FERC and Grid Policy — Federal Power Act, NERC, Major Orders, State-Federal Fault Line

FERC and Grid Policy

1. At a glance

The US electric grid is governed by an unusually complex regulatory architecture. The Federal Energy Regulatory Commission (FERC) is the federal economic regulator with jurisdiction over interstate transmission and wholesale sale of electricity in interstate commerce, derived from the Federal Power Act of 1935 as amended. The North American Electric Reliability Corporation (NERC) is the federally-designated Electric Reliability Organization (ERO) that develops and enforces mandatory reliability standards on the Bulk Electric System (BES), under FERC oversight following the Energy Policy Act of 2005. State Public Utility Commissions (PUCs) retain jurisdiction over retail rates, utility cost recovery, distribution facilities, and (where it exists) retail competition rules. The state-federal jurisdictional line — where FERC’s wholesale authority ends and state retail authority begins — is the chronically contested fault line of US grid policy.

This note is the umbrella reference for that architecture: FERC’s statutory authority, the major rulemakings that shaped the modern wholesale market (Orders 888, 2000, 745, 1000, 841, 2222, 2023, 1920, 1977, 1980), NERC’s reliability standards and Regional Entities, the state-federal jurisdictional cases (notably Hughes v. Talen 2016 and FERC v. EPSA 2016), capacity-market state-policy conflicts (MOPR), transmission siting (NIETC corridors + federal backstop), and the Inflation Reduction Act 2022 and Infrastructure Investment + Jobs Act 2021 grid + clean-energy provisions. For market mechanics covered by these rules, see electricity-markets-and-grids + missing-money-and-scarcity-pricing; for transmission planning detail, see transmission-and-grid-services.

2. The Federal Power Act and FERC’s statutory authority

The Federal Power Act of 1935 (FPA) was the New Deal-era reorganisation of the federal hydropower and wholesale-electricity regulatory architecture. The 1935 act amended the Federal Water Power Act of 1920 (which had originally addressed hydroelectric licensing on navigable waters and federal lands) by adding Part II to the FPA, which extended federal jurisdiction to interstate transmission and wholesale sale of electric energy in interstate commerce. The motivating case was Public Utilities Commission of Rhode Island v. Attleboro Steam & Electric Co. (Supreme Court 1927), in which the Court held that Rhode Island could not regulate a wholesale sale from a Rhode Island utility to a Massachusetts utility because such regulation would burden interstate commerce — creating the so-called Attleboro gap that left interstate wholesale unregulated. The FPA closed the gap by giving the Federal Power Commission (FPC, renamed FERC in 1977 via the Department of Energy Organization Act) authority over:

• Interstate transmission of electric energy — including operation of facilities used in such transmission.
• Wholesale sale of electric energy in interstate commerce — meaning sale for resale, as distinguished from retail sale to ultimate consumers.
• Rates, terms, and conditions for such jurisdictional transmission and wholesale sales — must be “just and reasonable” and not “unduly discriminatory or preferential” (FPA §205, §206).

The retail sale to ultimate consumers + the facilities used solely for local distribution remain under state jurisdiction. §201(b) of the FPA explicitly preserves state authority over “facilities used in local distribution or only for the transmission of electric energy in intrastate commerce, or … facilities for the transmission of electric energy consumed wholly by the transmitter.” The retail-wholesale line is the central jurisdictional boundary.

Modern FERC commissioners are five in number, appointed by the President and confirmed by the Senate for staggered five-year terms, with no more than three from one political party. The chairman is designated by the President. As an independent regulatory agency, FERC is structurally insulated from direct White House policy direction but is subject to OMB review of major rulemakings and to congressional oversight via authorisation and appropriations.

FERC’s authority is exclusively economic — rates, terms, and conditions — and reliability under the post-2005 ERO structure. FERC does not site generation (state jurisdiction in most cases, federal under specific statutes for nuclear via NRC and hydro via FERC itself). FERC has limited transmission siting authority via the NIETC + backstop provisions in EPAct 2005 §1221 + IIJA 2021 strengthening (see §10 below). FERC also has separate jurisdiction over:

• Natural Gas Act (NGA, 1938) — interstate natural gas pipelines + LNG export/import facility certification (under the Natural Gas Act §3 + §7) + pipeline rate regulation.
• Interstate Commerce Act (ICA, 1887, as amended) — interstate oil pipelines (rate regulation; siting under state and the BLM for federal lands).
• Federal Power Act Part I — hydroelectric project licensing on navigable waters or federal lands (50-year licences typically; relicensing process can take a decade or more for major projects).
• Public Utility Regulatory Policies Act (PURPA, 1978) — Qualifying Facility (QF) status for cogeneration + small renewables, with mandatory utility purchase obligation at avoided cost — though substantially reformed by FERC Order 872 (2020) shrinking PURPA QF reach.

3. The major orders, in chronological order

The modern wholesale electricity market is the cumulative product of a series of FERC rulemakings starting in the mid-1990s. The most consequential, in order:

3.1 Order 888 (April 1996) — Open Access Transmission Tariff

Title: Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities.

Substance: Required every public utility owning interstate transmission facilities to file an Open Access Transmission Tariff (OATT) offering transmission service to third parties on non-discriminatory terms equivalent to the utility’s own use. Also required functional unbundling of transmission from generation within vertically integrated utilities — separate functional control of transmission operations from generation merchant operations — to prevent informational advantage and self-dealing. Created the standardised pro forma OATT terms that became the foundation for wholesale market formation.

Significance: Order 888 is the structural enabler of every restructured wholesale market in the US. Without non-discriminatory access to transmission, independent power producers cannot reach load and bilateral wholesale trading collapses to dealings within a utility’s own footprint. The 1992 Energy Policy Act’s PURPA + IPP reforms had created merchant generators; Order 888 gave them the transmission service to reach customers.

Companion order: Order 889 (same date) required public utilities to operate the Open Access Same-time Information System (OASIS) — internet-based real-time posting of transmission service availability and pricing — and to comply with standards of conduct separating transmission staff from generation merchant staff.

3.2 Order 2000 (December 1999) — Regional Transmission Organisation Formation

Title: Regional Transmission Organizations.

