How it works
PJM Non-Firm Contract Demand and ERCOT SB 6 give you 12–18 months of speed-to-power in exchange for curtailment events. The trap nobody models: federal RICE NESHAP allows zero hours of demand-response runtime on backup generators, and state air permits cap aggregate runtime in fragmented ways. A 500 MW Virginia site can swing between 0% capacity loss and a 20–30% effective summer de-rate — depending on a single state DEQ guidance memo.
The trap
Your interconnection contract is one rule system. Federal RICE NESHAP is a second. Your state air permit is a third. Most developers price the first one when they evaluate a curtailable interconnection offer. Almost nobody prices the interaction.
The interaction is where the project value lives. RICE NESHAP allows up to 100 hrs/yr of non-emergency runtime on backup generators — and zero hours for demand response. State permits add their own caps, their own definitions of “emergency,” and their own quarterly guidance memos. When PJM curtails you, your site has to decide in real time whether running the generators is permitted — or whether you have to shed actual compute load.
That decision is a 20–30% swing in summer capacity. On a 500 MW site, it’s hundreds of millions of dollars of project value. And the answer changes every time a state DEQ updates its guidance.
The math
A worked example. 500 MW IT load, ~600 MW Tier II diesel fleet (250 × 2.5 MW), Virginia minor-source permit at 500 hrs/yr aggregate, RICE NESHAP at 100 hrs/yr non-emergency and 0 for DR, and a modeled 6 PJM curtailment events per year averaging 6 hours each.
Case A · DEQ treats curtailment as “emergency”
Post-APG-578, with utility outages noticed within 14 days counted as emergencies. 36 curtailment hrs + ~50 hrs testing + ~20 hrs true outages ≈ 106 hrs/yr, comfortably inside the 500-hr aggregate cap.
But: Title V Potential-to-Emit is likely triggered. ~140–180 tons NOx/yr puts the fleet above the 100 tons/yr major- source threshold. Compliance overhead lands at $2–5M/yr for CEMS, enhanced MACT, and a possible SCR retrofit. Add ~12 months of permit timeline.
Case B · DEQ treats curtailment as “non-emergency”
Pre-APG-578, or any time PJM notice exceeds 14 days. The 36 curtailment hrs/yr must fit inside the federal 100-hr non-emergency bucket and cannot count against the 50-hr DR-excluded subset — technically infeasible under RICE NESHAP.
Every PJM curtailment event becomes a RICE NESHAP violation: $25K–$100K/day in EPA penalties. Practical response: shed actual compute load during the event — an effective 20–30% capacity de-rate during summer peaks — or refuse Non-Firm and wait in the firm queue.
The swing: Case A is 0% capacity loss and $2–5M/yr in opex. Case B is 20–30% summer capacity loss. The difference depends on a single state DEQ guidance memo, plus how PJM notices any given curtailment event.
What we model
The calculator is built on a state-by-state air-permit logic layer that we maintain like an incentive atlas: structured records, weekly refresh, citation per claim, and a versioned changelog every time a state DEQ updates its guidance.
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Why now
FERC's December 2025 co-location order forced PJM to file three new transmission service options. ERCOT SB 6 took effect December 31, 2025. The FERC ANOPR final rule lands April 30. The decision tree is live.
Live dockets · updated weekly
“A 200 MW interconnection becomes about 85 MW of realized peak after the IT/overhead split and a 3–5 year buildout. That’s a 25–35% structurally stranded reservation gap, before curtailment ever enters the picture.”
“We used to be inside-the-four-walls experts. Now we’ve had to bolt on land enablement, site permitting, air permits, and power generation.”
Why nobody sells this
Federal RICE NESHAP rules are public. PJM and ERCOT tariff language is public. State air permit templates are public. The hard part is the mapping from each state’s emergency definition + standard permit + guidance memos to runtime-hour accounting that survives an EPA audit.
That mapping is fragmented across Virginia DEQ, TCEQ, Ohio EPA, GA EPD, ADEQ, and dozens more. It changes quarterly. Nobody — not Trinity Consultants, not Ramboll, not Paces, not Enverus — has it productized.
Trinity Consultants charges around $300K per engagement for bespoke air permit advisory. Paces ships air permits as a binary flag. Enverus ships queue data without an air-permit layer at all. The wedge isn’t the math — the math is in the rules. The wedge is the data discipline to keep the rules current.
Free first analysis
Site location, generator fleet specs, interconnection product, and your assumed curtailment frequency. We respond within 72 hours with your effective de-rated capacity, RICE NESHAP hour budget, Title V trigger analysis, and a $/MW-yr compliance cost delta against the firm-queue baseline.