Oil Pollution Act — Oil Spill Liability, Prevention & Response

The Oil Pollution Act of 1990 (33 U.S.C. §§ 2701–2762) — enacted in direct response to the Exxon Valdez disaster (which spilled 11 million gallons of crude oil into Alaska's Prince William Sound in 1989) — establishes a comprehensive federal framework for preventing, responding to, and paying for oil spills in U.S. waters. OPA makes the responsible party (the owner or operator of the vessel or facility that discharged oil, often subject to admiralty and maritime law) strictly liable for all removal costs and damages — including natural resource damage, lost profits, property damage, lost tax revenue, and the cost of providing additional public services. When the responsible party can't pay or can't be identified, the Oil Spill Liability Trust Fund (funded by a per-barrel tax on petroleum) covers the costs — up to $1.5 billion per incident. OPA also requires vessels and offshore facilities to have oil spill response plans, mandates double hulls on oil tankers operating in U.S. waters, and strengthened the National Contingency Plan for coordinating federal, state, and local oil spill response.

Current Law (2026)

Legal Authority

• 33 U.S.C. § 2702 — Elements of liability (responsible party is liable for removal costs and specified damages: natural resource damages, real/personal property damages, lost subsistence use, lost revenues, lost profits/earning capacity, and cost of additional public services)
• 33 U.S.C. § 2703 — Defenses (liability only if discharge caused solely by act of God, act of war, or act/omission of a third party — defenses are narrow and rarely successful)
• 33 U.S.C. § 2704 — Limits on liability (caps on responsible party liability by vessel/facility type; caps removed for gross negligence, willful misconduct, safety violations, or failure to report/cooperate)
• 33 U.S.C. § 2706 — Natural resources (federal, state, and tribal natural resource trustees may assess and recover natural resource damages; responsible party must restore or replace damaged resources)
• 33 U.S.C. § 2712 — Uses of Fund (Oil Spill Liability Trust Fund pays for removal costs not recovered from the responsible party, natural resource damage assessment and restoration, and federal response costs)
• 33 U.S.C. § 2718 — Relationship to other law (OPA does not preempt state oil pollution liability laws — states may impose additional or unlimited liability)

How It Works

The responsible party — the owner or operator of the vessel or facility from which oil is discharged — is strictly liable for all removal costs and damages. Strict liability means no proof of negligence is required; if your vessel or facility discharged oil, you pay. The only defenses are that the spill was caused solely by an act of God, act of war, or the act of a third party with no contractual relationship to the responsible party — defenses that almost never succeed in practice. OPA sets per-incident caps on liability (varying by vessel size and facility type), but those caps are removed entirely if the spill resulted from gross negligence or willful misconduct, violation of a federal safety or operating regulation, or the responsible party's failure to report the spill or cooperate with response efforts. In the Deepwater Horizon disaster (2010), BP's liability cap was effectively unlimited because the spill resulted from federal safety violations and gross negligence — BP ultimately paid over $65 billion in cleanup costs, fines, and settlements. The Oil Spill Liability Trust Fund, funded by a per barrel excise tax on petroleum produced in or imported to the United States (currently $0/barrel; tax suspended), covers federal response costs when the responsible party can't pay and claims by individuals and businesses damaged by a spill; the Fund held approximately $9+ billion in recent years.

Beyond cleanup costs, OPA establishes a framework for recovering natural resource damages — the harm to fish, wildlife, habitats, and ecosystems affected by oil spills. Federal, state, and tribal natural resource trustees (NOAA, Fish & Wildlife Service, state environmental agencies) conduct Natural Resource Damage Assessments (NRDAs) quantifying injury and determining the restoration needed; responsible parties must fund habitat restoration, species management, and recreational access improvements that can stretch over decades. OPA also mandated that all oil tankers operating in U.S. waters have double hulls — two layers of steel between the oil cargo and the sea — phasing out single-hull tankers like the Exxon Valdez between 1990 and 2015. Critically, OPA explicitly does not preempt state oil pollution liability laws: coastal states including Alaska, California, and Washington impose unlimited liability with no caps, and several maintain their own spill prevention and response programs that are stricter than the federal baseline.

How It Affects You

If you live in a coastal community affected by an oil spill: Under OPA, you can file a claim for damages directly against the responsible party (the vessel owner or facility operator) before filing any lawsuit. In fact, you generally must present a claim to the responsible party and allow 90 days for settlement before suing. If the responsible party denies your claim or doesn't settle within 90 days, you can then sue or file with the Oil Spill Liability Trust Fund through the National Pollution Funds Center (NPFC) — the Coast Guard's unit that administers the Trust Fund (uscg.mil/npfc).

