The largest and most proven data-centre market on earth, which is why it holds a strong rating despite a severe connection queue and rising cost. But it is saturated and expensive, and getting in is slow and slowing further. A builder free to go elsewhere may prefer a cheaper, faster market.
See live grid data →Dominion's contracted capacity pipeline rose from roughly 40 GW in early 2025 to about 47.1 GW by October 2025, pushing connection waits out by years, and a constraint in Loudoun County suppressed new connections outright. Dated relief is under way: the Golden-to-Mars 500 kV loop serves more than 40 new substations, and the Culpeper Technology Zone project adds about 1.2 GW for three of six new AI sites. Dominion publishes no per-substation capacity map for large load.
How to check for your site: Submit through Dominion's Data Center Requests process for a site-specific capacity position. Do NOT read Dominion's Hosting Capacity Tool as load capacity: it models additional generation on distribution feeders.
Why: FERC preliminarily found PJM's large-load tariff unjust (Section 206) and a DOE order allows curtailing data centres as a class; co-location and cost-allocation economics are in flux.
What would change the read: The FERC process settling on workable co-location and cost-allocation rules for large loads.
For new supply: PJM's reopened first-ready-first-served queue drew about 220 GW in its first cycle (106 GW gas, 67 GW storage), so the build pathway for new supply is genuinely open.
Beyond the grid: Community and land-use permitting is now decisive here: after residents raised water, noise and Civil War heritage concerns, courts voided the roughly 2,100-acre Prince William Digital Gateway approvals and the county stopped defending them in 2026, ending what would have been one of the world's largest campuses. Virginia Business Newsweek
Access is the binding constraint: a severe PJM interconnection queue, capacity-price spikes, and multi-year waits. Hyperscalers still execute via Dominion (~47 GW contracted pipeline), which earns the override; new greenfield entry is hard.
Tight availability: load growth of 30+ GW by 2030 is outrunning new supply.
Current filed-tariff costs are lower than previously estimated, while scheduled GS-5 obligations, tightening PJM capacity conditions and large-load connection requirements continue to weigh on the outlook.
Unmatched momentum: ~4 GW operational and ~1 GW added a year, the world's #1 market.
Carbon moderate (~280 g), gas-led with growing renewables.
Winter Storm Elliott (Dec 2022) drove nearly 46,000 MW of forced outages in PJM, about 25% of installed capacity, prompting PJM's first conservation call since 2014 and a warning that rotating outages were a real risk.
What this means: A large new load faces occasional exposure here. Monitor conditions and keep a contingency plan.
event-based · PJM Winter Storm Elliott report
Average customer interruption (SAIDI) of 131.3 minutes per year in 2024, excluding major event days as filed.
measured · Annual Report on Grid Modernization, Reliability and Integration of Renewables, Virginia SCC (Dec 2025) · EIA Form 861, Schedules 3B and 3C (annual electric power industry report) (major event days identified by the respondent's own method, not IEEE 1366, customer-weighted blend of 1 of 1 territories, 100% of customers, regional context only)
Reserve margins are tightening as data-center demand surges: the 2025 capacity auction cleared at the $333/MW-day cap with an installed reserve margin (the supply cushion above expected peak demand) near 14.8%, below the 20% target, and FERC members flagged reliability concerns. Mitigants include possible retirement deferrals and a lower forecast peak.
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 · PJM capacity prices hit record (Utility Dive) · NERC 2024 LTRA (PJM elevated-risk)
Virginia's regulator approved a separate rate class and tariff (GS-5) for the largest loads, effective 1 January 2027. Service is firm, and it is bought on a 14-year contract that includes a four-year ramp. The customer pays monthly the higher of actual demand or a minimum: 85% of contracted transmission and distribution demand, and 60% of contracted generation. Ceasing operations before term triggers exit fees equal to the minimum demand charges over the unexpired term. There is limited relief: contracted demand can be cut by 20% with 36 months notice without exit fees, and by up to 50% if the released capacity can be reallocated to another customer. Before that, the contracting chain itself carries cost: $250,000 at engineering agreement, then a construction agreement under which the customer reimburses 100% of costs incurred if the project is cancelled before energization. The commercial risk here is not curtailment. It is that you pay for capacity you reserved and did not use, and that the reservation itself is expensive to unwind.
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.
What this means: The supply picture looks likely to tighten; a new load should lock firm supply early and expect competition for capacity.
The average customer loses about 131.3 minutes of power per year (2024). This is the standard regulator outage measure (SAIDI); lower means a more reliable grid.
One operator’s record, not the whole market. No single customer experiences this figure as a market average: other operators serve load here and are not in it.
