourse
• Configuration: depends on customer
• Strong sale once identified. System rescue value is independent of utility and cohort.

The opening pitch (EDG customer — most common)

"You bought solar to save money on your electric bill, and Indiana's net metering rules changed in 2022. If you connected your system after July 2022, you're on EDG — your imports cost full retail, somewhere around [13 / 14 / 16 / 20] cents per kilowatt-hour depending on your utility, but your exports only earn 4 to 6 cents per kilowatt-hour. That's an 8 to 16 cent spread you're losing every time your solar exports to the grid.

A battery captures that spread. Every kWh you'd export at EDG gets used at home instead, avoiding a kWh you'd otherwise import at retail. The math works out to roughly [$24-$46] per month of bill savings for a typical 10 kWh battery at your utility's spread.

On top of that, the IURC is actively reviewing rate-hike petitions across the IOUs. I&M filed for 22%. Duke just put through an 11% phased increase. AES raised bills ~$30 per month in 2024. The Indiana governor and IURC have pushed back publicly, but the underlying capital-recovery drivers continue. A battery hedges that trajectory — the more rates climb, the more value your battery captures."

The opening pitch (NM II customer — 2032 cliff cohort)

"You connected your solar between 2018 and July 2022, so you're on full retail net metering — Indiana calls this NM II. That's the best rate Indiana offers solar customers today. But it expires on July 1, 2032. After that, your exports get EDG rates — 4 to 6 cents instead of 13 to 20 cents — just like everyone who installed after July 2022.

Battery doesn't help your bill much today, because you're already at the best math possible. The battery's job for you is forward-looking: it makes the 2032 cliff a non-event for your own consumption. Whatever you use at home doesn't depend on the net-metering regime; only what you export does. By the time the cliff hits, you've stored more of your value behind your meter, and the cliff stops mattering for your day-to-day."

The opening pitch (NIPSCO FIT customer — only at NIPSCO)

"You're on the Rate 665 Renewable Feed-In Tariff with NIPSCO. Your export rate — 17 cents per kilowatt-hour with that 1 to 1.5 percent annual escalator — is actually higher than what you avoid paying when you self-consume. That means a battery's bill economics work AGAINST you: every kWh you store and use yourself instead of exporting is a kWh you no longer get paid 17 cents for.

So I'm not going to pitch you on bill savings. What I am going to talk to you about is what happens when the grid goes down. Your solar shuts off automatically during outages — leaving you with no power even when the sun's shining. A battery solves that. We can talk about the resilience case, and we can talk about Top Tier's takeover of your existing system's service responsibility — but I'm not going to pretend the bill economics work for a FIT customer the way they work for everyone else."

AES Indiana — Indianapolis and Central Indiana

The Indianapolis Power & Light operating company (rebranded AES Indiana in 2022) covers Indianapolis, the Indianapolis metro, and most of central Indiana. As of 2024, AES Indiana's residential rate case raised average bills by approximately $30 per month. The utility is building 820 MW of utility-scale battery capacity by 2032 — useful proof point that "battery is real infrastructure," not speculative tech.

Service Territory

AES Indiana serves Indianapolis and central Indiana including Marion, Hamilton, Hendricks, Hancock, Johnson, Morgan, Shelby, Boone, Putnam, and Owen counties. Headquartered in Indianapolis. As an investor-owned utility regulated by IURC, AES Indiana's rates and programs are determined through IURC rate cases. Parent company AES Corporation is a multinational energy operator.

Net Metering: EDG (Excess Distributed Generation)

AES Indiana has three cohorts (NM I closed in 2018, NM II closed July 1, 2022, EDG ongoing). Every AES Indiana customer interconnected after July 1, 2022 is on EDG:

• Imports: billed at the customer's standard residential Rate RS — approximately 14¢/kWh blended.
• Exports: credited at the EDG rate, 5.4325¢/kWh effective July 1, 2026. This rate is statutorily set at 1.25× the prior calendar year's marginal MISO LMP per IC 8-1-40-17 and updates annually each March 1, effective July 1.

The 5.43¢/kWh EDG rate is up from 4.13¢/kWh in 2025 and 3.94¢/kWh in 2024 — a 38% climb over two cycles tracking rising MISO marginal energy prices. Reps should expect another upward step in 2027 if the trend persists.

Battery Rebate

None. AES Indiana does not offer a residential battery-specific rebate. The utility's incentive programs focus on heat pump installations and EV charging.

The 2024 Rate Case and 2026 IURC Pushback (Critical Pitch Context)

AES Indiana filed its most recent base rate case as IURC Cause 45911, with implementation phased through 2024. The effective 2024 result was approximately +$30/month for average residential customers. Combined with the EDG rate climb, AES customers have absorbed real rate increases over the last 24 months.

On March 24-25, 2026, the Indiana governor and IURC publicly questioned the "Big Five" IOU rate-case posture. Governor: "We can't take it anymore." This tempers near-term rate-case approval but does NOT reverse the underlying capital-investment drivers. AES Indiana's coal retirements + 820 MW utility-scale battery build are capital expenditures that flow through future rate cases. The trajectory continues.

AES Indiana's 820 MW Battery Build (Pitch Proof Point)

AES Indiana is investing in up to 820 MW of utility-scale battery storage by 2032 — this is grid-side infrastructure, not customer-side. The pitch point: "Your utility is investing nearly a billion dollars in battery storage. They're doing it because storage is real and proven. The same physics that justifies AES's grid battery justifies your battery — except yours is behind your meter, where it captures spread and provides resilience for you specifically."

Pitch Approach for AES Indiana Customers

1. Open with the EDG spread. ~14¢ retail vs 5.43¢ EDG = ~8.6¢/kWh spread capture on every self-consumed kWh.
2. Anchor the rate trajectory. AES 2024 case raised bills ~$30/mo. EDG rate +38% over two annual cycles. IURC pushback in Mar 2026 is real but the capital drivers continue.
3. Use AES's own battery investment as proof point. 820 MW utility-scale build by 2032 — battery is real infrastructure.
4. Cohort-screen first. Confirm customer is on EDG (post-July 2022 interconnection); if NM I or NM II, switch to cliff-hedge framing.

How To Identify AES Indiana Customers From a Bill

Look for:

• "AES Indiana" or legacy "Indianapolis Power & Light Company" header
• Rate Schedule RS (Residential Service) reference
• Indianapolis-area service address
• IURC tariff notation (e.g., "I.U.R.C. No. 24")

EDG customers will show a separate line item for "Excess Distributed Generation Credit" or similar.

CenterPoint Energy Indiana South (CEI South) — Evansville and Southwest Indiana

CenterPoint Energy Indiana South (CEI South, formerly Southern Indiana Gas and Electric / Vectren) covers Evansville and the southwestern Indiana service area. As of effective dates March 1-11, 2026, the CEI South tariff (I.U.R.C. No. E-14) carries the highest blended residential rate of any IN IOU at approximately 20¢/kWh all-in — driven by a combination of base energy charges, fuel cost, variable production, and 12+ adjustment riders.

Service Territory

CEI South serves Evansville, Vanderburgh County, Posey County, Warrick County, Spencer County, Dubois County, Daviess County, Knox County, Sullivan County, Gibson County, Pike County, and portions of surrounding counties — the historic Vectren Southern footprint. Parent company CenterPoint Energy is a Houston-based multi-utility holding company. The IN south service area is regulated separately from CenterPoint's Indiana North gas-only territory and CenterPoint's Texas operations.

Net Metering: EDG (under Rider EDG, I.U.R.C. No. E-14)

CEI South EDG customers (post-July 2022 interconnections) have exports credited at the Marginal DG Price under Rider EDG:

• Imports: billed at the customer's standard Rate Schedule, typically Standard Rate RS. The Standard RS rate stack (effective Mar 5, 2026):
  • Energy Charge: 15.7230¢/kWh
  • Fuel Charge (FAC): 4.1220¢/kWh
  • Variable Production Charge: 0.1692¢/kWh
  • Subtotal: ~20.0¢/kWh before adjustments
• Customer Facilities Charge: $11.00/month
• Exports: credited at the Marginal DG Price, 5.561¢/kWh under Rider EDG (effective Mar 1, 2026). Statutory 1.25× MISO marginal LMP per IC 8-1-40-17.

CEI South's tariff carries 12+ adjustment riders applied monthly: Fuel Adjustment Clause (FAC), DSM, CECA, Environmental Cost, MISO, Reliability, TDSIC, Tax Adjustment Rider, and others. Each is an active rate-case track. The composite blended rate climbs across cycles even when individual riders are denied or reduced.

Battery Rebate

None. CEI South does not offer a residential battery-specific rebate.

The CenterPoint Securitization Story (Cause 45990 — Pitch Context)

CEI South retired A.B. Brown coal units and recovered stranded asset costs through securitization (IURC Cause 45990). Excess Accumulated Deferred Income Tax credits + Production Tax Credits flow through the Tax Adjustment Rider (Appendix L). The Mar 11, 2026 effective TAR rate of $(0.008692)/kWh is a partial offset to other riders — but the underlying securitization economics continue through the bond term.