OPA's covered damage categories are broad: real or personal property damage (oil on your boat, your beach-front property, your gear), lost profits or earning capacity from the contamination (tourist operators, charter fishing, waterfront restaurants), lost subsistence use of natural resources (if you depend on fishing or shellfishing for personal consumption), loss of government revenues (state and local governments losing tax revenue), and cost of additional public services (overtime for emergency responders, public health monitoring). Mental anguish or personal injury claims are generally not recoverable under OPA — those go through general maritime law or state tort law.

Document everything immediately: photograph contamination, save receipts for any protective measures, keep detailed records of business income losses (comparing to same periods in prior years). The statute of limitations for OPA claims is 3 years from the date the person knew or should have known of the discharge and resulting damages. Don't miss this deadline — it's strictly enforced.

For large spills, the responsible party typically establishes a claims facility administered through a third party (BP's Gulf Coast Claims Facility, administered by Ken Feinberg, was the model for Deepwater Horizon). These facilities can process claims faster than litigation, but you should understand what rights you're waiving when you accept a settlement. Consider consulting an attorney before accepting any settlement offer from a claims facility, particularly for ongoing business losses that may extend years into the future.

If you're a commercial fisher, aquaculture operator, or tourism business near a spill: Your strongest claims are for lost profits and earning capacity — the core economic damage recoverable under OPA § 2702(b)(2)(E). The challenge is proving your losses: you need documented business records showing what you earned in comparable prior periods versus what you earned (or couldn't earn) during and after the spill.

Commercial fishers should document: catch records from prior years (including your state fish and wildlife agency data if you have state-required reporting), lease agreements for commercial fishing grounds, vessel expenses that continued even when you couldn't fish, and any state or federal fishing area closure orders affecting your grounds. Aquaculture operators have the strongest documentation requirements — shellfish operators near Deepwater Horizon sites recovered substantial damages through a combination of NPFC claims and BP's claims facility because they had excellent production records.

For processing and filing claims with the NPFC: the process requires a written Claim for Damages form specifying the categories of damage, supporting documentation, and a completed IRS Form W-9 (for payment processing). NPFC claims don't require an attorney, but larger claims benefit from experienced OPA claims counsel. The NPFC processes claims and pays from the Trust Fund if the responsible party hasn't compensated you. Contact NPFC at (800) 280-7118.

If you're an oil company, vessel owner, or facility operator: Your compliance obligations under OPA divide into prevention and financial responsibility requirements.

On prevention: (1) Vessel Response Plans are required under 33 CFR Part 155 for tank vessels over 250 barrels carrying oil, for vessels over 400 gross tons carrying oil in bulk, and for vessels with significant bunker fuel. Your VRP must identify a qualified individual (QI) reachable 24/7, list contracted oil spill removal organizations (OSROs), and plan for worst-case discharge scenarios. VRP non-compliance generates significant civil penalties and, critically, can strip your liability cap — you're strictly liable without limits if you violate federal operational regulations; (2) Spill Prevention, Control, and Countermeasure (SPCC) plans are required under 40 CFR Part 112 for onshore non-transportation-related facilities with oil storage above threshold quantities near navigable waters. SPCC violations are enforced by EPA and can generate civil penalties of up to $25,000/day/violation.

On financial responsibility: vessel owners and operators must obtain a Certificate of Financial Responsibility (COFR) from the Coast Guard demonstrating they can pay up to the applicable OPA liability limit. COFRs are issued to vessels of 300+ gross tons in U.S. waters, vessels of any size with a worst-case discharge over 1,000 barrels, and deepwater port licensees. Financial responsibility is typically demonstrated through insurance (Protection and Indemnity/P&I Club membership), surety bonds, or self-insurance. Operating without a COFR is a strict liability civil violation; operating after COFR denial can trigger criminal penalties.

The most important thing to know about OPA liability caps: they are removed entirely for gross negligence, willful misconduct, violation of a federal safety or operational regulation, failure to report, or failure to cooperate with response. The Deepwater Horizon disaster (2010) resulted in over $65 billion in costs for BP — the cap was effectively irrelevant because federal regulations had been violated and gross negligence was found. Your liability exposure is unlimited in any case involving regulatory non-compliance.

If you're a natural resources professional, environmental advocate, or tribal nation: OPA's Natural Resource Damage Assessment (NRDA) process is one of the most powerful environmental restoration tools in federal law. Natural resource trustees — federal agencies (NOAA, Fish & Wildlife Service, National Park Service, DOE), state environmental agencies, and federally recognized tribes — can assess and recover damages from responsible parties for injury to natural resources under their trusteeship.

