Outer Continental Shelf Lands Act & Offshore Energy

The Outer Continental Shelf Lands Act (OCSLA) — enacted in 1953 and codified at 43 U.S.C. §§ 1331–1356b — asserts federal jurisdiction over the seabed and subsoil of the OCS (the submerged lands off U.S. coasts beyond 3 miles from shore to the 200-mile Exclusive Economic Zone), and authorizes the leasing of OCS lands for oil, gas, and mineral development. The OCS produces approximately 15% of U.S. oil and 5% of U.S. natural gas, with the Gulf of Mexico dominating offshore production. The Bureau of Ocean Energy Management (BOEM) within the Department of Interior manages leasing through five-year oil and gas leasing programs — determining which OCS areas are offered for lease sale — while BSEE (Bureau of Safety and Environmental Enforcement) oversees drilling safety and environmental compliance. The Deepwater Horizon disaster (2010) — the largest marine oil spill in U.S. history, killing 11 workers and releasing 4 million barrels of oil — fundamentally reshaped OCS safety regulation, splitting the former Minerals Management Service into BOEM and BSEE and requiring dramatically more stringent blowout preventer standards and containment planning. Offshore energy has been at the center of major presidential executive order battles: Biden withdrew large OCS areas from new leasing (using withdrawal authority under 43 U.S.C. § 1341), Trump reversed those withdrawals and expanded the five-year leasing program, and Biden reinstated restrictions — with courts ruling in 2024 that presidential withdrawal authority is one-way (presidents can withdraw but cannot "un-withdraw" areas a predecessor withdrew). Offshore wind leasing — also governed by OCSLA — has grown rapidly on the Atlantic coast, with the Biden administration completing multiple lease sales before the Trump administration paused new leasing in 2025.

Current Law (2026)

Legal Authority

• 43 U.S.C. § 1331 — Definitions (outer Continental Shelf = submerged lands beyond state jurisdiction; coast line; lease; person)
• 43 U.S.C. § 1332 — Congressional declaration of policy (OCS is a vital national resource; development should be balanced with environmental protection; affected states and localities should have meaningful participation)
• 43 U.S.C. § 1334 — Administration of leasing (Secretary of Interior prescribes rules and regulations for OCS mineral leasing; safety, environmental protection, conservation of natural resources)
• 43 U.S.C. § 1337 — Leases, easements, and rights-of-way (competitive bidding for leases; royalty rates; lease terms; rights-of-way for pipelines; renewable energy leases on the OCS)
• 43 U.S.C. § 1338 — Disposition of revenues (royalties, rents, and bonuses deposited in the Treasury; revenue sharing with coastal states under certain programs)
• 43 U.S.C. § 1344 — Five-Year Leasing Program (Secretary must prepare and maintain a 5-year program of lease sales; size, timing, and location of sales; environmental and economic considerations; Congressional and public review)
• 43 U.S.C. § 1346 — Environmental studies (Secretary must conduct studies of environmental effects of OCS activities; baseline environmental data; monitoring)
• 43 U.S.C. § 1347 — Safety and health regulations (Secretary prescribes safety regulations; inspections of all OCS facilities; blowout prevention equipment; safety training)
• 43 U.S.C. § 1349 — Citizens suits (any person may bring suit to compel compliance with OCSLA; judicial review of lease sales and regulations)
• 43 U.S.C. § 1351 — Oil and gas development and production (development and production plans required after exploration; environmental review; consistency with coastal zone management plans)

How It Works

The Outer Continental Shelf Lands Act governs the extraction of oil, natural gas, and other minerals from the vast submerged lands of the U.S. continental shelf — an area roughly equivalent to the entire land mass of the contiguous 48 states. It is one of the most consequential energy and environmental statutes in federal law.

The Outer Continental Shelf consists of all submerged lands beyond state jurisdiction — generally 3 nautical miles from shore (9 miles for Texas and western Florida) — out to the edge of the continental margin or 200 nautical miles, whichever is greater. These federal lands contain massive reserves of oil and natural gas, with the Gulf of Mexico accounting for the vast majority of current production. Limited activity occurs off Alaska, and virtually none off the Atlantic or Pacific coasts due to decades of congressional moratoria and political opposition. OCS energy development follows a multi-stage process: the Secretary of the Interior develops a Five-Year Leasing Program identifying which areas will be offered for lease sales, involving extensive NEPA environmental review, state consultation, and public comment. The five-year program is one of the most politically contested energy policy decisions — it determines whether vast ocean areas open or close to drilling for years. Once a lease sale is scheduled, companies submit sealed competitive bids; winning bidders receive exploration rights but must still submit detailed development plans, complete environmental review, and obtain permits before any drilling begins. Companies pay bonuses (upfront payments when winning a lease), annual rents during exploration, and royalties on production — 18.75% for new deepwater leases, raised from the historical 12.5% by the Inflation Reduction Act of 2022, which also linked new offshore oil and gas lease sales to offshore wind development.

After the Deepwater Horizon disaster (2010) — the largest marine oil spill in U.S. history — the former Minerals Management Service was split into three agencies (BOEM, BSEE, and ONRR) to separate leasing, safety enforcement, and revenue collection functions and prevent the conflicts of interest that contributed to the disaster. BSEE now conducts inspections of all OCS facilities, requires blowout prevention equipment, and enforces well design and drilling safety standards; environmental studies under § 1346 require baseline data collection and impact monitoring throughout the lifecycle of development. OCSLA also authorizes leasing for renewable energy development, including offshore wind: BOEM has conducted Atlantic lease sales and several large-scale projects are in development, though the industry faces financing, supply chain, and permitting challenges.

How It Affects You

State Variations

OCS lands are exclusively federal, but states play important roles:

Implementing Regulations

• 30 CFR Part 250 — BSEE Oil and Gas and Sulphur Operations in the Outer Continental Shelf: the primary regulation binding offshore operators. Key subparts:

  • Subpart A (General) — Applicability, operator responsibilities, BSEE inspection authority (scheduled and unscheduled inspections without advance notice), service fees, and the requirement to protect health, safety, property, and the environment; operators may seek written approval for alternate procedures or departures from specific requirements
  • Subpart B (Plans and Information) — Operators must submit an Exploration Plan (EP) before exploratory drilling and a Development and Production Plan (DPP) before development; plans require environmental, geological, and engineering information; BSEE coordinates with BOEM on plan review
  • Subpart D (Drilling Operations) — Application for Permit to Drill (APD) required before any well; must submit casing and cementing programs, drilling prognosis, location plat, and well design criteria; blowout preventer (BOP) requirements; casing, cementing, and pressure integrity testing standards; post-Deepwater Horizon well control provisions significantly strengthened
  • Subpart E (Well-Completion Operations) — After drilling reaches the target formation, completion operations (perforating, stimulation, installing production tubing and wellheads) require a separate APM (Application for Permit to Modify); BOP must remain in place and tested before completion; subsurface safety valve requirements for all producing wells
  • Subpart F (Well-Workover Operations) — Re-entry into existing wells for remediation, repair, or intervention; workover rigs and BOP equipment requirements; coiled tubing and wireline operations standards; pressure testing before re-entering a zone
  • Subpart G (Well Operations and Equipment) — Well completion, workover, and abandonment requirements; tubing and packers; wellhead and surface safety system equipment standards
  • Subpart H (Production Safety Systems) (65 sections — largest) — Safety device testing frequencies and records; high-low pressure sensors, safety valves, and emergency shutdown systems; process piping pressure ratings; test schedules (surface safety valves tested monthly; subsurface safety valves tested semi-annually); production platform equipment installation standards
  • Subpart I (Platforms and Structures) — Offshore platform and structure design standards; structural integrity inspections; in-place inspection of jacket legs, conductors, and bracing; underwater inspection by ROV or diver at specified intervals; corrosion protection (cathodic protection systems); load data recordkeeping for life extension evaluations
  • Subpart J (Pipelines and Pipeline Rights-of-Way) — Design standards for OCS pipelines: internal design pressure, pipe wall thickness, and material specifications; installation, testing, and repair requirements; route surveys; leak detection systems; inspection schedules (pipeline routes inspected at BSEE-prescribed intervals for hazards such as free spans, scour, and encroachment); right-of-way grants (annual rental $15/mile); pipeline right-of-way holders must remove pipelines within one year of use cessation unless granted an extension
  • Subpart K (Oil and Gas Production Requirements) — Produced water discharge limits; hydrocarbon accounting and measurement standards; continuous monitoring of production separator performance; production testing requirements; flaring and venting restrictions
  • Subpart N (Civil Penalties) (30 sections) — BSEE may assess civil penalties for violations of OCSLA, BSEE regulations, or lease/permit conditions: first-instance violations up to $40,000/day; knowing and willful violations up to $100,000/day; each day of a continuing violation counts separately; recipients may request a hearing before an ALJ; penalties are separate from and in addition to any shut-in orders or lease termination
  • Subpart O (Well Control and Production Safety Training) — All personnel performing well control activities must complete a BSEE-approved well control training course and maintain currency; training records must be kept for review by BSEE inspectors; applies to rig crews, company-man representatives, and drilling contractors — a key reform after Deepwater Horizon
  • Subpart Q (Decommissioning) — All wells must be properly plugged and abandoned; platforms and pipelines must be removed within specified timeframes after production ceases; operators must maintain financial assurance (bonds) to cover decommissioning costs
  • Subpart S (Safety and Environmental Management Systems — SEMS) — All operators must develop, implement, and maintain a documented SEMS program; SEMS must include hazard analysis, management of change procedures, operating procedures, contractor safety management, training, mechanical integrity programs, emergency response, and incident investigation; audited by accredited third-party auditing companies (ATAPS)