Pitch Approach for CEI South Customers

1. Open with the widest IN spread. ~20¢/kWh all-in retail vs 5.56¢/kWh EDG = ~14.4¢/kWh self-consumption spread — the highest in IN alongside NIPSCO.
2. Anchor the multi-rider rate climb. 12+ adjustment riders, each on its own update cycle. The composite rate climbs even when individual tracks are denied.
3. Layer in the southwestern IN storm exposure. Tornado / severe weather risk for the Evansville area gives the resilience case some traction.
4. Cohort-screen first. Confirm EDG cohort; if NM I or NM II, switch to cliff-hedge framing.

How To Identify CEI South Customers From a Bill

Look for:

• "CenterPoint Energy" or legacy "Vectren Southern" or "SIGE" header
• Rate Schedule RS or "Standard Residential"
• Evansville-area service address
• "I.U.R.C. No. E-14" tariff notation
• Multiple adjustment-rider line items (FAC, DSM, CECA, TAR, etc.)

Duke Energy Indiana — Plainfield and Central/South/West Indiana

Duke Energy Indiana is the largest IN IOU by geographic service territory, headquartered in Plainfield. Parent company Duke Energy Corporation operates rate cases across multiple jurisdictions; the Carolinas NC division removed retail net metering in October 2023, providing documented parent precedent for IN reps to reference. Duke Indiana put through an 11% phased rate increase between February 2025 and early 2026.

Service Territory

Duke Indiana serves much of central, south, and west Indiana — including Bloomington, Lafayette, Terre Haute, Plainfield, Greencastle, Greensburg, Columbus (IN), and most counties west of Indianapolis. Largest IN service territory by geography. As an investor-owned utility regulated by IURC, Duke Indiana's rates and programs are determined through IURC rate cases.

Net Metering: EDG (under Rider EDG, IURC Cause 45508)

Duke Indiana EDG customers (post-July 2022 interconnections) have exports credited at the Marginal DG Price under Rider EDG:

• Imports: billed at the customer's standard residential Rate RS. Secondary sources cite a blended retail rate of approximately 11-13¢/kWh (TODO: verify against current Rate RS tariff for energy + customer charge + riders).
• Customer Charge: approximately $9.40/month (TODO: verify).
• Exports: credited at the Marginal DG Price, $0.041542/kWh — current per duke-energy.com customer-facing Rider 54 PDF (Third Revised Sheet No. 54, Issued/Effective March 13, 2024). The rate has held through the 2025 (Feb 25, 2025) and 2026 (Feb 24, 2026) annual compliance filings — Duke's customer-facing Rider 54 document still shows $0.041542/kWh as the operative rate. This is the LOWEST EDG rate of the 5 IN IOUs.

Duke Indiana has both the lowest EDG rate AND the lowest retail rate among the five IN IOUs. The combination produces a self-consumption spread of approximately 8.6¢/kWh — comparable to AES Indiana, smaller than NIPSCO (~15.5¢) and CenterPoint (~14.4¢). The pitch leans harder on the documented 11% phased rate climb and the cliff-hedge story than on the EDG spread alone.

Battery Rebate

None. Duke Indiana does not offer a residential battery-specific rebate.

The 11% Phased Rate Increase + Duke Carolinas NC Precedent (Critical Pitch Context)

Duke Energy Indiana's most recent base rate case settlement was approved by IURC and implemented in two phases:

1. February 27, 2025: 8% rate increase effective. Average residential bill impact approximately +$13.30/month at 1,000 kWh/mo.
2. Early 2026: 3% follow-on increase effective. Combined effect approximately +$18.76/month at 1,000 kWh/mo.

This is the most directly comparable rate-case data point reps will encounter at Duke Indiana — it's documented, it's already on customer bills, and it grounds the rate-trajectory hedge.

Beyond the IN settlement, parent Duke Energy's Carolinas NC division removed retail net metering in October 2023. This is parent precedent, not an IN filing — but it documents Duke's posture across jurisdictions. The pitch point: "Duke's parent has removed retail net metering in another state. They haven't done it in Indiana — and SEA 309 effectively took that step in 2022 — but the cycle continues. The customers most insulated from the next phase are the ones already capturing solar value behind the meter."

Pitch Approach for Duke Indiana Customers

1. Lead with the 11% phased rate climb. It's documented; it's on the customer's bill; it grounds the trajectory hedge.
2. Don't oversell the pure self-consumption spread. Duke Indiana's retail rate is the lowest of the IN IOUs; the EDG spread is the smallest. Be honest — the spread is ~7-9¢/kWh, not the 14-15¢ at NIPSCO / CEI South.
3. Use Duke Carolinas NC as documented parent precedent. Don't claim Duke IN is about to weaken NEM further; do reference Carolinas NC as parent posture.
4. Cohort-screen first. Confirm EDG cohort. NM II cliff hedge is particularly compelling for Duke customers because the day-to-day bill math is smaller.

How To Identify Duke Indiana Customers From a Bill

Look for:

• "Duke Energy Indiana" header
• Rate Schedule RS reference
• Plainfield, Bloomington, Lafayette, or Terre Haute service address
• "I.U.R.C. No. 165" tariff notation
• "EDG Credit" or "Excess Distributed Generation" line item for post-2022 customers

Indiana Michigan Power (I&M) — Fort Wayne and Northeast Indiana

Indiana Michigan Power is an AEP subsidiary serving Fort Wayne, northeast Indiana, and parts of southern Michigan. I&M is in the middle of a 22% rate-hike petition that the Citizens Action Coalition flagged as the most aggressive IN IOU filing of the current cycle, making it the most regulatorily-active IN utility right now. The I&M EDG rate dropped materially over the last three cycles tracking PJM LMP softening — see "Important rate update" below.

Service Territory

I&M serves Fort Wayne, Bluffton, Auburn, Decatur, Huntington, Wabash, Marion (IN), Muncie, Anderson, and northeast Indiana counties on the Indiana side; the Michigan side includes Niles, Three Rivers, and Berrien County. The Indiana service area is regulated by IURC; the Michigan side is regulated by Michigan PSC and has different rules — this guide covers the IN side only. Parent company American Electric Power Company is a major multistate IOU operator.

Net Metering: EDG (under Rider EDG, IURC Cause 45506)

I&M EDG customers (post-July 2022 interconnections) have exports credited at the Marginal DG Price under Rider EDG:

• Imports: billed at the customer's standard residential Rate RS. Secondary sources cite a blended retail rate of approximately 16.67¢/kWh (TODO: verify against current Rate RS tariff for energy + customer charge + riders).
• Customer Charge: TODO(in-verify-im-cust-chg) — pending Rate RS extraction.
• Exports: credited at the Marginal DG Price, $0.05466/kWh (effective billing month March 2026, Cause 45506, Second Revised Sheet No. 41.8 dated Feb 17, 2026, extracted from IM_IN_TB_20_04-30-2026.pdf at indianamichiganpower.com). The 1.25× MISO marginal LMP formula is statutory under IC 8-1-40-17.

Important rate update: I&M EDG dropped ~35% from 2023 to 2026

The previously circulated I&M EDG rate of 8.482¢/kWh (2023, based on 2022 MISO LMP) has been SUPERSEDED. The current rate effective March 2026 is 5.466¢/kWh — a ~35% reduction over three annual cycles. This reflects PJM LMP softening at the I&M load zone — the same dynamic driving the June 2026 ~3.6% bill DECREASE from the PJM/Off-System Sales rider.

Consequence: I&M is no longer the outlier high-EDG utility in IN. The 2026 rate of 5.47¢ is in line with AES (5.43¢), CenterPoint (5.56¢), and NIPSCO (4.97¢). The "Fort Wayne LMP premium / 2× peers / smallest spread in IN" framing is obsolete. I&M is now a standard EDG pitch.

Updated spread: I&M EDG 5.47¢ vs retail ~16.67¢ = ~11.2¢/kWh spread — comparable to a mid-pack IN utility (better than Duke/AES at ~8.6¢, smaller than CenterPoint at ~14.4¢ and NIPSCO at ~15.5¢).

Battery Rebate

None. I&M does not offer a residential battery-specific rebate.

The 22% Rate-Hike Petition + AEP Parent Posture (Critical Pitch Context)

The Citizens Action Coalition flagged I&M's 22% rate-hike petition as the most aggressive utility filing in IN in the current cycle. The IURC outcome is pending. The Indiana governor and IURC's March 24-25, 2026 pushback specifically called out the "Big Five" IOU rate cases by name — I&M was prominent in the coverage.

A consistent counter-trend data point: in June 2026, I&M's average residential bill is projected to DECREASE by approximately 3.6% (~$6/mo) due to an approved reduction in the PJM/Off-System Sales rider. The same PJM softening dropped the EDG rate from 8.48¢ (2023) to 5.47¢ (2026). This does NOT mean the underlying capital-recovery posture has softened — the 22% petition remains pending; the AEP parent's broader rate-case posture continues.

Parent precedent: AEP Ohio filed in late 2025 to weaken net metering in OH (Docket 25-0349-EL-ORD). PUCO denied the filing on January 7, 2026. AEP Ohio could refile in the next five-year review cycle. This is documented parent intent that reps can reference at I&M — the parent has shown its hand on NEM-weakening.