NRDA proceeds in two phases: (1) Injury assessment — quantifying the injury to resources (fish, shellfish, birds, marine mammals, habitats, recreational use) using the NOAA NRDA regulations at 15 CFR Part 990; (2) Restoration planning — developing restoration projects to compensate for the injury; these can be primary restoration (replanting marsh, restoring habitat) or compensatory restoration (acquiring equivalent resources elsewhere). The responsible party must fund the restoration — not just cleanup costs — which is what makes OPA fundamentally different from earlier oil spill law.

The Deepwater Horizon NRDA is the largest in history: the $8.8 billion natural resource damage settlement (part of BP's total $20.8 billion settlement) is funding hundreds of Gulf Coast restoration projects over 15 years. The Gulf Coast Ecosystem Restoration Council (restorethegulf.gov) administers a large portion of this restoration funding through a competitive grant program — state and local governments, tribes, and NGOs can apply for Gulf restoration project funding.

For tribal nations: OPA explicitly recognizes tribes as natural resource trustees for resources on tribal land or held in trust by the United States for the tribe. If an oil spill affects tribal fishing grounds, subsistence resources, or reservation waters, your tribe can participate in NRDA as a co-trustee with the relevant federal agencies and the affected state. Contact the relevant DOI regional office (doi.gov/oia/regions) and NOAA's Office of Response and Restoration (response.restoration.noaa.gov) to coordinate trustee activities.

State Variations

OPA preserves extensive state authority:

• States may impose stricter liability standards (including unlimited liability with no caps)
• Coastal states (Alaska, California, Washington, Maine) have enacted comprehensive oil spill laws
• State natural resource trustees participate in NRDAs alongside federal trustees
• State contingency plans coordinate with the federal National Contingency Plan
• State financial responsibility requirements may exceed OPA minimums

Implementing Regulations

• 33 CFR Part 155 — Oil or Hazardous Material Pollution Prevention Regulations for Vessels (111 sections across 9 subparts — the USCG's comprehensive on-vessel oil spill prevention and response plan regulations; authority: 33 U.S.C. § 1321, 46 U.S.C. § 70011; applies to all U.S.-operated vessels and foreign vessels calling at U.S. ports). This is the primary vessel-side companion to OPA's mandate that vessels have approved oil spill response capabilities before operating in U.S. waters:

  • Subpart B — Vessel Equipment (§§ 155.200–155.245): on-board oil spill containment and recovery equipment requirements scaled by vessel size and type — oil tankers and offshore oil barges 400 feet or more must carry boom, absorbent materials, and oil-recovery systems sufficient to contain and recover an on-deck spill of at least 12 barrels before discharge overboard; smaller tankers have a 1-barrel threshold; inland oil barges must have equipment ready during cargo transfer operations; emergency towing arrangements required at both ends of tankers 20,000+ DWT built after 1997 (§ 155.235); computerized shore-based damage stability software must be accessible to vessels to assess structural integrity after grounding or collision (§ 155.240)
  • Subpart C — Transfer Personnel, Procedures, Equipment (§§ 155.700–155.830): a Person in Charge (PIC) must supervise all oil transfers between vessels and between vessels and facilities; the PIC must have knowledge of the transfer procedures, the vessel's cargo system, and applicable regulations; before each transfer, the PIC must inspect the transfer hoses, verify connections, and confirm the vessel/facility Declaration of Inspection (DOI) — a joint checklist signed by both parties before transfers begin (this requirement is detailed in the companion 33 CFR Part 156); the PIC must be reachable during the entire transfer
  • Subpart D — Tank Vessel Response Plans for Oil (§§ 155.1010–155.1085): tank vessels carrying oil as cargo must have an approved Vessel Response Plan (VRP) before operating; the VRP must cover worst-case discharge scenarios, identify a 24/7-reachable Qualified Individual (QI), list contracted Oil Spill Removal Organizations (OSROs) with sufficient capacity to respond to worst-case discharges, and cover all geographic areas where the vessel operates; VRP must be submitted to the USCG Captain of the Port and receive approval before vessel operations begin — operating without an approved VRP is itself a violation generating significant civil penalties and stripping OPA liability limitations
  • Subpart J — Nontank Vessel Response Plans (§§ 155.5010–155.5070): extended after the M/V Cosco Busan bunker fuel spill in San Francisco Bay (2007, 58,000 gallons from non-tank vessel bunkers) — VRP requirements now apply to self-propelled nontank vessels of 400 GT or more that use oil as fuel for main propulsion; nontank vessels covered by Subpart J must identify a QI, contract with OSROs, plan for worst-case bunker fuel discharge, and submit VRPs for USCG approval; VRPs for nontank vessels may be filed as fleet plans covering multiple vessels of identical type and size

  Part 155's VRP framework is the operational core of OPA's vessel-side spill prevention mandate. In practice, most large vessel owners maintain VRPs through industry arrangements — the Vessel Response Plan Group (VRPG) and Marine Spill Response Corporation (MSRC) provide pooled OSRO capacity that allows individual vessel operators to meet OSRO contract requirements without contracting independently. USCG periodically conducts unannounced exercises to verify that QIs can be reached and that OSRO resources are actually deployed — "tabletop" VRPs with non-functional contractor relationships have been cited as enforcement deficiencies.