• 30 CFR Part 550 — BOEM Oil and Gas and Sulfur Operations in the Outer Continental Shelf (162 sections — the planning and information submission rules that sit upstream of BSEE's operational regulations in Part 250). While Part 250 governs what operators do on the OCS, Part 550 governs what they must submit and get approved before they can do it:

  • Subpart A — General (42 sections): BOEM authority and applicability (§ 550.101); scope (§ 550.102 — all oil, gas, and sulfur exploration, development, and production on the OCS); BOEM may issue Notices to Lessees and Operators (NTLs) providing additional guidance; appeals of BOEM decisions go to 30 CFR Part 590
  • Subpart B — Plans and Information (73 sections — largest): § 550.201 — no OCS activities may begin until BOEM has approved the required plan; the type of plan depends on the activity: an Exploration Plan (EP) is required before exploratory drilling; a Development and Production Plan (DPP) or Development Operations Coordination Document (DOCD) is required before development; § 550.202 — every EP, DPP, or DOCD must demonstrate that the operator has planned and is prepared to conduct proposed activities in compliance with the OCS Lands Act (OCSLA), will not cause undue harm, will not unduly interfere with other uses of the OCS, will protect corals and other OCS resources, and will use best available and safest technology; § 550.203 — BOEM reviews proposed well location and spacing; § 550.204 — Arctic OCS special requirement: an Integrated Operations Plan (IOP) must be submitted at least 90 days before the EP for any exploratory drilling on the Arctic OCS; § 550.206 — submission format: four proprietary copies plus eight public-distribution copies (with proprietary information redacted); § 550.207–210 — ancillary activities (geological and geophysical surveys, data collection) require 30-day advance notice to BOEM and may be conducted before or during plan review
  • Subpart C — Pollution Prevention and Control (3 sections): baseline environmental requirements applicable to all OCS activities under Part 550, covering discharge restrictions and spill prevention
  • Subpart N — OCS Civil Penalties (36 sections): BOEM (as distinct from BSEE) may assess civil penalties for violations of OCSLA, lease terms, and BOEM regulations; penalty structure parallels BSEE's: up to $40,000/day for standard violations, higher amounts for knowing and willful violations; each day of a continuing violation is a separate violation; ALJ hearing available
  • § 550.1011 — Financial assurance for pipeline ROW holders: operators holding pipeline right-of-way grants must furnish and maintain a $300,000 financial assurance bond for each ROW grant at the time of application, assignment, or renewal; this ensures funds are available for pipeline removal if the holder defaults or abandons the ROW

• 30 CFR Part 203 — BSEE Relief or Reduction in Royalty Rates (62 sections — the regulatory framework for obtaining royalty reductions or suspensions on OCS oil and gas leases; royalty relief is a key production incentive for economically marginal or technically challenging projects, and Part 203 defines exactly who qualifies and under what price conditions):

  • § 203.1 — Authority: royalty relief authority flows from § 1337 of OCSLA as amended by the OCS Deep Water Royalty Relief Act (DWRRA, P.L. 104-58) and the Energy Policy Act of 2005; BSEE may grant relief in four situations: (1) existing leases that cannot sustain production at current royalty rates, (2) deep water leases to encourage development, (3) pre-Act leases in designated fields, and (4) new leases in certain water depths under the five-year leasing program
  • § 203.2 — Types of relief: Royalty Suspension Volume (RSV) — a specified volume (in MCF gas or barrels of oil) exempt from royalty, after which normal royalty rates apply; Royalty Suspension Supplement (RSS) — additional suspension volume earned by drilling an unsuccessful well in a qualifying area; End-of-Economic Life (EOEL) relief — for leases approaching abandonment where production revenue cannot cover operating costs at current royalty rates; End-of-Economic Life Situations — case-by-case relief requiring BSEE approval on a showing that continued royalty payments would cause abandonment of the lease
  • § 203.3 — Application fees: applicants must pay fees to reimburse BSEE's processing costs; fees are charged for formal applications and preview assessments; federal policy requires cost recovery for services that primarily benefit the applicant
  • §§ 203.30–203.36 — Ultra-deep well royalty relief (Phase 2/3 wells below 18,000 feet TVD): leases in the Gulf of America (GOA) in ≥200m water depth may earn an RSV for drilling ultra-deep wells; the RSV is specified in BSEE tables based on water depth and production type; the operator must notify the BSEE Regional Supervisor before drilling begins; § 203.36 — price threshold: relief is suspended for any calendar year in which the average daily closing NYMEX price exceeds the threshold specified in the regulations — meaning relief is only available when prices are low enough that the economics justify subsidy; at high prices, the operator pays full royalties automatically
  • §§ 203.40–203.47 — Deep well royalty relief (Phase 1 wells at 15,000–18,000 feet TVD): similar RSV structure for deep wells; RSS is available for drilling certified unsuccessful wells (dry holes) in qualifying areas — a bonus incentive for taking exploration risk; price thresholds also apply

  OCS royalty relief under Part 203 is fundamentally about economics: the standard 18.75% royalty rate (raised by the Inflation Reduction Act in 2022) makes some marginal projects — end-of-life platforms, technically difficult ultra-deep reservoirs — uneconomic to develop. BSEE's relief authority allows the government to recover at least some royalty from production that would otherwise cease rather than nothing from premature abandonment. The price-threshold mechanism (§ 203.36) is a smart structural feature: when oil and gas prices are high, the operator keeps the benefit; when prices are low, BSEE provides the subsidy. This prevents windfall royalty relief when commodity markets are robust. The DWRRA royalty relief provided to new deepwater leases in the 1990s — before the price-threshold mechanism was in place — became controversial when oil prices rose significantly and companies continued claiming large royalty exemptions that Congress had not intended at high prices.

  The BOEM/BSEE regulatory split (established in 2011 after the Deepwater Horizon disaster separated the former Minerals Management Service) means an OCS operator typically interacts with both agencies: BOEM handles the planning side (Part 550 plans, leasing, environmental reviews, financial assurance) while BSEE handles the operational side (Part 250 permits, inspections, safety equipment, enforcement). 80 FR 57096 (2015) and 81 FR 18152 (2016) are among the most recent major Part 550 amendments, updating Arctic IOP requirements and financial assurance provisions in the post-Macondo reform era.