Pitch Approach for I&M Customers (Standard EDG + Forward Hedge + TOU Switch)

I&M is now a standard EDG pitch with a strong forward-hedge layer AND the only IN TOU rate-switch upside:

1. Open with the standard EDG spread. ~16.7¢/kWh retail vs 5.47¢/kWh EDG = ~11.2¢/kWh self-consumption spread. Pure bill economics for a 10 kWh battery: ~$34/mo savings (300 kWh × 11.2¢ = $33.60). Real, durable, and comparable to peer IN utilities.
2. Layer in the 22% rate-hike petition. Most aggressive IN IOU filing in current cycle. Battery captures self-consumption value AS the petition flows through (whatever the IURC ultimately approves).
3. Reference AEP parent posture. AEP Ohio NEM-weakening filing denied Jan 2026, but the parent has demonstrated its hand. Refile possible in next cycle.
4. Acknowledge the PJM softening honestly. The EDG rate has come DOWN, not up, over the last three cycles. Don't pretend otherwise. The trade is: smaller spread today (vs 2023) + active rate-petition hedge for 2027-2030.
5. Offer the TOU rate-switch upgrade. I&M is the only IN IOU with an open residential TOU (Tariff R.S.-TOD2, Cause 45933). On-peak 24.746¢ from 2-6 PM weekdays May-September; off-peak 10.764¢. Existing R.S. customers can switch any time (no 12-month tenure requirement). For a 100% solar offset customer with battery, this stacks ~$10/mo additional savings on top of the EDG daily-cycle math: battery covers the narrow peak window, residual imports re-priced at the lower off-peak rate. The proposal calculator includes this in the I&M monthly savings figure. See "TOU rate-switch" section below.
6. Cohort-screen first. Confirm EDG cohort. NM II at I&M still faces the 2032 cliff — the cliff hedge is meaningful here.

TOU Rate-Switch (I&M Only): Tariff R.S.-TOD2

This is the only open residential TOU rate at any IN IOU. All other 4 utilities either don't have one (AES, NIPSCO) or only have pilot / CPP programs (CenterPoint TimeWise, Duke pilots) that aren't structurally battery-arbitrage-friendly.

R.S.-TOD2 specs (per I&M Indiana Tariff Book IM_IN_TB_20_04-30-2026.pdf Sheet 9, Cause 45933, effective May 28, 2024):

• Service Charge: $15.00/month
• Energy Charge:
  • On-peak: $0.24746/kWh
  • Off-peak: $0.10764/kWh
• On-peak window: 2 PM – 6 PM local time, May through September only. Off-peak = all other hours, including all weekend/holiday hours during May-September AND all hours October-April.
• Eligibility: Residential, voluntary. AMI meter required (can be requested for non-AMI customers). Existing standard Rate R.S. customers may switch to R.S.-TOD2 immediately, without satisfying the 12-month minimum-tenure requirement that normally applies to tariff switches.

Why it stacks well with battery + solar (Top Tier customer profile):

• A 100% solar offset customer's residual imports are mostly OFF-PEAK (overnight, early morning, October-April). Switching to R.S.-TOD2 re-prices those imports at $0.10764/kWh — about 3-4¢ lower than the standard R.S. blended rate. On ~280 kWh/mo residual imports, that's ~$9/mo of base-rate savings.
• During the narrow summer peak window (4 hours × ~22 weekdays × 5 months = ~440 hours/year), the customer's net load = home consumption minus solar output. On hot afternoons, AC load may exceed solar production. The battery covers that gap: maybe ~2 kWh per peak event × 110 events × ~$0.14 spread = ~$31/yr of arbitrage savings.
• Net: ~$10/mo additional savings on top of EDG daily-cycle math. Modest but real.

What this is NOT:

• This is NOT a Georgia-scale TOU stack. GA's TOU-OA has a year-round peak window and ~27¢ on-peak vs ~2¢ super-off-peak — a much bigger spread captured across more hours. I&M's R.S.-TOD2 peak is 4 hours summer-only and the spread is ~14¢. The math is real but narrower.
• This is NOT a no-questions-asked switch. Reps should verify the customer's:
  • Existing tariff (standard R.S. vs heat-pump variants vs PEV variants)
  • Customer charge differential ($15/mo TOD2 vs whatever they're paying today)
  • Solar interconnection cohort (R.S.-TOD2 customers with cogeneration take Rider NMS, not the new EDG tariff — though for post-July-2022 EDG customers, this isn't a constraint)
• This is NOT available at AES Indiana, CenterPoint Indiana South, Duke Energy Indiana, or NIPSCO. Don't pitch a TOU rate switch at those utilities — it's I&M-only.

Pitch language for I&M reps:

"There's one more upside on top of the EDG self-consumption math. I&M is the only utility in Indiana with an open residential time-of-use rate — they call it R.S.-TOD2. Off-peak is about 10.76 cents per kWh, on-peak is about 24.75 cents. The on-peak window is just 4 hours, weekday afternoons from May through September. Most of your residual imports — overnight, early morning, all winter — are off-peak. Switching to R.S.-TOD2 saves you about 3 to 4 cents per kWh on those imports. During the summer peak window, your battery covers whatever your solar doesn't. Real number: about ten dollars a month additional savings, on top of the EDG spread capture. The proposal you're looking at already includes that in the monthly bill estimate."

How To Identify I&M Customers From a Bill

Look for:

• "Indiana Michigan Power" or "I&M" header
• "AEP" branding in the footer (parent company)
• Fort Wayne, Bluffton, Auburn, or northeast IN service address
• Rate Schedule RS reference
• IURC tariff notation
• "EDG Credit" or "Excess Distributed Generation" line item for post-2022 customers

NIPSCO — Northern Indiana Public Service Company

NIPSCO (Northern Indiana Public Service Company) is a NiSource subsidiary serving northern Indiana including Gary, Hammond, South Bend, and the I-65/I-80 corridor. NIPSCO has the highest residential energy rate in Indiana at $0.205/kWh flat, the widest battery self-consumption spread in IN, AND a legacy Rate 665 Feed-In Tariff cohort that reps must screen for. NIPSCO is the strongest standard EDG pitch in IN — and the only one where cohort screening adds a fourth bucket (FIT).

Service Territory

NIPSCO serves Lake, Porter, La Porte, St. Joseph, Marshall, Starke, Pulaski, Jasper, Newton, Benton, White, Kosciusko, Fulton, Cass, Carroll, Howard, Tipton, Madison, and parts of surrounding counties — the northern Indiana corridor. Major cities: Gary, Hammond, East Chicago, Whiting, Michigan City, La Porte, South Bend, Plymouth, Knox, Kokomo, Logansport. As an investor-owned utility regulated by IURC, NIPSCO's rates and programs are determined through IURC rate cases. Parent company NiSource Inc. operates utilities across multiple states.

Net Metering: EDG (under Rider 689) — with Legacy FIT Overlay (Rate 665)

NIPSCO has FOUR cohorts (NM I, NM II, EDG, plus a legacy FIT). EDG is the default for all new installs:

• Imports: billed at Rate 611 Residential: $0.205/kWh flat (effective Mar 1, 2026, Second Revised Sheet No. 48). No tiered pricing. No seasonal differentiation. Highest residential energy rate in IN.
• Customer Charge: $14.00/month.
• Exports: credited at the Marginal DG Price, $0.049685/kWh under Rider 689 (effective Apr 1, 2026, First Revised Sheet No. 209). Statutory 1.25× MISO marginal LMP per IC 8-1-40-17.

The retail-vs-EDG spread at NIPSCO is 20.5¢ − 4.97¢ = 15.5¢/kWh — the widest in IN. Battery self-consumption case is strongest at NIPSCO.

Legacy Rate 665 — Renewable Feed-In Tariff (Phase II, Closed)

NIPSCO's Rate 665 is a legacy renewable Feed-In Tariff that paid solar customers a contracted rate for ALL solar production (not just excess exports). Phase I and Phase II are closed to new applicants — the program filled — but legacy contracts run 20 years.

• Phase II Micro Solar (≤10 kW): $0.1700/kWh with 1.0-1.5%/yr escalator
• Phase II Small Solar (>10-25 kW): $0.1490/kWh with similar escalator
• Contract term: 20 years from interconnection

A FIT customer should NOT switch to EDG. Under FIT, every kWh produced earns $0.17+. Under EDG, only exports earn 4.97¢/kWh and self-consumed kWh avoid 20.5¢/kWh (the retail rate). For a FIT customer:

• Self-consumed kWh under EDG: avoids 20.5¢ (the retail rate) — net gain 20.5¢ per kWh.
• Self-consumed kWh under FIT: lost 17¢ (the FIT payment that no longer happens) — net gain 0¢ per kWh, plus retained the FIT contract obligation to deliver kWh.

This means FIT customers see NEGATIVE economics from a battery's bill case. Do not pitch bill savings to a FIT customer. The resilience pitch and the Top Tier system rescue value are still valid; the bill case isn't.

Battery Rebate

None. NIPSCO does not offer a residential battery-specific rebate.

The Rate 611 Climb + Rate-Case Cycle (Pitch Context)

NIPSCO's most recent base rate case put Rate 611 at $0.205/kWh flat effective Mar 1, 2026 — the highest single residential energy rate in IN. The flat-rate simplicity makes the math easy: no tiered pricing, no seasonal differentiation, no demand charges. The customer pays $0.205/kWh on every grid-imported kWh.

NIPSCO is also in the middle of retiring coal generation (Schahfer Generating Station, Michigan City Generating Station) and replacing with renewable + battery capacity. Capital costs flow through rate cases — the trajectory continues.

