Which market is this customer in?
Top Tier serves multiple states with different solar economics. Select the customer's location to load the right pitch framework, utility options, and battery configurations.
Arkansas
Entergy AR (MISO LRZ 9) + SWEPCO AR (SPP) · Cohort A grandfather / B post-docket / D new co-install
Arkansas launches with 2 IOUs covering ~820K residential customers. Entergy Arkansas (~700K, central + eastern + southern AR including Little Rock) operates in MISO Load Zone 9. SWEPCO AR (~120K, northwestern + west-central AR including Fort Smith) operates in SPP. Both utilities use cohort-aware routing: pre-APSC-successor-docket installs route to qualitative grandfather treatment (battery = future-proofing + backup); post-docket + new co-installs route to standard supply-only NM EDG dollar pitch. No state battery rebate, no state solar tax credit, no utility VPP — the AR pitch rests on bill arbitrage + Hidden Costs Avoided $11K bundle + resilience anchored on the 2009 Ice Storm of the Century, 2023 Little Rock EF3 tornado, and 2024 May Derecho.
Florida
Protection first · Resilience + future-proof
Most FL customers have favorable 1:1 net metering today. The pitch isn't bill capture — it's hurricane resilience, NBT future-proofing, and (for OUC) the rebate trade-off. KUA is the FL exception: live net billing today plus a 10/31/2028 cohort cliff, so the pitch is self-consumption spread capture.
Georgia
Clean energy · Independence · Backup · Long-term savings
Georgia Power's net billing means existing solar customers lose significant value on every exported kWh. A battery captures that value, protects your home when the grid goes down, and locks in your economics before the next round of rate increases.
Illinois
ComEd + Ameren · DG Rebate $300/kWh — keeps grandfather (storage rebate does NOT forfeit) · PJM ComEd Zone + MISO split
Illinois's two IOUs serve ~5.2M residential customers across distinct RTO footprints. ComEd (Exelon, ~4M customers, PJM ComEd Zone — Chicago metro + northern IL) and Ameren Illinois (Ameren Corp, ~1.2M, MISO — central + southern IL). Both administer parallel DG Rebate programs at $300/kW solar + $300/kWh storage, paid as a one-time check ~90 days after energization; the STORAGE rebate requires a rate-plan switch (ComEd → Rate BESH hourly pricing; Ameren → the customer's choice of Peak Time Rewards, Rider RTP, or Rider PSP), and that choice binds future occupants at the address. The Climate and Equitable Jobs Act (CEJA 2021) ended full-retail net metering for NEW interconnections statewide effective Jan 1, 2025 — a legislated date uniform across all IOUs, NOT a per-utility peak-demand cap; systems energized (docs submitted) before that date are grandfathered on full-retail netting for the ~30-yr life of the generator, and grandfather transfers with the system on sale. The critical customer-protective rule (CUB, both utilities' tariffs): a grandfathered customer who adds a battery and takes the $300/kWh STORAGE rebate KEEPS full-retail net metering — the storage rebate does NOT forfeit grandfather; only the SOLAR/generation rebate (new panels/expansion) forfeits. So there is no grandfather-vs-rebate tradeoff for a battery retrofit — the customer gets both. (Panel additions can forfeit: ComEd on any generation change; Ameren only on a >100% nameplate-capacity increase.) The Clean & Reliable Grid Affordability Act (CRGA, Public Act 104-0458, eff. June 1, 2026) reshaped the storage landscape: it requires utilities to allow net metering for behind-the-meter storage < 5 MW, adds a $250/kWh IPA rebate for standalone/community-paired storage < 5 MW, and mandates ComEd + Ameren battery VPPs (ComEd short-term VPP live ~June 2026; full SDVPP 2027; the $300/kWh storage DG rebate ties to VPP dispatch enrollment) — IL storage target 3,000 MW by 2030. Illinois Shines / Adjustable Block Program is a LIVE state SREC program (PY 2026-27, block-gated) — it is switched OFF in the initial Top Tier build only because Top Tier's Approved-Vendor status is unconfirmed (a Top-Tier gate, NOT a program closure). Cross-cohort framing guardrail: PJM 833% capacity-spike framing applies ONLY to ComEd content; Ameren routes via MISO context.