• 30 CFR Part 254 — BSEE Oil Spill Response Requirements for Offshore Facilities — the regulation that requires offshore oil and gas operators to prepare and maintain approved Oil Spill Response Plans (OSRPs) before conducting any operations on the Outer Continental Shelf. Key provisions:

  • § 254.1 — Who must submit: any owner or operator of an offshore facility used to explore for, develop, or produce oil or gas on the OCS must submit an OSRP to BSEE; this covers both fixed platforms and mobile offshore drilling units (MODUs) operating in U.S. federal waters
  • § 254.2 — Pre-approval requirement: no offshore facility may commence, resume, or continue operations unless BSEE has approved its OSRP; an unapproved plan is not a procedural technicality — it is an independent basis for BSEE to halt operations
  • § 254.21 — Plan format: an OSRP must contain a core plan and applicable appendices; the core plan includes facility identification, an emergency response action plan, a worst-case discharge scenario analysis, and contact information for the responsible party and Oil Spill Removal Organizations (OSROs) under contract
  • § 254.23 — Emergency Response Action Plan (ERAP): the ERAP is the operationally critical component — it must specify immediate notifications (BSEE, National Response Center, Coast Guard), initial response actions, command structure, and escalation procedures; it must be written so that any senior facility employee can execute it without consulting the rest of the OSRP
  • § 254.26 — Worst case discharge scenario (WCD): operators must calculate and plan for the largest foreseeable discharge from their facility — for a producing platform, typically the full flow from the largest well at its maximum rate for the time it would take to drill a relief well; WCD volumes drive the required response resource tier and OSRO contract capacity
  • § 254.27 — Dispersant use plan: operators must identify approved dispersants and describe when and how they would be applied, subject to pre-authorization from the Coast Guard and EPA; the Deepwater Horizon response's extensive dispersant use generated lasting controversy about subsurface application
  • § 254.28 — In situ burning plan: operators in ice-prone Arctic waters must include a plan for controlled burning of spilled oil on the water surface; burning requires pre-authorization and specific environmental conditions
  • § 254.29 — Training and drills: all personnel assigned spill response duties must be trained annually; BSEE may require unannounced drills to test OSRP implementation; drill results must be documented and deficiencies corrected
  • § 254.30 — Two-year review cycle: operators must review and resubmit their OSRP to BSEE every 2 years, or sooner if there is a significant change in operations, facility design, worst-case discharge calculation, or OSRO contract; BSEE may require plan amendments at any time

  Part 254 is the OCS counterpart to the EPA's SPCC rules for onshore facilities and the Coast Guard's vessel response plan requirements — together these three programs create the regulatory triangle that OPA required for all three facility types. The Deepwater Horizon spill (April 2010) was the most consequential enforcement test: BP's approved OSRP contained errors, listed dead experts and unavailable equipment, and anticipated maximum spill scenarios far below what actually occurred. BSEE rewrote the Part 254 requirements in the years after Horizon, requiring more rigorous WCD calculations and verified OSRO capacity. For offshore operators today, the OSRP is not a shelf document — it is the basis for BSEE inspectors to assess response readiness and the reference document in any enforcement action following a spill.

• 33 CFR Part 136 — Oil Spill Liability Trust Fund (OSLTF): Claims Procedures, Designation of Source, and Advertisement — the USCG National Pollution Funds Center (NPFC) rules governing how individuals, businesses, and government entities file claims against the OSLTF for compensation after an oil spill. The OSLTF is a $1 billion+ federal fund created by OPA that pays removal costs and damages when the responsible party is unknown, unwilling, or financially unable to pay. Key provisions:

  • § 136.103 — Order of presentment — present to the responsible party first: OPA requires claimants to present their claim to the responsible party (RP) or the RP's guarantor before bringing a claim to the OSLTF; the claimant must give the RP at least 90 days to settle before filing with the Fund; exceptions: the FOSC (Federal On-Scene Coordinator) may waive prior presentment when the RP denies liability, is unknown, or is in foreign bankruptcy proceedings; the order-of-presentment requirement prevents the OSLTF from becoming the first payor and ensures RP liability is actually imposed
  • § 136.101 — Time limits by claim type: claims must be presented within the OPA limitations periods — (a) 3 years from the date the claimant knew or should have known of the loss for most damage claims (real/personal property, lost profits, natural resource damages) and (b) 6 years from the removal action's completion for government removal cost claims; claims presented after the limitations period are time-barred; the NPFC strictly enforces these deadlines
  • § 136.105 — General claim requirements: every claim must be in writing, signed by the claimant or authorized representative, include a description of the spill incident, the basis for the claim (what was lost or expended), the amount claimed, and all supporting documentation; the claimant bears the burden of establishing entitlement and the amount of loss; interim claims for ongoing removal costs may be submitted before final costs are known
  • § 136.201–136.211 — Removal cost claims: any person (including state and local governments) who incurs costs for actions consistent with the National Contingency Plan (NCP) to prevent, minimize, or mitigate oil discharge may claim those costs from the Fund; the actions must be necessary and reasonable; the Federal On-Scene Coordinator's endorsement that actions were consistent with the NCP is significant but not dispositive; costs must be documented in reasonable detail
  • § 136.207–136.211 — Natural resource damage claims: only a designated natural resources trustee (federal, state, or tribal) may present NRD claims to the Fund; trustees must have conducted or initiated an NRD assessment under 15 CFR Part 990 and must provide the assessment plan and restoration plan; allowable compensation is the reasonable assessment cost plus the cost of restoring, rehabilitating, replacing, or acquiring equivalent natural resources — not speculative or uncertain future impacts
  • § 136.213–136.299 — Other damage categories: real/personal property damage (direct loss or destruction); subsistence use losses (fishing, hunting, gathering activities disrupted); government revenues (tax revenue losses from government entities); profits and earning capacity (business income disruption); and public services (removal of oil from non-public-vessel shorelines). Each category has specific authorized claimants, proof requirements, and compensation methodologies
  • § 136.115 — Settlement finality: acceptance of an NPFC settlement is final and conclusive; the claimant releases all claims against both the Fund and the responsible party covered by the settlement; partial settlements for specific damage categories may be accepted without releasing claims for other categories
  • Designation of Source and Advertisement (Subpart D): when a spill's responsible party cannot be identified promptly, the FOSC may publish an advertisement in newspapers of general circulation near the affected area informing potential claimants how to present claims to the Fund; this advertisement mechanism — one of OPA's innovations — ensures that even small boat operators, commercial fishermen, or recreational users in remote areas know their right to compensation

  The NPFC administers thousands of claims following oil spills each year, ranging from major pipeline ruptures to small vessel fuel spills. The Fund's practical significance is largest in spills where the RP is a small fishing vessel, barge operator, or pipeline company that lacks the financial resources to compensate all claimants — the OSLTF pays first and then pursues cost recovery against the RP and its insurer. For commercial fishermen, waterfront property owners, or recreational businesses affected by a spill, the critical first step is preserving evidence of losses (photos, catch records, reservation cancellations, business receipts) from the first day of impact — the claimant bears the burden of proof, and claims presented with inadequate documentation are denied or reduced.

  Recent rulemakings: 77 FR 37315 (2012) — updated claim forms and procedures. 82 FR 35081 (2017) — revised natural resource damage assessment claim requirements. No significant amendments since 2017.

• 33 CFR Part 137 — OPA Innocent Landowner Defense: Standards for Conducting All Appropriate Inquiries: the USCG implementing regulation for OPA § 1002(d)(1)(C)'s "innocent landowner" defense against OPA liability. An owner or operator of a facility that is the source of an oil discharge may avoid liability if the discharge was caused solely by a third party and the owner took all appropriate action to prevent and respond to the discharge — but only if the owner can demonstrate that they conducted proper environmental due diligence before acquiring the property:

  • § 137.1 — Scope: applies to owners of non-transportation-related facilities (onshore oil storage facilities, tank farms, refineries) seeking to establish the innocent landowner defense under OPA § 1002(d); vessel owners are not covered (vessel liability is governed separately); the regulation is triggered when an owner asserts that an oil spill was caused by the prior owner's contamination — not by the current owner's operations
  • § 137.18 — Required inquiries: to establish the defense, the current owner must demonstrate that before acquisition, they conducted environmental site assessment inquiries meeting specified standards — reviewing historical land use, current site conditions, records of prior contamination, and prior owner information; the inquiry must be conducted or overseen by an environmental professional (a licensed professional engineer, geologist, or environmental consultant meeting the Part 312 definition in 40 CFR Part 312)
  • § 137.20 — ASTM standard as safe harbor: a Phase I Environmental Site Assessment conducted in accordance with ASTM Standard E 1527-05 (or subsequent versions) satisfies the all-appropriate-inquiries requirement; the Phase I ESA is the industry standard transactional due diligence product — a document-and-interview review (no soil sampling) examining regulatory databases, historical aerial photos, fire insurance maps, and site reconnaissance for recognized environmental conditions (RECs); a Phase I ESA that identifies RECs typically triggers a Phase II assessment with soil/groundwater sampling before a transaction closes

