⚡ POWERGRIDIQ
Institutional Market Brief
🇺🇸 ISO New England · PGIQ Tier 3 Workable
As of June 2026 · powergridiq.com/rating/isone
PGIQ Rating v2 (reliability-adjusted) · as of June 2026
3

🇺🇸 ISO New England

Viable, with conditions, holding steady Reliability flags found
Tier 3 Workable · Composite 48/100, #54 of 79 markets (fundamentals 53 minus a reliability dock) · Outlook Stable · High confidence · how we score

Small, expensive and winter-gas-constrained, with an offshore-wind-heavy pipeline slow to land. Workable, not a magnet.

See live grid data →
One market,
four reads
BuildTier 3Siting ratingSellGrade BOfftakePlanLightLoad pressureMonitorWatchGrid strength
The same market, four decisions. Open any lens to see this market ranked against the rest.
Time to energize · file to power
~55 mo
File a large load today, powered ~2031. Typical range 47 to 63 months, measured.
End-to-end wait for a large new load, from a complete application being accepted to full firm energization of the nominated MW. Earlier milestones (initial, phased, temporary or conditional energization) are reported separately. A typical case, not a firm quote. · Source: LBNL Queued Up 2026 · Compare markets →
The same market, read four ways

ISO New England is a moderate market to sell power into

Grade B (Moderate)
Offtake score 69/100
Demand 45, build feasibility 52, combined into the score. For a seller: where buyers already pay, how tight supply is, and how feasible new build is here.
Price to beat
A 100 MW load on our standard case pays about $88/MWh delivered here. A competitive supply offer works against that level.
Forward capacity (firm supply promised for future years) price
$3.58 per kW-month (2027/28 (FCA 18)); forward cost pressure Moderate.
Queue depth (generation and storage)
About 15 GW in the interconnection queue (the line to connect to the grid), typical wait 55 months.
Regulatory momentum
Mixed, stable. FERC's 18 June 2026 Section 206 show-cause order requires ISO-NE to justify or reform how large loads connect, in a capacity-constrained, high-cost system where new demand competes for tight winter adequacy.
See it on the Offtake Grade →

ISO New England: little room at system level, light demand pressure

Little room 31/100
System-level room, not local capacity
Local capacity: not assessed. We have found no operator publication of area or substation capacity for this market, so whether the bus serving a candidate site can take the load is an open question. Absence of a finding here is not evidence that capacity exists.
Two reads for a grid planner: how much room the system as a whole looks to have (Little room), and how hard demand is already pushing (Light). The first is a market-level estimate from connection ease, forward adequacy and reliability margin. It is not local deliverability. Capacity at a specific substation is not assessed for this market, and a market can look roomy while the bus you want has nothing available. Confirm local capacity with the utility before relying on it.
Generation and storage queue
15 GW requested; about 3.8 GW likely to reach operation after historical withdrawal. The gap is speculative pipeline. This counts generation and storage seeking to connect, not load.
Demand growth
Moderate load growth in our read, the pull on your system.
Future firm supply
Future firm supply: tight for a large new load.
Load Pipeline Reality → Where demand is hungry → Connection friction →

Grid Risk Annex BETA

Watch
Needs structuring or mitigants · grid strength 41/100
A cited, dated grid-risk read on ISO New England for a capital provider, the banks and private-credit lenders, infrastructure funds and insurers holding or underwriting a power or data-centre exposure here. Drop it into a credit memo and watch each factor over the life of the exposure.
Read it against your asset. For a load asset (Buy), weight connection access and energization timing. For a generation or offtake asset (Sell), weight offtake demand, curtailment (when a plant is told to stop feeding the grid) and cost realisation. For a grid or transmission asset (Move), weight load-pipeline reality and buildout risk.
Rating and track record
PGIQ Tier 3 Workable, outlook Stable, High confidence. Scored on a public, dated, falsifiable record you can cite in a credit memo.
Delivery reliability
Reliability flags found in the bulk and local outage record we reviewed.
Future firm supply
Future firm supply: tight.
Cost certainty
Recurring cost about $88/MWh (band $70 to $115) for the standard 100 MW case, basis triangulated. Excludes connection capital.
Regulatory / stroke-of-pen
Mixed, stable. FERC's 18 June 2026 Section 206 show-cause order requires ISO-NE to justify or reform how large loads connect, in a capacity-constrained, high-cost system where new demand competes for tight winter adequacy.
Execution risk
15 GW in the generation and storage queue, about 75% historically withdrawn, the risk the project or load actually energizes on time.
Ongoing monitor
Track this market's rating actions and the Global Power Index as a covenant-style monitor over the life of the exposure.
Monitoring plan
Covenant-style triggers to watch over the life of the exposure: a change in the PGIQ rating or outlook; a dated regulatory move (stroke-of-pen risk); a capacity-auction or cost-band shift; a forward firm-supply adequacy warning; and a rise in queue drop-out or connection friction. Track them on this market page and the Global Power Index, or as Analyst Desk alerts.
Sources: ISO-NE / regional data
This is a directional grid-risk screen, not a credit rating, and not investment, engineering or procurement advice.
The formatted, cited Grid Risk Annex export is an Analyst Desk feature.See the Grid Exposure Monitor →