Indiana
EDG cohort default · Self-consumption spread + 2032 cliff hedge · IURC rate-case pressure
Indiana is a 5-IOU regulated battery market modeled around the EDG cohort (post-July 2022 enrollment). All five IOUs follow the statutory 1.25× marginal-LMP formula (IC 8-1-40-17) for EDG export credits — four reference MISO Zone 6, while I&M references PJM (the lone Indiana IOU on PJM, node EDC.PJMRT); 2026 EDG rates cluster ~5¢/kWh for AES, CenterPoint, NIPSCO with Duke pending and I&M an outlier ~8.5¢ (Fort Wayne LMP). The financial pitch is pure self-consumption capture against rising retail. No residential battery rebates exist statewide; no battery VPP / DR programs. Forward-pressure narrative: NM II 2032 cliff for grandfathered 2018-Jul 2022 customers + active IURC rate-case cycle (I&M ~19.7% petition active, Cause 46217; Duke 11% phased 2025-2026; AES ~$9.36/mo approved, Cause 46258, of a ~$30/mo ask). Tax landscape: IN sales tax exemption on solar equipment (IC 6-2.5-5-46), property tax exemption (IC 6-1.1-12-26.1), no state income tax credit, federal ITC expired 12/31/2025.
Kentucky
Duke Energy KY · NM I/II cohort split · PJM Zone DEOK · Cincinnati-area Northern KY
Duke Energy Kentucky serves ~142,900 customers in the Cincinnati-area Northern KY counties (Boone, Campbell, Grant, Kenton, Pendleton). Effective Jan 1, 2025, KY PSC Case 2023-00413 split residential solar into two cohorts: NM I (pre-2025 installs, full retail 1:1 net metering, 25-yr grandfather from the Rider NM-2 effective date, surviving property transfer) and NM II (post-2025 installs, avoided-cost net billing). Duke KY sits in PJM Zone DEOK; the October 2025 rate case (2024-00354) raised rates 9.61%. Top Tier focuses on Duke KY for the Kentucky launch — LG&E, KU, and Kentucky Power are out of scope for now.
Maine
Winter resilience · #1 outage state · Efficiency Maine battery income · Rate-hike hedge
Maine's Net Energy Billing gives residential rooftop solar full 1:1 retail-rate credits — intact with no dated cliff (the LD 1777 (2025) changes reformed community solar only, not residential rooftop). But rates are among the highest in the US and the supply half resets every January, and Maine's rural grid — the #1 outage exposure in the country — means winter outages measured in days. A battery locks in today's full-value NEB terms, hedges rising rates, earns income through the Efficiency Maine Small Battery Program, and provides backup when the grid goes down.
Maryland
BGE + Pepco + Delmarva + Potomac Edison · 2026 law made NEM term finite (PSC-set) · two-track config rule · RCES $5K reserve-first
Maryland's 4 IOUs (BGE + Pepco + Delmarva — all Exelon; Potomac Edison — FirstEnergy) are a THREAT-DOCUMENTED net-metering market. The 2026 Utility RELIEF Act (Md. Laws Ch. 353 / HB 1532, signed May 12, 2026) ended indefinite net metering: customers on NEM as of July 1, 2027 keep it only "for a length of time determined by the Commission through regulations" — no statutory floor, undetermined — and new solar after July 1, 2027 gets no NEM. Today's crediting is still full retail 1:1 with the indefinite credit-ROLLOVER election (2023 law), which is separate from the eligibility TERM the 2026 law made finite. The PSC's implementing proceeding (PC 78) is live (report Dec 15, 2026; framework Feb 1, 2027). Every battery add follows the MD two-track configuration rule so the addition doesn't jeopardize grandfathering. MEA's RCES program provides up to $5,000 reserve-first grants (Reservation Certificate BEFORE any work; FY26 closed, FY27 expected summer 2026). BGE + Pepco filed VPP pilots (DRIVE Act) — pending, positioning only, never income; Delmarva + Potomac Edison have none. MD Certified SRECs (Brighter Tomorrow Act 2024) pay 1.5x value through January 2028. All 4 IOUs in PJM (BGE / PEPCO / DPL / APS zones). The 2012 Mid-Atlantic Derecho remains the defining MD outage event. Federal ITC expired 12/31/2025; the state storage tax credit is dead (TY2024).