Substance: Encouraged (but did not strictly mandate) utilities to join RTOs satisfying twelve specific characteristics — independence from market participants, scope sufficient to ensure efficient + reliable + non-discriminatory transmission, operational authority + short-term reliability authority, four required functions (tariff administration + congestion management + parallel-path flow management + ancillary services + market monitoring + planning + interregional coordination + open access + flexibility to evolve). Did not force formation but created a clear regulatory preference + a path through which existing tight pools (PJM, ISO-NE, NYPP, MAIN, ECAR) and California (post-1998 restructuring) could evolve into FERC-approved RTOs.

Significance: PJM, MISO, NYISO, ISO-NE, SPP all emerged as RTOs under Order 2000’s framework over the 2000-2005 period. CAISO had been formed under California’s 1996 AB 1890 restructuring; ERCOT had been operating as a control area since 1970 and remained outside Order 2000’s jurisdictional reach because of the Texas Interconnection’s synchronous isolation. By 2005, organised wholesale markets covered the modern footprint.

3.3 Order 2003 (July 2003) — Standardised Generator Interconnection

Title: Standardization of Generator Interconnection Agreements and Procedures.

Substance: Pro forma Large Generator Interconnection Procedures (LGIP) + Large Generator Interconnection Agreement (LGIA) standardising the process by which generators (>20 MW) request and obtain interconnection to the transmission system. Required filed Tariff sections for the interconnection process. Companion Order 2006 (May 2005) extended similar standardisation to Small Generator Interconnection Procedures (SGIP) for generators ≤20 MW.

Significance: Standardised the procedural framework but did not solve the substantive problem — interconnection requests have grown faster than utilities + ISOs can study, producing the multi-year backlogs that became the binding constraint on US clean-energy deployment by the late 2010s. Order 2023 (2023) substantially reformed.

3.4 Order 745 (March 2011) — Demand Response Compensation

Title: Demand Response Compensation in Organized Wholesale Energy Markets.

Substance: Required RTOs to compensate demand response (DR) at the full Locational Marginal Price when DR (a) is offered into the wholesale market, (b) is dispatched (or self-deploys in response to the price signal), and (c) is cost-effective relative to generation (the “net benefits test”).

Litigation: Order 745 was challenged in Electric Power Supply Association v. FERC. The DC Circuit vacated the order in May 2014, holding FERC had exceeded its FPA jurisdiction by regulating retail-side activity (load reduction by retail customers). The Supreme Court reversed in FERC v. EPSA, 577 U.S. 260 (January 25, 2016), holding 6-2 (Justices Scalia + Thomas dissenting) that demand response participating in wholesale markets is itself a wholesale activity within FERC’s FPA jurisdiction, and that FERC’s compensation rule was reasoned. FERC v. EPSA is the leading modern statement of FERC wholesale jurisdiction and the legal foundation for FERC Orders 841 (storage) and 2222 (DER aggregation).

Significance: Established that demand-side resources participate in wholesale markets on equal terms to generation — a structural enabler for the demand-response industry, virtual power plants, and DER aggregation.

3.5 Order 755 (October 2011) — Frequency Regulation Pay-for-Performance

Title: Frequency Regulation Compensation in the Organized Wholesale Power Markets.

Substance: Required RTOs to compensate frequency regulation with two components — a capacity payment ($/MW-hr of regulation availability) + a performance/mileage payment proportional to how much the resource moved per AGC signal and how accurately it tracked.

Significance: Pre-Order-755, slow-responding steam units and fast-responding flywheel + battery units received identical $/MW-hr regulation payments. Post-Order-755 implementation in PJM (RegA / RegD split with mileage multipliers, 2012), CAISO, MISO, ERCOT, NYISO over 2012-2015, batteries and flywheels began earning multi-fold more per MW than steam units. Beacon Power Stephentown NY flywheel facility (which had filed Chapter 11 in 2011 partly because the prior pricing structure under-compensated fast response) was rescued + acquired by Rockland Capital. AES Energy Storage and convergent BESS deployments scaled in PJM. The order was the structural enabler of the first wave of grid-scale battery deployment in 2012-2017, well before the lithium-cost-curve collapse of 2017-2024 made batteries dominant on energy + capacity stacks.

3.6 Order 1000 (July 2011) — Regional Transmission Planning and Cost Allocation

Title: Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities.

Substance: Required public utilities to participate in regional transmission planning that:

• considers transmission needs driven by public-policy requirements (state RPS, federal mandates) — not just reliability and economic needs;
• removes the federal right of first refusal (ROFR) for incumbent transmission owners on regional transmission projects, allowing non-incumbent transmission developers (including merchant transmission developers, regional + interregional consortiums) to bid;
• allocates costs of regional projects based on beneficiaries — those who receive the benefit pay in rough proportion.

Significance: Created a framework for inter-utility regional planning. In practice the ROFR removal was substantially weakened by state laws restoring ROFR in many states (Texas, Minnesota, Iowa, North Dakota, South Dakota, Wisconsin, Nebraska, Oklahoma, Arkansas, Louisiana, Montana, Mississippi by 2024 — driven by incumbent utility political pushback) — though FERC + courts have intervened in some cases. Order 1000’s regional planning structure laid the groundwork for the MISO MTEP + LRTP processes, PJM RTEP, CAISO TPP, etc. Was substantially superseded by Order 1920 (2024).

3.7 Order 841 (February 2018) — Energy Storage Participation

Title: Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators.

Substance: Required RTOs to establish a participation model for electric storage that recognises the physical and operational characteristics of storage. Storage must be allowed to:

• provide all market services it is technically capable of providing,
• set wholesale market clearing price as both a wholesale buyer (when charging) and a wholesale seller (when discharging),
• participate at full capability without bid-floor or bid-ceiling impositions that don’t reflect actual cost,
• be eligible for state retail-level tariff participation as well.

Litigation + appeals: Multiple state PUC and incumbent-utility challenges. The DC Circuit upheld Order 841 in NARUC v. FERC (2020), affirming FERC’s authority to extend wholesale-market participation rules to storage even when those rules incidentally affect state retail-level tariff design.