• 30 CFR Part 551 — Geological and Geophysical (G&G) Explorations of the Outer Continental Shelf (BOEM, 15 sections): the pre-leasing exploration permit framework governing geological and geophysical surveys on unleased OCS lands or on lands under lease to a third party. Part 551 sits before the Part 556 lease sale process and Part 550 plan submissions — it governs the earliest stage of OCS exploration, when companies want to acquire seismic data, take core samples, or drill shallow stratigraphic test wells on areas they don't yet hold a lease for, in order to assess prospectivity before deciding whether to bid at a lease sale:

  • § 551.4 — Types of G&G activities requiring permits or notices: BOEM distinguishes between activities that require a full permit (those with potential to physically disturb the seafloor or subsurface — deep stratigraphic test drilling, shallow test drilling, and any coring that penetrates below the surface) and those that require only a notice (non-invasive remote sensing, seismic reflection surveys using air guns or other energy sources, and acoustic profiling that doesn't involve drilling or physical penetration beyond minimal penetration); the permit vs. notice distinction determines the level of BOEM scrutiny and environmental review required before the activity begins
  • § 551.5 — Permit applications: applicants must submit the BOEM permit application form (Form BOEM-0327) with four copies; the application must include: a detailed description of the proposed activity and equipment; maps showing the geographic area; an environmental impact assessment; a description of methods to minimize impacts to OCS resources, archaeological sites, and other seabed users; BOEM may require environmental studies as a condition of permit issuance for activities in sensitive areas (coral habitats, whale migration corridors, areas used by commercial fisheries); the permit review process takes 30–90 days for standard applications
  • § 551.6 — Obligations under a permit: permit holders must not interfere with other legitimate uses of the OCS (commercial fishing, navigation, existing lease operations); must use safe and environmentally responsible methods; must comply with all conditions specified in the permit; must report unexpected discoveries (archaeological artifacts, unusual geology, unusual biological observations) to BOEM; permit conditions typically include vessel-strike avoidance protocols for marine mammals (required speed reductions, observer presence, soft-start procedures for air guns)
  • § 551.7 — Test drilling activities: shallow test drilling under a Part 551 permit requires additional pre-activity submittals — the Regional Director may require the permittee to gather and submit geotechnical data, site-specific hazard information, and environmental information before drilling begins; deep stratigraphic test wells (which penetrate significant depths into the subsurface) are subject to the most stringent permitting conditions and may require environmental impact analyses
  • §§ 551.11–551.14 — Data submission and confidentiality: all geological data and information collected under a permit must be submitted to BOEM; raw data is kept confidential for 5 years from the date of collection (proprietary period), after which BOEM may make it available to the public; processed interpretive data may be kept proprietary for 10 years; BOEM may use confidential G&G data in its own environmental and resource assessments without disclosing it; this confidentiality framework incentivizes industry investment in pre-leasing exploration by ensuring competitors cannot access proprietary seismic data during the period when the collecting company is evaluating whether to bid at a lease sale

  The G&G permit program is the intelligence-gathering infrastructure for OCS leasing. Companies invest hundreds of millions of dollars in seismic surveys of prospective OCS areas — 3D seismic imaging, ocean-bottom cable surveys, and multi-beam bathymetric mapping — before deciding whether the underlying geology justifies submitting a high bid at a lease auction. BOEM benefits from this private investment: the agency reviews submitted G&G data in developing resource assessments for the Five-Year Leasing Program and in setting unpublished Fair Market Value estimates for individual tracts. The requirement to submit all data also means that BOEM's geological database improves continuously as industry surveys areas ahead of leasing. Controversially, the seismic airgun surveys authorized under Part 551 have been opposed by fishing and environmental groups in the Atlantic, where the Obama administration denied permits and the Trump administration issued them — with courts ultimately ruling that BOEM's authority to permit seismic surveys is clear under OCSLA.

• 30 CFR Part 556 — Leasing of Sulfur or Oil and Gas, and Financial Assurance Requirements in the Outer Continental Shelf (90 sections — BOEM's regulations governing the competitive lease sale process, lease issuance, transfers of lease interests, and the financial assurance requirements that lessees must maintain throughout the life of their OCS leases; Part 556 is the front-end complement to Part 550, which governs what happens after a lease is awarded):

  • Subpart C — Planning and Holding a Lease Sale (10 sections): BOEM's OCS lease sales follow from the five-year oil and gas leasing program; once an area is included in the program, BOEM issues a Call for Information and Nominations (Call) inviting industry input on which specific blocks to offer; BOEM then issues a Proposed Notice of Sale (PNOS) at least 30 days before the final Notice of Sale; § 556.303 — the Notice of Sale (NOS) specifies the blocks being offered, bid requirements, and lease terms; all OCS oil and gas lease sales are conducted competitively — sealed cash bonus bids are the standard mechanism; blocks are awarded to the highest qualified bidder above BOEM's unpublished Fair Market Value (FMV) estimate
  • Subpart E — Issuance of a Lease (12 sections): § 556.500 — BOEM issues a lease to the winning bidder after receipt of the first-year rental and any required financial assurance; a lease conveys the right to explore for and develop oil, gas, or sulfur within the leased blocks subject to OCSLA, lease terms, and applicable regulations; lease terms run 5 years in shallow water and 8 years in water depths ≥400 meters (deepwater leases run 8 years to reflect longer development timelines); § 556.504 — lessees must submit their bid deposit (typically 20% of the bonus bid) with their bid and remit the balance within 11 days after notification of high-bid status; § 556.506 — qualified bidders are U.S. citizens, resident aliens, or entities organized under U.S. or state law — foreign entities must form a U.S. subsidiary
  • Subpart G — Transferring Record Title Interest in a Lease (17 sections): § 556.700 — any conveyance of record title interest (ownership interest in the lease itself) requires prior BOEM approval; § 556.704 — BOEM approval requires demonstrating that the transferee is qualified to hold OCS leases (financial, technical, and legal qualification); § 556.705 — joint operating agreements (JOAs) and farmout agreements do not transfer record title and do not require BOEM approval, but must comply with Part 556 limitations on operating rights transfers; the transfer approval process can take 30–90 days, which affects M&A timelines for offshore assets
  • Subpart I — Financial Assurance (8 sections): § 556.900 — before BOEM will issue a new lease, the lessee must provide financial assurance; § 556.901 — the base financial assurance requirement is a $200,000 lease exploration bond before commencing any exploration activities; BOEM may also demand supplemental financial assurance whenever it determines a lessee cannot meet its decommissioning obligations — evaluated based on the lessee's projected decommissioning costs, net worth, and credit rating; supplemental financial assurance was significantly expanded after 2016 as BOEM became concerned that smaller, less-capitalized operators owning late-life OCS infrastructure lacked resources to fund decommissioning (estimated at tens of millions of dollars per platform); § 556.904 — rather than posting a traditional surety bond for decommissioning, operators may establish a decommissioning account at a federally insured institution with BOEM as beneficiary — funds vest with the government if the operator defaults; § 556.905 — third-party guarantees from creditworthy parent companies or affiliates may satisfy supplemental financial assurance demands; § 556.907 — BOEM may call for forfeiture of any financial assurance when an operator fails to meet its decommissioning obligations after termination of BOEM's compliance orders

  Part 556's financial assurance provisions became highly significant after the Deepwater Horizon disaster and in the years following as the Gulf of Mexico shelf production base aged. A cluster of smaller independent operators acquired late-life platforms from majors who were divesting, only to face decommissioning costs that exceeded their balance sheets. The risk of "orphan wells" — plugging and decommissioning liability falling on the government (and ultimately taxpayers) — prompted BOEM to issue the 2016 financial assurance rule (81 FR 18892) substantially strengthening supplemental FA requirements. The Trump administration suspended portions of that rule in 2017 and 2020, and the Biden administration reinstated it with revisions in 2024 (89 FR 30678). The fiscal exposure from offshore decommissioning obligations — estimated at $30 billion or more across the Gulf of Mexico — makes Part 556 financial assurance one of the most consequential regulatory issues in OCS policy. Recent rulemakings: 81 FR 18892 (March 2016) — major financial assurance rule; 87 FR 65000 (October 2022) — final rule strengthening review of operators' decommissioning financial capacity; 89 FR 30678 (April 2024) — revised risk-based financial assurance framework.