Regulatory momentum

The regulatory and permitting environment is increasingly the binding variable for a new large load.
Mixed→ stable

Why: FERC's 18 June 2026 Section 206 show-cause order requires ISO-NE to justify or reform how large loads connect, in a capacity-constrained, high-cost system where new demand competes for tight winter adequacy.

What would change the read: A Section 206 outcome that opens a workable large-load pathway without eroding ISO-NE's already tight capacity margin.

The five pillars behind the tier

A
A
C
M
C
The pillar signature: Access, Availability, Cost, Momentum, Carbon, taller is stronger. The same shape repeats across every market so peers compare at a glance.
Access30%52

Workable access with faster studies than most US ISOs (~3.6 yr), but a small, constrained system.

Availability25%50

Tight availability, especially winter gas constraints.

Cost25%60

Expensive power.

Momentum15%45

Lower momentum; offshore-wind-led pipeline is slow.

Carbon5%63

Carbon moderate (~240 g).

Default weights, which lean toward cost and access rather than carbon: Access 30 · Availability 25 · Cost 25 · Momentum 15 · Carbon 5. Momentum reflects the data-center build already underway, not just stated intentions.
Seller view: Read these the other way: momentum is your customer pipeline, cost is your revenue ceiling, and access is how hard it is to build and sell here, not only to connect.

Reliability overlay

Reliability adjustment: the five-pillar score of 53 is reduced to 48, a deduction of 5 points, reflecting the delivery-reliability and firm-supply risks flagged below. Reliability is reported as five separate layers, never as one combined label, because they answer different questions and a strong answer on one does not cover a gap in another: what has actually failed on the bulk system, what a forward assessment expects of firm supply, how the local network performs, what your contract actually promises, and what your site is designed to ride through. Any one of them can cap the tier.

Historical bulk-system performance: No reliability flags found

Historical utility-territory delivery performance: No reliability flags found

Average customer interruption (SAIDI) of 107.58 minutes per year in 2024, excluding major event days as filed.

measured · EIA Form 861, Schedules 3B and 3C (annual electric power industry report) (two major-event methods, IEEE; respondent-defined, customer-weighted blend of 9 utilities, regional context only)

Role not yet declared. We have not recorded whether this is one operator’s filing or an average across several, so read it as context until we do. mixed methods: IEEE 96%; respondent-defined 4% of customers. Major event days are excluded throughout; the methods differ only in how those days are identified, a smaller difference than the spread between the utilities themselves. Constituents below carry their own standard. It is a territory-wide history and is silent on: performance at a specific substation or feeder; transmission-level service, which is a different product from distribution service; the industrial or large-load customer class specifically; N-1 or other redundancy architecture at the supplying substation; contractual curtailment rights the utility may hold over the load; power quality and momentary interruptions, which this metric excludes by construction; on-site UPS, storage or generation; forward adequacy: it is a record of what happened, not a forecast.

Which utility would serve you?

The market figure above is an average across these territories. Your site sits in one of them, not in the average. Each row below is that utility’s own filed record, which is the evidence a Project Case can actually rest on.

Serving utilitySAIDI min/yrCustomersMajor-event method
NSTAR Electric Company (MA)66.11,462,127IEEE 1366
Massachusetts Electric Co (MA)90.721,345,044IEEE 1366
Connecticut Light & Power Co (CT)76.91,326,461IEEE 1366
Central Maine Power Co (ME)215.4679,726IEEE 1366
Public Service Co of NH (NH)81.5551,456IEEE 1366
The Narragansett Electric Co (RI)60.79509,231IEEE 1366
United Illuminating Co (CT)49.2345,159IEEE 1366
Green Mountain Power Corp (VT)281.4275,233own method
Versant Power (ME)478.0165,401IEEE 1366

Filed to EIA Form 861 for 2024, excluding major event days. Territory-wide averages: see the layer note above for what they do not establish.