FIT Screening Protocol — REQUIRED at NIPSCO

First 60 seconds of every NIPSCO conversation:

"Quick question before we get into anything else — are you on a 20-year Renewable Feed-In Tariff contract with NIPSCO? This is the program that pays you a contracted rate for ALL your solar production. If you signed up before they closed it around [date], you might be on it. If you don't know, that's fine — let me know how I can find out."

If YES (FIT customer): Branch to FIT-specific conversation. Bill economics work AGAINST adding a battery. Pitch is resilience-only + system rescue.

If NO or DON'T KNOW (probable EDG): Standard EDG pitch. Verify via bill review (FIT customers show a separate "Renewable Feed-In Tariff Payment" line item; EDG customers show "Excess Distributed Generation Credit" or similar).

Pitch Approach for NIPSCO Customers (Standard EDG)

1. FIT-screen first. Always.
2. Open with the widest IN spread. 20.5¢/kWh flat retail vs 4.97¢/kWh EDG = ~15.5¢/kWh self-consumption spread. Widest in IN.
3. Use flat-rate simplicity. No tiered pricing, no seasonal differentiation — battery economics are predictable.
4. Layer the rate-case trajectory. Rate 611 at $0.205/kWh is highest in IN; NIPSCO coal retirement + renewable build continues through rate cases.
5. Resilience anchor. Gary corridor / South Bend lake-effect snow + grid age = resilience case has real legs.
6. Cohort-screen for NM II. Cliff hedge if applicable.

How To Identify NIPSCO Customers From a Bill

Look for:

• "NIPSCO" or "Northern Indiana Public Service Company" header
• "NiSource" branding in the footer (parent company)
• Gary, Hammond, South Bend, La Porte, or northern IN service address
• "Rate 611 — Residential Service" reference
• $14.00/month customer charge
• Either "Excess Distributed Generation Credit" (EDG) OR "Renewable Feed-In Tariff Payment" (FIT) line item — REP MUST DISTINGUISH BEFORE QUOTE

Cohort Screening Protocol (CRITICAL — Read This Section)

Indiana's most important difference from Ohio, Georgia, Pennsylvania, and Texas is the cohort architecture. Every Indiana solar customer belongs to one of three (or four, at NIPSCO) cohorts, and the pitch differs significantly for each.

The proposal calculator assumes EDG cohort. Don't run NM I, NM II, or NIPSCO FIT customers through the standard calculator without first switching the conversation framing.

Screening Questions (In Order)

Question 1: "When did you connect your solar system to the grid?"

• Before 2018: NM I cohort. Pitch: resilience + system rescue only. Grandfathering runs to July 1, 2047.
• 2018 through July 1, 2022: NM II cohort. Pitch: cliff-hedge framing. Grandfathering runs to July 1, 2032.
• After July 1, 2022: EDG cohort. Standard pitch.
• Don't know: Ask for a recent bill or interconnection paperwork; the install date is usually on the bill or available from the utility.

Question 2 (at NIPSCO ONLY): "Are you on a Renewable Feed-In Tariff with NIPSCO?"

• Yes: FIT cohort. Pitch: resilience + system rescue only. Bill economics work AGAINST a battery for FIT customers.
• No or don't know: Verify via bill (FIT customers have a "Renewable Feed-In Tariff Payment" line item). If no FIT line, customer is EDG/NM I/NM II per Question 1.

Cohort-Specific Pitch Framings

NM I (pre-2018) — RARE:

• 20+ years of grandfathered retail NM remaining (cliff is July 1, 2047)
• Customer is on the best math IN has ever offered
• Battery doesn't improve today's bill; cliff is too far out to meaningfully discount
• Pitch: resilience-only + system rescue. Don't pitch bill savings.

NM II (2018 – July 2022):

• 6 years of grandfathered retail NM remaining (cliff is July 1, 2032)
• Today's bill economics are EXCELLENT
• Battery doesn't materially change today's bill
• Pitch: cliff-hedge. "Today's math works. July 2032 is the cliff. Battery makes it a non-event for your own consumption — whatever you use at home isn't subject to the cliff; only what you export is."
• Forward NPV of cliff hedge is most of the value at this cohort

EDG (post-July 2022) — MOST COMMON:

• Imports at retail; exports at the utility's EDG rate (4-6¢/kWh)
• Battery captures the retail-vs-EDG spread (~8-15¢/kWh depending on utility)
• Pitch: standard self-consumption spread + rate-trajectory hedge. The proposal calculator's default scenario.

FIT (NIPSCO ONLY, RARE):

• Legacy Rate 665 contract paying ~$0.17/kWh on Phase II Micro Solar production
• Self-consumption from a battery REDUCES customer's FIT revenue
• Net bill case is NEGATIVE
• Pitch: resilience-only + system rescue. Do NOT pitch bill savings.

Why The Calculator Assumes EDG

The proposal calculator was designed for the pitch target — the post-July-2022 customer adding a battery to existing solar to capture EDG spread. Modeling NM I, NM II, and FIT cohorts would require multi-window grandfathering logic the existing cohort engine doesn't support, and would add complexity that's unnecessary because the pitch for those cohorts is structurally different (resilience-only or cliff-hedge, not standard bill-savings).

If a rep mistakenly runs a NM II customer through the calculator, the output will likely UNDERSTATE the value of the cliff hedge (because the calculator can't project post-cliff economics) and OVERSTATE the day-to-day savings (because the calculator assumes EDG, not retail NM). Don't use the output for NM II/NM I/FIT customers. Use the rep guide narrative.

Battery Optimization: Rate Plans and Daily Operating Cycle

Time-of-Use Rate Availability by Utility

Residential TOU availability across IN IOUs is narrow. Only one utility (I&M) offers an open standard-residential TOU rate that a battery + solar customer can use as a rate-switch upside. The other 4 either don't have one or only run pilot / Critical-Peak-Pricing programs that aren't battery-arbitrage-friendly.

For 4 of 5 IN IOUs, TOU is NOT material to the battery pitch. The EDG spread (export-rate-vs-retail) drives the math. At I&M only, the R.S.-TOD2 rate switch stacks ~$10/mo additional savings on top of EDG — modest but real. See the I&M section's "TOU Rate-Switch" subsection for the full pitch.

Reps: do NOT pitch a TOU rate switch at AES, CenterPoint, Duke IN, or NIPSCO — there's no clean open residential TOU at those utilities. The IN proposal calculator only stacks the TOU upside on I&M proposals.

The Daily Operating Cycle (Self-Consumption Mode)

In self-consumption mode (the IN default):

1. Morning: Battery is at near-full charge from prior day's solar
2. Midday: Solar output exceeds home load. Battery is full. Excess production exports at EDG rate.
3. Evening: Solar output drops below home load. Battery discharges to cover the gap, AVOIDING grid imports at retail rate.
4. Overnight: Home load runs on minimal grid imports + battery residual until solar resumes the next morning.
5. Repeat.

The economic engine: every kWh the battery shifts from "exported at EDG (4-6¢)" to "self-consumed avoiding grid import at retail (13-20¢)" captures the spread. For a 10 kWh usable battery cycling once per day, that's ~30 cycles/month × 10 kWh = 300 kWh/month shifted, times the per-utility spread.

Battery Behavior During Outages (Backup-Capable Configuration)

In backup-capable configuration (optional upgrade in IN):

• Battery automatically isolates from the grid during a utility outage
• Critical loads (furnace blower, sump pump, fridge, lights, internet, medical equipment) run on the battery
• Battery recharges from solar during daylight hours
• Without solar recharge, battery lasts approximately 18-30 hours on critical loads; with daylight solar, can run indefinitely if loads are managed
• Battery does NOT power the whole home in backup mode — only the critical loads circuit panel

Important Configuration Note for Indiana

• Standard IN quote is self-consumption configuration (no whole-home backup)
• Backup-capable upgrade is available; pricing differs
• Customer should be told explicitly whether their quote is self-consumption-only or backup-capable
• Self-consumption-only is the DEFAULT in IN; backup-capable is the upgrade

Grid Charging Rules in Indiana

Indiana's EDG tariffs do NOT prohibit grid-charging the battery, but there is no economic case to grid-charge under EDG. Grid charging at retail (13-20¢) to discharge at retail-avoidance (13-20¢) is a wash (minus round-trip efficiency losses). Battery should be configured to charge from solar only.

Key Talking Points for Reps

• "Your battery's job is to convert kWh you'd export at the EDG rate into kWh you self-consume — capturing the spread on every shifted kWh."
• "Indiana's EDG rate updates annually. The trend over the last two cycles has been UP — at AES, EDG went from 3.94¢ in 2024 to 5.43¢ in 2026. That spread can compress over time."
• "Self-consumption doesn't depend on what the grid is doing. Your battery captures spread whether NEM rules change again or not."

Indiana Rate History and Future Outlook

Historical Rate Increases Across Indiana

Indiana residential electricity rates have climbed steadily through the documented IURC rate-case cycle:

• AES Indiana (Cause 45911): 2024 case raised average bills ~$30/month
• Duke Energy Indiana (settlement): 8% effective Feb 27, 2025 + 3% effective early 2026 = ~11% phased, ~$18.76/mo for 1,000 kWh customer
• CenterPoint Energy Indiana South: multiple component charges + 12+ adjustment riders updating on independent cycles; effective rate climbed to ~20¢/kWh all-in by Mar 2026
• NIPSCO: most recent base rate case set Rate 611 at $0.205/kWh flat (Mar 1, 2026), the highest single residential energy rate in IN
• Indiana Michigan Power: 22% rate-hike petition active per Citizens Action Coalition tracking; counter-trend ~3.6% bill decrease effective June 2026 from PJM rider reduction

The IURC Pushback in March 2026 (Critical Context)

On March 24-25, 2026, the Indiana governor publicly questioned IOU rate-case posture: "We can't take it anymore." The IURC followed with sharp questioning of the "Big Five" IOU filings. This is documented regulatory pushback and is real news — but it tempers NEAR-TERM approval rather than reversing the underlying drivers.