• 30 CFR Part 560 — Outer Continental Shelf Oil and Gas Leasing (BOEM, 23 sections): the auction mechanics regulation specifying which bidding systems BOEM may use when conducting OCS lease sales under § 1337 of OCSLA, and establishing the royalty suspension volumes for eligible deepwater leases under the OCS Deep Water Royalty Relief Act (DWRRA, P.L. 104-58). While Part 556 governs the pre-sale process (publishing the Notice of Sale, accepting bids, issuing the lease), Part 560 defines what type of competition occurs at the sale:

  • § 560.202 — Available bidding systems: BOEM selects one bidding system per tract for each lease sale from a menu that includes: (1) cash bonus bids with a fixed royalty rate (the standard — sealed cash bonus bids with the royalty rate specified in the Notice of Sale); (2) variable royalty rate bids (bidders compete on the royalty rate rather than cash); (3) royalty rate bids with a fixed cash bonus; (4) net profit share bids; (5) combinations of the above; in practice, BOEM has used almost exclusively the fixed-royalty/cash-bonus system for oil and gas leases, since it provides immediate certainty of the government's royalty take and maximizes upfront revenue — the other systems were authorized by statute but rarely implemented due to complexity
  • § 560.230 — Criteria for selecting bidding systems: when BOEM does consider alternative bidding systems, it must analyze: competition for the tract (whether sealed cash bidding will attract multiple qualified bidders); fiscal return to the government; oil and gas industry and public interest; and resource conservation; these criteria effectively preserve BOEM's discretion to experiment with royalty-rate or net-profit-share auctions for frontier areas where cash bonuses would discourage bidding on exploratory tracts
  • §§ 560.210–560.224 — Royalty suspension volumes for eligible deepwater leases: the DWRRA of 1995 authorized BOEM to grant royalty suspension volumes (RSVs) — specified production volumes exempt from royalty — to deepwater leases in the Gulf of Mexico to incentivize development in water depths where high capital costs made projects marginal at prevailing royalty rates; Part 560 implements this:
    • § 560.210 — an "eligible lease" is one in ≥200m water depth that was issued after November 28, 1995 (the DWRRA enactment date) and before November 2000 (after which a revised royalty suspension structure under §§ 560.220–560.224 applies)
    • §§ 560.211–560.212 — RSVs for eligible leases were specified in the Notice of OCS Lease Sale for each sale and recorded in BOEM's lease database; the RSV continues until the cumulative production from the lease reaches the specified volume — at which point full royalties apply to all subsequent production
    • §§ 560.220–560.224 — leases issued in sales held after November 2000 may receive royalty suspensions as specified in the Notice of Sale; the post-2000 suspension structure is not automatic but rather determined sale-by-sale by BOEM based on the economics of the specific offering
  • § 560.300 — Operating allowances: BOEM may specify an operating allowance in any lease when the Notice of Sale so provides; operating allowances reduce the royalty base by allowing the operator to deduct some operating costs before calculating royalties due — a targeted economic support tool for high-cost-of-production situations (e.g., leases in remote areas requiring specialized infrastructure)

  The royalty suspension volumes granted under DWRRA in 1990s Gulf of Mexico lease sales became one of the most controversial OCS royalty issues of the following decade. BOEM failed to include price thresholds — conditions that would halt the royalty exemption when oil prices rose above a certain level — in the notices of sale for approximately 1,100 deepwater leases issued in 1998–1999. When oil prices rose dramatically in the mid-2000s, lessees continued claiming royalty exemptions on billions of dollars of production that Congress had intended to be subsidized only when prices were low. The Government Accountability Office estimated the lost royalties at $10 billion. Congress ultimately reduced the royalty relief for some leases and enacted legislative fixes in the Energy Policy Act of 2005, but litigation over the omitted price thresholds continued for years. The episode drove BOEM to include explicit price-threshold mechanisms in all subsequent royalty relief programs.

• 30 CFR Part 553 — Oil Spill Financial Responsibility for Offshore Facilities (37 sections — BOEM's implementation of the Oil Pollution Act of 1990 (OPA 90) Section 1016 (33 U.S.C. § 2716), which requires any owner or operator of an offshore facility to establish and maintain evidence of financial responsibility — the ability to pay for oil spill cleanup costs up to the OPA liability cap — as a condition of operating on the OCS):

  • § 553.10 — Covered facilities: Part 553 applies to any Covered Offshore Facility (COF) on an OCS lease, permit, or right-of-use and easement (RUE) issued under OCSLA; this includes offshore platforms, pipelines, wellheads, and production systems; onshore facilities are covered by EPA's separate financial responsibility regulations under OPA 90 Section 1016
  • § 553.11 — Who must demonstrate OSFR: the designated applicant — typically the lessee, permit holder, or pipeline right-of-use holder — is the responsible party; the designated applicant may name another person with authority to act on its behalf, but ultimate liability for demonstration remains with the responsible party under OPA 90
  • § 553.13 — Required OSFR amount: the amount is the lesser of (a) the full cost of removal of a worst-case discharge or (b) the OPA 90 liability limits for offshore facilities — $150 million per incident for offshore facilities (the liability cap under 33 U.S.C. § 2704); for most deepwater operations, this requires demonstrating the full $150 million cap since worst-case discharge costs can exceed it; the required amount is calculated per facility group, not per individual well or platform
  • § 553.14 — Worst-case discharge calculation: the applicant must calculate the worst-case discharge volume (in barrels) as the largest foreseeable release, accounting for: the maximum release from a well blowout until control is restored (which drove the calculation requirement following Macondo — the Deepwater Horizon blowout released approximately 3.19 million barrels over 87 days before the well was killed); pipeline rupture volumes; and production separator or storage tank failures; the calculation must be documented and submitted to BOEM with the OSFR evidence
  • § 553.20 — Methods to demonstrate OSFR: a designated applicant may satisfy the requirement through one or a combination of: (1) self-insurance (demonstrated through net worth or unencumbered assets test); (2) an insurance certificate from a U.S.-domiciled insurer with A-rating or better; (3) an indemnity (financial guarantee from a creditworthy parent or affiliate); (4) a surety bond from a Treasury-approved surety; or (5) other methods approved by the BOEM Director
  • §§ 553.21–553.28 — Self-insurance thresholds: to self-insure, an applicant must pass either (a) a net worth test — total stockholders' equity in the most recent audited financial statements must be at least 10× the required OSFR amount — or (b) an unencumbered assets test — liquid, unencumbered assets located in the U.S. must equal at least the required OSFR amount; audited financial statements meeting SEC reporting standards are required; smaller operators and subsidiaries without sufficient balance sheets are pushed toward insurance or indemnity options
  • § 553.15 — Continuous coverage requirement: OSFR must be maintained continuously for all COFs; any gap in coverage — including an insurer downgrade below the required rating — triggers an immediate obligation to notify BOEM and replace the evidence within a specified cure period; operating without valid OSFR evidence is an OCSLA violation subject to civil penalties and potentially grounds for suspending operations

  The post-Deepwater Horizon policy environment significantly raised the practical stakes of OSFR. Before Macondo, the standard $150 million self-insurance threshold was routinely satisfied by major oil companies through net worth tests — ExxonMobil's and BP's balance sheets made compliance automatic. After 2010, Congress and BOEM faced pressure to raise the financial responsibility limits to reflect actual Deepwater Horizon cleanup costs (BP ultimately paid over $65 billion in penalties and cleanup costs, far exceeding the statutory cap). Proposals to raise the cap to $10 billion or more failed legislatively, but BOEM increased scrutiny of smaller operators' financial capacity, particularly for deepwater operations where a single blowout can exhaust even large balance sheets. For independent operators without major-company balance sheets, maintaining qualifying insurance (typically from Lloyd's of London markets or a small number of U.S.-based OPA 90 specialty insurers) is both a significant cost and an annual administrative requirement — and insurers conduct their own worst-case discharge assessments independent of the operator's self-calculation.