Michigan
Inflow/outflow spread · Documented rate climbs · Long storm-restoration history
Michigan is a backup-capable battery market spanning two utilities on the same cohort. Michigan replaced 1:1 net metering with an inflow/outflow Distributed Generation tariff (Public Act 235): imports bill at full retail (~$0.18/kWh) while exports credit at a sub-retail outflow rate, a real spread a battery captures via self-consumption. DTE Energy (Detroit / SE Michigan) credits exports at ~$0.09/kWh ($0.08765 on the first 17 kWh/day, $0.10139 on the excess) against ~$0.18 retail — a ~9¢ spread — and bars batteries from exporting to the grid (self-consumption/backup only). Consumers Energy (central / west Michigan) is the same cohort; its DG program bills on the default Rate RSP TOU rate, where the outflow credit tracks the power-supply energy rate so the honest self-consumption spread is roughly flat at ~9.3¢/kWh. CRITICAL honesty trap for both: Michigan's non-bypassable charges (fixed service/System Access charges + DTE's $2.31/kW-AC DG System Access Contribution + distribution) mean energy offset is NOT bill offset — a 90% energy-offset system saves only ~60% of the bill, so savings are quoted from the spread math, never a flat percentage. DTE's SolarCurrents is closed to new enrollment (a legacy REC contract) and Consumers has no residential solar production incentive — no income beat is stacked into savings. Both have climbed steadily through MPSC rate cases (DTE U-21534/U-21860; Consumers U-21870) and have a long storm-restoration history (the Feb 2023 ice storm alone left 680,000+ across the two utilities out for days). No federal ITC (expired Dec 31, 2025); no MI residential solar sales-tax or property-tax exemption for new installs. Legacy net-metering customers (DTE before 5/9/2019; Consumers before 1/1/2021) keep old 1:1 for up to 10 years from enrollment (resilience pitch, no spread savings; status terminates on a move). Reps must ask when the customer went solar and quote spread, not energy offset.
Missouri
Two net-billing utilities · Favorable monthly netting · Documented rate climbs
Missouri is a backup-capable battery market spanning two utilities on the same cohort: avoided-cost net billing (edg label). BUT the netting is MONTHLY at full retail on both — Ameren (St. Louis, Sheet 171) and Evergy Metro (Kansas City, Schedule NM Sheet 34D) each net all your kWh against each other over the billing month, so a battery's intra-month day/night shifting changes nothing at month-end. The battery does NOT reduce today's bill in Missouri (~$0 bill arbitrage) — say it plainly; monthly retail netting is genuinely favorable, and the honest value is resilience + rate-hedge + locked-in position + system takeover. Only net monthly OVER-production is credited at the low avoided-fuel-cost rate (Ameren $0.0384 summer / $0.0339 winter; Evergy Metro $0.0190) and expires at 12 months — a system-sizing matter no battery can change, so size to consumption. Ameren's residential bills rose ~20% from 2020 to 2023 (Consumers Council of Missouri); both face severe-weather exposure, no state battery incentive, no residential battery VPP, and no federal ITC (expired Dec 31, 2025). Reps never quote a per-kWh spread capture or a monthly bill reduction here; lead with protection.