The capital-investment drivers don't pause:

• AES Indiana 820 MW utility-scale battery build by 2032
• NIPSCO + AES coal retirements + renewable replacement capacity
• CenterPoint A.B. Brown securitization (Cause 45990) flowing through bond term
• MISO Zone 6 capacity-cost pressure from data-center load growth across the footprint
• Annual EDG rate updates per IC 8-1-40-17 statutory formula

What's Coming Next

Forward pressures shaping IN residential rates through the next cycle:

1. Annual EDG rate update (each March 1, effective July 1 or sooner) — the 1.25× MISO marginal LMP statutory formula. Rising wholesale prices flow through directly to EDG.
2. Capital-recovery rate cases — coal retirements + renewable + battery capacity builds + data-center transmission. Capital costs flow through periodic rate cases.
3. MISO capacity-cost pressure — Indiana sits in MISO Zone 6 footprint, heavy data-center growth, summer/winter peak risk.
4. The 2032 NM II cliff — for NM II customers, the regime change in July 2032 is the largest forward pressure. Cliff hedge framing applies for that cohort.
5. AEP / Duke parent posture — AEP Ohio's denied NEM-weakening filing (Jan 2026) and Duke Carolinas NC's retail NM removal (Oct 2023) are documented parent intent in adjacent jurisdictions. Not certain to land in IN; do reference as context.

The Rate Story for Reps to Tell

The IN rate story is structural, not speculative:

• AES Indiana 2024 case: +~$30/mo on bills
• Duke IN: 11% phased increase 2025-2026
• I&M: 22% petition active
• NIPSCO: highest IN residential energy rate at 20.5¢/kWh flat
• CenterPoint: 12+ adjustment riders, composite rate climbs even when individual tracks are denied

The customer's choice is between exposed-to-the-cycle and hedged. Battery is the hedge.

Critical Disclosure for All Customers

Rate-trajectory projections in the proposal are scenario-based, not certain. The IURC's regulatory environment is actively contested. Reps must NOT promise that rates will increase at any specific rate. The scenario columns (optimistic 4%/yr, moderate 6%/yr, aggressive 8%/yr) are framing tools showing the range of outcomes, not predictions.

Virtual Power Plants in Indiana — Negative Finding Section

What Is a VPP?

A virtual power plant (VPP) is a network of distributed batteries that the utility can dispatch during peak demand events, effectively using customer-owned storage as grid capacity. Customers typically receive an enrollment payment, ongoing event-participation credits, or both, in exchange for ceding some control over their battery's operation.

Current VPP Programs in Indiana (as of 2026)

No residential battery virtual power plant or demand-response program operates at any of the five IN IOUs in 2026.

This is verified across:

• AES Indiana: no residential battery VPP / DR program
• CenterPoint Energy Indiana South: no residential battery VPP / DR program
• Duke Energy Indiana: no residential battery VPP / DR program
• Indiana Michigan Power: no residential battery VPP / DR program
• NIPSCO: no residential battery VPP / DR program

IN utility incentive programs in 2026 focus on:

• Heat pump installations (rebates at most IOUs)
• EV charging infrastructure (rebates and time-of-use rates at some IOUs)
• Smart thermostat enrollment (at some IOUs)
• Energy efficiency audits and lighting upgrades

None of these stack with a residential battery purchase in a way that affects the Top Tier pitch.

Future Outlook

VPP programs may emerge in Indiana over the next several years as utility-scale battery deployment ramps (AES 820 MW by 2032). However, no IN utility has filed for residential battery VPP authorization with IURC as of Phase A research, and no announcement timeline exists.

How to Use the Absence of VPP in the Pitch

This is NOT a weakness — it's structural transparency:

"Indiana utilities don't offer battery VPP programs the way Georgia or Texas does. That means there's no 'stack the rebate on top of the battery' story to tell — but it also means the battery's value is structural and durable, not dependent on a program the utility can change or close. The math is the math: EDG spread capture today, cliff hedge for NM II, rate-trajectory hedge for everyone."

This frames the absence honestly. Reps who try to over-promise IN VPP value (because they're used to pitching GA / TX) lose credibility.

Resilience and Weather: The Indiana Outage Context

Recent Major Outages (Pitch Context)

Indiana has real outage risk, though materially less acute than Ohio. Recent context:

• Winter storms 2022-2024: Multiple severe-cold events across IN; localized outages but no statewide rolling-blackout near-misses comparable to OH's December 2022.
• Summer derecho events: Periodic severe thunderstorm wind events across central IN. Localized outages.
• Tornadoes (southwestern IN): Evansville / CEI South footprint sees periodic tornado-driven outages.
• Lake-effect snow (northern IN — NIPSCO footprint): Heavy snow events in the Gary / South Bend corridor.
• Rural distribution age: Older distribution infrastructure in less-densely-served areas drives longer restoration times when outages occur.

Why Indiana is Vulnerable

• MISO Zone 6 covers IN — same grid stress profile as the upper Midwest
• Coal-plant retirements + renewable replacement during the transition create capacity headwinds during summer/winter peak
• Data-center load growth in IN is real — Indianapolis-area data-center construction continues
• Distribution infrastructure age varies by utility but is generally older in rural areas

What Battery Backup Actually Provides

In backup-capable configuration (the IN upgrade option, not the default):

• Critical loads (furnace blower, sump pump, fridge, lights, internet, medical equipment) for 18-30 hours without solar recharge
• Indefinite runtime if solar recharge is available and loads are managed
• Automatic isolation from the grid during utility outages
• Does NOT power the whole home — only the critical loads circuit panel
• Does NOT replace a whole-home standby generator

The Honest Resilience Conversation

The IN resilience pitch is real but secondary to the bill-economics pitch. Customers asking about backup should be told:

"The backup-capable configuration is an upgrade from the standard quote. It adds cost. The IN default is self-consumption — the battery captures EDG spread but doesn't isolate from the grid during outages. If resilience is your primary concern, we can spec the backup-capable upgrade. If your primary concern is bill economics, self-consumption is the right call and we should focus the math there."

Don't lead with resilience in IN unless the customer raises it. The EDG spread + rate-trajectory hedge is the durable story.

Configuration Options

• Self-consumption only (default): Captures EDG spread; no whole-home backup; lower cost
• Backup-capable (upgrade): Adds critical-loads backup; modest cost increase; recommended for customers with elderly relatives, medical equipment, work-from-home setups, or heavy weather concern
• Some customers want both: The standard self-consumption configuration handles both bill economics and modest non-critical resilience; backup-capable adds the critical-loads guarantee

Bill Math: The Spread Capture Story

Without Battery (Current State, EDG Cohort)

A typical Indiana EDG-cohort customer with 100%-offset solar pays:

• Customer charge: $9-14/month
• Imports at retail rate: variable
• Exports credited at EDG rate (4-6¢/kWh depending on utility)
• Net bill: customer charge + (imports × retail) − (exports × EDG)

For a customer producing ~1,200 kWh/mo solar and consuming ~1,000 kWh/mo, with ~50% time-of-day match:

• Solar production directly self-consumed: ~600 kWh/mo (zero cost)
• Solar production exported at EDG: ~600 kWh/mo
• Grid imports needed: ~400 kWh/mo
• Bill = customer charge + 400 × retail − 600 × EDG

At NIPSCO: bill = $14 + 400 × $0.205 − 600 × $0.0497 = $14 + $82 − $29.82 = ~$66/mo At CEI South: bill = $11 + 400 × $0.20 − 600 × $0.0556 = $11 + $80 − $33.36 = ~$57/mo At AES: bill = $11 + 400 × $0.14 − 600 × $0.0543 = $11 + $56 − $32.58 = ~$34/mo At Duke IN: bill = $9.40 + 400 × $0.13 − 600 × $0.0415 = $9.40 + $52 − $24.90 = ~$36/mo At I&M: bill = $12 + 400 × $0.1667 − 600 × $0.0547 = $12 + $66.68 − $32.80 = ~$46/mo

(These are illustrative customer profiles; actual bills depend on consumption pattern, solar production, and time-of-day match.)

