FERC & Federal Energy Regulation

The Federal Energy Regulatory Commission (FERC) — an independent regulatory commission authorized under 16 U.S.C. §§ 791a–828c (Federal Power Act) and 15 U.S.C. §§ 717–717z (Natural Gas Act) — is the primary federal regulator of the interstate transmission of electricity, natural gas, and oil; the wholesale electricity markets that power most of the United States; and the licensing of hydroelectric projects on navigable waterways. FERC's decisions affect essentially every electricity customer in the United States (except those served by government-owned utilities and rural electric cooperatives): the commission sets the rates, terms, and conditions under which power plants, transmission companies, and natural gas pipelines can charge for interstate services, and must approve any new transmission line or natural gas pipeline that crosses state lines. FERC-regulated Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) — including PJM (mid-Atlantic and Midwest), MISO (Midwest/South), CAISO (California), NYISO (New York), and ISO-NE (New England) — operate wholesale electricity markets serving roughly two-thirds of U.S. electricity consumers. FERC is at the center of the U.S. energy transition: its Order 1920 (2024) required utilities to plan proactively for the transmission infrastructure needed for long-range renewable energy buildout — a landmark rule addressing the transmission bottleneck that has slowed the connection of new wind and solar projects to the grid. The commission also reviews LNG export terminal applications, making it a gatekeeper for U.S. natural gas export capacity.

Current Law (2026)

Legal Authority

• 16 U.S.C. § 824(a-b) — Federal Power Act (FERC has jurisdiction over transmission and wholesale sale of electric energy in interstate commerce; states retain jurisdiction over retail sales, local distribution, and generation facilities)
• 15 U.S.C. § 717 — Natural Gas Act (FERC regulates the transportation and sale of natural gas in interstate commerce; rates must be "just and reasonable"; FERC issues certificates for construction of interstate pipelines and LNG terminals)
• 42 U.S.C. § 7172 — FERC establishment (FERC is an independent regulatory commission within the Department of Energy; exercises regulatory functions previously held by the Federal Power Commission)
• 16 U.S.C. § 824d-e — Rate regulation (all rates for wholesale electricity must be just and reasonable and not unduly discriminatory; FERC may investigate and fix rates that are unjust or unreasonable)

How It Works

FERC is the federal agency that regulates the nation's electricity and natural gas markets — working alongside state public utility commissions that set retail rates — overseeing the infrastructure and market rules that determine how energy is produced, transported, and sold across state lines. Its decisions affect the price, reliability, and environmental impact of energy for every American.

FERC's electricity jurisdiction covers wholesale sales (power plant to utility) and interstate transmission — the high-voltage grid that moves electricity across state lines — but not retail sales to consumers (that's state public utility commissions) or generation siting (state jurisdiction). FERC oversees the Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) — PJM, MISO, CAISO, NYISO, ISO-NE, and others — that operate competitive wholesale electricity markets covering about two-thirds of the U.S. through day-ahead and real-time auctions. For natural gas, FERC regulates interstate pipeline transportation across approximately 300,000 miles of pipelines and certifies new pipeline construction and LNG import/export terminals under a public convenience and necessity standard — one of its most consequential and contested functions, given the years-long permitting timelines and environmental opposition major projects face. For hydropower, FERC issues licenses (up to 50 years) for non-federal projects on navigable waters or federal lands — roughly 2,500 projects with ~55 GW of capacity — balancing power generation against fish passage, water quality, and recreation requirements that are often heavily litigated at relicensing.

FERC's grid reliability authority runs through the North American Electric Reliability Corporation (NERC), a self-regulatory organization that develops and enforces mandatory reliability standards covering everything from vegetation management near power lines to cybersecurity protections for grid control systems. FERC can approve, reject, or direct revisions to NERC standards. Woven through all of this is FERC's growing role in the clean energy transition: new wind and solar generation frequently requires new high-voltage transmission lines to reach load centers, and FERC's rules governing transmission planning, cost allocation, and interconnection queues — overhauled by Order 1920 (May 2024) — directly determine how quickly that infrastructure gets built and who pays for it.

How It Affects You

State Variations

Implementing Regulations

• 18 CFR Part 1c — Prohibition of Energy Market Manipulation. Key provisions:

  • § 1c.1 — Natural gas market manipulation: it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to FERC jurisdiction, to: (1) use or employ any device, scheme, or artifice to defraud; (2) make any untrue statement of a material fact or omit to state a material fact necessary to make statements not misleading; or (3) engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any person
  • § 1c.2 — Electric energy market manipulation: the identical prohibition applies to purchases or sales of electric energy and the purchase or sale of transmission services subject to FERC jurisdiction — same three-prong prohibition: device/scheme to defraud, material misstatement or omission, or fraudulent act or practice

  Part 1c is FERC's analog to the SEC's Rule 10b-5 — the foundational anti-fraud rule for energy markets. The language was deliberately modeled on securities anti-fraud law following the Energy Policy Act of 2005, which gave FERC explicit anti-manipulation authority in response to the Enron/California energy crisis. Unlike rate regulation (which requires FERC to show rates are "unjust and unreasonable"), manipulation enforcement requires showing fraudulent intent — making it a more fact-intensive, adversarial process. FERC has used Part 1c to pursue: (a) wash trades (round-trip transactions creating artificial volume to influence price indices); (b) economic withholding (generators refusing to offer available capacity to drive up clearing prices); (c) false reporting to price-reporting services like Platts; and (d) cross-market manipulation (trading physical energy to profit on derivative positions). Civil penalties under the Federal Power Act and Natural Gas Act can reach $1 million per day per violation — FERC has issued penalties exceeding $100 million in single enforcement actions. The rule applies to any entity — not just FERC-jurisdictional utilities — that trades in FERC-regulated markets. Recent rulemaking: FERC Order 705 (2006) — established Part 1c implementing EPACT 2005 anti-manipulation authority.

• 18 CFR Part 2 — General policy and interpretations (transmission line policy, rate increase filings, good faith transmission requests, RTGs, pricing policy)

• 18 CFR Part 35 — Filing of Rate Schedules and Tariffs for electric public utilities (50 sections — the procedural rulebook implementing FPA Sections 205 and 206, which require every public utility to file its rates and terms with FERC; electric rates for wholesale power and transmission must be on file with FERC before they take effect). Key provisions:

  • § 35.1 — Obligation to file: every public utility (a company transmitting or selling electric energy in interstate commerce at wholesale) must file with FERC and keep on public file complete rate schedules and tariffs; no rate, charge, or condition not on file may be imposed — the filed-rate doctrine makes the tariff legally binding on both the utility and its customers
  • § 35.3 — Notice requirements: rate schedule changes must be filed with FERC and posted not less than 60 days before the proposed effective date; FERC may, on good cause shown, reduce the 60-day notice period; the 60-day window gives FERC time to review the filing and intervening parties time to protest before the rate takes effect
  • § 35.13 — Filing changes to existing rates: rate increase filings must include cost-of-service data supporting the increase; the supporting data requirement reflects FERC's just-and-reasonable rate mandate — rate increases must be supported by showing the costs that justify them; rate decreases and non-rate tariff changes have simplified filing requirements
  • § 35.19a — Refund requirements under suspension orders: when FERC suspends a proposed rate increase (up to 5 months of suspension pending investigation), the utility may collect the increased rate subject to refund; if FERC's final order establishes a rate lower than what was collected during suspension, the utility must refund the difference plus interest; the refund obligation prevents utilities from benefiting from the time value of a rate increase even if it's ultimately found unjust and unreasonable
  • § 35.10b — Electric Quarterly Reports (EQRs): each public utility must file an EQR showing all wholesale electric power and transmission service transactions from the prior quarter; EQRs are publicly available on FERC's website and are used by market monitors, state commissions, and traders to analyze wholesale market activity; the quarterly reporting requirement is the primary source of data on wholesale electric prices and contract terms
  • § 35.28 — Non-discriminatory Open Access Transmission Tariff (OATT): every public utility that owns, controls, or operates transmission facilities must maintain a FERC-accepted OATT; the OATT must offer transmission services to all eligible customers on rates, terms, and conditions no less favorable than the utility offers itself (the non-discrimination principle from FERC Order 888, 1996); the OATT is the foundational mechanism of competitive wholesale electricity markets — without guaranteed non-discriminatory transmission access, competitive generators cannot reliably reach customers
  • § 35.34 — Rate incentives for transmission investment: public utilities may apply for enhanced return-on-equity (ROE) incentives for new transmission projects that reduce congestion, improve reliability, or integrate renewables; FERC may grant incentive rates above the base ROE to encourage transmission infrastructure investment; the incentive ROE policy reflects FERC's recognition that transmission investment has been chronically underinvested relative to the needs of the competitive wholesale market

  Part 35's OATT requirement — operationalized through FERC Order 888 and its successors — transformed U.S. electricity markets by mandating that vertically integrated utilities provide the same transmission service to competitors that they provide to their own generation. Without the OATT, a utility owning both generation and transmission could favor its own power plants with priority grid access, effectively blocking competitive entry. The OATT opened transmission to competitive generators and paved the way for the regional transmission organizations (RTOs/ISOs) that now operate wholesale markets covering approximately two-thirds of U.S. electricity consumption.