Significance: The structural enabler of the 2018-2025 grid-scale battery deployment wave. By the 2025 capacity year, batteries are a $30B+/yr asset class in US wholesale markets and a substantial earnings source on energy + AS + capacity stacks. Combined with the IRA §48E ITC + §45X manufacturing credit, Order 841 set up the conditions for the >5 GW/yr deployment pace in ERCOT + CAISO + PJM + ISO-NE.

3.8 Order 2222 (September 2020) — DER Aggregation

Title: Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators.

Substance: Required RTOs to establish a participation model for DER aggregations — aggregations of distributed energy resources (residential + commercial batteries, EV chargers, smart thermostats, behind-the-meter PV, distributed generation, controllable loads) — to participate in wholesale markets through an aggregator. Required RTOs to:

• allow DER aggregations of 100 kW or larger to participate,
• allow heterogeneous aggregations (mixing storage + DR + DG + EV) within a single aggregation,
• not impose double-counting prevention requirements that effectively foreclose participation,
• coordinate with distribution utilities (the “RERRA” — Relevant Electric Retail Regulatory Authority) on metering + telemetry + operational coordination.

Implementation timeline: RTO compliance filings stretched 2021-2024 with multiple rounds of FERC review + filing amendments. NYISO + CAISO filed earliest; PJM + MISO + ISO-NE + SPP later. ERCOT outside FERC jurisdiction not bound directly, but PUCT has pursued analogous reforms.

Significance: Together with Order 841, Order 2222 reshapes the boundary between wholesale + retail electricity markets and between transmission + distribution operation. The implementation has been messy — state PUCs concerned about retail-level interference, distribution utilities concerned about operational coordination + cost recovery, aggregators concerned about onerous registration + measurement requirements. Full DER aggregation potential remains substantially unrealised as of mid-2026; the order is foundational but not yet effective at scale.

3.9 Order 2023 (July 2023) — Interconnection Queue Reform

Title: Improvements to Generator Interconnection Procedures and Agreements.

Substance: Reformed the LGIP / LGIA framework from 2003 + 2006 to address the multi-year interconnection queue backlogs that had become the binding constraint on US generation deployment. Key reforms:

• First-ready, first-served rather than first-come-first-served — projects with site control + permits + commercial readiness move ahead of speculative early-stage queue entries.
• Cluster studies — group projects in the same electrical neighbourhood for joint study rather than sequential study, with proportional cost allocation of network upgrades.
• Commercial readiness deposits — substantial dollar deposits (typically $1-2M per project) at study milestones to clear speculative queue positions; deposits forfeit if project withdraws.
• Strict timelines — deadlines for ISO to complete studies + for developers to advance, with explicit penalties for ISO study delays + forfeiture for developer delays.
• Withdrawal penalties — escalating penalties for withdrawal as project progresses through queue.

Implementation: All FERC-jurisdictional RTOs and many vertically integrated utilities filed compliance plans 2023-24. PJM, MISO, CAISO, NYISO, ISO-NE, SPP all in mid-stage implementation 2024-26.

Significance: The most consequential interconnection reform since Order 2003. Whether it actually clears the backlog will depend on implementation — the queue is hundreds of GW at every major RTO and reform takes years to flow through study cycles.

3.10 Order 1920 (May 2024) — Long-Term Regional Transmission Planning

Title: Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection.

Substance: Most consequential transmission rulemaking in a generation. Replaces + extends Order 1000. Key elements:

• Long-term scenario planning — RTOs + planning regions must conduct 20-year forward-looking transmission planning under multiple scenarios reflecting policy, load growth, climate, fuel mix, electrification, and federal/state policy.
• Seven categories of benefits that planning must consider: reduced congestion + losses, reduced production costs, deferred generation, reduced reserve margins, reduced ancillary service costs, mitigation of extreme weather + system contingencies, fuel-mix diversity.
• Cost-allocation methodology — must be approved ex ante, applied to long-term regional projects with multiple benefit categories.
• Right of first refusal — partial restoration of incumbent rights for certain reliability projects, while preserving competitive solicitation for other regional projects.
• Grid-enhancing technologies (GETs) — dynamic line ratings, advanced power flow controls, advanced conductors, storage-as-transmission — must be explicitly considered in transmission needs assessments as alternatives to new wires.

Significance: Pairs with Orders 2023 (interconnection), 1977 (siting), 1980 (interregional) to constitute the most ambitious federal transmission policy push since the FPA itself. Implementation begins in 2024-26 compliance filings. Whether the orders deliver the transmission build-out the energy transition requires — IRA-projected 47,000 miles of new high-voltage transmission by 2035, versus a historical pace of 1,000 miles/yr — depends on state cooperation, ROFR battles, and the federal-backstop framework.

3.11 Order 1977 (May 2024) — Federal Backstop Transmission Siting

Title: Applications for Permits to Site Interstate Electric Transmission Facilities.

Substance: Implements the FERC backstop siting authority over National Interest Electric Transmission Corridors (NIETCs), originally authorised by §1221 of the Energy Policy Act 2005 but largely dormant after the 4th Circuit’s Piedmont Environmental Council v. FERC (2009) decision narrowly construed the statute. The IIJA 2021 §40105 substantially strengthened the backstop authority, and Order 1977 implements the strengthened version. FERC can issue permits + condemnation authority for transmission in DOE-designated NIETCs when states delay or deny siting beyond statutory windows.

3.12 Order 1980 (May 2024) — Interregional Transmission Planning

Title: Interregional Transmission Coordination.

Substance: Requires neighbouring transmission planning regions to engage in coordinated interregional planning + cost allocation. Targets the long-standing gap between PJM-MISO, PJM-NYISO, MISO-SPP, SPP-ERCOT etc. where transmission projects spanning two RTOs have struggled to win cost allocation across the seam.