With Battery (Self-Consumption Mode, EDG Cohort)

A 10 kWh usable battery cycling once per day shifts ~300 kWh/mo from "exported at EDG" to "self-consumed avoiding retail import." The bill changes:

For the same customer profile above with battery:

• Solar production directly self-consumed: ~600 kWh/mo (unchanged)
• Solar production stored + later self-consumed via battery: ~300 kWh/mo
• Solar production exported at EDG: ~300 kWh/mo (reduced by 300)
• Grid imports needed: ~100 kWh/mo (reduced by 300)
• Bill = customer charge + 100 × retail − 300 × EDG

At NIPSCO: bill = $14 + 100 × $0.205 − 300 × $0.0497 = $14 + $20.50 − $14.91 = ~$20/mo (down $46) At CEI South: bill = $11 + 100 × $0.20 − 300 × $0.0556 = $11 + $20 − $16.68 = ~$14/mo (down $43) At AES: bill = $11 + 100 × $0.14 − 300 × $0.0543 = $11 + $14 − $16.29 = ~$9/mo (down $25) At Duke IN: bill = $9.40 + 100 × $0.13 − 300 × $0.0415 = $9.40 + $13 − $12.45 = ~$10/mo (down $26) At I&M: bill = $12 + 100 × $0.1667 − 300 × $0.0547 = $12 + $16.67 − $16.40 = ~$12/mo (down $34 from EDG daily-cycle alone; the R.S.-TOD2 rate-switch stack adds another ~$10/mo for a total of ~$44/mo savings — see the I&M "TOU Rate-Switch" subsection)

The Year-1 Cost Conversation

After battery loan payment (~$210/mo on Service Finance 15-year), the customer's combined utility + loan cost is:

• NIPSCO: $20 + $210 = $230/mo (vs $66 today, +$164/mo year 1)
• CEI South: $14 + $210 = $224/mo (vs $57 today, +$167/mo year 1)
• AES: $9 + $210 = $219/mo (vs $34 today, +$185/mo year 1)
• Duke IN: $10 + $210 = $220/mo (vs $36 today, +$184/mo year 1)
• I&M: $2 + $210 = $212/mo (vs $46 today, +$166/mo year 1 — includes ~$10/mo R.S.-TOD2 TOU rate-switch stack on top of EDG daily-cycle savings)

The TRUE NET in year 1 is meaningfully higher than today's bill at every IN utility. Year 1 is NEGATIVE. This is normal for the IN pitch.

The structural value accrues over 25 years:

• EDG rate climbs over the period (5-cycle trajectory documented across IOUs)
• Retail rate climbs (4-8%/yr scenarios across optimistic / moderate / aggressive)
• For NM II customers, the 2032 cliff converts retail-rate value into EDG-rate value overnight; battery captures the delta
• After loan amortization (year 15+), the battery continues to capture spread with no offsetting loan payment

The Honest Bill Pitch

"Year 1, the math is going to look uncomfortable. You're adding a loan payment that's bigger than today's bill savings. That's because we're paying off 15 years of capture in 15 years of equal payments — the value comes later.

The case isn't 'save money this month.' The case is 'lock in the spread before the rate cases compound and the cliff hits.' At NIPSCO you save ~$46/month off your bill today; at I&M ~$44/month (EDG daily-cycle plus the R.S.-TOD2 rate-switch stack); at CenterPoint ~$43/month. Combine that with the 4-8%/yr retail rate climb scenarios, the EDG rate trend (up 38% at AES over two cycles), and the 2032 cliff if you're NM II — the 25-year math compounds in your favor.

Most IN customers we work with are willing to accept the year-1 cash flow for the structural hedge. If year 1 is a hard no, the answer is probably 'wait' — but the wait isn't free, because the EDG rate and the retail rate are both climbing while you wait."

Top Tier System Rescue Value (Beyond Utility Programs)

The Orphaned Solar Customer Problem

A significant portion of IN solar customers were installed by companies that no longer exist or no longer service IN:

• Original installer out of business
• Original installer pivoted to commercial-only
• Original installer was acquired and the residential service line was discontinued
• Original installer never honored warranty obligations

These customers have:

• An aging solar system (typical IN installs are now 5-12 years old)
• No service path for inverter / panel / monitoring issues
• No warranty recourse when components fail
• Often no documentation of the original system spec

The Inverter Failure Reality

Solar inverters have a finite operating life:

• String inverters (SolarEdge, SMA): typical 8-15 year operating life
• Microinverters (Enphase): typical 10-20 year operating life
• Failure cost (out-of-pocket): $3,000-$5,000 for a typical residential string inverter replacement
• Failure cost (out-of-pocket): $1,500-$3,000 for typical microinverter replacement on a 6-12 kW system

For an IN solar customer with no warranty recourse, an inverter failure is a $3,000-$5,000 surprise bill. Top Tier's takeover offer addresses this.

What Top Tier System Takeover Provides

When a customer purchases a battery from Top Tier, the package includes:

• Full system service responsibility: Top Tier becomes the service point for the existing solar system (not just the new battery)
• 10-year workmanship warranty: Top Tier covers the workmanship for installation
• Align Solar Protection service contract (5-year): Added coverage for mechanical breakdown of the existing solar equipment, $0 deductible
• Single point of contact: No more chasing the original installer; Top Tier handles all service calls

Align Solar Protection (5-Year Added Coverage)

Align Solar Protection is a 5-year service contract bundled with every Top Tier battery purchase. Coverage includes:

• Mechanical breakdown of the existing solar inverter (most common failure point)
• Mechanical breakdown of the existing panel-level monitoring (Enphase microinverters, SolarEdge optimizers)
• Mechanical breakdown of the existing AC/DC disconnects
• $0 deductible for covered claims
• 5-year coverage period starting at battery installation

This addresses the "orphaned solar customer" pitch directly. For a customer 7 years into a typical Enphase install, the next 5 years is exactly when their first microinverter failures are likely. Align covers that out-of-pocket cost.

How the Takeover Works

1. Customer purchases battery from Top Tier
2. Top Tier installs the battery and integrates with the existing solar inverter
3. Top Tier becomes the service point for the entire system (battery + existing solar)
4. 10-year workmanship warranty + 5-year Align Solar Protection contract is in force
5. Customer's existing inverter is covered for mechanical breakdown under Align for 5 years; battery is covered under Top Tier's workmanship warranty for 10 years

Quantifying the Value

For a customer with an aging existing solar system:

• Avoided inverter replacement cost: $3,000-$5,000 (1 failure within 5 years probable)
• Service-call cost avoidance: 2-4 calls × $200-$400 = $400-$1,600 over 5 years
• Total takeover value: $3,400-$6,600 over 5 years

This is real economic value that does NOT show up in the proposal calculator (which focuses on bill economics) but materializes in the customer's actual long-term experience. Reps should call it out explicitly.

Why Indiana Customers Especially Benefit

• Many IN solar systems installed during the 2017-2022 SEA 309 rush are now reaching the 5-8 year mark
• Multiple high-profile IN solar installers have exited the market in the last 24 months
• The combination of aging-systems + orphaned-customers + no IN utility VPP/rebate sweeteners means the takeover value is a meaningful pillar of the IN pitch

Pitch Language for Reps

"Beyond the battery, you also get Top Tier as your service partner for your whole solar system. Most of our IN customers' systems were installed by companies that don't service residential IN anymore. When your inverter fails — and it will, somewhere between 8 and 15 years from your install date — you don't want to be chasing the original installer. We take that over. 10-year workmanship warranty on what we install, 5-year Align Solar Protection contract on your existing equipment, $0 deductible. That's $3,000-$5,000 of avoided surprise cost in many cases."

When to Lead With System Rescue vs. Layer It In

• Lead with system rescue: Orphaned solar customers (Archetype 5); customers who mention their installer "went out of business" or "won't return calls"
• Layer it in: Standard EDG cohort customers (Archetype 1) — system rescue is real value but not the primary pitch
• Don't oversell: Newly-installed customers (within 2 years) where the existing installer is still in business — Align value is still real but the customer is less acutely exposed

Honest Caveats Reps Must Disclose

• Align Solar Protection covers MECHANICAL BREAKDOWN. It does NOT cover physical damage from storms, lightning, animal damage, or installation-related defects from the original installer.
• The 10-year Top Tier workmanship warranty covers WORK TOP TIER PERFORMED. It does NOT cover original solar installation defects from a prior installer.
• The 5-year Align contract starts at battery installation, not at original solar install. If the customer's solar is 12 years old, Align coverage starts at year 12 and runs to year 17.

Federal Tax Credit Status (Important for All Customers)

The 30% Federal Investment Tax Credit Expired December 31, 2025

The federal residential clean-energy tax credit (Investment Tax Credit, ITC) — 30% of the installed cost of residential solar + battery — expired on December 31, 2025. New residential battery installations in 2026 do NOT qualify for the federal tax credit.

Reps must NOT tell customers:

• "You'll get 30% back on your taxes" (wrong — credit expired)
• "There's a federal credit on this" (wrong — credit expired)
• "We'll help you file the tax form" (wrong — there's no form for a credit that doesn't exist)

Reps MAY tell customers:

• "The federal tax credit expired at the end of 2025. New installations in 2026 don't qualify."
• "Indiana state-level sales tax and property tax exemptions still apply — that's roughly $2,300-$3,200 of avoided cost on a typical install" (see Indiana Tax Landscape section)

Why the Federal Credit Expired

The federal ITC for residential battery storage was extended through the Inflation Reduction Act (2022) but the residential portion was not further extended. The 2025 sunset was statutory. Future federal action is possible but not predicted; reps should NOT promise the credit will return.

The Pitch Impact

Pre-2026 IN battery installs benefited from 30% federal credit + state tax exemptions = ~$5,000-$7,000 of total tax incentive. 2026 installs receive only the state exemptions = ~$2,300-$3,200.

This makes the IN pitch math materially tighter than pre-2026. The 25-year structural case is still strong, but Year-1 cash flow is even more negative without the federal credit offsetting installed cost. Reps should set this expectation upfront — the credit is gone, the structural case still works.