144 GW
72 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/northern-virginia with a paid key. These are generation and storage queue figures: they show interconnection-system congestion, not a typical large-load connection wait.
Severe
$333.44 per MW-day
2027/28 delivery year
PJM's capacity auction cleared at a record $333.44 per MW-day for 2027/28, the maximum allowed, and for the first time the whole region fell short of its reliability target. The forward cost of firm capacity is at its historical ceiling, driven by data-center load outpacing new supply.
Source: PJM 2027/28 Base Residual Auction (RTO Insider). A derived indicator: we publish the public clearing price and our read, never paywalled exchange data.
Current tariff-derived estimate for a 100 MW, 95% load-factor customer taking transmission-voltage service under Dominion GS-4.
Supply assumption. standard utility supply under the bundled regulated tariff; no competitive service provider, no self-supply, no special contract.
Recurring delivered charges only. Two riders, RGGI and DIST, are currently filed at exactly zero and are carried as applicable-and-zero rather than treated as absent.
Connection capital and contributions in aid of construction are outside this figure.
Rate Schedule GS-5 takes effect 2027-01-01. GS-5 is mandatory for qualifying new load of 25 MW or more at a load factor of at least 75%. Its rate levels for this archetype are not yet established, so it cannot be priced. The current estimate is GS-4 and only GS-4. Virginia State Corporation Commission, PUR-2025-00058.
These are separate customer cases, not the ends of a cost band. The standard PowerGridIQ archetype is a general large load.
Effective 1 July 2026 and scheduled to sunset before 1 July 2028 unless extended. Stated pre-refund. A refund mechanism exists and is not assumed.
Applies to: A qualifying data centre under HB30 Item 3-5.24. This is a DIFFERENT customer from the published PowerGridIQ archetype, which is a general large load and does not automatically incur this tax.
Qualifying offshore-wind contract: Rider OSW adjustment of approximately -$2.82/MWh, before the separately contracted cost of offshore-wind supply and environmental attributes. Net delivered cost is not publicly observable.
Applies to: A qualifying large general service customer under Va. Code 56-585.1:11 A, which requires a 15-year contract to procure offshore-wind supply and environmental attributes. Size alone does not qualify a customer.
Not a delivered-cost total. Removing the rider without adding the separately contracted cost of offshore-wind supply and environmental attributes would understate the customer's total cost.
Current tariff-derived estimate for a 100 MW, 95% load-factor customer taking transmission-voltage service under Dominion GS-4. This replaces a withdrawn band that was materially too high; see the correction record. GS-4 is the CURRENT tariff. Schedule GS-5 is a scheduled change effective 1 January 2027, is mandatory for qualifying new load, and is NOT included in this estimate.
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: Dominion Energy Virginia rates and tariffs · Virginia SCC, Dominion biennial review PUR-2025-00058.
The proceeding is concluded. GS-5 begins 1 January 2027. Projects expected to take service under the new regime should plan against its mandatory contract and minimum-payment requirements now.
Still unresolved
High
4 of 4 data layers measured
Full
3 of 3 dimensions: reliability, connection, cost
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) (major event days identified by the respondent's own method, not IEEE 1366, customer-weighted blend of 1 of 1 territories, 100% of customers, regional context only) |
| Forward cost | measured | 2027/28 delivery year | Fresh | PJM 2027/28 Base Residual Auction (RTO Insider) |
| Interconnection queue | measured | end-2025 (LBNL 2026) | Fresh | LBNL Queued Up 2026 |
| Realized cost | measured | 2026 | Fresh | Dominion Energy Virginia rates and tariffs |
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.
Territories in this market, each with its own filed record: Virginia Electric & Power Co. Which one serves a given site depends on where that site is.
Who runs the connection process: PJM Interconnection (regional transmission organisation), via New Service Request, plus the serving utility's own large-load process. PJM runs transmission interconnection; the distribution-level large-load path runs through the serving utility and its state regulator. Where the process starts.
The real-world events that test our Tier 2 call for Northern Virginia (PJM): 4 support it and 6 challenge it. Each is dated and cited, so you can check the rating against what is actually happening on the ground.
PJM filed with FERC on 13 Aug 2026 an Interim Resource Adequacy Service (IRAS) covering new Large Loads that neither bring their own capacity nor have it covered through the Reliability Backstop Procurement. In a supply emergency PJM would direct affected zones to reduce or transfer demand from those loads before calling on Load Management customers who are paid in advance to curtail, and before any action affecting residential consumers. PJM would build and maintain a Large Load Registry of all Large Loads, existing and new, and share it with states, utilities and regulators. From the 2029/2030 capacity auction, new Large Loads that bring no new supply would be excluded from the future need PJM procures against. PJM states that of 32 GW of forecast demand growth between 2024 and 2030, 30 GW is data centres. Retail cost allocation and load-reduction plans are left to the states, which is where the framework can stall. PJM asked FERC to accept within 60 days. This is a proposal, not a rule: it is unaccepted, and the six large-load Section 206 proceedings it sits alongside are still awaiting a Commission ruling on the abeyance requests filed in early August.