• 30 CFR Part 285 — Renewable Energy and Alternate Uses of Existing Facilities on the Outer Continental Shelf (89 sections across 8 subparts — BSEE's operational regulation governing the construction, operation, and decommissioning of offshore wind and other renewable energy facilities authorized under OCSLA; the companion leasing regulation is 30 CFR Parts 585–586, administered by BOEM):

  • Subpart A — General Provisions (14 sections): BSEE has authority over safety, environmental protection, and operational compliance for OCS renewable energy activities; developers must design and conduct all activities to ensure safety and avoid undue harm to natural resources, other OCS uses, and the environment; § 285.105 — operator responsibilities include using best available technology consistent with sound commercial practices
  • Subpart D — Lease and Grant Administration (12 sections): BSEE may issue cessation orders when a developer fails to comply with applicable law, regulations, or lease terms (§ 285.401); upon receiving a cessation order, the developer must immediately stop all activities; BSEE may also issue suspension orders when continued activities pose an imminent threat of serious harm to persons, natural resources, or property; lease and co-lessee obligations are joint and several (§ 285.406)
  • Subpart G — Facility Design, Fabrication, and Installation (13 sections): before installing any OCS renewable energy structure (wind turbine foundations, monopiles, jacket structures, offshore substations, inter-array cables, export cables), the developer must submit a Facility Design Report (FDR) and Facility Inspection and Installation Report (FIR) to BSEE; § 285.705 — developers must use a Certified Verification Agent (CVA) — an independent engineering firm approved by BSEE — to independently verify that the facility design meets accepted industry standards (IEC 61400 for wind turbines; ISO 19902 for fixed steel structures); the CVA requirement parallels the independent design verifier system in European offshore wind regulation
  • Subpart H — Environmental and Safety Management, Inspections, and Facility Assessments (20 sections — largest subpart): developers must maintain an environmental and safety management system for all OCS renewable energy activities; BSEE inspects OCS renewable energy facilities; developers are required to report incidents and near-misses within specified timeframes
  • Subpart I — Decommissioning (13 sections): when a lease expires or terminates, the developer must decommission all structures and restore the seafloor within specified timeframes; BSEE may require financial assurance to ensure funds are available for decommissioning; the 88 FR 6413 (Feb 2023) and 89 FR 42714 (May 2024) rulemakings updated Part 285's decommissioning provisions and aligned BSEE's enforcement authority with the program's growth
  • Subpart J — Rights of Use and Easement for Alternate Uses (5 sections): covers a distinct use case — repurposing existing OCS oil and gas infrastructure (platforms, pipelines) for renewable energy or marine-related activities; developers can obtain an Alternate Use RUE from BOEM/BSEE to use existing infrastructure without requiring a separate renewable energy lease; relevant to proposals to convert retired Gulf platforms into offshore wind support structures or wave energy conversion facilities

  89 FR 42714 (May 2024): Most recent significant amendment — updated BSEE's Part 285 inspection authority, CVA requirements, and decommissioning financial assurance framework as the Atlantic offshore wind program matured from the planning to construction phase. The industry's first major Atlantic offshore wind projects (Vineyard Wind, South Fork Wind, Revolution Wind) required BSEE to operationalize Part 285's construction oversight and CVA framework at commercial scale for the first time.

• 33 CFR Part 67 — Aids to Navigation on Artificial Islands and Fixed Structures (USCG, 52 sections): while BSEE and BOEM regulate the resource extraction and environmental aspects of OCS structures, the U.S. Coast Guard separately regulates the maritime safety marking requirements for all artificial islands, drilling rigs, production platforms, and other fixed structures on the OCS under 14 U.S.C. § 503 (USCG authorities) and 43 U.S.C. § 1333 (OCSLA, extending U.S. laws to the OCS). Part 67 requires owners and operators of OCS structures to install and maintain obstruction lights and sound signals that warn passing mariners of the structure's presence — a critical safety function in busy shipping lanes and fishing grounds. The requirement applies from the moment construction begins (§ 67.05-15 — obstruction lights must display from sunset to sunrise starting the first day of construction).

  • § 67.01-15 — Classification of structures: the District Commander assigns each structure to Class A, Class B, or Class C as part of the permit application process; classification determines the specific lighting and sound signal requirements and reflects the structure's location (offshore exposure, proximity to shipping lanes) and mariners' ability to detect it by other means
  • § 67.05-1 / § 67.05-10 — Obstruction light requirements: structures with a maximum horizontal dimension of 30 feet or less require one 360° visible light; larger structures require lights at each corner or extremity sufficient to define the full horizontal extent of the structure; all obstruction lights must display a quick-flash characteristic (approximately 60 flashes per minute) and operate from a reliable power source with auxiliary backup
  • § 67.05-20 — Minimum requirements: the Part prescribes minimum requirements only; structure operators may install additional lights with District Commander approval; the minimum standard is the floor, not the ceiling — offshore wind platforms, for instance, routinely exceed Part 67 requirements to satisfy BOEM permit conditions
  • § 67.10 subpart — Sound signals: structures must maintain sound signals operable during periods of restricted visibility; the type, range, and frequency of signals depends on the structure's classification and surrounding shipping density; fog signals must be activated when visibility drops below specified thresholds
  • §§ 67.20–67.30 — Class A, B, and C requirements: Class A (most exposed, highest traffic) requires the most powerful lights and most robust sound signals; Class B and Class C structures in more sheltered locations may use less powerful equipment meeting scaled-down specifications
  • §§ 67.35–67.40 — Permit applications and notifications: operators must apply to the USCG District Commander for a permit to establish lights and sound signals on each structure; applications must include the structure's location (latitude/longitude), dimensions, classification request, and proposed equipment specifications; the District Commander approves or modifies the application before the structure is installed; operators must notify the District Commander before installing or significantly modifying any structure so the Commander can process the marking permit and publish Notice to Mariners

  The USCG's Part 67 program intersects with the BSEE/BOEM regulatory framework at every OCS structure: a production platform that BSEE inspects for equipment safety also carries USCG-mandated obstruction lights that the platform's owner must maintain in working order regardless of BSEE's inspection findings. The two regulatory frameworks are independent — an obstruction light malfunction is a USCG violation under Part 67, not a BSEE violation under Part 250, even if the same platform is subject to both agencies' authority. The Outer Continental Shelf Lands Act extension of U.S. law to the OCS (43 U.S.C. § 1333) is the jurisdictional hook that allows the USCG — whose primary statutory maritime jurisdiction covers navigable waters and the high seas — to require safety marking on structures that are fixed to the seabed rather than floating. As offshore wind development places thousands of turbine foundations in the same OCS waters where oil and gas platforms operate, Part 67's lighting and sound signal requirements have taken on renewed importance for wind project operators — USCG marking requirements for turbine arrays must be coordinated with BOEM permit conditions and BSEE facility safety plans.