4. NERC and reliability standards

The Energy Policy Act of 2005 created the Electric Reliability Organization (ERO) designation, certified by FERC. NERC was certified in 2006 as the ERO for North America and operates under FERC oversight under FPA §215. NERC develops mandatory reliability standards for the Bulk Electric System (BES — typically generation + transmission ≥ 100 kV) that are subject to FERC approval and enforceable with civil penalties up to $1.5M/day per violation (NERC + FERC concurrent enforcement). Six Regional Entities act as delegated enforcement bodies under NERC:

• WECC (Western Electricity Coordinating Council) — Western Interconnection.
• MRO (Midwest Reliability Organization) — Manitoba + Saskatchewan + portions of MISO + SPP + non-RTO Midwest.
• SERC (SERC Reliability Corporation) — Southeast US (Duke + Southern + TVA + Entergy footprint).
• RF (ReliabilityFirst) — Eastern Interconnection portion including most of PJM + parts of MISO.
• NPCC (Northeast Power Coordinating Council) — NYISO + ISO-NE + Ontario IESO + Québec.
• Texas RE (Texas Reliability Entity) — ERCOT footprint.

NERC reliability standards fall into categories:

• BAL — Balancing Standards — frequency response, Area Control Error (ACE), reserve obligations, contingency reserve, Inadvertent Interchange.
• CIP — Critical Infrastructure Protection — cybersecurity (CIP-002 through CIP-014; CIP-013 for supply chain risk; CIP-014 for physical security after the 2013 Metcalf substation attack).
• EOP — Emergency Operations — emergency procedures, blackstart, restoration.
• FAC — Facilities Design + Connection — interconnection requirements, facility ratings, transmission planning data.
• INT — Interchange Scheduling and Coordination — transactions across balancing authorities.
• IRO — Interconnection Reliability Operations + Coordination — reliability coordinator (RC) roles + responsibilities.
• MOD — Modeling, Data, and Analysis — generator modelling + transmission system models.
• NUC — Nuclear — Nuclear Plant Interface Coordination (small set).
• PER — Personnel Performance, Training, and Qualifications — operator certification (NERC-certified system operators).
• PRC — Protection and Control — relay coordination + transmission protection (Misoperations) + Special Protection Systems (Remedial Action Schemes).
• TOP — Transmission Operations — real-time operations + outage coordination.
• TPL — Transmission Planning — long-term reliability planning + N-1 + N-1-1 contingency analysis + winter + summer planning.
• VAR — Voltage and Reactive — voltage support + reactive power capability.

The most-cited modern NERC standards in cybersecurity + reliability + planning policy:

• CIP-002 through CIP-014 — cybersecurity for cyber assets supporting BES Reliability Operating Services + physical security for critical substations.
• BAL-003 — Frequency Response Obligation by balancing authority, set every 5 years against Eastern + Western + Texas + Quebec interconnection frequency response standards.
• BAL-001-2 — Reliability Standards for Real Power Balancing Control Performance (CPS1 + CPS2 metrics replaced by BAAL since 2014).
• FAC-008 — Facility Ratings (the basis for transmission line thermal limits used in SCED).
• TPL-001-4 / TPL-001-5 — Transmission System Planning Performance Requirements (Category P0 through P7 contingencies — N-0 + N-1 + N-2 + extreme + cascading + breaker failure).

The NERC Long-Term Reliability Assessment (LTRA), published annually, evaluates resource adequacy + transmission adequacy across all NERC Regions for 10 years forward. The 2024 LTRA flagged elevated reliability risk in MISO + WECC + ERCOT driven by coal retirements + load growth + interconnection-queue backlog + extreme-weather risk.

Post-Uri reforms (FERC + NERC joint inquiry on the February 2021 Winter Storm Uri ERCOT event, completed November 2021) drove substantial reliability-standard updates:

• EOP-011 + EOP-012 — Emergency Operations + Extreme Cold Weather Preparedness (new + revised post-Uri).
• EOP-004 + EOP-005 — Event Reporting + Restoration from Blackstart.
• FAC-005 / FAC-013 — extreme weather facility ratings.
• Joint Cold Weather Reliability Standard development in 2022-25, with mandatory weatherisation of generators + cold-weather preparedness performance metrics. NERC + FERC adopted Cold Weather Reliability Standards in stages 2022-24.

The Texas PUCT + RRC (Railroad Commission) implemented parallel state-level weatherisation rules under SB 3 (2021) and subsequent rulemakings, addressing both electric generation + gas infrastructure (the cascading gas-curtailment failures during Uri).

5. State PUCs and the state-federal fault line

State Public Utility Commissions retain jurisdiction over:

• Retail rates charged to ultimate consumers — including the distribution charge component (always state) and the generation supply charge component (state-regulated under integrated utility, or competitively-set under retail competition).
• Utility cost recovery through rate cases — fuel adjustment clauses, rate-base prudence reviews, allowed return on equity (typical 9-10.5% in 2024-26).
• Integrated Resource Plans (IRPs) — utility long-term resource planning + procurement, with PUC review + approval of major generation + transmission investments.
• Generation procurement — long-term PPAs, all-source RFPs, renewable solicitations.
• Demand-side management — energy efficiency programs, demand response programs (interaction with FERC Order 745 at the wholesale-retail line).
• Net energy metering (NEM) — residential + commercial behind-the-meter solar tariffs.
• Retail competition rules — where it exists (TX, PA, IL, OH, NY, NJ, MA, ME, RI, MI, CT, MD, DC, DE, NH).
• Distribution facility planning + siting — distribution upgrades, hosting capacity, DER interconnection.
• Distribution utility cybersecurity + physical security below the BES threshold.
• Generation siting in most states (some states have separate siting boards; some delegate to local zoning).

The state-federal jurisdictional line is contested where state retail policies effectively constrain wholesale market outcomes (subsidies for state-preferred generation, retail rate designs affecting wholesale demand), and where federal wholesale rules effectively constrain state retail policies (Orders 841 + 2222 affecting retail-level DER + storage).

5.1 Hughes v. Talen Energy Marketing (2016)

Citation: 578 U.S. 150 (April 19, 2016).

Facts: Maryland created a state-subsidised contract-for-differences arrangement for a new in-state gas plant (CPV Maryland) that the state PUC determined was needed for in-state reliability + economic-development reasons. The CfD would top up the plant’s revenue if PJM wholesale prices fell below a state-determined “strike price.” PJM merchant generators argued the subsidy effectively set the wholesale price for the CPV plant, displacing FERC’s exclusive wholesale rate authority.