Nebraska
100% public power · OPPD + LES + NPPD · Monthly netting (battery = protection, not bill savings)
Nebraska is the only state served entirely by consumer-owned public utilities. OPPD (Omaha, ~400K customers), LES (Lincoln, ~140K), and NPPD (~95K retail across outstate Nebraska) are the three largest. All net monthly at full retail (Neb. Rev. Stat. 70-2003) — genuinely favorable netting that already smooths the daily solar mismatch, so a battery does NOT reduce today's bill. Only net monthly over-production is credited at avoided cost with annual cash-out. NPPD has a confirmed 3-tier TOU with the widest spread in the book (17.82c summer) — but how NM netting interacts with TOU periods is unconfirmed, so no TOU dollar figure is quoted until the rider confirms it. No VPP, no state solar credit. The battery value case is severe-weather resilience, rate-trajectory hedge, locked-in position, and system takeover.
New Hampshire
Eversource + Liberty + Unitil + NHEC · ISO-NE · NEM 2.0 (~75-79% export) · NHCEF $3K upfront
New Hampshire is served by 4 electric providers: Eversource NH (largest, ~520K customers), Liberty Utilities NH (~47K), Unitil Energy Systems (~80K), and NH Electric Cooperative (~85K members). All sit in ISO-NE. NEM 2.0 (PUC Order 26,029, September 2017) credits exports at 100% supply + 100% transmission + 25% distribution — approximately 75-79% of the full retail rate for the IOUs. NEM 1.0 customers (pre-September 2017) retain full retail 1:1 net metering with a statutory lock through 12/31/2040. The NH Clean Energy Fund (NHCEF) offers a $230/kWh (max $3,000) upfront battery incentive — currently Enphase and FranklinWH ONLY (no Tesla, no SolarEdge). No annual DR performance payments in NH. No VPP. The battery value stack: self-consumption spread capture (Eversource/Liberty), NHCEF upfront incentive, severe-weather resilience, rate-trajectory hedge, and system takeover.
North Carolina
Duke Carolinas + Duke Progress (Bridge Rate / RSC EDG) + Dominion NC (1:1 NM) · PowerPair waitlisted/closed · Helene 2024 anchor
North Carolina's residential solar landscape spans 3 IOUs across 2 RTOs and 3 cohort treatments. Duke Energy Carolinas (~2M households, central/western NC, SERC) and Duke Energy Progress (~1.6M, central/eastern NC, SERC) both run on the Bridge Rate (transitional through 12/31/2026, 15-yr lock) / RSC (permanent successor, TOU + CPP) EDG framework since legacy 1:1 NM closed to new customers September 30, 2023. Pre-10/1/2023 install customers are grandfathered on retail 1:1 through 2027 cliff. Dominion Energy NC (smaller NE NC footprint, PJM Dom Zone) preserves full retail 1:1 NM. Duke PowerPair $9K residential battery rebate: both territories fully subscribed as of June 2026 — Duke Progress CLOSED since Nov 7, 2025 (0%, no waitlist); Duke Carolinas WAITLISTED / 0% (30,000 kW cap reached June 2026). Duke EnergyWise Home Battery Program (Duke VPP, up to $92/mo) still ACTIVE separately. Hurricane Helene 2024 is THE NC outage anchor (~1.34M Duke customers out in Carolinas; 703k in NC alone; western NC devastation including two submerged Swannanoa substations). Federal ITC expired 12/31/2025.
Ohio
Winter resilience first · Moderate bill savings · Documented rate climb
Ohio is a deregulated, backup-capable battery market. All six Ohio utilities net ALL charges — generation and non-generation — at the full retail rate within the billing month on a single register (only the net monthly excess credits at the SSO generation rate, a better excess rate than most states), so a battery does NOT reduce the monthly bill here — bill arbitrage is ~0, and every surface says so plainly. AES Ohio has the highest all-in of the six (~20.75¢) and the steepest climb, but the battery is still ~$0 on the bill there too. Winter-storm resilience is the dominant value driver: Ohio is #5 nationally for weather-related outages, Winter Storm Elliott (Dec 2022) triggered a PJM RTO-wide conservation call, and the region has taken direct hits (Duke-Cincinnati Ike 2008 ~782K out; the Dayton 2019 tornadoes). Regulatory hedging is third — AEP's 2025 net-metering reduction was reviewed and declined by PUCO (Docket 25-0349-EL-ORD, Jan 7 2026) but demonstrates intent; FirstEnergy Ohio 2025 supply-rate impacts were ~11.8-13.3%.