• 18 CFR Part 36 — Transmission services (notice provisions for Section 211 applications)

• 18 CFR Part 37 — Open Access Same-Time Information System (OASIS): FERC's regulations requiring transmission providers to operate or participate in an OASIS — a real-time, publicly accessible electronic system that allows potential transmission customers to view available transmission capacity, post requests for service, and monitor the status of their requests on a non-discriminatory basis. OASIS was mandated by FERC Order 889 (1996) as the information transparency companion to the Open Access Transmission Tariff (OATT) in Order 888. Key provisions:

  • § 37.2 — Purpose: OASIS ensures that potential transmission customers can obtain transmission service on a non-discriminatory basis by providing access to the same real-time capacity information that the transmission provider's own generation affiliates use; without OASIS, a utility could provide its own generation subsidiaries with inside information about available capacity while leaving competitors to estimate based on published schedules — creating an information asymmetry that undermines competitive access
  • § 37.5 — Obligations of transmission providers: each transmission provider must operate an OASIS, either individually or jointly with other transmission providers; the OASIS must be operational 24 hours a day, 7 days a week; the transmission provider must post all information about available transmission capacity (ATC) in real time; the transmission provider may not use information on the OASIS for competitive advantage — affiliates of the transmission provider cannot receive information about competitors' transmission requests or customer identities through the OASIS system; this information firewall is enforced through Standards of Conduct rules (18 CFR Part 358) that require separation between transmission and marketing personnel
  • § 37.6 — Information to be posted: the OASIS must enable customers to: (1) make requests for transmission services; (2) view ATC and Total Transfer Capability (TTC) for all paths on the transmission provider's system; (3) view existing transmission reservations and their capacity impacts; (4) view prices and terms for all transmission services; and (5) track the status of their own service requests in real time; OASIS postings must be updated continuously and must reflect all accepted reservations within specified time windows; inaccurate or delayed OASIS postings can disadvantage competing generators and are subject to FERC enforcement
  • § 37.7 — Auditing: all OASIS database transactions must be stored, dated, and time-stamped; audit data must remain available for three years; FERC staff may audit OASIS records to verify that transmission providers are not using the system to favor affiliates; the time-stamped audit trail allows FERC to determine whether the transmission provider's own generation affiliates received capacity information before it was posted publicly — the core compliance concern
  • § 37.8 — OASIS user obligations: OASIS users (companies making transmission service requests) must notify the responsible party (the transmission provider operating the OASIS) one month in advance if they anticipate significant automated queries; high-volume automated queries can overload OASIS systems, and advance notice allows the system operator to accommodate heavy traffic; users who conduct excessive automated queries without notice may lose OASIS access

  Part 37 OASIS is the technical foundation for open access transmission markets. Without a standardized, real-time information posting system, transmission providers could delay posting available capacity to disadvantage competitors, or provide their own generators with advance notice of system conditions through informal channels. FERC's Standards of Conduct rules in Part 358 work in tandem with Part 37 to enforce the information firewall — prohibiting transmission employees from sharing non-public system information with their marketing or generation colleagues. Modern OASIS systems have evolved significantly from the 1996 mandate, with most large transmission providers now operating OASIS nodes that are integrated into RTO/ISO platforms (MISO's e-Tagging, PJM's eRPM) providing far more sophisticated market information than the original Order 889 contemplated.

• 18 CFR Part 154 — Rate Schedules and Tariffs for natural gas pipelines — the formal framework that every interstate natural gas pipeline must use to file and maintain its rates, terms, and conditions with FERC under Section 4 of the Natural Gas Act. Key provisions:

  • § 154.1 — Scope and NGA Section 4 obligation: all rates, charges, terms, and conditions for natural gas transportation and sales by jurisdictional pipelines must be filed in a tariff with FERC and kept on file for public inspection; no pipeline may charge any rate not on file
  • § 154.103 — Tariff composition: a complete tariff filing must include (1) a table of contents, (2) a preliminary statement with general information about the pipeline's system and rates, (3) a map of the pipeline system with URL, (4) the rate schedules themselves, (5) general terms and conditions (GTs&Cs), and (6) any pro forma service agreements
  • § 154.107 — Rate expression: rates must be stated in cents or dollars per MMBtu (million British thermal units) or per Dth (dekatherm) — the unit of thermal content rather than volumetric delivery; pipelines that historically quoted rates in Mcf (thousand cubic feet) were required to convert to thermal units, reflecting that customers pay for energy content, not gas volume, which varies with BTU content by source
  • § 154.108 — Rate schedule composition: each rate schedule must identify the type of service, the applicable customer class, the rate components (reservation charge + commodity charge + fuel retention percentage), and the maximum and minimum rates; maximum rates represent the ceiling FERC has approved; discounts below maximum are allowed but must be reported
  • § 154.109 — General terms and conditions: the GTs&Cs section governs nomination and scheduling procedures, capacity release rules, force majeure provisions, measurement methodology, and quality specifications; for shippers, the GTs&Cs are typically more operationally consequential than the rate schedule itself
  • §§ 154.201–154.205 — Filing changes: a pipeline must file a tariff change with FERC at least 30 days before the proposed effective date for rate increases, and at least 1 day for rate decreases or non-rate tariff revisions; FERC may suspend a proposed rate increase for up to 5 months while it investigates whether the new rate is just and reasonable; during suspension, the pipeline may collect the new rate subject to refund

  The Part 154 tariff framework is the practical mechanism for FERC's just-and-reasonable rate mandate over interstate gas transportation. Unlike electricity, where organized markets set real-time prices, natural gas pipeline rates are set through cost-of-service proceedings and filed as public tariffs — making the tariff filing the primary way FERC controls what pipelines can charge shippers. For natural gas shippers, marketers, and LDCs (local distribution companies), the filed tariff is the contract: the rate schedule determines what you pay for firm and interruptible capacity, and the GTs&Cs determine when and how your gas moves. Tariff interpretation disputes — over scheduling priority, imbalance penalties, or force majeure claims — are heard by FERC's Office of Administrative Law Judges under the same procedural framework as rate cases.

• 18 CFR Part 284 — Certain Sales and Transportation of Natural Gas Under the Natural Gas Policy Act of 1978 and Related Authorities (58 sections across 10 subparts — the blanket certificate framework enabling self-executing cross-sector natural gas transportation without case-by-case FERC approval; the operational heart of FERC's open-access gas transportation regime established by Order 636). Key provisions:

  • § 284.102 — Interstate pipeline blanket authority: any interstate pipeline is authorized without prior FERC approval to transport natural gas on behalf of any intrastate pipeline or local distribution company, at rates established under § 284.10; this blanket authority replaced the prior case-by-case Section 311 authorization process and enabled the development of hub-and-spoke gas transportation networks; pipelines must file rates on tariff before commencing service, but no individual project approval is required
  • § 284.122 — Intrastate pipeline blanket authority: symmetrically, any intrastate pipeline may transport gas on behalf of any interstate pipeline or LDC without prior FERC approval; the intrastate blanket authority is the NGPA Section 311(a)(2) counterpart to § 284.102; this provision is critical in Texas and Louisiana, where major intrastate pipelines (including major Texas pipelines that are not FERC-jurisdictional for rate purposes) connect to interstate markets
  • § 284.12 — NAESB business practice standards: interstate pipelines operating under Part 284 blanket authority must comply with North American Energy Standards Board (NAESB) gas business practices and electronic communication standards incorporated by reference; NAESB standards govern nomination cycles, scheduling priorities, imbalance management, and electronic data interchange — the operational rules that allow gas to move across hundreds of interconnected pipelines without bilateral negotiation for every transaction
  • Subpart G (§§ 284.221–284.288) — Blanket certificates for open-access transportation: the foundational FERC Order 636 requirement that interstate pipelines provide open-access transportation on a non-discriminatory basis to any shipper on the same terms as they provide to affiliated gas marketing companies; blanket certificates make affiliate preference effectively impossible because the same rate schedule and service terms apply to all shippers; this is the gas-market analog to FERC's open-access transmission tariff (OATT) requirements for electricity
  • Subpart I (§§ 284.301–284.315) — Emergency natural gas transportation: FERC may authorize emergency gas sales and transportation outside normal rate and certificate requirements during gas supply emergencies; invoked during the 2021 February polar vortex (Winter Storm Uri) and other events where supply disruptions threatened public safety
  • Subpart M (§§ 284.501–284.512) — Market-based rates for storage: pipelines may apply for market-based rate authority for natural gas storage services if they demonstrate insufficient market power in the relevant storage market; market-based storage rates reflect FERC's recognition that the gas storage market has become competitive in many regions, unlike the monopoly pipeline transportation market

