PGIQ Rating v2 (reliability-adjusted) · as of June 2026

🇺🇸 MISO (Midwest)

Strong, with known trade-offs, and the path is improving Reliability flags found
Tier 2 Strong · Composite 57/100, #25 of 79 markets (fundamentals 64 minus a reliability dock) · Outlook Positive · Med confidence · how we score

Cheap power and a real build pipeline across Ohio, Indiana, Chicago and Iowa, with the ERAS fast-track easing a deep connection queue. Getting connected is the main hurdle; low cost and steady demand are the strengths.

See live grid data →

One market,
four reads

BuildTier 2Siting rating SellGrade BOfftake PlanRisingLoad pressure MonitorWatchGrid strength

The same market, four decisions. Open any lens to see this market ranked against the rest.

Time to energize · file to power

~50 mo

File a large load today, powered ~2030. Typical range 42 to 57 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

BuildSellPlanMonitor

MISO (Midwest) is a moderate market to sell power into

Grade B (Moderate)

Offtake score 74/100

Demand 47, build feasibility 56, 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 $60/MWh delivered here. A competitive supply offer works against that level.

Forward capacity (firm supply promised for future years) price

about $217 per MW-day, annualized (2025/26 planning year); forward cost pressure High.

Queue depth (generation and storage)

About 382 GW in the interconnection queue (the line to connect to the grid), typical wait 50 months.

Regulatory momentum

Mixed, improving. FERC's 18 June 2026 Section 206 show-cause order pushes MISO to set clear large-load connection and cost-allocation rules, reinforcing reforms MISO was already developing for fast-growing Midwest data-centre demand.

See it on the Offtake Grade →

MISO (Midwest): effectively full at system level, rising demand pressure

Effectively full 27/100

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 (Effectively full), and how hard demand is already pushing (Rising). 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

382 GW requested; about 95.5 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

Fast 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 48/100

A cited, dated grid-risk read on MISO (Midwest) 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 2 Strong, outlook Positive, Med 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 $60/MWh (band $48 to $78) for the standard 100 MW case, basis triangulated. Excludes connection capital.

Regulatory / stroke-of-pen

Execution risk

382 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: MISO ERAS

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↑ improving

Why: FERC's 18 June 2026 Section 206 show-cause order pushes MISO to set clear large-load connection and cost-allocation rules, reinforcing reforms MISO was already developing for fast-growing Midwest data-centre demand.

What would change the read: MISO's Section 206 response becoming a durable, open large-load connection process rather than case-by-case treatment.

The five pillars behind the tier

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%50

Constrained access (deep queue), eased by the ERAS fast-track for priority projects.

Availability25%55

Moderate availability across a large footprint.

Cost25%88

Cheap power.

Momentum15%70

High momentum: a growing Midwest build (Ohio, Iowa).

Carbon5%52

Carbon moderate-high (~330 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 64 is reduced to 57, a deduction of 7 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: Minor flags found

Exposed in Winter Storm Uri (Feb 2021), with rolling blackouts in the MISO South region during the extreme cold.

What this means: A large new load faces occasional exposure here. Monitor conditions and keep a contingency plan.

event-based · FERC/NERC Feb 2021 cold weather final report

Historical utility-territory delivery performance: No reliability flags found

Average customer interruption (SAIDI) of 121.15 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 17 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 93%; respondent-defined 7% 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 utility	SAIDI min/yr	Customers	Major-event method
DTE Electric Company (MI)	159.17	2,261,010	IEEE 1366
Consumers Energy Co - (MI) (MI)	154.97	1,889,301	IEEE 1366
Northern States Power Co - Minnesota (MN)	110.39	1,361,168	IEEE 1366
Union Electric Co - (MO) (MO)	94.0	1,283,126	IEEE 1366
Ameren Illinois Company (IL)	120.6	1,249,900	IEEE 1366
Wisconsin Electric Power Co (WI)	109.0	1,212,936	IEEE 1366
Duke Energy Indiana, LLC (IN)	112.89	910,102	IEEE 1366
MidAmerican Energy Co (IA)	88.0	740,347	IEEE 1366
AES Indiana (IN)	87.3	525,000	IEEE 1366
Wisconsin Power & Light Co (WI)	67.52	501,445	own method
Interstate Power and Light Co (IA)	99.35	499,530	own method
Northern Indiana Pub Serv Co (IN)	169.0	485,189	IEEE 1366
Wisconsin Public Service Corp (WI)	95.0	469,161	IEEE 1366
Northern States Power Co - Minnesota (SD)	63.63	104,471	IEEE 1366
Northern States Power Co - Minnesota (ND)	54.54	95,754	IEEE 1366
MidAmerican Energy Co (IL)	174.0	85,293	IEEE 1366
MidAmerican Energy Co (SD)	42.0	5,299	IEEE 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

The only region NERC's 2024 assessment rates high-risk: coal retirements and delayed additions push reserve margins below reference levels from 2025, with a projected shortfall of about 2.7 GW by 2029.

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: 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.

Balanced

Demand pressure

Fast load growth competing for the same capacity.

New supply in motion

About 95.5 GW of the generation and storage queue is likely to reach operation after historical withdrawal.

Can new supply arrive

Regulatory momentum mixed, improving.

Future firm supply

Future firm supply: tight.

What this means: Supply and demand look broadly balanced; the outcome hinges on the drivers below.

Reliability metrics

Delivery reliability (measured)

The average customer loses about 121.15 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 17 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

382 GW

Typical wait

50 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/miso 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

High

Latest capacity clearing price

about $217 per MW-day, annualized

2025/26 planning year

Trend: Volatile: a record summer clearing price of $666.50 per MW-day, easing about 42% the following year but staying tight.