Oklahoma
Mandatory TOU for solar · OG&E 23.90c spread + PSO 19.74c all-in · Storm state
Oklahoma is a mandatory-TOU market: both utilities' NEBO tariffs require DG customers onto time-of-use rates, creating structural battery arbitrage. OG&E (OKC, ~880K customers) has a 23.90c base spread. PSO (Tulsa, ~527K) has a 19.74c all-in spread with per-interval netting. No VPP, no state incentives — value is TOU spread + storm resilience.
Pennsylvania
Strong statewide 1:1 net metering — stable for residential rooftop
PA mandates 1:1 retail-rate net metering by state law, and it is intact for residential rooftop across all seven IOUs. PPL (R-2025-3057164, settlement approved June 2026) and FirstEnergy (DSP-VII, P-2026-3060298) filed net-metering repricings, but primary-source verification confirms both reach only ≥ 100 kW demand/MRPL customers (utility-scale generators) — residential Rate RS (≤ 50 kW) stays on full-retail 1:1. All seven utilities pitch as stable-1:1 rate-hedge + resilience markets; the differentiators are territory, rate, and storm exposure, not a residential NEM cliff. Default config: backup-capable.
South Carolina
Sub-retail exports · Documented rate trajectory · Hurricane resilience
Most SC residential solar customers are now on Solar Choice TOU (DEC/DEP fully as of 1/1/2026; DESC's NEM 1.0 cohort as of 1/1/2026 with the NEM 2.0 cohort still on retail through 5/31/2029; co-ops on DER Rider). Three of four utility categories credit exports below retail. Documented rate trajectory at Dominion (Jul 2026), Duke Carolinas (Aug 2024–Aug 2026 stacked), Duke Progress (Feb 2026), and Santee Cooper (Apr 2025 + 2027/2028 proposed). Hurricane Helene 2024 was DESC's largest restoration in company history.
Tennessee
TVA territory · NES confirmed (NESolar Savings ~6¢ spread) · 4 LPCs qualitative pending primary-source confirmation
Tennessee launches with 5 LPCs across TVA territory — monopoly municipal and cooperative utilities with no retail choice. Nashville Electric Service (NES) is the confirmed dollar market: NESolar Savings purchases excess at ~6¢/kWh all-in vs ~12¢ retail, producing a moderate per-interval spread. The remaining four LPCs (Middle Tennessee EMC, Knoxville Utilities Board, Chattanooga EPB, Memphis Light Gas & Water) ship qualitative-only — no bill savings are claimed until each LPC's export compensation is confirmed from primary sources. All five LPCs carry the TVA Grid Access Charge on DG customers, the GPP legacy-cohort screen, and the statewide facts: no VPP routes any hardware in TN, TN sales tax 7%+ applies with no solar/battery exemption, and the federal ITC expired 12/31/2025. The pitch across TN is self-consumption spread (where confirmed) + TVA rate-trajectory hedge + tornado/severe-weather resilience + system takeover.
Texas
ERCOT deregulation · 5 deregulated TDUs + 4 single-layer · 9 utilities
Texas runs on ERCOT — except at the edges. In ~85% of the state the customer has two separate entities on the bill: a TDU (Oncor, CenterPoint, AEP Texas, TNMP, LP&L — the wires company) and a REP (the supply company they choose). The 4 single-layer entries are munis or regulated IOUs on their own terms: Austin Energy and CPS Energy (munis on ERCOT), El Paso Electric (regulated, WECC grid — far west), and Entergy Texas (regulated, MISO South grid — southeast TX / Beaumont). LP&L is the newest — Lubbock completed its SPP→ERCOT migration Dec 2023 and opened retail choice March 2024.