  Part 284's significance lies in its role as the enabling mechanism for the modern, competitive U.S. natural gas market. Before FERC Order 636 (1992), integrated pipelines bundled gas sales with transportation — customers bought the pipeline's gas and transportation as a package. Order 636 required unbundling: pipelines must transport gas for any shipper at the same terms they transport their own affiliate's gas. Part 284 provides the blanket certificate framework that makes this operational — without it, every cross-sector transportation arrangement would require a separate FERC certificate proceeding. The result is a liquid, competitive market where hundreds of shippers transact across thousands of interconnection points on dozens of pipelines, creating the price discovery that makes Henry Hub the global LNG benchmark price. Recent rulemakings: 88 FR 14440 (March 2023) — updated Part 284 reporting requirements for gas market transactions.

• 18 CFR Part 153 — Applications for Authorization to Construct, Operate, or Modify LNG Import/Export Facilities: the FERC implementing regulation for Section 3 of the Natural Gas Act (15 U.S.C. § 717b), which requires FERC authorization before any entity may construct, expand, or operate a facility to import or export natural gas — including LNG terminals, LNG peaking facilities, and cross-border pipeline connections; the regulation is triggered by the physical facility, not by the commodity contract:

  • § 153.1 — Scope: covers all applicants seeking FERC authorization under NGA Section 3 and Executive Order 10485 (which delegated the President's NGA Section 3 authority to DOE and FERC); LNG export projects require both a FERC certificate (for the liquefaction/terminal facility under Part 153) and a DOE export authorization (for the commodity itself — the right to export LNG to free-trade or non-free-trade countries); a project cannot proceed with FERC approval alone if DOE authorization is pending or denied
  • § 153.12 — Pre-filing procedures: before filing a formal application, an applicant seeking to site, construct, maintain, or modify LNG export or import facilities must complete a FERC pre-filing process — typically 6-18 months of stakeholder engagement, environmental review preparation, and agency coordination; the pre-filing docket opens publicly in FERC's eLibrary (elibrary.ferc.gov), enabling early public participation before the formal application; pre-filing is where communities near proposed LNG terminals have the most leverage to shape the scope of environmental review
  • § 153.6 — Application content: a formal application must include technical descriptions of the proposed facilities, construction and operation plans, financial and ownership information, evidence of public need, and an Environmental Report (ER) prepared in accordance with FERC's environmental regulations; for major LNG export projects (the 20+ bcf/day Gulf Coast facilities), the ER runs thousands of pages covering air quality, water quality, ecological impacts, noise, traffic, cumulative impacts, and environmental justice
  • § 153.8 — Environmental review: FERC prepares an Environmental Impact Statement (EIS) for all major LNG projects; the EIS process includes public scoping meetings (where the community can demand specific environmental issues be analyzed), draft EIS publication with comment period, response to comments, and final EIS; if FERC issues a certificate after the EIS, federal eminent domain authority follows — the developer can condemn private land for the facility and access routes

  FERC's LNG certificate program has been at the center of U.S. energy export policy since 2011, when the first major Gulf Coast LNG export projects were filed. The LNG export boom made the U.S. the world's leading LNG exporter by volume by 2023. Each major project — Sabine Pass, Corpus Christi, Freeport, Cameron, Calcasieu Pass, Plaquemines — required a FERC certificate under Part 153 plus DOE authorization. DOE's authority over who can export (to which countries, at what volumes) is separate from FERC's authority over the facility — the intersection has been litigated extensively. The Biden administration's January 2024 pause on new DOE LNG export authorizations (to study economic and climate impacts) was challenged by industry; the Trump administration reversed the pause in January 2025 and expedited pending applications.

• 18 CFR Part 141 — Statements and Reports (Schedules): FERC's annual and quarterly financial reporting requirements for electric utilities, natural gas companies, and oil pipelines — the data backbone that FERC uses to monitor market structure, financial health, and grid reliability. Key forms:

  • § 141.1 — FERC Form No. 1 (Annual Report for Major Electric Utilities, Licensees, and Others): every major electric public utility must file Form 1 annually — a comprehensive financial and operational report covering balance sheet, income statement, fuel costs, generation statistics, transmission capacity, and sales data; "major" is defined as utilities with annual sales ≥ 1 million MWh or transmission revenues ≥ $500,000; the Form 1 data is publicly searchable at FERC's eLibrary and is the primary source for academic and regulatory analysis of utility financials
  • § 141.2 — FERC Form No. 1-F (Annual Report for Nonmajor Public Utilities): a streamlined version of Form 1 for utilities below the "major" thresholds; covers the same financial categories at a higher level of aggregation; nonmajor utilities that are subsidiaries of holding companies often file consolidated reports
  • § 141.51 — FERC Form No. 714 (Annual Electric Balancing Authority Area and Planning Area Report): filed by balancing authorities (grid operators like PJM, MISO, ISO-NE) and planning authorities; reports hourly load data, interchange transactions, and planning area reserve margins; Form 714 is a primary data source for NERC reliability assessments and FERC's capacity market oversight
  • § 141.300 — FERC Form No. 715 (Annual Transmission Planning and Evaluation Report): transmission providers must annually report how they plan and evaluate their transmission systems — including criteria used to identify reliability violations, results of reliability assessments, and planned capital projects; Form 715 documents the transmission planning process that FERC requires under Order 890 and Order 1000
  • § 141.400 — FERC Form No. 3-Q (Quarterly Financial Report): public utilities and licensees subject to Form 1 must also file quarterly financial statements covering income, balance sheet, and cash flow; the 3-Q provides a faster look at financial distress than the annual Form 1 — FERC monitors these for early warning signs of credit deterioration in regulated utilities
  • § 141.500 — Cash management programs: holding company systems that pool subsidiary cash must file annual reports on their cash management programs, including interest rates charged to subsidiaries, credit lines, and intercompany loan terms; designed to prevent holding companies from draining cash from regulated utilities to fund unregulated subsidiaries

  Part 141 filings are the granular data infrastructure behind FERC rate cases, transmission planning reviews, and market monitoring. When FERC or a state PUC conducts a rate case for a regulated utility, Form 1 data is the starting point for calculating the rate base and allowed return. The Form 714 hourly load data feeds into NERC's annual Long-Term Reliability Assessment and is used by transmission planners modeling future grid needs. The cash management reporting in § 141.500 directly responds to post-Enron concerns about affiliate transactions draining regulated utility assets. Recent rulemakings: 88 FR 73459 (2023) — FERC updated Form 1 to add distributed energy resource reporting categories.

• 18 CFR Part 294 — Electric energy shortages (emergency procedures)

• 18 CFR Part 292 — Qualifying Facilities under PURPA (small power production and cogeneration — the full lifecycle from certification through mandatory purchase obligations and rate-setting):