Holding: 8-0 (Justice Alito did not participate) — Maryland’s program is preempted by the FPA because the CfD targets wholesale rates by guaranteeing the seller a specific wholesale rate, “an arrangement … that aims directly at interstate wholesale rates that FERC has jurisdiction to regulate.” Justice Ginsburg’s majority opinion was narrow — it preserved state authority to subsidise generation through programs that don’t condition payment on wholesale rates (e.g. state PPAs at fixed prices, ITC + PTC analogues, RPS-based REC purchases, capacity-tariff supplements not tied to wholesale clearing price).

Significance: Hughes set the modern test — state policies that condition payment on wholesale market clearing prices are preempted; state policies that subsidise via non-wholesale-rate mechanisms (capital grants, fixed-price PPAs, ITC, RPS, ZEC nuclear credits) survive. New York Zero Emission Credits (ZECs) for in-state nuclear (Indian Point + FitzPatrick + Ginna + Nine Mile Point) were challenged on similar grounds and upheld by the 2nd Circuit in 2018 because ZECs were fixed payments not conditioned on wholesale rates. Illinois ZECs for Clinton + Quad Cities upheld by 7th Circuit 2018 on similar grounds.

5.2 FERC v. EPSA (2016)

See §3.4 above. Established that demand response and other demand-side resources participating in wholesale markets are within FERC’s FPA jurisdiction, even when the underlying physical activity occurs at retail facilities.

5.3 MOPR — Minimum Offer Price Rule

The PJM Capacity Performance market historically applied a Minimum Offer Price Rule (MOPR) to prevent state-subsidised generation from suppressing capacity-market clearing prices. The MOPR set a floor on subsidised generators’ capacity-market offers tied to estimated unsubsidised cost — effectively excluding subsidised resources from clearing at low prices that reflected the subsidy. ISO-NE applied a similar Minimum Offer Price Rule for sponsored policy resources.

The MOPR was the focal point of a multi-year fight 2017-2022. State policymakers in PJM (Maryland, NJ, Illinois, Virginia, DC) and ISO-NE (Massachusetts, Connecticut, Maine) argued the MOPR effectively suppressed state RPS + nuclear-subsidy + offshore-wind procurement by raising the capacity-market clearing-price implication of state policy. The 2019 PJM FERC MOPR expansion (“Subsidy MOPR” or “FERC-imposed MOPR”) prompted NJ Governor Murphy + PJM state coalition threats to withdraw from PJM capacity market.

FERC reversed direction in 2021. PJM filed (September 2021) a substantially scaled-back MOPR limiting application to a narrow category of state-subsidised new entry. FERC accepted by operation of law (October 2021) when the divided commission failed to act within the 60-day statutory window. The ISO-NE FCM CASPR (Competitive Auctions with Sponsored Policy Resources) substitution mechanism allows state-subsidised renewables to enter the FCM after primary clearing via a substitution auction.

The MOPR fight has subsided but the underlying tension — wholesale market clearing prices vs state preference for specific resources via subsidies — remains. The 2024 PJM 2025/26 BRA price explosion + ELCC accreditation reform are partially the deferred consequence of MOPR resolution + state-subsidised resource entry. Pennsylvania Governor Shapiro’s August 2024 FERC complaint over BRA outcomes + the FERC-ordered $325/MW-day cap on 2026/27 BRA are the latest iteration.

5.4 Zero Emission Credits (ZECs) and state nuclear support

State ZECs paid to in-state nuclear plants for their carbon-free attributes have been authorised in:

• New York (2016) — Clean Energy Standard ZEC program covering FitzPatrick, Ginna, Nine Mile Point. ~$500M/yr revenue stream from ratepayers.
• Illinois (2016 FEJA, 2021 CEJA) — ZECs for Clinton + Quad Cities, extended in 2021 CEJA to cover Byron + Dresden + Braidwood + LaSalle. Total ~$700M-$1B/yr depending on year + carbon price benchmark.
• New Jersey (2018) — ZECs for Salem + Hope Creek (PSEG nuclear). ~$300M/yr.
• Connecticut (2017) — ZEC bilateral contract for Millstone (Dominion).

ZECs have been upheld in federal court (Hughes preemption rejected because not conditioned on wholesale rates). The IRA §45U Production Tax Credit for nuclear power (2024-2032) effectively federalises a similar program: existing nuclear units receive a tax credit covering production at ~$15/MWh nominal less wholesale revenue + state subsidies, partially crowding out state ZECs.

Three Mile Island Unit 1 restart — Constellation + Microsoft 20-year PPA September 2024 (835 MW restart targeted 2028) is a market-based revival not requiring state ZEC (though Pennsylvania is non-PJM-ZEC state; the PPA + IRA §45U is the support stack).

6. Capacity market state-policy conflicts

Beyond MOPR + ZECs, the broader question of how state policy interacts with wholesale capacity markets is unresolved. The 2024 PJM 2025/26 BRA outcome ($269.92/MW-day, ten-fold prior auction) is partly attributable to:

• Coal retirements driven by state + federal environmental policy (MATS, CSAPR, GHG NSPS, state-level coal-retirement orders),
• Renewable + storage + nuclear entry suppressed by interconnection-queue backlogs (a federal problem partially solved by Order 2023),
• Load growth driven by datacenter siting (commercial decisions plus state economic-development policy),
• Capacity-accreditation reform reducing ELCC for renewables + battery storage,
• Capacity Performance penalty regime + Stop-Loss formula creating high option-value of firm capacity.

State responses 2024-26:

• Pennsylvania Governor Shapiro — August 2024 FERC complaint over BRA outcomes; threatens PJM departure if reforms don’t moderate prices.
• Maryland — Public Service Commission directs Maryland utilities to procure capacity outside PJM if BRA fails to clear at “just and reasonable” prices.
• New Jersey — Continued offshore wind procurement + state-subsidised resource development.
• Virginia — Considers state-level capacity construct + Dominion VEPCO capacity tariff in parallel with PJM.

PJM responses:

• Filed at FERC for capacity-accreditation tweaks + auction-parameter adjustments + price cap for 2026/27 BRA.
• Capacity reform working group + stakeholder process 2024-26.
• Demand-response + interconnection-queue + transmission-build accelerations.