Forward resource adequacy (assessed): Tight

NERC's 2024 assessment rates New England elevated-risk: persistent winter natural-gas constraints plus electrification-driven demand growth could raise shortfall risk by 2026, and extreme cold could challenge reliability further.

What this means: A large new load should expect genuine exposure to forced power cuts (curtailment), price spikes, and delays in getting connected, and should design in backup power or firm supply contracts.

assessed · NERC 2024 Long-Term Reliability Assessment

Contractual service terms: not assessed

We have not compiled what firm service actually promises here: whether it is firm, non-firm or interruptible, the conditions under which you can be curtailed, the redundancy required of you, and the transfer time behind any N-1 commitment. Treat this as an open diligence item, not as an indication that service is firm.

Ask the utility for the tariff or service agreement terms before relying on firm supply.

Designed site resilience: not applicable at market level

Utility feeds, UPS, storage, on-site generation, islanding, black start and the residual energy you still expect to lose are properties of a specific site design, not of a market. This layer only exists once there is a site, and we never assert it for you.

Confidence: Med-High. Each input is labelled as measured, modelled, or drawn from a specific event, and is framed as a risk to a prospective large new load, not as a verdict on any utility or grid operator. Forward adequacy is an assessment of what is expected, not a measurement of what has happened; it is a forecast and is labelled as one.
Seller view: Tight forward capacity is scarcity that firm generation and storage get paid for; an adequacy flag is a demand signal for new supply, not only a risk to a load.

Supply relief outlook

Will the power crunch ease before your load energizes? This nets the demand racing for capacity against the new supply likely to arrive and the old supply leaving. A cross-side read, using the same data a seller sees the other way.
Tightening
Demand pressure
Moderate load growth competing for the same capacity.
New supply in motion
About 3.8 GW of the generation and storage queue is likely to reach operation after historical withdrawal.
Can new supply arrive
Regulatory momentum mixed, stable.
Future firm supply
Future firm supply: tight.

What this means: The supply picture looks likely to tighten; a new load should lock firm supply early and expect competition for capacity.

Reliability metrics

Delivery reliability (measured)

The average customer loses about 107.58 minutes of power per year (2024). This is the standard regulator outage measure (SAIDI); lower means a more reliable grid.

Source: EIA Form 861, Schedules 3B and 3C (annual electric power industry report) (two major-event methods, IEEE; respondent-defined, customer-weighted blend of 9 utilities, regional context only)

Hard, cited measures behind the reliability overlay above: the regulator outage series (SAIDI, measured, published with a lag) and the forward resource-adequacy assessment (a measured forecast). Framed as risk to a prospective large new load, not a verdict on any utility.

Interconnection queue

These are generation and storage interconnection queues. They show how congested the interconnection system is. They do not measure how long a new large load waits, and their withdrawal rates are not load withdrawal rates. At the end of 2025, generation and storage projects totalling about 2,060 GW were actively waiting in United States queues, down 10% from a year earlier. Of the capacity that entered between 2000 and 2020, about 75% withdrew before connecting and only about 13% reached operation by end-2025. The typical project built in 2025 waited about 61 months from request to operation (Lawrence Berkeley National Laboratory, Queued Up 2026). Figures below are refreshed quarterly; each is labelled measured or modelled.

Active queue depth

15 GW

Typical wait

55 months

The full queue analysis for this market, which covers the share of projects that give up and leave the queue (the withdrawal rate), how much of the queue is data centers, and the sources, is available through /api/v1/queue/isone with a paid key. These are generation and storage queue figures: they show interconnection-system congestion, not a typical large-load connection wait.

Seller view: A deep queue is both your own time-to-revenue and a moat against competing supply; what matters is the effective supply likely to complete after withdrawal, not the headline queue.

Forward cost anchor

Siting a load is a decade-long cost bet, so the forward cost of firm capacity matters more than today's spot price. This is the public capacity-auction clearing price, the market's own forward read, not a paywalled forward curve.

Forward cost pressure

Moderate

Latest capacity clearing price

$3.58 per kW-month

2027/28 (FCA 18)

Trend: Rising, up about 40% from the prior auction; the next auction is delayed to 2028.

ISO New England's most recent capacity auction cleared at $3.58 per kW-month for 2027/28, up roughly 40%. The next auction is delayed to 2028, so this is the standing forward signal.

Source: ISO-NE Forward Capacity Auction 18 (Utility Dive). A derived indicator: we publish the public clearing price and our read, never paywalled exchange data.