  • § 292.203 — General requirements: a facility must meet either the small power production or cogeneration definition and satisfy operating and efficiency standards before FERC certifies it as a Qualifying Facility (QF); QF status entitles the facility to sell power to the local electric utility at regulated rates
  • § 292.204 — Small power production facility size cap: a facility qualifies as a small power producer only if its net power production capacity does not exceed 80 megawatts (increased from 30 MW by the Energy Policy Act of 1992); primary energy source must be renewable (solar, wind, biomass, geothermal, waste, water) or a combination of renewable and waste heat; fossil fuels may comprise no more than 25% of total energy input during any calendar year
  • § 292.205 — Cogeneration efficiency standards: a cogeneration QF must sequentially or simultaneously produce electric power and useful thermal energy (steam, heat, cooling) from a single fuel source; topping-cycle cogenerators (electricity first, then thermal) must meet minimum operating efficiency standards — the combined useful power and thermal outputs must equal at least 42.5% of total fuel energy input (45% if the power-to-heat ratio exceeds 15%); bottoming-cycle cogenerators (thermal first, then power) have no minimum efficiency standard but must demonstrate meaningful useful thermal output
  • § 292.207 — Self-certification via FERC Form 556: a facility that meets the QF criteria may obtain QF status through self-certification — filing FERC Form 556 electronically and paying no filing fee; alternatively, a facility may petition FERC for a formal determination, which involves a more detailed review and takes longer; self-certified QFs must retain supporting documentation; misrepresentation on Form 556 is grounds for QF status revocation and potential refund of all avoided-cost payments received
  • § 292.303 — Electric utility purchase obligation: every electric utility must purchase any energy and capacity made available by a QF that the utility is required to interconnect; this is the "must-buy" rule that gave PURPA its economic teeth and drove the first wave of independent power development in the 1980s and 1990s; the obligation runs regardless of whether the utility has other, cheaper generation available
  • § 292.304 — Avoided-cost rates: utilities must pay QFs the avoided cost — the incremental cost the utility would have incurred to generate or purchase the equivalent electricity itself; states set the specific avoided cost methodology; rates may be fixed at the time of contracting (giving QF developers long-term revenue certainty) or may vary with the utility's actual avoided costs; the avoided cost principle ensures utilities are not forced to overpay for QF power — they pay only what the power is "worth" to them given alternatives
  • § 292.309 — Termination of purchase obligation for competitive markets: the Energy Policy Act of 2005 authorized FERC to relieve utilities of the mandatory purchase obligation for QFs larger than 20 MW if the QF has non-discriminatory access to a competitive wholesale electricity market where it can sell power — as most QFs in RTO/ISO regions (MISO, PJM, CAISO, SPP) do; the utility must petition FERC for the exemption; the obligation remains in full for QFs ≤ 20 MW and for QFs in non-competitive markets (much of the Southeast and West outside RTOs)
  • § 292.601 — Federal Power Act exemptions: QFs are fully exempt from FERC's ratemaking, financial, and organizational regulation under the Federal Power Act (FPA); small power producers are also exempt from the Public Utility Holding Company Act (PUHCA) and from state utility regulation over rates, financial structure, and organization — the exemption package that made QF development commercially viable

  The Part 292 regulations implement PURPA's twin goals: reducing dependence on fossil fuels (through renewables and efficiency incentives) and opening electricity generation to non-utility producers for the first time. PURPA-driven QF capacity grew from near zero in 1978 to over 60,000 MW by 2000, launching the modern independent power industry. The 2005 competitive-market exemptions reduced the mandatory purchase obligation in organized wholesale markets, but the program remains significant in states served by vertically integrated utilities that lack access to competitive power markets — particularly in the Southeast and parts of the Mountain West.

• 18 CFR Part 39 — Rules Concerning Certification of the Electric Reliability Organization and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards: FERC's framework for implementing Section 215 of the Federal Power Act (16 U.S.C. § 824o), which created the mandatory bulk electric system reliability program and established FERC's authority to certify a single Electric Reliability Organization (ERO) to develop and enforce reliability standards:

  • § 39.2 — Jurisdiction: applies to all users, owners, and operators of the Bulk-Power System in the contiguous United States (ERCOT, Texas is partially excluded from FERC jurisdiction), Canada (under NERC's international scope), and Mexico's northern interconnection; "Bulk-Power System" means high-voltage (100 kV and above) transmission facilities and generation resources connected to the grid; the mandatory reliability program does not extend to distribution systems — utilities and cooperatives are responsible for their own distribution reliability under state law
  • § 39.3 — ERO Certification: FERC certifies one organization as the ERO after finding it has the ability to develop and enforce reliability standards, has governing documents establishing independent board governance, appropriate rules for membership, dues, and funding, and international jurisdiction consistent with cross-border grid operations; NERC (North American Electric Reliability Corporation) received FERC certification in 2006 as the sole ERO; NERC operates as an independent nonprofit under FERC oversight, funded by assessments on registered users
  • § 39.5 — Reliability Standards process: NERC develops reliability standards through a stakeholder process; each proposed standard must be filed with FERC for approval; FERC may approve, remand, or direct modification of any standard; FERC may also independently develop or direct NERC to develop new standards if existing standards are deficient; approved standards are mandatory and enforceable — every registered entity must comply; the current body of NERC reliability standards (organized in FAC, BAL, VAR, INT, IRO, MOD, PRC, COM, CIP, TPL, EOP, and other standard categories) covers operations, planning, and critical infrastructure protection
  • § 39.7 — Enforcement: NERC and its Regional Entities (eight regional entities including NPCC, SERC, MRO, WECC, and others, covering different geographic footprints) have mandatory audit programs covering all registered entities; when violations are found, NERC can assess penalties up to $1 million per violation per day; FERC retains oversight of NERC's enforcement program and approves NERC's penalty structures; self-reports and Violation Risk Factor/Severity assessments drive penalty calculations; egregious violations (particularly Critical Infrastructure Protection — CIP — standards) can result in large penalties assessed against utilities; FERC reviews NERC penalty filings and can reduce or increase penalties
  • § 39.8 — Regional Entity delegation: NERC delegates enforcement and standard development functions to Regional Entities, which conduct audits, receive self-reports, and assess penalties for violations in their respective footprints; regional entities have formal agreements with NERC specifying their delegated authority; the delegation structure ensures local expertise in enforcement while maintaining national consistency through NERC oversight of RE decisions
  • § 39.11 — Reliability reports: NERC must conduct and file with FERC annual assessments of Bulk-Power System reliability, including long-term reliability adequacy studies; these reports identify regions at risk of generation or transmission inadequacy; NERC's annual Long-Term Reliability Assessment and the Electricity Market Monitor assessments are the primary tools for identifying grid stress before problems become acute; the assessments have flagged growing reliability risks in regions with rapid thermal generation retirement and slower interconnection of renewable resources

  The NERC ERO framework created the first mandatory, enforceable electric reliability standards in U.S. history. Before FPA Section 215 (enacted in the Energy Policy Act of 2005, following the August 2003 Northeast blackout that blacked out 55 million people), reliability standards were purely voluntary. The 2003 blackout — triggered partly by tree contact in Ohio that cascaded due to inadequate situational awareness and operating procedures — demonstrated that voluntary standards were insufficient. NERC reliability standards now cover operations, planning, protection, modeling, and cybersecurity (the CIP standards protecting bulk electric system cyber assets from attack). Recent rulemakings: FERC Order 902 (October 2023) — approved CIP-003-9 and CIP-010-4 cybersecurity standards for low-impact BES cyber systems; multiple 2025-2026 standard approvals for inverter-based resources, frequency response, and vegetation management.

• 18 CFR Part 50 — Applications for Permits to Site Interstate Electric Transmission Facilities: FERC's implementing regulations for Section 216 of the Federal Power Act (16 U.S.C. § 824p) — the federal "backstop" siting authority that allows FERC to issue a permit for an interstate transmission line when a state has failed to act on a complete siting application within one year. Section 216 is one of the most consequential authorities for the clean energy transmission buildout, because new high-voltage transmission must often cross state lines and historically required separate approvals from every state:

  • § 50.2 — Purpose and scope: FERC's Section 216 permit authority activates in two scenarios: (1) when a state has denied a permit application for a transmission facility that DOE has designated as being in a "National Interest Electric Transmission Corridor" (NIETC); or (2) when a state has not acted on a complete application within one year and the facilities are in a NIETC; the backstop authority was significantly strengthened by the Bipartisan Infrastructure Law (IIJA, 2021), which expanded FERC's authority to act in corridors and directed DOE to designate additional NIETCs; as of 2025-2026, DOE has finalized several NIETC designations in the Mountain West, Southeast, and Mid-Atlantic, expanding the zones where FERC backstop permits are available
  • § 50.4 — Stakeholder participation plan: before filing a permit application, the applicant must prepare and implement a Project Participation Plan ensuring affected landowners, tribes, local governments, state agencies, and the public have access to information about the project and opportunity to participate; FERC emphasizes early and robust stakeholder engagement as a requirement, not just a courtesy; the plan must identify all affected communities and describe how the applicant will engage them throughout the process
  • § 50.5 — Pre-filing procedures: applicants must complete pre-filing consultation with FERC staff, affected state agencies, tribes, and landowners before submitting a formal application; the pre-filing process typically takes 6-12 months; it culminates in a pre-filing Environmental Review document; the mandatory pre-filing process reflects FERC's lesson from natural gas pipeline siting — early stakeholder engagement and environmental analysis reduces post-filing opposition and delays
  • § 50.12 — Code of conduct for landowner engagement: any applicant that receives a FERC permit and then seeks to acquire rights-of-way through eminent domain (if applicable) must comply with FERC's landowner code of conduct, including providing affected landowners with the full permit and application documents, contacting them in good faith, not making misrepresentations, and informing them of their legal rights; the code of conduct addresses concerns that applicants with federal eminent domain authority may intimidate or mislead landowners about their legal options
  • § 50.11 — Conditions on permits: FERC Section 216 permits will include conditions protecting environmental values, landowner rights, and regional grid reliability; conditions typically address routing alternatives, environmental mitigation, construction practices, and ongoing operational requirements