Indiana Tax Landscape

Sales Tax Exemption — Solar / Battery Equipment

Indiana Code 6-2.5-5-46 exempts qualifying solar and battery equipment from Indiana state sales tax. Applies to the equipment portion of an installed solar + battery system. Typical savings:

• Sales tax rate: 7% Indiana state sales tax
• Typical battery equipment cost: ~$10,000-$14,000 (battery + inverter + balance-of-system)
• Sales tax avoided: $700-$980
• On a full solar + battery install (~$30,000-$45,000): $2,100-$3,150 sales tax avoided

Property Tax Exemption — Solar / Battery Equipment

Indiana Code 6-1.1-12-26.1 exempts solar and battery installations from increasing the assessed property value of a residence. Customer's property tax assessment does NOT increase because of the solar/battery system. This is meaningful for customers worried about property-tax implications.

NO State Income Tax Credit

Indiana does NOT offer a state-level income tax credit for residential solar or battery installations. The state-level incentives are limited to the two exemptions above.

NO Local Incentives (Generally)

Indiana municipalities and counties do not offer significant local battery or solar incentives in 2026. Some EV charging municipal rebates exist (Indianapolis, Bloomington) but these don't stack with battery purchases.

Combined Indiana State Incentive Value

For a typical IN battery install in 2026:

• Federal ITC: $0 (expired)
• Indiana sales tax exemption: ~$2,300-$3,200
• Indiana property tax exemption: ongoing avoidance of property-tax increases
• Total upfront tax savings: ~$2,300-$3,200

This is meaningful but materially less than the pre-2026 federal-plus-state package. Reps should set the expectation honestly.

Loan Economics

Standard Indiana Financing

Top Tier's standard IN financing through Service Finance:

• Cash price: $17,000 (self-consumption configuration)
• Financed price: $20,500 (includes financing fees)
• Term: 15 years
• APR: 7.95%
• Monthly payment: approximately $210

Backup-Capable Configuration (Upgrade)

For customers selecting the backup-capable upgrade:

• Cash price: $18,500
• Financed price: $22,500 (includes financing fees)
• Monthly payment: approximately $228

Important: No Re-Amortization

Service Finance does NOT re-amortize after the federal tax credit (when one exists). For 2026 IN customers, this is moot because the federal credit is expired. For customers asking about re-amortization, the answer is: "Service Finance is a fixed-term, fixed-payment product. Whatever federal incentive applies at the time of install offsets the upfront cost; the monthly payment is calculated on the financed total at install and doesn't change."

Loan Tenor Notes

• 15-year term is the IN standard
• Longer terms (20-year) increase monthly affordability but cost more in total interest
• Shorter terms (10-year) reduce total interest but raise monthly payment beyond most IN customer thresholds
• Service Finance underwrites the customer's debt-to-income; the rep should NOT make affordability promises

Critical Disclosure for Loan Math

Reps must disclose:

• Monthly payment is approximately $210 for self-consumption / $228 for backup-capable
• Total interest paid over 15 years is material
• The proposal's "TRUE NET" calculation shows the customer's total monthly cash flow (utility bill + loan payment)
• Year-1 TRUE NET will be HIGHER than the customer's current bill in most IN scenarios — see Bill Math section

Battery Products

Top Tier offers two primary battery product lines in IN:

Enphase IQ Battery 10 (2× IQ Battery 5P)

• 10 kWh usable capacity
• Requires the Enphase IQ8 microinverter ecosystem — for IN customers with existing Enphase microinverter solar systems ONLY. The IQ 5P is technically AC-coupled but uses the IQ8 ecosystem for communications, so it cannot install on SolarEdge string-inverter systems. (Enphase has a universal-AC battery in development that will be inverter-agnostic — not yet shipping.)
• Best fit for customers with existing Enphase microinverter systems
• Self-consumption configuration: ~$17,000 cash / ~$210/mo financed
• Backup-capable upgrade: ~$18,500 cash / ~$228/mo financed

SolarEdge Energy Bank 10 kWh

• 10 kWh usable capacity
• DC-coupled to SolarEdge string inverter systems
• Best fit for customers with existing SolarEdge string inverter systems
• Self-consumption configuration: ~$17,000 cash / ~$210/mo financed
• Backup-capable upgrade: ~$18,500 cash / ~$228/mo financed

Tesla Powerwall 3 (Available, Not Default)

Available in IN for customers who specifically request Tesla product. Pricing differs; lead times vary. Default IN quotes are Enphase or SolarEdge based on the customer's existing inverter platform.

Sizing Notes

• Standard IN quote is a single 10 kWh battery
• Larger configurations (20 kWh, 30 kWh) are available for customers with higher consumption or larger solar systems
• Battery should be sized to the customer's evening + overnight load, NOT to solar production
• Over-sizing reduces marginal value per kWh of capacity; under-sizing leaves spread on the table

Customer Qualification Questions

Reps should ask these questions in the first 10 minutes of the conversation:

Cohort Questions (REQUIRED)

1. "When did you connect your solar system to the grid?" → cohort classification (NM I / NM II / EDG)
2. "Which utility serves your home?" → utility classification
3. (At NIPSCO only): "Are you on a Renewable Feed-In Tariff contract?" → FIT screening

Bill / Usage Questions

1. "What's your typical monthly electric bill?" → bill anchor for the calculator
2. "How big is your solar system in kilowatts?" → production estimate
3. "Do you have a sense of your monthly electricity usage in kilowatt-hours?" → consumption profile

Existing System Questions

1. "Who installed your solar system originally?" → orphaned-customer screening
2. "Are they still in business and servicing your system?" → orphaned-customer screening
3. "What brand of inverter do you have — Enphase, SolarEdge, or something else?" → battery product matching
4. "How old is your system roughly?" → inverter-failure-window screening

Resilience / Configuration Questions

1. "How often do you lose power at your address?" → resilience-fit screening
2. "Do you have anything critical that runs on electricity — medical equipment, work-from-home setup, sump pump, well pump?" → backup-capable upgrade screening
3. "Have you ever had a long outage that you remember?" → resilience anchor

Decision Questions

1. "What's your timeline on making a decision?" → urgency calibration
2. "Are you the sole decision-maker, or is someone else involved?" → decision-maker confirmation
3. "What would have to be true for this to be the right move for you?" → objection surfacing

Walk-Away Profile

NOT every IN customer is a fit. Reps should walk away from:

• Customers without existing solar. Top Tier sells batteries to existing solar customers only. Refer out, move on.
• Customers on NIPSCO FIT contracts. Bill economics work AGAINST a battery for FIT customers. Resilience-only pitch is honest but rarely closes; FIT customers usually decline.
• Customers expecting the federal tax credit. If a customer is anchored on getting 30% back federally, set the correct expectation upfront (credit expired) and judge the response. If they walk on that, the rest of the math won't save the conversation.
• Customers with Year-1 cash flow as a hard constraint. IN year-1 math is negative in most scenarios. Customers who can't absorb $150-200/mo above today's bill in year 1 are walk-aways.
• Customers in coop or muni territory who aren't covered by this guide. Don't try to back-of-envelope coop math; refer for separate qualification.
• Customers with a solar system <2 years old who don't see structural value. The structural case requires multi-year horizon; very new customers with short time horizons rarely close.
• Customers with consumption patterns mismatched to battery. Customers with 90% midday consumption already self-consume most solar; battery adds marginal value. Customers with extremely small consumption can't justify even the smallest battery.

Required Customer Disclosures

Before close, reps MUST disclose:

Federal ITC

"The federal residential investment tax credit expired December 31, 2025. New installations in 2026 do not qualify for the federal credit."

Indiana State Incentives

"Indiana sales tax and property tax exemptions still apply — that's approximately $2,300 to $3,200 of avoided cost. There is no Indiana state income tax credit."

EDG Rate Variability

"Indiana's EDG rate updates annually each March, effective July or sooner. The rate has trended UP over the last two cycles at most utilities. We model the current rate; the actual future rates depend on MISO marginal energy prices."

NM I / NM II Cliff (Cohort-Specific)

For NM I customers:

"Your retail net metering is grandfathered through July 1, 2047. The battery's day-to-day bill impact is modest; the pitch is resilience and system rescue."

For NM II customers:

"Your retail net metering is grandfathered through July 1, 2032. After that date, your exports get the EDG rate just like everyone interconnected after July 2022. The battery makes that cliff a non-event for your own consumption."

Year-1 TRUE NET

"Your year-1 TRUE NET — utility bill plus loan payment — is going to be higher than today's bill. The structural case accrues over 25 years; the first year cash flow is the cost of locking in that hedge."

No VPP / DR Programs

"Indiana utilities don't offer battery virtual power plant or demand-response programs. The battery's value is the EDG spread, the cliff hedge if applicable, and resilience — there's no enrolled program to stack on top."

No Battery-Specific Rebates

"No Indiana utility offers a residential battery rebate. The state-level sales tax and property tax exemptions apply to the equipment cost."

Verification for Duke and I&M

"We use the most recently verifiable EDG rate for each utility. Duke Indiana filed its 2026 annual update in February 2026 and the updated rate was not yet extracted at the time of this quote; we'll confirm the current EDG rate against the IURC docket before final paperwork." (Or similar disclosure for I&M.)

Objection Handling

"Why is year 1 so expensive?"