• 30 CFR Parts 580–581 — BOEM Prospecting and Leasing of OCS Non-Oil/Gas Minerals: the regulatory framework for the Outer Continental Shelf's non-hydrocarbon mineral resources — including sand and gravel, hard minerals, polymetallic nodules, and other OCS resources not covered by the oil and gas or sulphur leasing programs. Parts 580 (prospecting) and 581 (leasing) establish the two-phase process for accessing these resources. These regulations implement 43 U.S.C. § 1337(k) of the Outer Continental Shelf Lands Act. Key provisions:

  • 30 CFR § 580.10 — Prospecting permit requirement: before any operator may conduct prospecting activities on the OCS for non-oil/gas minerals, they must obtain a BOEM-approved prospecting permit; the permit specifies the geographic area, authorized activities (geological and geophysical surveys, sampling), and conditions to protect environmental resources; § 580.11 creates a lighter pathway for purely scientific research that does not involve resource extraction — researchers may notify BOEM rather than obtain a full permit for non-commercial G&G work
  • 30 CFR § 580.12 — Permit application contents: prospecting permit applications must identify the specific area by coordinates, describe the prospecting methods (acoustic surveys, core samples, seafloor grab samples), identify potential environmental impacts, and provide a financial guarantee sufficient to cover cleanup and reclamation; BOEM evaluates applications for potential conflicts with existing OCS oil and gas leases, navigation, fishing operations, and defense activities
  • 30 CFR § 580.20–580.22 — Operating restrictions: prospectors must avoid unnecessary interference with other seabed uses; must not use explosives, drill for core samples, or conduct activities likely to damage the seabed without specific permit authorization; must allow BOEM inspection of operations at any time; must report discovery of any significant mineral resource to BOEM
  • 30 CFR § 581.11 — Unsolicited lease request: any person may petition BOEM to offer a specific OCS area for competitive mineral leasing; BOEM evaluates unsolicited requests against resource data, environmental considerations, and conflict with existing uses; if BOEM accepts the request, it conducts the state coordination and competitive leasing process of §§ 581.12–581.18
  • 30 CFR § 581.13 — Joint state/federal coordination: before offering OCS minerals for lease, BOEM must invite adjacent state governors to participate in coordinating the leasing process — particularly relevant for sand and gravel projects that directly affect coastal state beaches and nearshore environments; states cannot veto OCS leasing (it is federal jurisdiction), but BOEM must consider state input
  • 30 CFR § 581.16–581.18 — Leasing notice and competitive bidding: OCS mineral leases are offered by competitive, cash bonus bidding; BOEM publishes a proposed leasing notice and final leasing notice in the Federal Register; interested parties submit sealed bids; BOEM awards the lease to the highest qualifying bidder; royalties are set in the lease terms

  The OCS non-oil/gas mineral program has historically been dominated by sand and gravel dredging for beach nourishment and coastal construction projects — the U.S. Army Corps of Engineers is the primary customer, using OCS sand to replenish eroding beaches under its coastal storm damage reduction programs. The OCS contains approximately 15 billion cubic yards of sand deposits that meet nourishment quality criteria — a nationally significant resource for coastal resilience. The program has gained additional attention from the critical minerals focus of recent energy policy: OCS seafloor nodules contain cobalt, nickel, manganese, and copper — minerals important for EV batteries and other clean energy technologies. The pending S 2860 (Revitalizing America's Offshore Critical Minerals Act) would expand the framework for leasing these deposits. No commercial-scale hard-mineral OCS lease has been issued; the program's current focus is sand and gravel for the Corps' beach nourishment contracts.

• 33 CFR Part 106 — Marine Security: Outer Continental Shelf (OCS) Facilities (USCG — the maritime security requirements for fixed and floating offshore oil and gas platforms, drilling units, and production facilities on the OCS, implementing the Maritime Transportation Security Act of 2002 (MTSA), 46 U.S.C. § 70051):

  • § 106.105 — Applicability: Part 106 applies to owners and operators of any fixed or floating facility located on the OCS, including Mobile Offshore Drilling Units (MODUs), floating production storage and offloading vessels (FPSOs), tension-leg platforms, spars, and similar installations; facilities that are not normally manned or that present minimal security risk may qualify for a reduced security plan
  • § 106.110 — Facility Security Plans (FSPs): each OCS facility owner or operator must submit an approved Facility Security Plan to the USCG District Commander; the FSP must address the full range of potential security threats — unauthorized access, sabotage, terrorism — and specify security measures for each Maritime Security (MARSEC) level; MARSEC levels (1, 2, 3) are set nationally by DHS, with higher levels corresponding to greater threat environments and more stringent security measures
  • § 106.115 — Compliance documentation: facility operators must maintain copies of the approved FSP, MARSEC level implementation records, security drill logs, and access control logs aboard or readily accessible; records must be available for USCG inspection at any time
  • § 106.120 — Temporary deviations: when a facility must temporarily deviate from FSP requirements (due to operations, maintenance, or weather), the operator must notify the USCG District Commander; temporary deviations may not be used to avoid implementing required security measures for extended periods
  • § 106.135 — Alternative Security Programs: OCS facility operators may use an USCG-approved Alternative Security Program (ASP) developed by an industry association or classification society in lieu of submitting an individual FSP — a compliance streamlining option that reduces the administrative burden for operators of multiple similar facilities
  • § 106.140 — MARSEC Directives compliance: all OCS facility operators must comply with any MARSEC Directive issued by the USCG — classified security instructions that provide threat-specific guidance that is not publicly disclosed; failure to comply with a MARSEC Directive is a violation of Part 106

  Part 106 was promulgated after the 2002 MTSA extended the Act's vessel and port security framework to OCS facilities — reflecting the terrorism threat to critical U.S. energy infrastructure. The OCS hosts approximately 1,800 active platforms in the Gulf of Mexico alone, with concentrations of deepwater production infrastructure (Macondo-type facilities) that represent significant national energy security assets. A successful attack on a major deepwater production hub could disrupt a significant fraction of U.S. offshore oil and gas output. The USCG District 8 (New Orleans) is the cognizant district commander for the vast majority of Gulf of Mexico OCS facilities and conducts periodic security assessments and compliance audits.

• 30 CFR Part 582 — Operations in the Outer Continental Shelf for Minerals Other Than Oil, Gas, and Sulphur (BOEM, 28 sections): the companion operations regulation to the prospecting (Part 580) and leasing (Part 581) framework for OCS hard minerals — sand and gravel, polymetallic nodules, cobalt crusts, and other non-hydrocarbon resources. Once a lessee wins a competitive bid under Part 581, Part 582 governs everything they actually do on the lease:

  • § 582.10 — BOEM Director jurisdiction: exploration, testing, and mining operations together with all associated environmental protection measures are under the Director's jurisdiction; this extends to handling, measurement, and transportation of OCS minerals from the point of extraction to shore
  • §§ 582.21–582.24 — Three-stage plan sequence: every lessee must submit and obtain BOEM approval for three sequential plans before progressing to the next stage: (1) a Delineation Plan — locating and characterizing the deposit, including quantity, quality, and feasibility data; (2) a Testing Plan — pilot operations and processing trials where more data is needed before full-scale development; (3) a Mining Plan — the comprehensive development and production proposal with detailed descriptions of equipment, methods, processing, and environmental mitigation; no exploration activities may begin until the Delineation Plan is approved
  • § 582.28 — Environmental protection measures: exploration, testing, development, and production activities will only be approved when BOEM determines adverse impacts can be avoided, minimized, or mitigated; BOEM considers the environmental impact statement (EIS) or environmental assessment prepared for the lease sale and may impose supplemental conditions; any activity with potential for serious harm requires a Contingency Plan (§ 582.26) specifying emergency response procedures
  • § 582.14 — Noncompliance and penalties: if a lessee fails to comply with applicable law, regulations, or the approved plans, and the noncompliance poses a threat of immediate, serious, or irreparable environmental damage, the Director must order immediate remedial action; less urgent violations result in written notices of noncompliance with specified cure periods; continued noncompliance is grounds for lease cancellation under § 582.15

  Part 582 is the operational spine of BOEM's growing OCS critical minerals program. For decades, the program's real-world activity was almost entirely sand and gravel dredging for the Army Corps of Engineers' beach nourishment projects — the OCS contains an estimated 15 billion cubic yards of qualifying sand deposits that coastal states depend on for shoreline restoration. The program has attracted renewed attention under Executive Orders 14285 and 14154 (2026) directing BOEM to facilitate expanded OCS critical mineral development, as the OCS seafloor contains cobalt-rich ferromanganese crusts and polymetallic nodule fields that could supply cobalt, nickel, manganese, and copper for clean energy technology manufacturing. Recent rulemakings: 90 FR 24072 (April 2025) — BOEM administrative revisions to facilitate OCS critical minerals development consistent with Trump administration energy dominance directives.