  Section 216 backstop siting is among the most contested areas of federal energy law. State utility commissions and state governors have resisted federal override of their siting authority; the Fourth Circuit struck down FERC's initial Part 50 regulations in 2009 (Piedmont Environmental Council v. FERC), holding that FERC had exceeded the statute. The IIJA's 2021 expansion addressed the statutory gap the court identified. As of 2026, FERC has approved very few permits under Part 50 — the program is still more important as a potential backstop than as an operational permitting pathway. The threat of FERC backstop authority may incentivize states to approve transmission projects rather than face federal override. Recent rulemakings: 88 FR 75854 (November 2023) — FERC revised Part 50 to implement the IIJA's expanded Section 216 authority; 89 FR 25753 (April 2024) — DOE's final rule on NIETC designation procedures.

• 10 CFR Part 900 — DOE Coordination of Federal Authorizations for Electric Transmission Facilities: the Department of Energy's implementing regulation for Section 216(h) of the Federal Power Act (16 U.S.C. § 824p(h)), which directs DOE to coordinate all federal authorizations required for interstate electric transmission facilities — creating a "one-stop shop" process to reduce permitting delays for new transmission lines. While 18 CFR Part 50 governs FERC's backstop siting authority, Part 900 governs DOE's role as the coordinator for the broader federal permitting landscape that every major transmission project must navigate. Key provisions:

  • § 900.1 — Purpose and scope: DOE establishes the Coordinated Interagency Transmission Authorizations and Permits (CITAP) process, which is a coordinated permitting process for electric transmission facilities requiring authorizations or permits from two or more federal agencies (BLM, Forest Service, Army Corps of Engineers, EPA, U.S. Fish and Wildlife Service, etc.); CITAP is available to transmission project developers who voluntarily opt in and is mandatory for projects in National Interest Electric Transmission Corridors (NIETCs) seeking FERC backstop permits under Section 216
  • § 900.2 — Definitions: the "Integrated Interagency Pre-Application (IIP) Process" is the early-stage coordination phase where DOE convenes relevant federal agencies with the project proponent before formal permit applications are filed; the IIP Process is designed to identify permitting requirements, data needs, and potential conflicts early enough for project design changes to avoid delays — the classic problem that transmission projects run into after filing is that one agency's requirements are incompatible with another's, requiring costly and time-consuming plan revisions
  • § 900.4 — IIP Process initiation: a project proponent submits a request to DOE to begin the IIP Process; DOE then notifies all relevant federal entities — agencies with permitting, environmental review, or consultation responsibilities for the proposed project — and schedules an initial meeting with the proponent; the initial meeting establishes the "analysis area" (geographic scope of environmental studies), identifies the relevant federal authorizations required, and sets a schedule for the pre-application coordination phase
  • § 900.10 — Consolidated administrative docket: DOE maintains a single public docket containing all information exchanged during the CITAP process — agency comments, proponent submissions, environmental study data, meeting summaries; this consolidated record is available to all participating agencies, the project proponent, and the public; the consolidated docket requirement reflects the core CITAP premise that all agencies should be working from the same information base simultaneously rather than sequentially
  • § 900.11 — NEPA lead agency: DOE designates the NEPA lead agency for the required environmental review (typically an EIS for a major transmission line) after the IIP Process; the lead agency is generally the agency with the largest "footprint" in the project's permitting — for projects crossing federal land managed by BLM, BLM often serves as lead; for projects primarily over private land, DOE may serve as lead; the lead agency designation consolidates the NEPA process and prevents multiple agencies from conducting duplicative environmental analyses
  • § 900.12 — Coordinated environmental review: once the IIP Process closes, all participating agencies must coordinate their required environmental analyses and permit reviews to run concurrently rather than sequentially; the rule establishes milestones and requires agencies to commit to a permitting schedule; for projects in NIETCs where FERC backstop authority may be invoked, the DOE CITAP timeline is linked to the FERC Part 50 application clock — FERC may not issue a backstop permit unless DOE's coordination process has been completed

  Part 900 represents the "coordination before application" philosophy that distinguishes modern federal transmission permitting from the prior project-by-project, agency-by-agency approach. A major 1,000-mile transmission line in the western U.S. might require right-of-way grants from BLM, special use permits from the Forest Service, nationwide permits from the Army Corps, biological opinions from U.S. Fish and Wildlife, and Section 106 consultation with the Advisory Council on Historic Preservation — plus the FERC permit for the interstate portions and multiple state public utility commission approvals. Without coordination, each agency issues its requirements independently, and incompatible conditions can require design changes that restart the clock at other agencies. CITAP compresses this to a single coordinated process. The program was adopted in October 2016 and aligns with DOE's NIETC designation authority, creating a linked regulatory pathway from corridor designation through coordinated permitting to FERC backstop authority. Voluntary CITAP use has been limited; the program's value is greatest for complex multi-state projects in NIETCs.

• 18 CFR Part 33 — Applications Under Federal Power Act Section 203: FERC's procedures for reviewing public utility mergers, asset sales, and other dispositions that require Commission approval under Section 203 of the Federal Power Act:

  • § 33.1 — Applicability: any public utility that seeks to sell, lease, or otherwise dispose of jurisdictional facilities; to merge or consolidate its facilities with those of another; to purchase or acquire the securities of any public utility; or to acquire any other electric utility facility above the blanket authorization threshold must file an application with FERC; Section 203 applies to transactions involving FERC-jurisdictional facilities (wholesale power sales, interstate transmission) — it is distinct from Hart-Scott-Rodino antitrust review (DOJ/FTC) but complements it
  • § 33.3 — Horizontal competitive analysis: applicants must submit a horizontal Competitive Analysis Screen if the transaction creates horizontal market power concerns — where both parties compete in the same geographic market for electricity; the screen compares the merged entity's generation capacity in each relevant market against the total market capacity; if the combined market share exceeds the screen threshold, the applicant must either provide competitive mitigation measures (such as virtual divestitures or market power mitigation) or conduct a more detailed market simulation analysis
  • § 33.4 — Vertical competitive analysis: applicants must analyze vertical market power concerns — where the transaction combines a company with control over transmission access or natural gas transportation with a generator that needs that access; vertical market power occurs when the merged entity could disadvantage competitors by discriminating in access to transmission or fuel supply; FERC examines whether the merged entity has the incentive and ability to foreclose competition
  • § 33.11 — Processing timeline: FERC will act on a complete Section 203 application within 180 days of the filing date; for straightforward transactions (no competitive concerns, no rate impacts), FERC often issues approval much faster through delegated letter orders; transactions with significant market power concerns may receive a deficiency letter requesting additional information, pausing the 180-day clock; FERC may approve subject to conditions (behavioral or structural remedies) rather than outright approval or rejection
  • § 33.12 — Notification for smaller transactions: utility mergers below the threshold for full Section 203 review (certain transactions below $10 million in assets) must still file a notification with FERC, even if they don't require full application review; this notification system gives FERC visibility into the overall pattern of utility consolidation even when individual transactions are too small to require full review

  Part 33 is the procedural framework for the ongoing consolidation of the electric utility industry. The wave of utility mergers since the 1990s — driven by deregulation, scale efficiencies, and the transition to renewable energy — has consistently required FERC Section 203 review. FERC has approved most utility mergers with conditions addressing market power concerns (typically requiring the merged entity to offer transmission access on non-discriminatory terms and to refrain from using market power to raise wholesale prices). The growing importance of renewable energy development has shifted Section 203 analysis toward examining how mergers affect access to transmission for independent renewable generators. Recent rulemakings: 84 FR 6075 (February 2019) — FERC revised Section 203 merger review procedures to incorporate updated competitive analysis methods.