  The practical significance: property buyers acquiring industrial sites with above-ground oil storage or pipeline segments routinely commission Phase I ESAs precisely to preserve the innocent landowner defense under CERCLA (the parallel Superfund innocent landowner defense under 42 U.S.C. § 9607(b)(3)) and under OPA. The USCG's Part 137 harmonizes the OPA inquiry standard with EPA's CERCLA Phase I standard, so a single Phase I ESA protects against liability under both statutes. Real estate transactions involving commercial or industrial property near petroleum storage commonly include Part 137/ASTM E 1527-compliant ESA as a closing condition.

• 33 CFR Part 138 — Limits of Liability; Financial Responsibility for Water Pollution (OPA and CERCLA): the USCG National Pollution Funds Center (NPFC) regulation implementing OPA 90's Certificate of Financial Responsibility (COFR) requirement and its liability limits. Any vessel of 300 gross tons or more, any vessel of any size with a worst-case discharge potential exceeding 1,000 barrels, and any operator of a deepwater port or certain onshore pipeline/facility must obtain and maintain a COFR demonstrating the ability to pay cleanup costs and damages up to the OPA liability limit — before operating in U.S. waters. Key provisions:

  • § 138.100 — Total applicable amount: the COFR must cover the sum of (1) the OPA 90 liability limit applicable to the vessel or facility type (set by 33 U.S.C. § 2704 — for tank vessels, the higher of $1,200/gross ton or $10 million; for smaller vessels, $600/gross ton or $500,000; for onshore pipelines, the greater of $350/mile or $35,000 per incident) plus (2) the applicable CERCLA § 108(a) financial responsibility amount for hazardous substance discharges; the COFR must cover both OPA and CERCLA simultaneously — a single document satisfies both statutes for covered vessels
  • § 138.110 — Evidence of financial responsibility: the vessel owner, bareboat charterer, or operator submits evidence of financial responsibility to the NPFC through one of the authorized mechanisms: (a) P&I Club entry — a letter of undertaking from a Protection and Indemnity Club confirming the vessel is entered for oil pollution liability to the required limit; (b) surety bond from an approved surety company; (c) self-insurance — demonstration of net worth and working capital at or above five times the required coverage amount; (d) financial guarantee — a letter of credit or other guarantee from an approved financial institution; evidence must specify effective and termination dates and the vessel(s) covered
  • § 138.120 — Fees: the NPFC charges a processing fee for each COFR application; fee schedules are published in the Federal Register and updated periodically; no fee waiver for government vessels, though federal agencies' vessels are covered under separate statutory provisions
  • § 138.130 — Designation of U.S. agent: vessels without a permanent U.S. presence (foreign-flagged vessels calling at U.S. ports) must designate a U.S. agent for service of process as a condition of COFR issuance; the agent must accept service on behalf of the vessel owner and guarantor; the designation allows the NPFC to enforce OPA liability against foreign owners without the complexity of international service
  • § 138.140 — Denial and revocation: the NPFC may deny a COFR application or revoke an existing certificate if (a) the evidence of financial responsibility does not meet the requirements, (b) the P&I Club or guarantor is no longer approved, (c) coverage lapses, or (d) the vessel is otherwise ineligible; a vessel operating in U.S. waters without a valid COFR is subject to seizure and detention by the USCG and civil penalties up to $25,000 per day of violation
  • § 138.150 — Reporting changes: a COFR holder must notify the NPFC within 30 days of any material change in information — including changes in vessel ownership, gross tonnage, P&I Club, surety, or termination of coverage; failure to report changes can result in revocation as if the change had not been reported

  Subpart B — OPA Liability Limits: Part 138 also implements the liability cap provisions of OPA § 1004 (33 U.S.C. § 2704). Tank vessels of 3,000 gross tons or more are subject to a per-incident limit of $1,200/gross ton or $10 million (whichever is greater); vessels under 3,000 GT have a limit of $1,200/GT or $6 million. The limits are stripped entirely — and the responsible party faces unlimited liability — if the spill was caused by (i) gross negligence or willful misconduct, (ii) violation of a federal safety, construction, or operating regulation, or (iii) failure to report the discharge or cooperate with removal activities. The Deepwater Horizon's loss of liability limitation was grounded in these provisions. Part 138 establishes the COFR regime precisely because OPA's liability limits create a moral hazard — operators with capped liability might underinvest in prevention — and the financial responsibility requirement ensures that even at the capped amount, funds are actually available to pay claims.