Virginia
Dominion VA + APCo VA · 1:1 NM preserved (NEM 2.0 April 2026 + APCo Sept 2025) · Community Energy Act VPP coming · PJM
Virginia's two IOUs (Dominion Energy VA, ~2.8M customers; Appalachian Power VA, ~530K) both preserved 1:1 retail net metering in 2025-2026 regulatory decisions. Dominion VA NEM 2.0 final order April 30, 2026 retained behind-the-meter retail-rate offset (year-end excess cashes out at $0.05829/kWh including the SCC-added $0.01 RPS credit). APCo VA SCC order September 2025 preserved 1:1 up to annual usage (above-usage credit at 5.66¢/kWh). Both utilities sit in PJM. Community Energy Act (signed May 2025) mandates Dominion VPP pilot with ≥15 MW residential battery additions — SCC tariff petition due Nov 15, 2026. No statewide battery rebate; no state solar tax credit; residential solar ≤ 25 kW property-tax exempt since Jan 1, 2023.
West Virginia
Appalachian Power WV + Mon Power + Potomac Edison · POST-SUNSET EDG (all 3 IOUs) · PJM · derecho + winter-storm resilience
West Virginia's three investor-owned utilities are all post-sunset for new net metering as of 2026. Appalachian Power WV (AEP subsidiary; southern WV) sunsetted 1:1 NM March 1, 2026 (application cutoff) / September 1, 2026 (completion cutoff); new customers credited at ~12.4¢/kWh export vs ~17.2¢/kWh retail. Mon Power + Potomac Edison (both FirstEnergy subsidiaries; north-central WV and Eastern Panhandle respectively) sunsetted January 1, 2025; new customers credited at $0.0934/kWh vs ~13-14¢/kWh retail. All three IOUs are PJM members. The 2025 PJM capacity-auction 833% price spike flowed through APCo as PJM APS Zone pass-through and through Mon Power + Potomac Edison as part of the FirstEnergy 27-28% 2025 supply-rate hike (same pattern that hit OH FirstEnergy customers). No WV state battery rebate, no WV state solar tax credit (historic 30%/$2K credit no longer in current state tax code), no utility VPP programs. WV leads the nation in lingering ice-storm outages — the June 2012 derecho remains the iconic outage event, with 2021 Winter Storm Shirley, the 2022 Double Derecho, and January 2026's statewide State of Emergency completing the recent outage history. HB 2568 (2025) sought to eliminate WV net metering; died in committee but the legislative threat could return.
On the roadmap
Arizona
APS + SRP + TEP · ACC / self-regulated · Export Rate post-2017
Arizona is served by APS (largest IOU, ACC-regulated), SRP (Phoenix metro cooperative, self-regulated political subdivision), and TEP (Tucson, ACC-regulated). APS transitioned from full-retail NM to an Export Rate framework in 2017 (Rate Rider E-RCP). SRP has mandatory time-of-use + demand charges for solar customers. Real export rates + demand charge structures + battery-addressability mechanics need primary-source verification before Top Tier launches the market.
California
PG&E + SCE + SDG&E · NEM 3.0 (NBT) live since April 2023
California's three big IOUs (Pacific Gas & Electric, Southern California Edison, San Diego Gas & Electric) all operate under NEM 3.0 — the Net Billing Tariff — since April 15, 2023. Exports credit at avoided-cost rates (~$0.05–$0.10/kWh) while imports run at TOU rates that hit $0.50+/kWh during peak summer evenings. Battery is essential to make solar pencil under NEM 3.0. Top Tier is scoping the CA market separately — TOU optimization + per-IOU rate trajectories require dedicated work.
