FERC Jurisdiction — Wholesale Power and Interstate Transmission — Compliance Brief

FERC Jurisdiction — Wholesale Power and Interstate Transmission — Compliance Brief

Covers records: electrical-power-cert-022 (Electrical/Power), energy-renewable-reg-020 (Energy/Renewable) Record type: Regulation — federal agency jurisdiction (not a single rule; the body of FERC authority and its major orders) Issuing body / enforcer: Federal Energy Regulatory Commission (FERC), an independent agency within the U.S. Department of Energy Jurisdiction: United States, federal — wholesale electricity sales and interstate transmission in interstate commerce. (ERCOT/Texas is largely outside FERC wholesale jurisdiction because its grid is intrastate; state PUCs govern retail sales everywhere.) Also see: NERC reliability standards, IEEE 1547

1. What it is

FERC is the federal regulator of the high-voltage, wholesale side of the U.S. electricity business. Its authority over electric power comes primarily from the Federal Power Act (FPA): Sections 205/206 (rates for wholesale sales and transmission must be "just and reasonable" and not unduly discriminatory), Section 215 (reliability — the NERC regime), Section 203 (mergers and asset transfers), and Section 207-era authorities over interconnection. Two jurisdictional boundaries define everything FERC does:

1. Wholesale vs. retail: FERC regulates sales of electricity for resale (wholesale); states regulate retail sales to end users.
2. Interstate commerce: FERC's reach covers transmission in interstate commerce — which, because the Eastern and Western Interconnections cross state lines, means nearly the entire country except ERCOT.

FERC does not site generation, set retail rates, or mandate resource mixes — those are state powers. But through its control of interconnection procedures, transmission planning, and wholesale market rules, FERC shapes what gets built and how it connects.

2. Scope — who/what it applies to, triggers

• Public utilities (as defined in the FPA — essentially any entity owning/operating jurisdictional transmission or making wholesale sales): must file tariffs, obtain market-based-rate authority to sell at market prices, and comply with open-access transmission rules.
• Transmission providers (ISOs/RTOs and non-RTO utilities): must offer transmission service under the pro forma Open Access Transmission Tariff (OATT) and process generator interconnections under the pro forma Large Generator Interconnection Procedures/Agreement (LGIP/LGIA).
• Generators ≥ 20 MW interconnecting to FERC-jurisdictional transmission: subject to the LGIP cluster-study process (Order 2023). Generators ≤ 20 MW fall under the Small Generator Interconnection Procedures (SGIP) — Order 2006, as updated.
• Qualifying Facilities (QFs) under PURPA: small renewables/cogeneration retain must-purchase rights from utilities at avoided cost (FERC Order 872, 2020, narrowed but preserved PURPA).
• Trigger events: selling power at wholesale without authorization, interconnecting a large generator, merging utility assets (FPA §203), or operating transmission — all require FERC filings and approvals.

3. Key requirements and compliance obligations

• Market-based rate authority: to sell wholesale power at market prices, a seller needs FERC authorization (triennial market-power reviews, change-in-status filings). Without it, sales default to cost-based rates.
• Open access (Orders 888/889, 1996): transmission owners must provide non-discriminatory open-access service under the OATT — the foundation of competitive wholesale markets.
• Generator interconnection — Order 2023 (July 2023) + Order 2023-A: the current LGIP framework. Core reforms: cluster studies replacing serial first-come-first-served ("first-ready, first-served"); a 150-day cluster study window (plus 45-day request and 60-day engagement windows); commercial-readiness deposits and site-control requirements to enter the queue; per-business-day penalties on transmission providers for late studies ($1,000/day cluster study, $2,000/day restudy/affected-system study, $2,500/day facilities study); withdrawal penalties; and technology-neutral modeling requirements. Implementation has been uneven — see Live changes.
• Transmission planning and cost allocation — Order 1920 (May 2024) + Order 1920-A: requires 20-year long-term regional transmission planning cycles (every 5 years), three modeled scenarios using best-available data (retirements, interconnection queues, state policies, corporate commitments), and ex ante cost-allocation methods. Compliance filings were due in 2025; OATT revisions phase in toward 2027.
• Reliability oversight: FERC approves/rejects NERC standards and can direct modifications (Section 215) — see NERC brief.
• PURPA / QF obligations: utilities must interconnect with and purchase from QFs; FERC Order 872 (2020) gave states flexibility on avoided-cost calculations and raised the rebuttable presumption threshold.
• Large-load / co-location policy (2025–2026): FERC is actively building the rules for data-center-scale loads and behind-the-meter generation (Talen–Amazon Susquehanna precedent: FERC's March 2025 rejection of the amended interconnection service agreement). PJM was ordered to create co-located-customer transmission options; SPP's High Impact Large Load (HILL) process was approved January 2026.