The underlying structural issue is that the PJM capacity market clears against a 13-state federation with different policy preferences (RPS + storage targets + nuclear support + retail-rate political tolerance). Whether the market can survive in current form, or whether some states withdraw to bilateral procurement + state capacity construct, is an open question for 2026-28.

7. Transmission siting

Transmission siting is mostly a state matter — each state has its own siting board or PUC process, with environmental review under state SEPA + federal NEPA for federal-land or federal-action components. Multistate transmission lines must obtain siting approvals from each state crossed, and any single state can deny + delay.

Federal levers:

• National Interest Electric Transmission Corridor (NIETC) — Energy Policy Act 2005 §1221 + IIJA 2021 §40105. DOE designates corridors where transmission is in the national interest. FERC backstop siting authority under Order 1977 (May 2024). The first round of DOE NIETC designations was contested + narrow (2007-2009); the 2024 DOE NIETC process is broader, with 10 potential corridors under study (including Lake Erie-Canada, Plains-and-Eastern HVDC, Southern Spirit HVDC).
• Federal lands — BLM + USDA Forest Service authority over rights-of-way across federal lands (substantial in the Western US). Designation + categorical exclusions under NEPA reform (2023 Fiscal Responsibility Act + 2024 BLM rule).
• Plains-and-Eastern HVDC, Grain Belt Express, SunZia, Champlain Hudson Power Express, Cardinal-Hickory Creek, Cross-Tie HVDC, TransWest Express — major long-distance HVDC + EHV AC projects in various permitting stages 2024-26.

The siting + permitting bottleneck is widely considered the binding constraint on the IRA’s transmission build-out ambitions. The IIJA 2021 categorical exclusions + DOE Coordinated Interagency Transmission Authorizations and Permits (CITAP) Program + 2024 BLM right-of-way reform partially address it.

8. The Inflation Reduction Act 2022

The Inflation Reduction Act (IRA, Public Law 117-169, August 16, 2022) is the most consequential US climate + energy law ever enacted. Major provisions relevant to grid + clean energy:

Production + investment tax credits (technology-neutral as of 2025):

• §45Y Clean Electricity Production Tax Credit — 2.5¢/kWh base + bonuses, technology-neutral from 2025 onward (replacing §45 PTC for wind + §48 ITC for solar at category-specific rates). 10-year duration from placed-in-service date.
• §48E Clean Electricity Investment Tax Credit — 30% base + bonuses, technology-neutral from 2025 onward. Available to storage starting 2023.
• §45U Zero-Emission Nuclear Power Production Credit — 2024-2032 for existing nuclear units, ~1.5¢/kWh adjusted for inflation, less subtracted state subsidies + wholesale gross receipts above a threshold.
• §45V Clean Hydrogen Production Tax Credit — 4-tier system 0.6¢-3.0¢/kg H2 by lifecycle emissions, 10-year duration. Final Treasury regulations January 2025 with three-pillars framework (additionality, geographic correlation, hourly temporal matching by 2028).
• §45Q Carbon Oxide Sequestration Credit — expanded for CCS + DAC; $85/tonneforindustrialCCStodedicatedgeologicalstorage,upto$180/tonne for DAC.
• §45X Advanced Manufacturing Production Credit — domestic manufacture of clean-energy components (solar wafers + cells + modules; wind tower + blade + nacelle; batteries; critical minerals). Driving onshoring of clean-energy supply chains.

Bonuses on §45Y + §48E:

• +10% Domestic Content — meets domestic content thresholds for steel + iron + manufactured products (40% MP threshold in 2024 escalating to 55% by 2027 for offshore wind; 40-55% similarly for other technologies).
• +10% Energy Community — sited in census tracts with closed coal/gas/oil employment or brownfield sites.
• +10-20% Low-Income Community — for residential + small-scale solar + storage serving low-income households or in low-income census tracts.

Transferability + Direct Pay — IRA tax credits are transferable for cash (a new market that has scaled to $30B+/yr by 2024-25, with major buyers JPM + BAML + Citi + Truist + corporate tax-equity buyers; auction-style platforms Crux + Reunion + Basis Climate + Evergreen Climate Innovations). Direct pay (Treasury sends cash rather than tax credit) available to tax-exempt entities — municipal utilities, rural cooperatives, tribal governments, federal entities, 501(c)(3) nonprofits.

Grant + loan programs:

• DOE Loan Programs Office — expanded authority from ~$6B/yrto$300B+ loan + loan guarantee capacity. Funded restart of LPO’s Section 1703 Clean Energy + 1706 Energy Infrastructure Reinvestment programs. Major loan announcements 2023-25 (Hyzon, Sunnova, Ford battery, Plug Power green hydrogen, Holtec Palisades nuclear restart, multiple Indiana battery + Arizona battery + Tennessee EV + Georgia solar).
• Grid Resilience and Innovation Partnerships (GRIP) — $10.5B for grid + transmission projects.
• Transmission Facilitation Program — $2.5B revolving fund (DOE anchor purchase + capacity-allocation backstop).
• Hydrogen Hubs — $8B for seven regional hydrogen hubs selected 2023.
• Advanced Reactor Demonstration Program (ARDP) — TerraPower Natrium + X-Energy Xe-100 + Kairos + others.

Cumulative IRA + IIJA impact:

• IRA: ~$369Bnominalsubsidy(2022-2032)perCBO;estimated$1T+ over 2022-2032 if uptake exceeds projections (Goldman Sachs + Wood Mackenzie + Princeton REPEAT Project).
• IIJA (Bipartisan Infrastructure Law, Nov 2021): ~$73B for energy + grid (TFP + GRIP + advanced reactor + DOE LPO supplemental capitalisation + state weatherisation).
• Combined effect: largest US industrial policy push since the Apollo + Manhattan programs, reshaping the entire energy supply chain.