Connecticut
Eversource + UI · ConnectedSolutions VPP ($200/kWh) · NE cluster
Connecticut's two IOUs (Eversource Energy and United Illuminating) jointly operate the ConnectedSolutions residential battery VPP — one of the strongest battery-payment programs in the country ($200/kWh-summer capacity payments). Net metering closed to new applicants in early 2022; current rooftop solar customers are on the Residential Renewable Energy Solutions tariff with Netting or Buy-All-Sell-All options. Top Tier is scoping CT separately — the VPP-first pitch differs structurally from the bill-spread pitch that anchors most current markets.
Massachusetts
Eversource + National Grid · ConnectedSolutions ($1-3K/yr) · SMART program
Massachusetts has the highest-paying residential battery VPP in the country: Eversource + National Grid jointly operate ConnectedSolutions with $200/kWh-summer and $50/kWh-winter capacity payments. Typical battery participation earns $1,000-3,000/yr. Net metering for new solar was replaced by the SMART program (Solar Massachusetts Renewable Target) in 2018; existing solar customers earn SMART incentive compensation alongside the battery VPP. Top Tier is scoping MA separately — the VPP-first pitch + SMART program mechanics differ structurally from the bill-spread anchor used in most current markets.
Nevada
NV Energy · PUCN · tiered declining export rate (AB 405 restoration)
Nevada is served primarily by NV Energy (Berkshire Hathaway Energy subsidiary). The Public Utilities Commission of Nevada (PUCN) restored net metering in 2017 via AB 405 after the controversial 2015 NEM reduction that nearly killed rooftop solar in the state. Current framework uses a tiered declining export rate schedule. Real current export tier position + rate trajectory + battery-addressability mechanics need primary-source verification before Top Tier launches the market.
New Jersey
PSE&G + JCP&L + ACE · NJ BPU · PJM · ADI successor NM + SREC-II
New Jersey is a deregulated market served by PSE&G (largest TDU), JCP&L (FirstEnergy), and Atlantic City Electric (Exelon). NJ BPU jurisdiction. NJ transitioned from legacy net metering to the ADI successor program in 2024. NJ sits in PJM (same RTO as PA/MD/VA), sharing PJM capacity-cost dynamics. Solar + storage incentives exist (NJ Clean Energy programs, SREC-II). Real ADI export terms + SREC-II value + battery-addressability mechanics need primary-source verification before Top Tier launches the market.
Rhode Island
Rhode Island Energy (PPL) · ISO-NE · NE cluster · single-utility scope
Rhode Island is served primarily by Rhode Island Energy (the PPL-owned successor to National Grid RI since May 2022). RI sits in ISO-NE, sharing the regional capacity-market pressure that drives the MA + CT battery-pitch dynamics. Net metering is currently 1:1 retail with capacity caps; whether RI follows MA's SMART-style transition is a regulatory open question. Single-utility market scope simplifies the data side, but the rate trajectory + any future battery VPP launch timing both need primary-source verification before Top Tier launches the market.
Utah
Rocky Mountain Power · Utah PSC · Export Credit Rate post-2020
Utah is served primarily by Rocky Mountain Power (PacifiCorp, Berkshire Hathaway Energy subsidiary). The Utah Public Service Commission transitioned net metering to an Export Credit Rate framework in 2020 (Docket 17-035-61), replacing full-retail 1:1 with a lower export rate. Real export credit rates + rate trajectory + battery-addressability mechanics need primary-source verification before Top Tier launches the market.
Vermont
Green Mountain Power + VEC + BED · Vermont PUC · strong NM (Act 99) + GMP battery programs
Vermont is served by Green Mountain Power (largest), Vermont Electric Cooperative, and Burlington Electric Department. Vermont PUC jurisdiction. VT has strong net metering rules (Act 99, 2014) with group net metering and a 500 kW residential cap. GMP operates battery programs including Bring Your Own Device and a Tesla Powerwall partnership. Real export rates + GMP battery program terms + battery-addressability mechanics need primary-source verification before Top Tier launches the market.