Seller view: This capacity clearing price is a direct revenue signal for new supply: a rising trend supports the build thesis, a falling one is a warning.

Realized cost band

What a large electricity user pays for power here on one declared case, 100 MW contracted demand, 95% load factor, HV service, per megawatt-hour. Not the wholesale price and not the sticker tariff: energy plus the grid, delivery and other charges that land on the bill. It is a range, because real contracts vary, and it is labelled by how it was built.

Recurring cost, delivered

$70 to $115 per MWh

Midpoint about $88 per MWh

How this band was built

triangulated

From 3 public fragments

What builds the $88 midpoint

$48
$31
Wholesale energy$48
Transmission & delivery$31
Capacity (Forward Capacity Market)$6
Ancillary & other$3
All-in delivered$88 /MWh
How the $88/MWh figure is built up, component by component, for 100 MW contracted demand, 95% load factor, HV service. The split is our estimate; the total is the midpoint of the compiled band (triangulated). Recurring cost only: customer-funded connection capital is a separate one-off and is not included. New England carries some of the heaviest transmission and delivery costs in the country, which is the main reason its delivered cost runs well above the wholesale energy price. Anchored to published figures (ISO New England wholesale prices).

Where the cost lands

$88
Low $70Midpoint $88High $115
A band, not a single price: the cheaper end is a well-structured contract on favourable terms, the higher end a less optimised one. The midpoint is our best central read.
What is in the number: Wholesale energy near $40 to $50 per MWh (the 2024 real-time average was about $39.50), plus New England's high transmission and delivery charges, a Forward Capacity Market charge, and ancillary services.

New England carries one of the higher US large-load bands: gas-set energy plus some of the country's heaviest transmission and delivery costs. A new large load's delivered cost runs well above the wholesale price.

This market's band is free here; the ranked cross-market table with every market's precise midpoint is the Analyst Desk. See the ranked view.

Basis: triangulated from public sources, in US dollars per MWh delivered to a large high-load-factor load, excluding refundable taxes. Sources: ISO New England wholesale energy prices · Industrial electricity prices (EIA).

Seller view: This delivered price is the level a competitive supply offer must beat, and the revenue ceiling a merchant plant works against here.

Data provenance and freshness

What we hold for this market, field by field. Each tier below is assigned from the evidence actually held for that field, with provenance. A low tier means we looked and it is thin; it is not a verdict on the market.
cost: M3connection: M2reliability: M2carbon: M2regulatory: M2local capacity: not_assessed
Against a Standardized Project Case, the binding field is connection, reliability. That is what a standardized case would turn on here; a readiness result for your own project depends on your own requirements, siting and utility, which this market-level read does not know.
Read against other uses: Discovery and monitoring: M2 · Market comparison: M2 · Project Case with a carbon requirement: M2 · Conditional site diligence: insufficient.
Depth is not a rating strength, a confidence score or a feasibility conclusion. An aggregate is only ever shown for a named use case, and equals the lowest tier across that use case's required fields. Definitions v1.0. See the full coverage matrix.
How solid the data behind this rating is, on two separate axes plus recency. Source reliability is how measured the numbers are, as opposed to triangulated or modelled. Coverage is how many of the decision-relevant data dimensions (reliability, connection, and cost) are compiled for this market. The two are kept apart because they answer different questions: a market can have strong sources on the little that is covered, or broad coverage that still leans on models. Neither grades the rating itself. The rating is a cited opinion, graded separately and falsifiably by the public track record and baseline measurement plan.

Source reliability

High

3 of 4 data layers measured

Coverage

Full

3 of 3 dimensions: reliability, connection, cost

Last reviewed

June 2026

per-layer vintages below

LayerMethodVintageFreshnessSource
PGIQ Rating opinionopinionJune 2026CurrentPGIQ methodology
Reliabilitymeasured2024FreshEIA Form 861, Schedules 3B and 3C (annual electric power industry report) (two major-event methods, IEEE; respondent-defined, customer-weighted blend of 9 utilities, regional context only)
Forward costmeasured2027/28 (FCA 18)FreshISO-NE Forward Capacity Auction 18 (Utility Dive)
Interconnection queuemeasuredend-2025 (LBNL 2026)FreshLBNL Queued Up 2026
Realized costtriangulated2026FreshISO New England wholesale energy prices

Freshness reflects each layer's refresh cadence: reliability annual to three-yearly, capacity-auction and queue yearly, tariffs every year or two. The full cross-market freshness dashboard is at /data-quality.