• 18 CFR Part 358 — Standards of Conduct for Transmission Providers: the behavioral firewall rules that prevent electric transmission providers and interstate natural gas pipelines from using control over transmission infrastructure to favor their affiliated wholesale marketing businesses. Part 358 is FERC's primary tool for enforcing the non-discrimination principle at the center of electricity and gas market restructuring:

  • § 358.1 — Applicability: Part 358 applies to any interstate natural gas pipeline that transports gas for others and conducts transmission transactions with a marketing affiliate, and to any public utility owning or controlling facilities used for interstate electric transmission; ISO/RTO-approved transmission providers are exempt because the independent grid operator structure provides equivalent separation
  • § 358.2 — General principles: three overarching rules — (1) the non-discrimination requirement: transmission providers must treat affiliated and non-affiliated customers on a not-unduly-discriminatory basis in all aspects of transmission service; (2) the independent functioning rule: transmission function employees must operate independently of marketing function employees; (3) the no-conduit rule: no person may serve as a channel for disclosing non-public transmission information to marketing function employees
  • § 358.4 — Non-discrimination requirements: transmission providers must strictly enforce tariff provisions without discretion; where tariff provisions permit discretion, must apply them fairly; may not give undue preference in price, curtailments, scheduling, priority, ancillary services, or balancing; must process all similar requests in the same manner and timeframe
  • § 358.5 — Independent functioning rule: transmission function employees may not conduct marketing functions; marketing function employees may not conduct transmission functions or have different access to system control centers than other customers; the wall between operations and trading is physical, not just policy
  • § 358.6 — No conduit rule: neither the transmission provider nor any affiliate employee may disclose non-public transmission function information (available capacity, planned outages, queued interconnection requests) to marketing function employees through any channel
  • § 358.7 — Transparency rule: if a disclosure prohibited by § 358.6 occurs, the transmission provider must immediately post the disclosed information on its website — making accidental or deliberate leaks self-correcting by requiring public disclosure; exceptions apply to customer-specific request details that the requesting customer itself may not want public
  • § 358.8 — Implementation requirements: annual training for all transmission function employees, marketing function employees, officers, and directors; new employees must receive training within 30 days; each employee must acknowledge receipt and understanding in writing; FERC compliance personnel must be designated

  Part 358 was substantially revised by FERC Order 717 (73 FR 63829, October 2008) and Order 717-A (74 FR 54482, October 2009), which updated the definitions of "marketing functions" and "transmission functions" to track market evolution and clarified the independent-functioning rule's application to modern wholesale markets. The rule operates in tandem with FERC's Open Access Transmission Tariff (OATT, 18 CFR Part 35) — the OATT sets the tariff terms that must be non-discriminatorily applied; Part 358 ensures the employees who administer the OATT aren't sharing queue and capacity information with affiliated traders. Violations are enforced through FERC complaint proceedings; remedies include disgorgement of profits and civil penalties under Part 385. No major rulemakings since 2009.

• 18 CFR Part 342 — Oil Pipeline Rates: Rate Methodologies and Procedures: the framework governing how interstate oil pipelines subject to the Interstate Commerce Act set, change, and justify the tariff rates they charge shippers. FERC regulates these rates under 49 U.S.C. § 60502 and 42 U.S.C. § 7172(b). The Trans-Alaska Pipeline System (TAPS) is excluded — it operates under a separate statutory regime (§ 342.0):

  • § 342.1 — Rate change mechanisms: pipelines may change rates only through one of two mechanisms — (1) the indexing methodology (§ 342.3) used by most pipelines, or (2) the cost-of-service methodology (§ 342.4) available when there is a substantial divergence between actual costs and the index ceiling; pipelines may not freely set rates at whatever level they choose — any rate change must fit within the applicable method
  • § 342.2 — Initial rates: when a pipeline first establishes a rate (for a new route or a new shipper category), the initial rate may be set based on cost and revenue data demonstrating the rate is just and reasonable, OR based on a sworn affidavit that a non-affiliated shipper has agreed to the rate as a willing buyer — the non-affiliated agreement serves as market validation that the rate isn't exploitative
  • § 342.3 — Indexing methodology (the primary mechanism): FERC annually computes a ceiling level for oil pipeline rate changes based on the Producer Price Index for Finished Goods (PPI-FG) minus 1.23 percentage points; pipelines may raise their rates up to this ceiling without a full cost-of-service filing; rates may also be reduced at any time; the index is computed each July 1 and applies for the following year; pipelines choosing not to use the full index headroom may carry unused "index ceiling" capacity forward; a pipeline that can demonstrate its costs increased faster than the index may apply to FERC for a rate above the ceiling
  • § 342.4 — Cost-of-service alternative: pipelines may instead justify rates through a traditional cost-of-service filing — documenting actual operating costs, depreciation, and a permitted rate of return on the rate base; this is the method used when a pipeline's costs have diverged substantially from the index (e.g., a major new capital investment or a significant volume decline that increases per-barrel cost); cost-of-service cases involve full FERC proceedings with discovery and evidentiary hearings

  The PPI-based indexing system was established by FERC Order 561 (1993) and represents a regulatory bargain: pipelines get predictable rate increase authority tied to general inflation without the burden of annual cost-of-service filings; shippers get assurance that rate increases won't outpace economy-wide cost growth. The index ceiling functions as a maximum — a pipeline cannot exceed it unilaterally but may always charge less. Shippers who believe a pipeline's rates are unjust and unreasonable even within the index ceiling may file a complaint with FERC, which then determines whether refunds are warranted. Recent rulemakings: 88 FR 4040 (January 2023) — FERC Order 894, revised the PPI-FG multiplier for the 2021–2026 quinquennial period.

• 10 CFR Part 590 — Administrative Procedures for Import and Export of Natural Gas (DOE/Office of Fossil Energy and Carbon Management, 48 sections across 5 subparts — the procedural framework for obtaining DOE authorization to import or export natural gas under Section 3(a) of the Natural Gas Act (15 U.S.C. § 717b); while FERC's Part 153 governs the physical LNG terminal facility, DOE's Part 590 governs the separate commodity authorization — the legal permission to export specified volumes of LNG to free-trade-agreement (FTA) or non-FTA countries):

DOE's Section 3 authorization is a distinct regulatory gate from FERC's facility certificate: FERC authorizes the construction and operation of the LNG terminal; DOE authorizes who may export natural gas and to whom. The two authorizations must both be obtained before LNG exports can begin. DOE manages its authorizations through the Office of Fossil Energy and Carbon Management (FECM), which maintains public dockets for all applications.

• Subpart A — General Provisions (§§ 590.101–590.109): Part 590 applies to any person seeking to import or export natural gas to or from the United States — including LNG, compressed natural gas, and pipeline gas; the Assistant Secretary for Fossil Energy (or delegee) has final decisional authority; § 590.103 — all documents (applications, amendments, protests) must be filed with FECM according to its current filing procedures; § 590.106 — FECM maintains a public docket for each proceeding, forming the administrative record on which all decisions are based; § 590.108 — off-the-record communications are prohibited in contested proceedings — a critical rule ensuring transparency in high-stakes export authorization decisions

• Subpart B — Applications (§§ 590.201–590.209): any person seeking a new or amended import/export authorization files under § 590.201; § 590.202 — the application must identify: the exact legal names of applicant and counterparties; the quantity to be imported or exported (expressed in Bcf/year); the source or destination country; the terms of the authorization sought (short-term vs. long-term; FTA vs. non-FTA countries); evidence of the applicant's financial and technical capability; the application of Section 3 of the NGA; and whether the application involves a new facility or existing infrastructure; § 590.207 — for FTA countries (Mexico, Canada, South Korea, Japan, Australia, and others with free-trade agreements with the U.S.), NGA Section 3(c) creates a rebuttable presumption that the export is "consistent with the public interest" — DOE must authorize FTA export applications on an expedited basis without the full public interest analysis; non-FTA country applications require DOE to evaluate whether the export is in the public interest, a more complex and lengthy process

• Subpart C — Procedures (§§ 590.301–590.315): § 590.301 — upon receipt of a complete application, FECM publishes notice in the Federal Register inviting protests and motions to intervene within 30 days; any person may protest a proposed export authorization or seek to intervene as a party; § 590.302 — FECM may hold an informal conference with the applicant and intervenors to clarify issues; § 590.307 — before issuing an opinion and order on a non-FTA application, FECM may request additional information from the applicant, including economic analyses of the impact of exports on domestic gas prices; § 590.315 — FECM may consolidate multiple related proceedings for joint consideration

• Subpart D — Opinions and Orders (§§ 590.401–590.407): § 590.401 — FECM issues a written opinion and order after reviewing the record; for FTA applications, FECM issues an authorization without full opinion unless protests raise issues requiring a response; for non-FTA applications, FECM issues a detailed opinion addressing: the public interest (including domestic natural gas prices, energy security, balance of trade, and employment), opposition arguments, and conditions on the authorization; § 590.403 — authorizations issued by FECM specify the volume, duration (typically 20-25 years for major LNG projects), source or destination countries, and conditions (such as requirements to report actual export volumes quarterly); § 590.407 — FECM may modify or rescind authorizations for good cause (breach of conditions, fraud in the application, or material changes in circumstances)

