Source Report

PJM (Northern Virginia Data Center Alley)

PJM's Reliability Pricing Model (RPM) capacity auctions have failed to procure sufficient resources to meet reliability targets due to explosive data center load growth in Northern Virginia's Dominion zone, where real-time sales data and interconnection queues now stretch to 7 years, forcing developers to delay energization or seek colocation with existing generation; this mechanism—bidding three years ahead—exposes shortages early but amplifies costs as retirements and queue backlogs (140 GW generation queue) prevent new supply, with the December 2025 auction for 2027/2028 falling 6,516 MW short for the first time in history.[1][2]
- Capacity prices surged 833% to $269.92/MW-day (RTO) in 2025/2026 BRA, $329/MW-day in 2026/2027, and $333.44/MW-day in 2027/2028, all hitting FERC caps; data centers drove 97% of 5,250 MW load growth forecast.[1][3]
- Dominion queue: 30 GW+ data center demand by 2030; congestion costs up 64% to $1.7B in 2024; $6.7B 765kV backbone approved Feb 2025 but years from completion.[4][5]
- Public cases: Under-construction capacity fell 29% in NoVA (2025); projects entering queue now face 2028+ agreements; first-ever auction shortfall signals 24-55 GW gap by 2030-2035.[2]

Implications for competitors/entrants: New data centers in Loudoun/Dominion face 5-7 year waits; colocation (e.g., nuclear) or behind-the-meter gas bypasses queues but requires FERC tariff changes; non-obvious: backstop auctions (14.9 GW bilateral by 2026) allocate costs to loads, raising entry barriers unless flexible demand (curtailment) qualifies for credits.[6]

ERCOT (Texas Data Center Build Rate)

ERCOT's shift to batch interconnection studies amid 410 GW large-load queue (87% data centers) creates a "speculative bubble," where only 1.8% of requests are energized, delaying projects via stricter viability rules (SB6) and fast-build gas peakers, but weather risks (e.g., 2021 freeze) amplify shortages as reserves tighten post-2028 despite 10 GW Texas Energy Fund gas.[7][8]
- Queue exploded: 63 GW (Dec 2024) to 233-410 GW (late 2025); peak forecast 278 GW (2029), 368 GW (2032)—4x current 85 GW peak.[8][9]
- No formal capacity market; reserves drop below 13.8% reference post-2028; 70%+ queue data centers, but curtailment rules for non-firm loads.[10]
- Cases: No specific failures reported, but PUCT rejected inflated forecasts; 26% national delays (2025), queue reforms wash out speculation; Permian Tx upgrades ($30B) lag build rate.[4]

Implications for competitors/entrants: Fast-build gas (2.5 GW replacements) favors incumbents; entrants need firm commitments or off-grid/onsite gen to bypass 4x peak queue; weather risk means diversified backup or curtailment contracts essential by 2028 deficits.[11]

MISO (Reserve Margin Trends)

MISO's declining reserve margins (7.9% summer PY2025/26, dropping to 4.3% by 2029) stem from slower data center growth vs. PJM/ERCOT but coal/gas retirements outpacing solar/battery queue (296 GW backlog), with ERAS fast-track for 3 GW+ urgent needs highlighting allocation failures for non-dispatchable resources.[12][13]
- Peak load +35% to 163 GW by 2035 (data centers 20% electricity by 2030); surplus fell 43% to 2.6 GW (2025/26); PRA summer price $666.50/MW-day.[14]
- Queue reforms reduced to 174 GW (Nov 2025); elevated risk 2027+ per NERC; 8-14 GW data centers 2026-27 uncertain.[15]
- Cases: No specific delays; 43% CAGR data centers (2020-25), but "right-sizing" emerging; LOLE study shows winter risks rising.[13]

Implications for competitors/entrants: Slower growth eases pressure, but PRM target (7.9%) demands dispatchable capacity; ERAS prioritizes firm resources—flexible loads/data centers gain edge; compete via co-location or DR for accreditation.[16]

CAISO (Transmission Constraints)

CAISO's transmission planning now prioritizes reliability-driven upgrades ($7B for 38 projects, 2025-26 plan) as data center load (1.8 GW by 2030) exacerbates Path 15/Silicon Valley congestion amid gas peaker retirements (3.7 GW once-through cooling), delaying remote clean energy delivery and forcing local backups.[17][18]
- Load +15 GW (2035); data centers key in Bay Area overloads; no RA shortage yet, but queue paused/reformed (185 GW backlog).[17]
- $1.4B Silicon Valley project for large loads; high gas retirement sensitivity (11 GW by 2034) strains locals.[19]
- Cases: Utilities see rising apps; no public failures, but national 26-50% delays; TPP concurs post-forecast loads.[18]