• 30 CFR Part 586 — Alternate Uses of Existing Facilities on the Outer Continental Shelf (BOEM, 30 sections): the regulatory framework for repurposing existing OCS oil and gas infrastructure — platforms, pipelines, subsea equipment — for energy- or marine-related activities that have nothing to do with the original oil and gas operation. Part 586 implements OCSLA § 1337(p)(1)(D), which authorizes BOEM to issue Rights of Use and Easement (RUEs) allowing third parties or lessees to use existing OCS structures for alternate purposes:

  • § 586.101 — Authorized alternate uses: activities covered include offshore renewable energy installations that co-locate with or use existing platform infrastructure, marine aquaculture operations (fish cages, shellfish arrays attached to existing structures), marine research facilities, offshore energy storage, and carbon capture and sequestration activities using existing subsurface infrastructure; Part 586 does not authorize mineral extraction — oil and gas rights remain governed by the underlying OCS lease
  • § 586.200–586.201 — Pre-application requirement: if the alternate use applicant is not the owner of the existing facility and not the current lessee, they must first reach a preliminary agreement with the facility owner before submitting a formal RUE application; the application must describe the proposed activities, identify the specific OCS facility, provide project timelines, and demonstrate technical and financial capability
  • § 586.202 — BOEM's case-by-case evaluation: BOEM considers RUE requests individually, consulting relevant federal agencies and evaluating whether the proposed activities can be conducted safely, with minimal adverse environmental impact, without interfering with the rights of the current lessee or other authorized OCS users, and consistent with BOEM's safety and environmental protection standards
  • § 586.203 — Competitive issuance: Alternate Use RUEs must be offered competitively unless BOEM determines after public notice that no competing interest exists; BOEM publishes a Federal Register notice; if competitive interest is confirmed, BOEM solicits formal bids
  • § 586.210 — Term: RUE duration is set case-by-case based on the scale and type of the alternate use activity; existing oil and gas leases do not need to have expired before BOEM can issue an Alternate Use RUE (§ 586.102(c)) — BOEM may authorize co-located alternate use or restrict it until the primary lease terminates, depending on operational compatibility

  The Part 586 program matters most as the oil and gas industry retires aging Gulf of Mexico platforms: approximately 2,000 idle or late-life platforms in the Gulf represent both a massive decommissioning liability and a potential infrastructure asset for offshore aquaculture, carbon storage, or marine research. Environmental groups and commercial fishermen have both supported repurposing eligible structures rather than removing them entirely — decommissioned "rigs to reefs" programs (separate from Part 586) are already common, but Part 586 enables active commercial reuse. No large-scale commercial projects have been authorized to date; the most likely near-term applications involve offshore carbon dioxide sequestration using existing Gulf deepwater infrastructure. No significant recent rulemakings — the regulatory framework dates to the Energy Policy Act of 2005 amendments to OCSLA.

• 30 CFR Part 583 — Negotiated Noncompetitive Agreements for the Use of OCS Sand, Gravel, and/or Shell Resources: the BOEM regulations implementing the authority under OCSLA § 8(k) (43 U.S.C. § 1337(k)) to enter into noncompetitive agreements with state and local governments for the use of OCS aggregate materials (sand, gravel, and shell) in coastal protection and restoration projects. Unlike the competitive bidding that governs oil, gas, and wind leasing on the OCS, Part 583 allows BOEM to negotiate directly with qualified entities — without a competitive bid process — when the project serves a shore protection, beach restoration, or coastal wetlands restoration purpose. This program is a critical tool for Atlantic, Gulf, and Pacific coastal communities facing accelerating beach erosion: the OCS contains vast quantities of sand and shell that can be dredged and deposited on eroding beaches, but the materials lie on federal seabed and require BOEM authorization. Key provisions:

  • § 583.105 — Purpose and scope: Part 583 applies to any person seeking an agreement for OCS aggregate use in shore protection, beach restoration, or coastal wetlands restoration; the noncompetitive pathway is only available for these qualifying purposes — commercial aggregate extraction for construction must use a different authorization process
  • § 583.110 — BOEM authority: grounded in OCSLA § 8(k), which specifically authorizes the Secretary to negotiate agreements for OCS sand, gravel, and shell use without competitive bidding when the use serves "the lateral protection of the coastline of a State, territory, or possession of the United States"; Congress added this authority in 1986 recognizing that competitive bidding created barriers for public coastal restoration projects
  • § 583.120 — Qualified entities: BOEM may enter into an agreement with any person proposing OCS aggregate use for shore protection, beach restoration, or coastal wetland restoration; in practice, the primary users are state coastal agencies, the Army Corps of Engineers, counties, and municipalities managing beach nourishment programs; private beach-fronting property owners typically access OCS sand through state or local programs rather than directly from BOEM
  • § 583.130 — Minimum agreement contents: every Part 583 agreement must specify the material to be used (sand, gravel, or shell), the volume authorized, the OCS area from which dredging is permitted, the purpose of the project, required environmental mitigation measures, reporting obligations, and the compensation to be paid to the United States; compensation rates reflect the market value of the aggregate material and are negotiated case-by-case
  • § 583.300 — Application process: applicants submit a written request to BOEM describing the project scope, location, material needed, and environmental information; BOEM determines qualification, conducts a technical and environmental evaluation, issues a Finding of No Significant Impact (FONSI) or requires an Environmental Impact Statement, and then negotiates agreement terms; BOEM coordinates with BSEE, USACE, EPA, and the relevant state coastal programs during review
  • § 583.305–583.310 — Qualification and evaluation: BOEM evaluates whether the project qualifies (shore protection purpose), whether the OCS area can support the proposed dredging without significant harm to natural resources (particularly submerged coral, shellfish habitat, or sensitive benthic communities), and whether environmental mitigation is adequate; BOEM may approve the project with conditions requiring specific dredging methods, season restrictions, or post-project monitoring

  The Part 583 program is increasingly important as sea level rise and coastal erosion accelerate demand for beach nourishment materials. Major beach nourishment projects — such as those along the Jersey Shore, Florida's Gulf Coast, and Carolina beaches — routinely use OCS sand sources accessed through Part 583 agreements or through USACE projects that obtain BOEM authorization. Compensation to the United States is typically modest relative to the project's public benefit (beach nourishment projects protect billions of dollars in coastal property), and BOEM has generally facilitated rather than restricted access for qualifying shore protection projects. No major amendments — the Part 583 framework has been stable since promulgation.