• 33 CFR Part 153 — Control of pollution by oil and hazardous substances (notification requirements, discharge reporting, removal obligations)

• 33 CFR Part 154 — Facilities Transferring Oil or Hazardous Material in Bulk (100 sections across 7 subparts — the USCG regulation governing the design, equipment, and operations of shore-side marine transfer facilities: petroleum terminals, refineries with marine docks, chemical plants with vessel loading berths, and offshore loading platforms. While 33 CFR Part 156 regulates the transfer operations themselves and 33 CFR Part 155 regulates the vessels, Part 154 focuses on the physical infrastructure of the receiving facility — the marine terminal, pipeline manifolds, spill containment, and emergency shutdown equipment. Authority: 33 U.S.C. § 1228 (Ports and Waterways Safety Act) and 33 U.S.C. § 1321 (Clean Water Act § 311)):

  • Subpart A — General (§§ 154.100–154.130): applicability to facilities on navigable U.S. waters or the contiguous zone that transfer oil or hazardous material in bulk to or from vessels; facilities covered include marine oil terminals, bulk liquid chemical terminals, offshore oil loading platforms, and petroleum refineries with marine berths; facilities not covered include individual vessels, offshore drilling units, and floating production systems
  • Subpart B — Design and Equipment (§§ 154.300–154.470): requirements for spill containment at transfer points (drip pans, coamings, or containment systems sized to contain at least the maximum transfer rate × 10 minutes); emergency shutdown systems accessible to the PIC from both the facility and vessel sides; vapor control equipment for volatile liquid transfers; hose and loading arm specifications; pressure relief and overflow alarms; grounding cables for static-generating liquids
  • Subpart C — Operations (§§ 154.500–154.570): manning requirements during transfer; communication equipment capable of contact with the vessel and emergency services; transfer records retention (must be retained for 3 years and made available to the COTP on request); periodic inspection and maintenance of transfer equipment
  • Subpart F — Facility Response Plans (§§ 154.1010–154.1090): consistent with OPA 90's mandate, most facilities subject to Part 154 must prepare and maintain a Facility Response Plan describing worst-case discharge scenarios, the qualified individual (QI) who can authorize cleanup expenditures, contracted oil spill removal organizations (OSROs) capable of responding to the worst-case discharge within defined timeframes, and training and drill schedules; FRPs must be submitted to the COTP for approval and updated every 5 years or when significant changes occur

  Part 154 in the OPA compliance picture: The three USCG regulations — Part 154 (shore facilities), Part 155 (vessels), and Part 156 (transfer operations) — form an interlocking framework for every maritime oil transfer event. A crude oil tanker arriving at a refinery marine terminal must have a Part 155-compliant VRP; the terminal must have a Part 154-compliant facility design and FRP; and the actual cargo transfer requires both sides to complete the Part 156 Declaration of Inspection before pumping begins. COTP inspectors can board vessels during transfers and inspect facilities at any time — deficiencies in any of the three Parts can result in civil penalties, suspension of operations, or certificate revocation.

• 33 CFR Part 156 — Oil and Hazardous Material Transfer Operations: the USCG regulation governing the physical transfer of oil or hazardous material between vessels and between vessels and facilities on U.S. navigable waters and the contiguous zone — the most operationally intensive moment when spills are most likely to occur. The rule covers vessels with a capacity of 250 barrels or more and the facilities that serve them:

  • § 156.115 — Person in charge limitations: no person may simultaneously serve as person in charge (PIC) for transfer operations on more than one vessel at a time; the PIC responsibility is non-delegable during active transfer — a single point of accountability for each side of the transfer
  • § 156.118 — Advance notice of transfer: the COTP (Captain of the Port) may require a facility operator to provide at least 4 hours' advance notice before a transfer begins; this allows the COTP to schedule oversight and ensures emergency responders know transfers are underway
  • § 156.120 — Requirements for transfer: a transfer begins when the PIC on the transferring and receiving sides complete a pre-transfer agreement; each PIC must verify the receiving vessel or facility can accept the product, the transfer rate, the emergency shutdown procedures, and the agreed stopping points; no transfer may begin without both PICs' confirmation
  • § 156.130 — Connection requirements: hoses and connections must use suitable gasketing material for a leak-free seal; bolts must be present in at least every other flange bolt hole; connections must be visually inspected before transfer begins; the rule specifies minimum hose ratings for working pressure
  • § 156.150 — Declaration of Inspection (DOI): before any transfer, both the vessel and facility persons in charge must jointly complete and sign a Declaration of Inspection — a checklist confirming that both sides have reviewed transfer procedures, communication signals, emergency shutdown sequences, and spill response equipment; the DOI is the primary documentation of pre-transfer safety verification and is required to be retained aboard the vessel for 30 days after the transfer
  • § 156.160 — Supervision during critical procedures: no person may connect or disconnect a hose, top off a tank, or engage in other critical procedures during a transfer unless the PIC — or a person designated in writing by the PIC — is physically present and supervising; this eliminates the practice of leaving connections or disconnections to untrained crew
  • § 156.170 — Equipment tests and inspections: before each transfer, the PIC must test and inspect transfer equipment listed in the regulation (overflow alarms, emergency shutdown systems, gauging devices, communication equipment); equipment that fails inspection may not be used; the required tests must be documented in the facility or vessel records
  • § 156.125 — Discharge cleanup: any person conducting a transfer must stop operations immediately whenever oil or hazardous material is discharged from any source during the transfer, even if unrelated to the transfer itself; operations may not resume until the discharge is contained and reported