9. Other relevant federal statutes

• PURPA (1978) — created Qualifying Facility (QF) status for cogeneration + small renewables with mandatory utility purchase at avoided cost. Foundational for early IPP industry. Reformed by FERC Order 872 (2020) shrinking QF reach (one-mile rule + state authority over avoided-cost determination).
• Public Utility Holding Company Act (PUHCA, 1935) — broken into multiple acts; PUHCA 1935 repealed by EPAct 2005 + replaced with PUHCA 2005 (less restrictive holding-company structure rules).
• Energy Policy Act of 1992 (EPAct 1992) — created Exempt Wholesale Generator (EWG) status; required utilities to provide non-discriminatory wholesale wheeling; predicate to Order 888.
• Energy Policy Act of 2005 (EPAct 2005) — established mandatory reliability standards via ERO (NERC), expanded FERC merger authority + market manipulation authority (§1283, 16 USC §824v), created NIETC framework, expanded loan guarantee program.
• Energy Independence and Security Act of 2007 (EISA 2007) — fuel economy + renewable fuel standard + smart-grid policy.
• American Recovery and Reinvestment Act of 2009 (ARRA) — $90B+ clean-energy stimulus including smart-grid + battery + EV + renewable + transmission funding.
• Infrastructure Investment and Jobs Act of 2021 (IIJA / Bipartisan Infrastructure Law) — ~$73B energy + grid + EV charging + advanced reactor + battery supply chain + weatherisation + carbon capture.
• CHIPS and Science Act of 2022 — ~$52B semiconductor manufacturing + R&D + advanced technology.
• Inflation Reduction Act of 2022 — see §8 above.

10. International parallels

• European Union — primary energy regulation under TFEU + EU directives + ACER (Agency for the Cooperation of Energy Regulators) + ENTSO-E (Transmission System Operators) + ENTSOG (Gas). The Internal Electricity Market Regulation (Regulation 2019/943) is the core legal framework, substantially updated by Regulation 2024/1747 (Electricity Market Design Reform, June 2024) addressing energy crisis (Russia gas) + renewable integration + CRM rules + retail consumer protection. National regulators: CRE (France), Bundesnetzagentur (Germany), AEEGSI/ARERA (Italy), CNMC (Spain), CRE (Belgium), etc. Capacity Remuneration Mechanisms notified to DG COMP under State Aid rules.
• United Kingdom — Ofgem (Office of Gas and Electricity Markets) regulates retail + networks + licence codes; NESO (formerly National Grid ESO, split + nationalised October 2024) operates the system; DESNZ (Department for Energy Security and Net Zero, since February 2023 split from BEIS) sets policy. Capacity Market under the Energy Act 2013. Contracts for Difference (CfDs) for new low-carbon generation via LCCC. Review of Electricity Market Arrangements (REMA) 2022-26 proposes broader market reform (nodal vs zonal pricing debate, CfD reforms, capacity-market redesign).
• Australia — AEMC (Australian Energy Market Commission) sets rules; AER (Australian Energy Regulator) enforces; AEMO (Australian Energy Market Operator) operates the NEM. Capacity Investment Scheme (32 GW renewables + storage CIS by 2030, federally underwritten via CfD auctions).
• Japan — METI (Ministry of Economy, Trade and Industry) + OCCTO (cross-regional coordinator) + EPSO-J (post-2020 unbundling). Capacity auctions since 2020.
• Korea — KPX (Korea Power Exchange) cost-based pool transitioning to bid-based; KEPCO retail + generation incumbent.
• Brazil — ANEEL (regulator) + ONS (operator) + CCEE (market chamber). Energy + capacity auctions.

11. Common questions

Q: Why is ERCOT not under FERC jurisdiction? Because the Texas Interconnection is synchronously isolated — no AC ties to the Eastern or Western Interconnections (only DC ties via the Welsh DC Tie + Eagle Pass + East DC Tie + Railroad + Mexico CFE DC connections). Energy flowing within ERCOT does not cross state lines via AC interconnection. The narrow exception is the DC-tie transactions themselves, which are FERC-jurisdictional. Post-Uri, there was extensive discussion of adding AC ties to MISO South + WECC that would have brought ERCOT under FERC jurisdiction; that has not happened as of 2026.

Q: Why doesn’t FERC site generation? FPA §201(b) reserves to the states authority over generation facilities. The narrow exceptions: nuclear (NRC, under Atomic Energy Act 1954 + NRC regulations) + hydroelectric on navigable waters or federal lands (FERC under FPA Part I) + LNG export/import terminals on shorelines (FERC under NGA §3 for siting + DOE for export authorisation).

Q: Can FERC override a state PUC’s retail rate? No. Retail rates are state jurisdiction (FPA §201(b)). FERC can regulate the wholesale component that flows into retail rates (the transmission charge + the wholesale energy + capacity + ancillary cost), but the state PUC sets the retail tariff design + retail rate level + distribution charges.

Q: What happens when state policy conflicts with wholesale market clearing? Hughes preemption test: if state policy conditions payment on wholesale rates, it is preempted; otherwise it survives. State subsidies via capital grants, fixed-price PPAs, ITC + PTC analogues, RPS-based REC, and ZECs survive. State CfDs tied to wholesale price are preempted. The capacity-market MOPR question is whether wholesale-market design must accommodate or insulate from state subsidies.

Q: Why does the same plant get different prices at different nodes? Locational Marginal Pricing — the cost of meeting one more megawatt of withdrawal at that node, given binding transmission constraints + losses. See electricity-markets-and-grids §4.

Q: How does FERC enforce against market manipulation? Energy Policy Act 2005 §1283 (16 USC §824v) prohibits manipulation in connection with the purchase or sale of electric energy or transmission service. Implementing rule at 18 CFR §1c.2. FERC Office of Enforcement investigates + brings administrative cases; civil penalties up to $1M/dayperviolation+disgorgement.Majorcases:Constellation$245M (2012, virtual trading), JPMorgan $410M(2013,MISO+CAISObiddingstrategies),DeutscheBank$1.6M (2013), BP $20M(2016,ICEphysicalgas),Total$9M (2015), Coaltrain $26M (2018), Vitol settlement (2019, CAISO bidding).