Implications for competitors/entrants: Transmission-limited; large loads post-TPP need PTO concurrence—Bay Area first; flexible/interruptible preferred amid retirements; compete by co-developing Tx upgrades.[20]

NYISO (Downstate Congestion)

NYISO's downstate (NYC/Long Island) faces Local Capacity Requirements (LCR) deficits from peaker retirements (1.5 GW ozone-season by 2025) and data center/EV growth, with Central East congestion blocking upstate hydro/nuclear, projecting statewide shortfalls by 2034 absent CHPE (2026).[21]
- Gold Book: 3 GW+ large loads queued (data centers/Micron); NYC reliability need summer 2025 resolved via peaker retention til CHPE.[22]
- IRM 25.3% (2026-27); MLCR NYC 82.6%, LI 106.7%; aging fleet +3 GW data centers strain.[23]
- Cases: Queue 12 GW large loads (Jan 2026); 3-year moratorium proposed; no specific failures but transmission overload risks.[24]

Implications for competitors/entrants: Downstate LCR binding—data centers need firm imports or onsite; upstate viable but congestion caps; policy risk high (moratoriums); DR/SCR critical for accreditation.[25]

SPP/Southeast (TVA/Duke Territory)

SPP's reserve margins plummet from 20.7% (2025) to -1.6% (2030) as data center/re-shoring demand outpaces intermittent queue, with no capacity market forcing bilateral risks; TVA/Duke see 37 GW queued but delays from equipment/power shortages mirror national 30-50% slip.[26]
- SPP BA: PRM rises to 17% (2029), but gap widens; Southeast utilities plan 10 GW gas for speculative DC growth (0.2% probability).[27]
- TVA/Duke: Cluster queues (2025-26); Carolinas DC 10% sales by 2030; re-shoring (chips) adds uncertainty.[28]
- Cases: National delays 26% (2025); no region-specific failures; Duke high-load tariffs enforce 75% take-or-pay.[29]

Implications for competitors/entrants: No auction safety net—bilaterals rule; SPP winter PRM 36% demands firm capacity; Southeast overbuild risk (half DC speculative); on-site gen or flexibility de-risks.[30]

Ranked Risk Matrix: Constraint Severity vs. Timing (2025-2030)

Region	Primary Constraint	Severity (1-5)	Earliest Stress	2025-26	2027-28	2029-30	Key Metric
PJM	Capacity Auction Shortfalls/Queue	5	2025 Auction (DOM/BGE Caps)	●●●●●	●●●●●	●●●●●	-6.5 GW Short (2027/28)[1]
ERCOT	Interconnection Queue Overload	4	2028 Reserves	●●●●	●●●●●	●●●●●	<13.8% RM Post-2028[10]
NYISO	Downstate LCR/Congestion	4	Summer 2025 (Peakers)	●●●●●	●●●●	●●●●	NYC Deficit til CHPE 2026[22]
MISO	Declining RM (Queue)	3	2027 Elevated Risk	●●●	●●●●	●●●●●	4.3% RM (2029)[15]
SPP/SE	Reserve Erosion	3	2027 Deficit	●●●	●●●●	●●●●●	-1.6% RM (2030)[26]
CAISO	Tx Constraints	2	2026+ Overloads	●●	●●●	●●●	Bay Area DC-Driven[17]

Severity: 5=Immediate shortages/delays; 1=Ample headroom. Timing: ●=Stress level (5 bullets=peak). PJM leads near-term; ERCOT/SPP long-term. Confidence: High (NERC/PJM auctions verified); further queue tracking needed.[15]

---

Recent Findings Supplement (April 2026)

PJM (Northern Virginia Data Center Alley)

PJM's capacity market has entered scarcity pricing due to data centers adding over 13 GW of forecasted load in the Dec 2025 2027/2028 auction, outpacing supply amid a clogged queue transition and 3-4 year supply chain delays for transformers/gas turbines; this drove a 285% capacity cost spike to $10.39B in 2025 (from $2.69B in 2024), with congestion up 78% to $7.3B.[1][2]
- 2027/2028 Base Residual Auction (Dec 2025 results, Feb 2026 report): Cleared at cap $333.44/MW-day; procured 145,777 MW UCAP, 6,517 MW short of reliability requirement; 14.4% IRM vs 20% target (5.6 pp shortfall), first miss >1 pp, triggering investigation and potential backstop auction if persists.[3][2]
- Apr 2026: PJM proposes 14.9 GW two-phase backstop (bilaterals then auction) for data centers/large loads; FERC eyes June decision; governors push data centers bear full costs.[4]
- Queue reforms (post-2025): Cleared 14 GW in Cycle 1; 24 GW projects terminated since 2020; data centers face no explicit delays but contribute to "transition gap" with 82 GW peak demand growth forecast to 2040.[2]
Implications for Competitors/Entrants: Data centers must self-procure via co-location or backstops (15-yr contracts eyed); queue fast-track (RRI) helps but permitting/supply chains delay new gen 24-44 months; non-Virginia sites less stressed short-term.