"Year 1 carries the full loan payment but only one year of cumulative spread capture. The structural value accrues over 25 years — by year 10 you're well above breakeven; by year 15 the loan is paid and the battery continues to capture spread; by year 25 the cumulative case is materially positive. The first year is the cost of locking in 25 years of hedge. Most IN customers we work with accept that trade because the alternative — wait — isn't free, since retail rates and EDG rates are both moving."

"I'll just wait until the federal credit comes back."

"Honest answer: nobody knows if it will. The 30% credit was statutory and it sunset on schedule. There's no current legislation reinstating it. If you wait, you're betting on a tax outcome that isn't predicted. Meanwhile, the IN retail rate climbs through documented rate cases — Duke 11%, AES +$30/mo from 2024 — and the EDG rate is climbing too. The cost of waiting isn't zero."

"My NEM is locked in until 2032. Why do I need a battery now?"

"If you're on NM II, your day-to-day economics today are excellent — better than EDG customers. The case isn't 'save more today.' The case is 'make 2032 a non-event.' Whatever you self-consume isn't subject to the cliff; only what you export is. If you install the battery now, by 2032 you've already shifted most of your exposure off the EDG-vs-retail math. Wait until 2031 and you're scrambling to install in a market where everyone else is scrambling too."

"I don't have outages here. Why do I need backup?"

"Self-consumption is the IN default — no backup capability. The pitch is the EDG spread and the cliff hedge, not the backup. If you don't have outage concerns, you're a great fit for the self-consumption configuration. Backup-capable is an optional upgrade if you do have outage concerns."

"Can't I get the same battery cheaper somewhere else?"

"Maybe — there are competitive installers in IN. What you get with Top Tier specifically: 10-year workmanship warranty (industry-standard is 1-2 years), 5-year Align Solar Protection on your existing solar equipment (most installers don't service the existing system at all), and a single point of contact for the whole system. Most of our IN customers had a prior installer who's no longer servicing residential — the takeover is real value."

"What if my utility changes EDG rules?"

"EDG rules are statutory under SEA 309 (2017) — the 1.25× MISO LMP formula is in state law (IC 8-1-40-17). The utility can't change the formula unilaterally; legislation would have to change. The rate updates annually based on MISO LMP, which is rising, not falling. Self-consumption — what the battery captures — doesn't depend on any of that. Your battery captures retail-avoidance value, which is what you're charged for grid imports. That value increases when retail rates go up."

"What if my battery breaks?"

"Top Tier's workmanship warranty covers installation work for 10 years. The battery itself carries manufacturer warranties — Enphase is 15 years on the battery and microinverters, SolarEdge is 10-12 years on the battery and inverter. We handle warranty claims for you; you don't deal with the manufacturer directly."

"I want to think about it."

"Totally fair. What specifically would you like to think about? If it's the year-1 cash flow, I can talk you through the structural math. If it's whether the federal credit might come back, I can be honest about that. If it's whether your system is a good fit, I can run the spread math against your actual bill. What's the specific question you want to resolve?"

What To Say · What NOT To Say (Indiana Edition)

DO SAY:

• "Indiana's EDG rate is statutorily 1.25× MISO marginal LMP — it updates annually."
• "The 2032 NM II cliff is the largest forward pressure for customers in your cohort."
• "Self-consumption captures the retail-vs-EDG spread on every shifted kWh."
• "The federal Investment Tax Credit expired on December 31, 2025. Indiana state-level sales tax and property tax exemptions still apply."
• "No Indiana utility offers a residential battery rebate today."
• "Top Tier takes over service responsibility for your entire solar system, not just the new battery."
• "I'm not going to promise you a specific future rate. The scenario columns show a range — optimistic, moderate, aggressive."
• "Your year-1 TRUE NET is going to be higher than today's bill. The structural value accrues over 25 years."

DO NOT SAY:

• "You'll get 30% back on your taxes." (WRONG — federal ITC expired)
• "Your rate is locked in at today's rate." (WRONG — even NM II expires July 2032)
• "Your utility offers a battery rebate." (WRONG — no IN utility does)
• "There's a virtual power plant you can join." (WRONG — no IN utility offers one)
• "I&M's bill math is the strongest in Indiana." (WRONG — I&M's spread is the SMALLEST; pitch is forward hedge, not pure bill economics)
• "You'll save $150/month starting day one." (WRONG — year-1 is negative in most scenarios)
• "Your bill will go to zero." (WRONG — customer charge + minimum imports remain)
• "Net metering is going away across Indiana." (WRONG — NM II is grandfathered to 2032; NM I to 2047; EDG is the post-July-2022 default)
• "Duke is about to remove net metering." (WRONG — that was Carolinas NC in October 2023, not Duke Indiana; reference as parent precedent, not as IN filing)
• "NIPSCO FIT customers should switch to EDG." (WRONG — FIT economics work AGAINST switching; resilience-only pitch for FIT)

Reading an Indiana Utility Bill

Common Bill Structure (All Indiana IOUs)

Most IN residential bills include:

1. Customer Charge / Customer Facilities Charge — fixed monthly (typically $9-14)
2. Energy Charge — per-kWh rate (varies by utility, 4-20¢/kWh)
3. Fuel Cost Adjustment / FAC — pass-through fuel cost (separate line item)
4. Distribution / Delivery Charge — bundled into energy in some tariffs, separate in others
5. Adjustment Riders — DSM, ECR, Reliability, TDSIC, Tax, etc. (CenterPoint has 12+; others vary)
6. State / Local Sales Tax — Indiana 7% applies to electricity (with solar/battery equipment exemption per IC 6-2.5-5-46)
7. EDG Credit / Net Metering Credit / FIT Payment — separate line item for solar customers

Identifying Cohort From a Bill

• NM I / NM II: Look for a "Net Metering" credit line that nets the customer's imports against exports at the retail rate. NM I and NM II are not distinguishable on the bill alone — you have to ask the customer when they connected.
• EDG: Look for an "Excess Distributed Generation" or "EDG Credit" line item that credits exports at a separately-itemized per-kWh rate (4-6¢/kWh). Imports are billed at the full retail rate WITHOUT first netting against exports.
• NIPSCO FIT: Look for a "Renewable Feed-In Tariff Payment" or "Rate 665" line item paying ~$0.17/kWh on all production (not just excess exports).

AES Indiana Bill

• "AES Indiana" or "Indianapolis Power & Light Company" header
• Rate Schedule RS reference
• EDG customers: "Excess Distributed Generation Credit" line at 5.43¢/kWh (2026)

CenterPoint Energy Indiana South Bill

• "CenterPoint Energy" or legacy "Vectren" / "SIGE" header
• Rate Schedule RS reference; "I.U.R.C. No. E-14" notation
• Multiple adjustment rider line items (FAC, DSM, CECA, TAR, etc.)
• EDG customers: "EDG Credit" line at 5.56¢/kWh (2026)

Duke Energy Indiana Bill

• "Duke Energy Indiana" header
• Rate Schedule RS reference; "I.U.R.C. No. 165" notation
• EDG customers: "Excess Distributed Generation Credit" line at 4.15¢/kWh (current per duke-energy.com Rider 54, Third Revised Sheet No. 54)

Indiana Michigan Power Bill

• "Indiana Michigan Power" or "I&M" header; "AEP" parent branding
• Rate Schedule RS reference
• EDG customers: "EDG Credit" line at ~5.47¢/kWh (effective March 2026, Cause 45506)

NIPSCO Bill

• "NIPSCO" or "Northern Indiana Public Service Company" header; "NiSource" parent branding
• "Rate 611 — Residential Service" reference
• $14.00/month customer charge
• EDG customers: "EDG Credit" or "Rider 689" line at 4.97¢/kWh (2026)
• FIT customers: "Rate 665" or "Renewable Feed-In Tariff Payment" line at ~17¢/kWh

Final Thoughts for Reps

Indiana is a structural-case market, not an incentive-case market. There are no federal credits in 2026, no utility rebates, no VPP programs, no demand-response stacking. What there IS:

• EDG spread capture — the durable financial pillar. 8-15¢/kWh across the IN IOUs.
• NM II 2032 cliff hedge — the cohort-specific forward case for customers who interconnected 2018-July 2022.
• Rate-trajectory hedge — active IURC rate-case cycle; documented climb across the IN IOUs.
• Resilience case — secondary but real, especially for Gary corridor / lake-effect snow / SW IN tornado footprint.
• System rescue value — many IN solar systems are orphaned by departed installers; takeover + Align Solar Protection is a meaningful pillar.

The IN customer who buys is the customer who can absorb a year-1 negative TRUE NET in exchange for a 25-year structural hedge. That's a different customer than the GA "free battery via VPP" customer or the TX "Tesla VPP stacking" customer. Reps used to those markets need to recalibrate.

Cohort screen first. Calculator is for EDG only. NM I, NM II, FIT customers get the rep guide narrative, not the calculator output.

All 2026 EDG rates are verified. Duke at 4.1542¢/kWh per duke-energy.com Rider 54 (current); I&M at 5.466¢/kWh per Cause 45506 (effective March 2026). AES, CenterPoint, and NIPSCO 2026 rates verified previously. Secondary retail rates for Duke and I&M still carry TODO markers — quote those against the customer's actual bill rather than relying on the secondary cite when running specific bill math.

When in doubt, fall back to the structural case: the math, the cliff, and the trajectory. That's the IN pitch.

End of Top Tier Indiana Battery Sales Reference — Q2 2026 Edition.