12. Glossary of acronyms

• ACER — Agency for the Cooperation of Energy Regulators (EU)
• ARRA — American Recovery and Reinvestment Act 2009
• ATC — Available Transfer Capability
• BES — Bulk Electric System
• CASPR — Competitive Auctions with Sponsored Policy Resources (ISO-NE)
• CCS — Carbon Capture and Storage
• CHIPS — Creating Helpful Incentives to Produce Semiconductors Act 2022
• CIP — Critical Infrastructure Protection (NERC standards)
• CITAP — Coordinated Interagency Transmission Authorizations and Permits Program (DOE)
• CRM — Capacity Remuneration Mechanism (EU)
• DAC — Direct Air Capture
• DESNZ — Department for Energy Security and Net Zero (UK, since 2023)
• DOE — Department of Energy (US)
• EAJA — Equal Access to Justice Act (intervenor cost recovery)
• EISA — Energy Independence and Security Act 2007
• EPA — Environmental Protection Agency (US)
• EPAct — Energy Policy Act (1992 + 2005)
• ERO — Electric Reliability Organization (NERC’s designation)
• FERC — Federal Energy Regulatory Commission
• FPA — Federal Power Act 1935 (as amended)
• GETs — Grid-Enhancing Technologies (dynamic line ratings, advanced power flow controls)
• IIJA — Infrastructure Investment and Jobs Act 2021 (Bipartisan Infrastructure Law)
• IRA — Inflation Reduction Act 2022
• LCCC — Low Carbon Contracts Company (UK, CfD counterparty)
• LGIA — Large Generator Interconnection Agreement (>20 MW)
• LGIP — Large Generator Interconnection Procedures
• MOPR — Minimum Offer Price Rule (PJM, ISO-NE capacity-market subsidy floor)
• NEPA — National Environmental Policy Act 1970
• NERC — North American Electric Reliability Corporation
• NESO — National Energy System Operator (UK, since October 2024)
• NGA — Natural Gas Act 1938
• NIETC — National Interest Electric Transmission Corridor
• NRC — Nuclear Regulatory Commission
• OATT — Open Access Transmission Tariff
• OE — Office of Enforcement (FERC)
• OEMR — Office of Energy Market Regulation (FERC)
• OER — Office of Electric Reliability (FERC)
• PTC — Production Tax Credit
• PUC — Public Utility Commission (state)
• PUCT — Public Utility Commission of Texas
• PUHCA — Public Utility Holding Company Act
• PURPA — Public Utility Regulatory Policies Act 1978
• QF — Qualifying Facility (under PURPA)
• RERRA — Relevant Electric Retail Regulatory Authority (state PUC in DER aggregation context)
• REMA — Review of Electricity Market Arrangements (UK)
• RGGI — Regional Greenhouse Gas Initiative (Northeast US cap-trade)
• ROFR — Right of First Refusal (incumbent transmission owners)
• SGIA / SGIP — Small Generator Interconnection Agreement / Procedures (≤20 MW)
• TFP — Transmission Facilitation Program (DOE)
• ZEC — Zero Emission Credit (state nuclear support)

13. Cross-references

• electricity-markets-and-grids — market mechanics + ISO/RTO structure
• missing-money-and-scarcity-pricing — capacity vs energy-only debate
• capacity-and-ancillary-services-markets — capacity + AS product detail
• transmission-and-grid-services — transmission planning + grid services
• demand-response-and-flexibility — demand side under Orders 745 + 2222
• carbon-markets-and-compliance — RGGI + EU ETS + CA cap-trade + clean-energy compliance
• renewable-energy-certificates — RECs + state RPS compliance
• microeconomics — regulatory economics + market-failure framework

14. References

Statutes:

• Federal Power Act, 16 USC §§791-828c (Parts I, II, III).
• Natural Gas Act, 15 USC §§717-717w.
• Public Utility Regulatory Policies Act 1978.
• Energy Policy Act of 1992; Energy Policy Act of 2005; Energy Independence and Security Act of 2007.
• Infrastructure Investment and Jobs Act of 2021 (Pub L 117-58).
• Inflation Reduction Act of 2022 (Pub L 117-169).

Major cases:

• Public Utilities Commission of Rhode Island v. Attleboro Steam & Electric Co., 273 US 83 (1927) — the Attleboro gap.
• FERC v. Mississippi, 456 US 742 (1982) — PURPA upheld against Tenth Amendment challenge.
• New York v. FERC, 535 US 1 (2002) — FERC unbundling authority upheld.
• Hughes v. Talen Energy Marketing, 578 US 150 (2016) — preemption of state CfDs.
• FERC v. EPSA, 577 US 260 (2016) — DR within FERC wholesale jurisdiction.
• Coalition for Competitive Electricity v. Zibelman, 906 F.3d 41 (2d Cir 2018) — NY ZECs upheld.
• Electric Power Supply Ass’n v. Star, 904 F.3d 518 (7th Cir 2018) — Illinois ZECs upheld.
• NARUC v. FERC, 964 F.3d 1177 (DC Cir 2020) — Order 841 storage participation upheld.

FERC orders cited (chronological):

• Order 888 (April 1996); Order 889 (April 1996); Order 2000 (December 1999); Order 2003 (July 2003); Order 2006 (May 2005); Order 745 (March 2011); Order 755 (October 2011); Order 1000 (July 2011); Order 825 (June 2016); Order 841 (February 2018); Order 872 (July 2020); Order 2222 (September 2020); Order 2023 (July 2023); Order 1920 (May 2024); Order 1977 (May 2024); Order 1980 (May 2024).

Regulatory reports:

• FERC + NERC, Inquiry into Bulk-Power System Operations During February 2021 Cold Weather Event (November 2021).
• FERC, State of the Markets Reports (annual).
• NERC, Long-Term Reliability Assessment (annual); State of Reliability (annual); Compliance Monitoring and Enforcement Program annual report.

Academic + policy:

• Joskow + Schmalensee 1983 Markets for Power — early framework.
• Joskow 2007 Restructured Electricity Markets: Issues and Outlook (Yale Journal on Regulation).
• Tierney 2024 Capacity Markets Revisited — Analysis Group reviews.
• Brattle Group Capacity Market reviews + ELCC studies (multiple, 2019-2025).
• Princeton REPEAT Project (Jenkins et al.) — IRA + IIJA impact modelling.
• Resources for the Future (RFF) — FERC + carbon-pricing + transmission research.
• Energy Innovation + RMI + ICF + Wood Mackenzie + S&P Global market analyses.