  The Declaration of Inspection requirement is Part 156's primary compliance and enforcement hook: a DOI signed by both PICs creates a contemporaneous record of the agreed-upon transfer procedures. USCG marine inspectors routinely request DOIs during boarding inspections; a missing or incomplete DOI is a specific regulatory violation independent of whether any spill occurred. The pre-transfer checklist model — adapted from aviation pre-flight checks — reflects the USCG's risk management approach: most oil transfer spills result from miscommunication between vessel and facility personnel, not equipment failure; the DOI and PIC supervision requirements directly address that root cause. The Part 156 regime applies on top of the vessel response plan requirements of 33 CFR Part 155 — vessels with approved VRPs must still comply with every Part 156 transfer procedure.

• 40 CFR Part 112 — EPA oil pollution prevention (SPCC plans — Spill Prevention, Control, and Countermeasure requirements for onshore facilities)

• 40 CFR Part 110 — Discharge of Oil: the EPA regulation defining when an oil discharge constitutes a quantity "harmful" enough to trigger mandatory notification under CWA § 311(b)(4) (33 U.S.C. § 1321). The operative test is the "sheen rule":

  • § 110.3 — Harmful quantity: a discharge is deemed harmful — and triggers mandatory reporting — if it: (a) causes a film or sheen upon or discoloration of the water surface or adjoining shoreline; (b) causes a sludge or emulsion to be deposited beneath the surface of the water or on adjoining shorelines; or (c) violates applicable water quality standards; there is no minimum volume threshold — even a small fuel spill visible as an iridescent sheen on water requires immediate notification; the sheen test is deliberately broad to capture any environmentally significant surface release
  • § 110.4 — Anti-evasion: adding chemical or biological agents to oil specifically to disperse it before it reaches the water surface — to avoid the visual sheen test — is prohibited; the regulation closes the obvious workaround of pre-treating spills to hide them
  • § 110.6 — Mandatory notification: any person in charge of a vessel or facility must immediately notify the National Response Center (1-800-424-8802, 24/7) as soon as they have knowledge of a discharge in violation of § 311(b)(3); notification to the NRC triggers the federal response chain — USCG, EPA, and potentially state agencies are alerted automatically; failure to notify is a separate federal crime independent of the spill itself
  • § 110.5 — Exemptions: certain discharges are categorically excluded even if they cause a sheen — discharges of oil already regulated under NPDES permits (in compliance with permit terms), discharges from a properly functioning vessel engine, and certain oil exploration operations; these exemptions narrow but do not eliminate the notification obligation

The sheen rule is the practical trigger that most vessel operators, marina operators, fuel terminals, and industrial facility personnel encounter: if you can see it on the water, you must report it. The NRC notification is non-negotiable — the regulation contains no good-faith or de minimis exception to the notification obligation once a visible sheen exists. The $50,000-per-day civil penalty for illegal discharges under CWA § 311(b)(7) applies from the moment of discharge; the separate $250,000 or 5-year criminal penalty for knowing failure to notify under § 311(b)(5) is independent of whether the spill itself was accidental.

Pending Legislation

Oil spill liability and response provisions appear in broader energy and environmental legislation. See Outer Continental Shelf and Clean Water Act.

Recent Developments

The Deepwater Horizon spill (2010) — the largest marine oil spill in U.S. history (4.9 million barrels) — tested OPA at an unprecedented scale and led to extensive natural resource restoration across the Gulf Coast (funded by BP's $20.8 billion settlement). Congress raised liability limits and the per-barrel tax rate in response. BSEE (Bureau of Safety and Environmental Enforcement) strengthened offshore drilling safety regulations. The Trust Fund balance has remained healthy. Climate change and Arctic oil development have raised questions about spill response capacity in remote, ice-affected waters. Pipeline safety (regulated separately under the Pipeline Safety Improvement Act) has become a growing focus following high-profile inland pipeline spills.