MISO's first seasonal, reliability-based auction produced a record summer clearing price of $666.50 per MW-day and an annualized level near $217; the following year eased toward $126 but the market stays structurally tight.

Source: MISO Planning Resource Auction (Modo Energy). 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

$48 to $78 per MWh

Midpoint about $60 per MWh

How this band was built

triangulated

From 3 public fragments

What builds the $60 midpoint

$35

$15

Wholesale energy$35

Transmission & delivery$15

Capacity (Planning Resource Auction)$6

Ancillary & other$4

All-in delivered$60 /MWh

How the $60/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. The Midwest is a moderate, generally low-cost market; the capacity charge is modest outside scarcity years, and transmission is the main non-energy cost. Anchored to published figures (MISO 2024 State of the Market (Potomac Economics)).

Where the cost lands

$60

Low $48Midpoint $60High $78

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: Real-time wholesale energy near $31 per MWh in 2024, plus transmission and delivery, a modest Planning Resource Auction capacity charge, and ancillary services.

The Midwest is a moderate, generally low-cost large-load market: cheap wholesale energy plus transmission and a modest capacity charge. Delivered cost sits below the coastal ISOs.

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: MISO 2024 State of the Market (Potomac Economics) · Wholesale 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

Layer	Method	Vintage	Freshness	Source
PGIQ Rating opinion	opinion	June 2026	Current	PGIQ methodology
Reliability	measured	2024	Fresh	EIA Form 861, Schedules 3B and 3C (annual electric power industry report) (two major-event methods, IEEE; respondent-defined, customer-weighted blend of 17 utilities, regional context only)
Forward cost	measured	2025/26 planning year	Fresh	MISO Planning Resource Auction (Modo Energy)
Interconnection queue	measured	end-2025 (LBNL 2026)	Fresh	LBNL Queued Up 2026
Realized cost	triangulated	2026	Fresh	MISO 2024 State of the Market (Potomac Economics)

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 $48 to $78 per MWh, midpoint $60, basis triangulated, against the 100 MW archetype
Historical utility-territory delivery performance 121.15 minutes per year (2024)
Historical bulk-system performance (event-based)
Forward resource adequacy (assessed)
Typical interconnection wait about 50 months (generation and storage queue, not a load wait)

What is open

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: DTE Electric Company, Consumers Energy Co - (MI), Northern States Power Co - Minnesota, Union Electric Co - (MO), Ameren Illinois Company, Wisconsin Electric Power Co, Duke Energy Indiana, LLC, MidAmerican Energy Co. 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 $48 to $78 per MWh, midpoint $60 (triangulated)
Schedule: interconnection queues here run about 50 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

Interconnection backlog.
Availability through the fossil transition.

Five questions for the utility or system operator

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?
Is firm service available at 100 MW, and what curtailment rights would you retain over us once we are energised?
What are the milestone dates from a complete application to full firm energisation, and which network upgrades would a 100 MW load trigger?
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?
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

ERAS and queue reform shorten connection timelines.
Wind and solar additions lower carbon.

↓ Downgrade triggers

Queue backlog and study delays persist.
Coal-exit tightens availability.

Key risks

Interconnection backlog.
Availability through the fossil transition.

Peer comparison

Trades like

SPP (cheap, building)

Ahead

on momentum vs SPP

Behind

ERCOT on access

Evidence behind this rating

The real-world events that test our Tier 2 call for MISO (Midwest): 2 support it. Each is dated and cited, so you can check the rating against what is actually happening on the ground.

MISO declares a maximum generation emergency in its second July heat dome ✓ Supports the rating

Jul 2026AvailabilityMateriality: med

A dayslong heat dome over the Midwest drove demand to about 122 GW and MISO invoked maximum generation emergency procedures (15 Jul 2026), its second emergency of the month.

Source: RTO Insider ↗

MISO forecasts peak load up 35% to ~163 GW by 2035 on data centers ✓ Supports the rating

Apr 2026MomentumMateriality: med

MISO's long-term forecast (13 Apr 2026) sees peak load rising from 121 GW in 2025 to about 163 GW by 2035, led by data centers, with 8 to 14 GW of DC load expected online in 2026-2027. MISO flags high uncertainty and signs of right-sizing.

Source: Utility Dive / MISO ↗

Cited, dated developments tagged to the pillar they bear on, and whether they support or challenge the current tier. A material item flags the market for analyst review and may drive a rating action.

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Rating history

Jun 2026

AffirmedNamed in the FERC show-cause suite; reform process is preliminary and procedural. Tier holds, monitoring the 17 Aug response.

Trigger: FERC Section 206 show-cause order (18 Jun 2026)

Jul 2026

AffirmedTier holds. The 35% load-growth forecast confirms demand momentum without changing near-term access or availability.

Trigger: MISO long-term load forecast, 13 Apr 2026

Jul 2026

AffirmedEmergency procedures managed the heat dome without reported firm load shed. Consistent with the thin-margin availability profile already in the rating. Tier holds.

Trigger: Maximum generation emergency at ~122 GW demand, 15 Jul 2026

June 2026

New ratingNew rating: Tier 2 Strong assigned.

🔒 The full time series behind MISO (Midwest), 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 MISO (Midwest)'s reliability-adjusted score and tier have moved, month by month. Part of your Analyst Desk.

Loading history…

How does MISO (Midwest) compare to the other 78 markets?

This page is our full read on MISO (Midwest) 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 MISO (Midwest) 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, "MISO (Midwest)" (Tier 2 Strong), 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.