4. Penalties / consequences of non-compliance

• Civil penalties: up to $1,000,000 per day per violation under FPA Section 316A for violations of the FPA, FERC rules, or orders (inflation-adjusted annually — check the current Federal Register notice for the year's figure). Criminal penalties apply for knowing violations in some provisions.
• Market-based-rate revocation: FERC can strip a seller's market-based-rate authority — a commercial death sentence for a merchant generator — for market manipulation or failure to file required reports.
• Disgorgement: FERC routinely orders disgorgement of unjust profits from market manipulation (the anti-manipulation rule, modeled on SEC Rule 10b-5, is enforced by FERC's Office of Enforcement with headline nine-figure settlements in past cases).
• Order 2023 study penalties run against transmission providers, not generators — a rare reversal where the utility pays for delay.
• Practically, the heaviest consequence for developers is procedural: loss of queue position, withdrawal penalties (which can reach millions for large projects), and forfeited site-control and readiness deposits.

5. Version / edition status and live changes (verified to 2026-09-30)

• Order 2023 compliance is the live battlefield. FERC denied PJM's initial Order 2023 compliance filing (July 2025) and issued a second order (April 2026) partially accepting/partially rejecting the revised filing. PJM's reformed queue reopened in 2026: the first cycle drew 715 projects / 201.5 GW (nearly half natural gas, ~67 GW storage, 27 nuclear projects). MISO, CAISO, and SPP have filed compliance tariffs with varying progress. Practical effect through 2026: readiness requirements are washing speculative projects out of queues, but timelines for quality projects remain long where transmission upgrades are unfunded. (Sources: trade press and policy analyses, 2025–2026.)
• Order 1920 implementation: compliance filings due June 2025; OATT revisions effective toward June 2027. Watch for FERC action on contested compliance filings through 2026–2027.
• Co-located large loads: FERC set a June 2026 deadline for PJM to rewrite large-load rules (three new transmission service options for co-located customers, 50 MW netting threshold); full mechanism expected active ~2027. SPP HILL/HILLGA approved January 2026. This is the fastest-moving FERC policy front as of late 2026.
• Dynamic line ratings NOPR (RM24-6) and a supply-chain cybersecurity NOPR (September 2025) are in the pipeline — proposed rules, not final; do not cite as requirements.
• OBBBA (July 4, 2025) reshaped the economics of what interconnects (wind/solar credit cliff — see the Energy/Renewable briefs) but did not change FERC's jurisdiction or interconnection procedures.

6. Related certifications (same-discipline, license/flagship, from the catalogue)

• Professional Engineer (PE), Electrical and Computer: Power (electrical-power-cert-001) and PE License (energy-renewable-cert-001) — interconnection studies, system-impact and facilities studies, and LGIA exhibits are stamped engineering work; FERC-jurisdictional interconnection is a core PE power practice area.
• Chartered Engineer (CEng) via IET (electrical-power-cert-002) — not a FERC credential.
• NABCEP PV Installation Professional (PVIP) (energy-renewable-cert-002) — relevant at the distribution-interconnection level (SGIP/state rules), not FERC wholesale.
• Certified Energy Manager (CEM) (energy-renewable-cert-005) — wholesale procurement context only.
• State Master/Journeyman Electrician License (electrical-power-cert-007) — installation-level; no FERC nexus.

7. Honest flags

• The $1M/day statutory penalty is inflation-adjusted annually — the current-year figure must be pulled from the Federal Register; the adjusted amount is not stated here.
• Order 2023 per-day study-penalty figures ($1,000/$2,000/$2,500) are from the final rule; confirm against the current pro forma LGIP if citing in a filing.
• FERC's large-load/co-location rules are evolving through 2026–2027 — PJM's mechanism is not yet fully active; treat any summary as a snapshot.
• ERCOT carve-out: none of the above applies to wholesale transactions wholly within ERCOT — a frequent source of confusion for national developers.
• NOPRs (dynamic line ratings, supply chain) are proposals, not law — flagged as such above.

Original ETS reference writing, verified against public sources on 2026-09-30. Thin sourcing is flagged inline. Not legal advice — confirm current editions with the issuing body.