• 30 CFR Part 291 — Open and Nondiscriminatory Access to Oil and Gas Pipelines Under OCSLA: the BSEE regulations implementing the pipeline access provisions of OCSLA § 5(f) (43 U.S.C. § 1334(f)), which requires that oil and gas pipelines on the OCS provide open and nondiscriminatory access to all OCS production — meaning pipeline owners cannot favor their own production over other producers' crude oil or gas when there is available pipeline capacity. OCSLA's nondiscriminatory access requirement prevents offshore pipeline infrastructure from being used as a competitive bottleneck: a company that builds an OCS pipeline cannot refuse to transport a competitor's production while capacity is available. BSEE administers this requirement through a complaint-based enforcement process. Key provisions:

  • § 291.100 — Purpose: Part 291 establishes procedures for filing a complaint with BSEE alleging that a grantee or transporter has denied open and nondiscriminatory access to an OCS pipeline that is not otherwise regulated by FERC; the carve-out for FERC-regulated pipelines is significant — FERC has separate jurisdiction over many OCS pipelines that connect to onshore facilities and enter interstate commerce; Part 291 covers the gap (intrastate and OCS-only segments that fall outside FERC jurisdiction)
  • § 291.101 — Definitions: key terms include "transporter" (any person owning, operating, or controlling an OCS pipeline), "shipper" (any person entitled to transport production through an OCS pipeline), and "right-of-way" (a BSEE-granted authorization for an OCS pipeline); the regulatory framework distinguishes between parties who own pipeline infrastructure and those who seek to use it
  • § 291.102–291.103 — Informal resolution: before filing a formal complaint, a shipper who believes access has been denied may call the BSEE Hotline to attempt informal resolution; parties may also request Alternative Dispute Resolution (ADR) at any stage — before or after a formal complaint; BSEE encourages informal resolution to avoid formal proceedings
  • § 291.104 — Who may file: any shipper who believes they have been denied open and nondiscriminatory access to a non-FERC OCS pipeline may file a complaint; third parties may also file briefs in existing proceedings if they have a direct interest
  • § 291.105–291.106 — Complaint requirements and filing: complaints must be comprehensive written briefs stating the legal and factual basis for the access denial allegation; the complaint must explain why the shipper believes access was wrongly denied, describe the pipeline and the production involved, and specify the relief sought; filed with the BSEE Director by certified mail or personal delivery
  • § 291.107 — Answer: the respondent (the pipeline owner/operator) must file an answer within 60 days; missing the deadline can result in the answer being disregarded; the answer must address each allegation and state the legal and factual basis for the denial of access
  • § 291.108 — Processing fee: complainants must pay a BSEE processing fee electronically before their complaint is accepted; the fee structure reflects OCSLA's user-charge authority under 31 U.S.C. § 9701

  The nondiscriminatory pipeline access requirement reflects Congress's policy that OCS production infrastructure should not become a tool for foreclosing competition in offshore energy markets. For independent oil and gas producers operating on the OCS without their own pipeline infrastructure, Part 291 provides a critical remedy if the pipeline owner — often a larger integrated company — denies transport without legitimate justification. Recent rulemakings: 76 FR 64462 (October 2011) — initial rule promulgating Part 291; 81 FR 36154 (June 2016) — amendments updating processing fee and ADR procedures.

• 33 CFR Part 147 — Safety Zones Around OCS Facilities (USCG, 65 sections): the U.S. Coast Guard's mandatory safety exclusion zone system for all OCS structures — oil and gas platforms, drilling units, and production facilities. Part 147 implements the USCG's authority under 14 U.S.C. § 544 and OCSLA's extension of U.S. jurisdiction over OCS activities (43 U.S.C. § 1333) to prohibit entry by vessels into the 500-meter ring around each designated structure without permission from the USCG District Commander. Key provisions:

  • § 147.1 — Purpose: safety zones protect OCS facilities from accidental collision by commercial vessels, fishing boats, and recreational craft; they also provide a buffer against sabotage and unauthorized access; the 500-meter standard radius corresponds to the international 500-meter safety zone established by the 1958 Convention on the Continental Shelf and preserved under UNCLOS
  • § 147.10 — Establishment: when a USCG District Commander determines a safety zone is needed for a specific OCS facility, the Commander issues regulations establishing the zone; the District Commander may issue emergency zones with immediate effect for facilities under construction or emergency response situations
  • §§ 147.1102–147.1105 (and subsequent platform-specific sections) — Individual platform zones: the bulk of Part 147's 65 sections are platform-specific safety zone definitions, each specifying the structure's position in lat/long coordinates and confirming the standard 500-meter exclusion boundary; the Gulf of Mexico platforms (District 8) and Pacific platforms (District 11) are the primary geographic concentration; platforms include named structures such as Platform GRACE, Platform GINA, and the ELLEN & ELLY complex
  • Unauthorized vessel entry: any vessel entering a 500-meter safety zone without permission commits a USCG violation; penalties can include fines and vessel detention; USCG cutters and aircraft enforce the zones, particularly during drilling operations and well intervention activities where collision risk is highest

  Part 147 is operationally significant for the Gulf of Mexico's commercial fishing fleets, which operate near and between the roughly 1,800 active platforms in the Gulf. Fishing vessels must navigate around the safety zones while pursuing shrimp, snapper, and menhaden in the same waters where offshore oil infrastructure is concentrated. The same 500-meter exclusion that protects platforms from fishing gear entanglement also creates "de facto reef sanctuaries" around platform legs — a phenomenon where the zones inadvertently protect marine habitat that has colonized the structure. The Rigs-to-Reefs program (administered cooperatively by BSEE and Gulf Coast states) explicitly leverages this habitat value by allowing decommissioned platforms to be toppled in place rather than fully removed, converting the structure into an artificial reef with an adjacent safety zone.

Pending Legislation

• HR 6930 — Protecting Military Readiness from Offshore Wind Act: would restrict offshore wind development in areas that may interfere with military operations and training ranges. Status: Introduced.
• S 2860 — Revitalizing America's Offshore Critical Minerals Act: would authorize leasing on the OCS for critical mineral extraction, expanding the OCS framework beyond oil, gas, and wind. Status: Introduced.
• HR 4018 — Would unleash offshore critical mineral extraction by streamlining permitting and leasing for seabed mining on the OCS. Status: Introduced.
• HR 3948 — Offshore Pipeline Safety Act: would strengthen safety standards for offshore oil and gas pipelines on the OCS. Status: Introduced.
• HR 3742 — Offshore Energy Modernization Act: would set a target of 30 GW of offshore wind capacity by 2030 and streamline permitting. Status: Introduced.
• HR 3071 — Increasing Penalties for Offshore Polluters Act: would significantly increase civil and criminal penalties for pollution from OCS operations. Status: Introduced.
• S 1486 — COAST Anti-Drilling Act: would permanently ban oil and gas leasing in the Atlantic OCS planning areas. Status: Introduced.
• HR 2848 — Stop Arctic Ocean Drilling Act: would prohibit oil and gas leasing in Arctic OCS waters. Status: Introduced.

Recent Developments

• Trump reverses offshore wind; reaffirms Gulf oil/gas leasing (2025-2026): BOEM reaffirmed Gulf of Mexico (now "Gulf of America") OCS lease sales under the current five-year program, extending oil and gas leasing with favorable terms. Simultaneously, BSEE began advancing regulatory frameworks for offshore wind operations while the Trump administration imposed a moratorium on new offshore wind approvals — creating a disconnect between the operational safety framework and the political pause on new projects. BSEE proposed revisions to the 2023 blowout preventer rule, relaxing some Biden-era well control equipment requirements that industry had opposed. The Sable Offshore pipeline off California received a BSEE special permit to resume operations after a 2015 spill shutdown, opening access to California OCS reserves.
• The Inflation Reduction Act (2022, § 50261) raised the OCS minimum royalty rate from 12.5% to 16.67% and capped it at 18.75% for ten years, and linked offshore oil/gas leasing to wind energy leasing requirements; OBBBA § 50102 (Pub. L. 119-21, July 4, 2025) repealed IRA § 50261
• The 2024-2029 Five-Year Leasing Program was finalized with a historically limited number of lease sales
• Offshore wind development has progressed with lease sales and approvals off the Atlantic coast, though several projects face financial headwinds
• Ongoing litigation over the scope of NEPA review required for OCS lease sales
• Debate continues over whether to open Atlantic and Pacific OCS areas to oil and gas leasing
• In March 2026, BSEE revised Outer Continental Shelf downhole commingling regulations consistent with the One Big Beautiful Bill Act, and BOEM announced its intent to prepare a programmatic EIS for proposed oil and gas lease sales in the Northern, Central, and Southern California Program Areas.
• In February 2026, consistent with Executive Orders 14285 ("Unleashing America's Offshore Critical Minerals") and 14154 ("Unleashing American Energy"), BOEM published administrative revisions to regulations related to Outer Continental Shelf minerals other than oil, gas, and sulphur — enabling expanded critical mineral development on the OCS.