• Subpart E — Rehearing (§§ 590.501–590.505): any adversely affected person may apply to FECM for rehearing within 30 days of the issuance of an order; the rehearing application must state the grounds for rehearing and the specific portions of the order the applicant believes are in error; if FECM does not act on a rehearing application within 30 days, it is deemed denied; after exhausting FECM review, parties may seek judicial review in federal district court

The DOE authorization landscape evolved dramatically with the U.S. LNG export boom beginning in 2015 (Sabine Pass received the first non-FTA export authorization since the 1970s). By 2025, DOE had authorized LNG exports totaling ~59 Bcf/day to FTA countries and ~25 Bcf/day to non-FTA countries — far exceeding current physical export capacity (~14 Bcf/day as of 2025). The excess authorized volume provides a regulatory buffer for future capacity expansion without new Part 590 proceedings. The Biden administration's January 2024 pause on new non-FTA LNG export authorizations (pending a new public interest analysis including climate impacts) generated significant controversy; the Trump administration reversed the pause in January 2025, issued a public interest determination finding LNG exports serve U.S. interests, and resumed processing pending applications. Recent rulemakings: 89 FR 36508 (May 2024) — DOE proposed rule to update the public interest factors considered in non-FTA export authorizations; withdrawn January 2025.

• 18 CFR Part 34 — Application for Authorization of Issuance of Securities or Assumption of Liabilities: FERC's implementing regulation for the Federal Power Act § 204 requirement (16 U.S.C. § 824c) that public utilities (FERC-jurisdictional entities engaged in interstate wholesale power sales or transmission) obtain FERC authorization before issuing long-term securities or assuming long-term liabilities. The requirement reflects Congress's 1935 concern that utility holding company structures and overleveraged capital stacks had contributed to the Depression-era financial collapse of the electric utility industry. Authority: FPA § 204 (16 U.S.C. § 791a) and DOE Organization Act (42 U.S.C. § 7101):

  • § 34.1 — Applicability and exemptions: Part 34 applies to public utilities as defined by FPA § 201 — entities engaged in interstate wholesale power sales or transmission; natural gas companies regulated under the Natural Gas Act have parallel requirements under Part 34 by cross-reference; exempt from prior FERC approval are: (a) issuances of securities with maturities of one year or less; (b) utilities whose securities issuances are regulated under state law if FERC determines the state regulation is sufficient (many states regulate utility capitalization); and (c) qualifying facilities (QFs under PURPA) below specified thresholds
  • § 34.2 — Placement of securities: upon receiving FERC authorization, a utility may sell authorized securities through competitive bid or negotiated placement; in a competitive bid, the utility publicly solicits bids from underwriters and selects the best offer; negotiated placement uses an investment bank retained by the utility to structure and price the offering; FERC's authorization covers the maximum amount of securities that may be issued, not the specific terms of each offering, giving utilities flexibility in timing and pricing within the authorized ceiling
  • § 34.3 — Application contents: the application must include: (a) the type, amount, and maturity of the securities to be issued; (b) the purpose of the proposed financing (capital expenditure, debt refinancing, working capital); (c) the utility's most recent financial statements; (d) description of existing securities outstanding; and (e) the board resolution authorizing the transaction; for bond issuances, the application typically includes a description of the indenture and covenants
  • § 34.4 — Required exhibits: specifically required are the utility's articles of incorporation (corporate purpose), board resolutions authorizing the securities issuance, and a map showing the utility's principal facilities; the facilities map establishes the utility's FERC jurisdictional nexus — a utility with no interstate facilities might not require FERC authorization at all
  • § 34.5 — Additional information: FERC retains discretion to require additional information, including detailed financial projections, rate case information, or environmental analysis if the financing relates to a major capital project such as a new transmission line or generation facility

  In practice, FERC processes the large majority of Part 34 applications through a blanket authorization mechanism — under Order 523 (1995), utilities that meet financial eligibility criteria (investment-grade credit ratings, established track records) receive blanket authorization to issue securities without case-by-case FERC approval; only utilities not meeting the blanket authorization criteria must file individual applications. This streamlining means that most major utilities' bond issuances proceed without active FERC review, while smaller or financially stressed utilities face the more burdensome application process. State public utility commissions regulate retail utility capitalization separately — a utility issuing bonds for a retail rate base investment may need both FERC authorization (for the FPA § 204 requirement) and state PUC approval (for recovery of the capital cost in retail rates). No recent major amendments to Part 34 — the blanket authorization framework established in 1995 remains current.

• 18 CFR Part 381 — Fees: FERC's schedule of filing fees for applications, petitions, and other submissions under the Federal Power Act, Natural Gas Act, and Interstate Commerce Act, implementing 31 U.S.C. § 9701 (the user-fee authority). FERC charges fees to offset the cost of processing regulatory filings; fee schedules are reviewed and adjusted annually through notice-and-comment rulemaking and published in the Federal Register before each fiscal year. Key provisions:

  • § 381.103 — Filings: the filing fee must accompany the application at submission; FERC will not process filings submitted without the required fee
  • § 381.104 — Annual adjustment: FERC reviews fee schedules annually to reflect changes in regulatory processing costs; revised schedules are published in the Federal Register
  • § 381.105 — Method of payment: fees must be paid by check, money order, or electronic funds transfer payable to the Federal Energy Regulatory Commission
  • § 381.106 — Waivers: FERC may waive fees upon a showing of financial hardship or other good cause; waiver requests must accompany the initial filing and are granted at Commission discretion
  • § 381.107 — Direct billing: high-volume filers (typically large utilities with multiple annual submissions) may be direct-billed rather than required to submit fees with each individual filing; direct billing is by agreement and simplifies accounting for routine regulatory filers
  • § 381.108 — Exemptions: the following are fee-exempt: filings by federal agencies; filings by states or local governments; interventions, protests, and comments on pending proceedings; complaints; and routine informational filings not requiring Commission action
  • § 381.109 — Refunds: fees for filings rejected without processing are refundable; fees for accepted and processed filings are generally non-refundable, even if the application is later withdrawn or denied
  • § 381.110 — Substantial amendments: amendments that materially expand the scope of a pending application (e.g., adding new facilities or pipeline segments to a certificate application) trigger additional fees; minor clarifications do not
  • § 381.207 — Pipeline certificate applications: fee schedule for NGA § 7(c) applications to construct, operate, or abandon interstate natural gas pipeline facilities — the most consequential (and expensive) individual FERC regulatory proceedings for energy infrastructure
  • §§ 381.302–381.305 — General activity fees: schedules for petitions for declaratory orders (§ 381.302), review of DOE remedial orders (§ 381.303), DOE denial-of-adjustment reviews (§ 381.304), and OGC interpretive letters (§ 381.305)
  • § 381.403 — Rate approval petitions: fee for petitions for natural gas pipeline rate approval
  • § 381.501 — Qualifying facility (QF) certifications: fee for applications to certify small power producer or cogeneration status under PURPA

  FERC's filing fee program is a relatively modest revenue stream — total Part 381 collections are typically under $50 million annually — relative to FERC's approximately $400 million operating budget, most of which is recovered through annual charges assessed on all jurisdictional entities under 18 CFR Part 382 (a separate recurring assessment independent of individual filings). For major infrastructure projects — LNG terminals, long-haul pipelines, major hydroelectric licenses — the filing fee is a trivial fraction of total development costs; for smaller applicants seeking OGC interpretations or QF certifications, the fee may be a meaningful factor in the decision to file formally rather than seek informal guidance. The fee exemption for state and local government filings reflects FERC's recognition that public power entities and state regulatory commissions are functional partners in the regulatory process, not commercial applicants monetizing FERC authorizations.