PJM said on 11 Aug 2026 it is evaluating changes to interconnection reliability requirements for computational loads including data centers and crypto mining, after roughly 3.8 GW of load tripped offline in Dominion's zone on 22 Jul 2026 following a 230 kV fault, the largest such event in PJM history. Candidate requirements cover voltage and frequency ride-through, on-site generation behaviour, and reconnection after disturbances. PJM restored its area control error within nine minutes against a 30 minute NERC requirement. Revises the earlier 3 GW figure for the same event.
Each of the six RTOs and ISOs, with their transmission owners, moved to hold its Section 206 show cause proceeding in abeyance: PJM on 28 Jul 2026 for 90 days (EL26-67), and SPP (EL26-68, 95 days), NYISO (EL26-69), MISO (EL26-70), CAISO (EL26-71) and ISO-NE (EL26-72) on 3 Aug 2026 for 90 days. The Commission set an answer period closing 7 Aug 2026. These are requests, not grants. Unless and until FERC rules on them the existing response deadlines stand. US wide in effect; keyed here because Northern Virginia is the largest affected concentration.
Source: Federal Register, FERC notice, Docket EL26-67-000 ↗A transmission line in Ashburn faulted and went out of service on 22 Jul 2026, after which data centers' own protection systems transferred them to backup generation. PJM reported more than 3 GW dropped off, about 3% of system demand at the time, producing a measurable frequency change but no reliability impact to the bulk power system. Dominion said no load was shed and that it did not disconnect the sites. A comparable 2024 Northern Virginia event was reported at about 1.5 GW. NERC is reviewing the event.
Source: Reuters ↗In Docket RD26-7 (16 Jul 2026) FERC directed NERC to file one or more new or modified mandatory reliability standards governing the integration of computational loads by 31 Dec 2026, to propose registry criteria bringing computational load entities under the mandatory framework, and to file a Phase II work plan by 1 Mar 2027. US wide in effect; keyed here because Northern Virginia is the largest affected concentration.
Source: Willkie on FERC RD26-7 ↗The 2028/29 Base Residual Auction (14 Jul 2026) procured 138,318 MW UCAP but cleared the footprint at the FERC-approved cap of $325/MW-day, 6,821 MW short of the reliability requirement, the second consecutive shortfall year.
Source: PJM Inside Lines ↗The FY2026 budget imposes a consumption tax of $0.011/kWh on all electricity used by Virginia data centers from 1 Jul 2026, including behind-the-meter and self-generated supply, projected at about $600M a year. A structural cost adder in the world's largest market.
Source: Williams Mullen / VA HB30 ↗Northern Virginia ended 2025 with roughly 4 GW of operating data-center capacity, up about 37% year on year and still the largest such market on earth, about 13% of global operational capacity. Demand keeps choosing the region despite the grid strain, an argument it may merit more than a middling tier, and a live test of whether access can keep pace.
Source: CBRE ↗A DOE 202(c) order (30 Jun 2026) authorizes PJM to direct curtailment of data centers and other large loads with backup generation as a last resort; the 2 Jul 2026 forecast peak of 166,241 MW approached the 2006 record of 165,563 MW and Pre-Emergency Demand Response was activated.
Source: PJM Inside Lines ↗Section 206 show-cause orders (18 Jun 2026) preliminarily find each RTO/ISO tariff unjust and unreasonable for large-load integration; 60 days to respond (due 17 Aug 2026), covering study speed, cost allocation, co-location and behind-the-meter generation.
Source: FERC ↗811 projects (106 GW gas, 67 GW storage) under the first-ready, first-served reform, which aims to speed connections in the world's largest market.
Source: PJM Inside Lines ↗The 2027/28 Base Residual Auction (17 Dec 2025) cleared the whole footprint at the FERC-approved cap of $333.44/MW-day, the first auction where the entire RTO fell short of the reliability requirement; PJM attributes ~5,100 MW of forecast load growth to data centers.
Source: PJM Inside Lines ↗How Northern Virginia (PJM)'s reliability-adjusted score and tier have moved, month by month. Part of your Analyst Desk.
Every field above carries its own source and freshness. Price, imports and exports are modelled in every market because no feed supplies them. Carbon intensity is derived from the fuel mix.
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