What this market can and cannot answer yet

No market-level read closes a project case on its own, and saying only that would waste the evidence we do hold. Below is what is established, what is open, and what to do next.

What is established

  • Recurring cost band $70 to $115 per MWh, midpoint $88, basis triangulated, against the 100 MW archetype
  • Historical utility-territory delivery performance 107.58 minutes per year (2024)
  • Forward resource adequacy (assessed)
  • Typical interconnection wait about 55 months (generation and storage queue, not a load wait)

What is open

  • Historical bulk-system performance
  • Contractual service terms (would change the answer)
  • Designed site resilience
  • local_capacity evidence

Who would actually serve you

Territories in this market, each with its own filed record: NSTAR Electric Company, Massachusetts Electric Co, Connecticut Light & Power Co, Central Maine Power Co, Public Service Co of NH, The Narragansett Electric Co, United Illuminating Co, Green Mountain Power Corp. Which one serves a given site depends on where that site is.
Who runs the connection process: not yet compiled for this market. This is wayfinding rather than evidence, and its absence is a gap in our compilation, not a fact about the market.

Credible ranges today

  • Cost $70 to $115 per MWh, midpoint $88 (triangulated)
  • Schedule: interconnection queues here run about 55 months for generation and storage; a large load follows a different process and we do not hold its measured distribution

What could disqualify this market

  • Winter reliability and gas dependence.
  • Slow offshore-wind pipeline.

Five questions for the utility or system operator

  1. What is the available capacity at the bulk supply point and substation that would serve this site, and what would a 100 MW request do to it?
  2. Is firm service available at 100 MW, and what curtailment rights would you retain over us once we are energised?
  3. What are the milestone dates from a complete application to full firm energisation, and which network upgrades would a 100 MW load trigger?
  4. What is your own territory's SAIDI and SAIFI for the industrial class, on which major-event standard, and what redundancy serves the candidate substation?
  5. What is the all-in delivered rate for 100 MW at a 95% load factor, including demand, network and rider charges, under the tariff that would actually apply?

Documents that would advance the case

  • The area or substation capacity study, and the current queue position list.
  • The applicable large-load tariff or the draft electric service agreement.
  • The interconnection or system impact study, and a specimen connection offer.
  • The utility's own reliability filing and the substation single-line diagram.
  • The current tariff sheet with all riders, and any large-load contract terms.

Outlook drivers

↑ Upgrade triggers

  • Offshore wind energizes at scale.
  • Transmission upgrades ease winter constraints.

↓ Downgrade triggers

  • Winter gas-supply stress.
  • Offshore-wind delays persist.

Key risks

Peer comparison

Trades like
NYISO (small, constrained, pricey)
Ahead
on study speed
Behind
on scale
🔔 Get alerts for ISO New England
Be notified the moment this market's PGIQ Rating, outlook, or a material development changes. Free while we validate demand.

Rating history

Jun 2026
AffirmedNamed in the FERC show-cause suite; preliminary stage, tier holds, monitoring.
Trigger: FERC Section 206 show-cause order (18 Jun 2026)
June 2026
New ratingNew rating: Tier 3 Workable assigned.
🔒 The full time series behind ISO New England, how its score, recurring cost, and interconnection queue have moved month by month, is part of the Analyst Desk. The rating actions above are always free.
Every rating action is dated and explained, and the log is only ever added to, never edited. Reviews happen on a regular schedule and whenever a significant event occurs. "Affirmed" means we reviewed a development and the tier held; "Under review" means a significant item is being assessed and the rating could change.

Score history

How ISO New England's reliability-adjusted score and tier have moved, month by month. Part of your Analyst Desk.

Loading history…

How does ISO New England compare to the other 78 markets?

This page is our full read on ISO New England alone, and it is free. To decide where a large load should actually go, you need every market side by side, ranked on recurring cost and time-to-connect, with the history and alerts when your shortlist moves. That is the Analyst Desk.

With your Analyst Desk, compare ISO New England against every market side by side, ranked on recurring cost and time-to-connect, with the full history and shortlist alerts.

+ Add to your shortlist Recurring cost, ranked Connection friction, ranked Get the Analyst Desk →
Cite as: PowerGridIQ Rating, "ISO New England" (Tier 3 Workable), as of June 2026. A proprietary, directional screen for siting a large electricity load; not a connection guarantee, and not investment, engineering or procurement advice. Sources and methodology at powergridiq.com/methodology. © PowerGridIQ.