• 18 CFR Part 382 — Annual Charges: FERC's recurring annual assessment on all jurisdictional entities — natural gas pipeline companies, electric public utilities, and oil pipeline companies — to recover the full cost of FERC's regulatory operations that are not covered by individual filing fees. Unlike Part 381 filing fees (transaction-specific, paid at filing), Part 382 annual charges are assessed annually on all regulated entities proportionate to their jurisdictional activities:

  • § 382.103 — Payment: annual charges must be paid within 45 days of the Commission's bill; late payment triggers interest at the Treasury rate; FERC may refuse to process any petition, application, or other filing submitted by any person that does not pay the annual charge when due — effectively barring a delinquent company from regulatory action until arrears are cleared
  • § 382.104 — Enforcement: the Commission may refuse to process any filing from a non-paying entity; for jurisdictional entities that must file for rate changes, certificate amendments, or market-based rate approvals, this is a powerful enforcement lever — a delinquent pipeline cannot get a rate increase approved while in arrears
  • § 382.105 — Waiver: any annual charge bill recipient may petition for waiver of Part 382; a petition must be filed before the payment deadline; FERC grants waivers for demonstrated financial hardship or unusual circumstances; denied waivers do not extend the 45-day payment window
  • § 382.201 — Electric annual charges: the adjusted costs of administering the FPA Parts II and III regulatory program are assessed to public utilities based on their jurisdictional sales and transmission volumes; higher-volume utilities pay proportionally larger charges reflecting their larger share of FERC's regulatory workload
  • § 382.202 — Natural gas annual charges: the adjusted costs of administering the Natural Gas Act regulatory program are assessed to interstate natural gas pipeline companies; charges are allocated based on pipeline throughput volumes reported in FERC's financial reporting system (Part 141 annual reports)

  Annual charges under Part 382 fund FERC as a fee-funded agency: Congress appropriates FERC's budget, but the appropriation is offset by the Part 382 collections — effectively making the regulated industries, not the general taxpayer, bear the cost of energy regulation. For large pipeline companies and electric utilities with extensive FERC filings, annual charges can reach several million dollars; for smaller entities, annual charges may be the most significant regulatory cost not tied to a specific proceeding. The 45-day payment requirement and the filing-suspension enforcement mechanism make Part 382 compliance a treasury operations priority for FERC-jurisdictional entities.

• 10 CFR Part 205 — Administrative Procedures and Sanctions (98 sections — DOE's general regulatory enforcement procedures governing how DOE issues orders, notices of violation, and sanctions in its energy regulatory programs; authority: 16 U.S.C. § 792 (Federal Power Act) and 42 U.S.C. § 7101 (DOE Organization Act); a legacy framework from DOE's integrated energy regulatory role that now applies primarily to DOE's non-FERC energy orders, petroleum allocation proceedings, and natural gas export enforcement):

  • § 205.1 — Purpose and scope: establishes the procedural rules for DOE's energy regulatory proceedings — the processes by which DOE issues interpretations, grants exceptions, conducts hearings, and imposes sanctions for violations of energy regulations; applies to proceedings under DOE's energy authorities distinct from FERC (which has its own procedural rules under 18 CFR Part 385)
  • § 205.10 — Effective date of orders: DOE orders take effect as specified in the order, or if no date is specified, upon issuance; emergency orders under the Emergency Petroleum Allocation Act may take effect immediately; the effective date provision gives DOE authority to issue orders requiring immediate compliance when energy emergencies arise
  • Subpart F — Interpretations (§§ 205.80–205.86): any person subject to or directly affected by a DOE rule or order may request a formal written interpretation clarifying how the rule applies to their situation; interpretations are advisory, not binding on other parties, but carry substantial weight in enforcement proceedings; DOE may publish interpretations in the Federal Register when they address issues of broad applicability; the interpretation mechanism serves the same function as IRS rulings in the tax context — providing regulatory certainty to parties structuring transactions
  • Subpart K — Rulings (§§ 205.150–205.155): DOE may issue rulings (more formal than interpretations) establishing DOE's position on specific regulatory questions; rulings may be issued on DOE's own motion or in response to petitions; a published ruling may be modified or rescinded by a subsequent published ruling (§ 205.152); there is no administrative appeal of a ruling (§ 205.154) — challenges must go to federal court
  • Subpart O — Notice of Probable Violation and Remedial Orders: DOE's primary enforcement tool is the Notice of Probable Violation (NOPV) — a formal notice that DOE believes a person has violated an applicable energy statute, rule, or order; the NOPV provides the basis for a proposed remedial order or civil monetary penalty; recipients have the right to a conference and to submit written responses before a final order issues; Subpart O establishes the due process framework ensuring regulated parties have notice and an opportunity to be heard before sanctions are imposed
  • Subpart U — Electricity Export Procedures: special procedural rules for DOE's review of applications to export electricity to foreign countries under Section 202(e) of the Federal Power Act; DOE (rather than FERC) has authority over electricity exports to foreign nations; export authorization proceedings under Subpart U involve public notice, comment periods, and DOE review of whether the export is consistent with the public interest and grid reliability

  Part 205 predates the 1977 separation of FERC from DOE — it was developed when DOE had unified jurisdiction over electricity, natural gas, and petroleum regulation. Most of DOE's energy regulatory enforcement functions for electricity and natural gas were transferred to FERC upon its establishment, leaving Part 205 applying primarily to DOE's remaining energy order authorities: petroleum allocation (from the Emergency Petroleum Allocation Act era), electricity export authorizations, and DOE programmatic orders. Last substantially revised: 1990s; the procedural framework remains operational but the scope of DOE proceedings governed by Part 205 has contracted as FERC's jurisdiction expanded.

Pending Legislation

• HR 7729 — FERC shared-savings incentive for transmission efficiency, DOE studies, state grants for performance-based rate models. Status: Introduced.
• S 3976 — Brings ERCOT under FERC jurisdiction, minimum transfer capacity, siting/labor rules, $13.5B transmission loan authority. Status: Introduced.
• HR 8033 — Data centers pay full grid upgrade costs, FERC sets/approves retail rates to them, bars cost-shifting. Status: Introduced.
• HR 6378 — Requires FERC to quantify GHG emissions and environmental justice impacts for natural gas project certificates. Status: Introduced.
• HR 7728 — Brings ERCOT under FERC oversight, cross-region transfer targets, transmission financing. Status: Introduced.
• HR 6529 — Requires FERC technical conference on AI data center electricity costs. Status: Introduced.
• S 3500 — Force FERC to publish annual status reports on pending hydropower licenses. Status: Introduced.
• S 3324 — FERC must weigh GHG emissions and environmental justice in gas project approvals, 100K metric ton threshold. Status: Introduced.

Recent Developments

• FERC's Order 1920 on regional transmission planning aims to accelerate grid buildout for the energy transition

• Interconnection queue reform (Order 2023) addresses the backlog of renewable energy projects waiting to connect to the grid

• Natural gas pipeline permitting reform remains politically contested, balancing energy infrastructure needs with environmental concerns

• Grid reliability challenges from extreme weather (Winter Storm Uri 2021, heat waves) have prompted FERC and NERC to strengthen reliability standards

• In March 2026, FERC published an extension request for its information collection on market-based rate authorization holders' records retention requirements (FERC-915) under the Paperwork Reduction Act.

• FERC's role in the energy transition — balancing reliability, affordability, and decarbonization — is one of the most consequential regulatory questions in energy policy

• In March 2026, FERC solicited public comment on revisions to multiple reliability standards information collections (FERC-725T, 725Z, 725L, 725G, 725A, and 725X) covering primary frequency response, real power balancing, and bulk electric system reliability.

• In February 2026, FERC took several significant actions: approved inverter-based resources and generators modeling reliability standards from NERC; withdrew its proposed policy statement on oil pipeline affiliate committed service; proposed categorical exclusions under NEPA for certain license terminations/revocations; confirmed removal of regulations limiting construction authorizations pending rehearing; and adopted categorical exclusions from the Tennessee Valley Authority under NEPA.

• In March 2026, President Trump signed the 'Ratepayer Protection Pledge,' an executive action directing federal agencies to advance energy affordability by reducing regulatory burdens on electricity generation and transmission that contribute to higher consumer energy costs.

• In early March 2026, the White House announced that America's leading AI and technology companies had signed the Ratepayer Protection Pledge at the White House, committing to keep electricity affordable as data center and AI energy demand surges.

• The Trump administration's "Unleash American Energy" initiative directed agencies to expedite permitting for oil, gas, and critical mineral development on federal lands, reversing prior administration restrictions; the order has implications for FERC's pipeline certification and LNG terminal approval processes.

• The Trump administration approved the Keystone XL pipeline, reversing the prior administration's cancellation of the cross-border permit and advancing the administration's "energy dominance" agenda for North American oil infrastructure.

• A February 2026 White House fact sheet announced that President Trump was "strengthening United States national defense with America's beautiful clean coal power generation fleet," framing coal plant preservation as a grid reliability and national security imperative — with implications for FERC's resource adequacy rules and generator retirement procedures.

• In February 2026, the House marked up H.R. 7258, the Energy Emergency Leadership Act, alongside four other energy-related bills, advancing legislation to strengthen federal energy emergency response coordination.