NYISO (Downstate Congestion)

Downstate (NYC/Long Island) faces binding transmission bottlenecks from upstate renewables to load, worsened by peaker deactivations like Gowanus/Narrows barges (608 MW, Zone J); 19 large loads (3+ GW incl. data centers/Micron) queueing amid 1.2 GW retirements over decade.[5][6]
- NYSRC IRM Filing (Dec 2025): 2026-2027 IRM at 24.5% (up from 24.4%); deactivations cut IRM 0.69%; Zone J MLCR 79.2% (+3.6 pp), G-J 88.75%; CHPE (1.25 GW summer-only) boosts J by 8.47% but winter fuel risks rise to 14% LOLE share.[6]
- Reliability needs: Summer 2026 downstate shortfalls (410-650 MW, 6-8 hrs); NYC potentially deficient by 2033 without CHPE/Empire Wind; LOLE nears 0.1 days/yr by 2034.[5]
No reported data center delays; queue reforms refocus storage downstate.
Implications for Competitors/Entrants: Co-locate with upstate imports or storage; downstate land/congestion favors smaller/distributed loads; CLCPA mandates (70% RE by 2030) prioritize renewables but delay hyperscalers.

SPP/Southeast (TVA/Duke Territory, Re-shoring + Data Centers)

SPP forecasts peak doubling to 109 GW by ~2035 amid 26 GW large load requests since 2020 (9 GW data centers), tightening PRM (16% summer/35% winter Year 10); Duke sees industrial/data center demand up 6.1% CAGR next 5 yrs, queue at 5.6 GW peak.[7][8]
- SPP 2025 ITP (Nov 2025): 11 GW spot loads (Future 2); peak from 61.7 GW (2026) to 76.4 GW (2034); $19.4B portfolio (2,921 mi new HV incl. 765 kV overlay) for congestion/voltage; reserve met with scoped RE but load shed risks in extremes.[8]
- Duke (Feb-Apr 2026): 38 advanced projects (5,610 MW peak, 80% data centers); $102B capex thru 2030; contracts mandate 50-hr/yr curtailment for faster hookup.[9]
No specific delays/failures; HILL framework expedites large loads.
Implications for Competitors/Entrants: Regulated returns favor utilities; curtailment clauses enable entry but cap firm power; re-shoring (oil/gas/manufacturing) competes with data centers for southern capacity.

CAISO (Transmission Constraints)

CAISO's Apr 2026 draft plan flags Path 15 north-south congestion as binding, needing 500 kV line amid 15 GW load growth by 2035 (20 GW by 2040, incl. data centers); reconductoring/advanced conductors prioritized over peakers (no retirements noted recently).[10]
- Recommends 38 upgrades ($7B) for electrification/manufacturing/large loads; Greater Bay/Tesla corridors targeted.
No data center delays reported; queue not detailed.
Implications for Competitors/Entrants: Northern imports strained; on-site PPAs or storage needed; policy pushes RE but transmission lag favors distributed gen.

ERCOT, MISO: Limited New Data Post-Oct 2025

ERCOT: 226 GW large loads monitored (Dec 2025, ~75% data centers); may delay energization for stability but no specific failures/delays found recently.
MISO: No new reserve margin/queue updates; tightening noted in NERC LTRA (Jan 2026) but pre-existing.[11]
Implications: ERCOT fast-build gas mitigates weather risk short-term; entrants watch PUCT rules (e.g., SB6 financials for 75+ MW).

Ranked Risk Matrix: Severity (High/Med/Low) vs Timing to 2030

Region	Primary Constraint	Earliest Stress	2026-27	2028-30	Notes
PJM	Capacity Shortfall/Queue	2027/28 Delivery (ongoing)	High	High	Backstop eyed; 60 GW gap possible.[2]
NYISO	Downstate Congestion/Retirements	Summer 2026	High	High	3 GW loads queueing.[5]
SPP/SE	Load Growth/Transmission	2030 (PRM negative)	Med	High	26 GW requests; Duke curtailments.[7]
CAISO	Transmission (Path 15)	2035 (15 GW load)	Med	Med	$7B plan eases.[10]
ERCOT	Large Load Queue	N/A (monitoring)	Low	Med	Potential delays but fast gas.[11]
MISO	Reserve Trends	N/A	Low	Low-Med	No new data; slower growth.

Confidence: High on PJM/NYISO (direct reports); medium elsewhere (sparse post-Oct 2025 data). Additional RTO filings would refine 2026-30 projections.