Office of Emergency Management 

EPA 550-B-05-001 

SPCC Guidance 

for Regional Inspectors 

Version 1.0 

November 28, 2005 

U.S. Environmental Protection Agency 

Office of Emergency Management 

Regulation and Policy Development Division 

The Oil Pollution Prevention regulation includes requirements for 

facilities to prepare, amend, and implement Spill Prevention, Control, 

and Countermeasure (SPCC) Plans to prevent discharges of oil to 

navigable waters and adjoining shorelines. The regulation allows 

flexibility in meeting some of the requirements. This document is 

designed to assist regional inspectors in implementing the SPCC 

program and in understanding its applicability. 
This document was prepared by the Regulation and Policy Development Division of the EPA 

Office of Emergency Management under the direction of Mark Howard and Patricia Fleming. 

EPA engineering review was conducted by Troy Swackhammer. Technical research, writing, 

and editing was provided under EPA Contract No. 68-W-03-020. 

The Office of Emergency Management gratefully acknowledges the contributions of EPA's 

program and regional offices in reviewing and providing comments on this document. 

Copies of this document may be obtained online at www.epa.gov/oilspill. In addition, updates to 

the document will be available online. 

Office of Emergency Management (5104A)

EPA 550-B-05-001

www.epa.gov
Table of Contents 

TABLE OF CONTENTS
 


DISCLAIMER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii 
 


OIL PROGRAM CONTACTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix 
 


ACRONYMS LIST . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xiii 
 


INTRODUCTION ............................................................. 1-1 
 


1.1 SPCC Background ............................................... 1-1 
 


1.1.1	 Purpose and Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 
 


1.1.2 	 Statutory Framework . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-2 
 


1.2 	 Regulatory History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-4 
 


1.2.1 	 Initial Promulgation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-4 
 


1.2.2 	 SPCC Task Force and GAO Recommendations . . . . . . . . . . . . . . . . . . . 1-5 
 


1.2.3	 Proposed Revisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-7 
 


1.2.4 	 Final Rule Revision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-8 
 


1.2.5	 Compliance Date Amendments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-9 
 


1.3	 Revised Rule Provisions .......................................... 1-9 
 


1.3.1	 Rule Organization .......................................... 1-10 
 

1.3.2 	 Summary of Major Revisions ................................. 1-11 
 

1.4 Using This Guidance ............................................ 1-12 
 

APPLICABILITY OF THE SPCC RULE ............................................ 2-1 
 


2.1 Introduction ..................................................... 2-1 
 


2.1.1	 Summary of General Applicability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 
 


2.2 	 Definition of Oil and Activities Involving Oil . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3 
 


2.2.1	 Animal Fats and Vegetable Oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3 
 


2.2.2 Synthetic Oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3 
 

2.2.3	 Determination of “Oil” for Natural Gas and Hazardous Substances . . . . . 2-4 
 

2.2.4 	 Activities Involving Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-5 
 


2.3 	 “Non-transportation-related” Facilities – EPA/DOT Jurisdiction .......... 2-6 
 

2.3.1	 Definition of Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-6 
 

2.3.2	 Determination of Transportation-related and Non-transportation-related 
 

Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-8 
 


2.3.3	 EPA/DOT Jurisdiction Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-9 
 


2.4	 Reasonable Expectation of Discharge to Navigable Waters in Quantities That
 

May Be Harmful . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-12 
 

2.4.1	 Definition of “Discharge” and “Discharge as Described in §112.1(b)” . . . 2-12
 

2.4.2	 Reasonable Expectation of Discharge . . . . . . . . . . . . . . . . . . . . . . . . . . 2-13 
 

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2.4.3	 Geographic Scope ......................................... 2-14 
 

2.4.4	 Definition of “Navigable Waters” ............................... 2-15 
 

2.5 Storage Capacity ................................................ 2-16 
 

2.5.1	 Capacity Thresholds ........................................ 2-16 
 

2.5.2	 Storage Capacity Calculation ................................. 2-16 
 

2.5.3	 Definition of Storage Capacity ................................ 2-17 
 

2.5.4	 Tank Re-rating ............................................ 2-18 
 

2.6 Exemptions to the Requirements of the SPCC Rule ................... 2-18 
 

2.6.1	 Facilities Subject to Minerals Management Service Regulations ...... 2-18 
 

2.6.2	 Underground Storage Tanks ................................. 2-19 
 

2.6.3	 Wastewater Treatment Facilities ............................... 2-20 
 

2.7 Determination of Applicability by the Regional Administrator ........... 2-21 
 

2.8 SPCC Applicability for Different Types of Containers .................. 2-23 
 

2.8.1	 Bulk Storage Container ...................................... 2-23 
 

2.8.2 	 Oil-filled Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-23 
 

2.9 Determination of Applicability of Facility Response Plans .............. 2-24 
 

2.10 Role of the EPA Inspector ........................................ 2-25 
 

ENVIRONMENTAL EQUIVALENCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 
 


3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 
 

3.2	 Substantive Requirements Subject to the Environmental Equivalence
 

Provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-3 
 


3.3	 Policy Issues Addressed by Environmental Equivalence . . . . . . . . . . . . . . . . 3-4 
 


3.3.1 	 Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-5 
 


3.3.2	 Facility Drainage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-7 
 


3.3.3 	 Corrosion Protection and Leak Testing of Completely Buried Metallic Storage
 

Tanks ................................................... 3-10
 


3.3.4	 Overfill Prevention . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-11 
 


3.3.5 	 Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-12 
 


3.3.6	 Evaluation, Inspection, and Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-15 
 


3.4 Review of Environmental Equivalence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-16 
 


3.4.1 	 SPCC Plan Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-16 
 


3.4.2 	 Role of the EPA Inspector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-19 
 


SECONDARY CONTAINMENT AND IMPRACTICABILITY DETERMINATIONS . . . . . . . . . . . 4-1 
 


4.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 
 


4.2 	 Overview of Secondary Containment Provisions . . . . . . . . . . . . . . . . . . . . . . 4-2 
 

4.2.1	 General Secondary Containment Requirement . . . . . . . . . . . . . . . . . . . . 4-8 
 

4.2.2	 Specific Secondary Containment Requirements . . . . . . . . . . . . . . . . . . . 4-10 
 

4.2.3	 Role of the EPA Inspector in Evaluating Secondary Containment 
 

Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-11 
 


4.2.4	 Sufficient Freeboard . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-12 
 


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4.2.5	 Role of the EPA Inspector in Evaluating Sufficient Freeboard . . . . . . . . 4-16 
 


4.2.6	 Passive versus Active Measures of Secondary Containment . . . . . . . . . 4-16 
 


4.2.7	 Role of the EPA Inspector in Evaluating the Use of Active Measures of
 


Secondary Containment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-20 
 


4.2.8 	 “Sufficiently Impervious” . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-22 
 


4.2.9	 Role of the EPA Inspector in Evaluating “Sufficiently Impervious” . . . . . 4-23 
 


4.2.10 Facility Drainage (Onshore Facilities) . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-25 
 


4.2.11 Role of the EPA Inspector in Evaluating Onshore Facility Drainage . . . . 4-27 
 


4.3	 Overview of the Impracticability Determination Provision . . . . . . . . . . . . . 4-27 
 


4.3.1	 Meaning of “Impracticable” . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-28 
 


4.4	 Selected Issues Related to Secondary Containment and Impracticability
 


Determinations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-28 
 


4.4.1	 General Secondary Containment Requirements, §112.7(c) . . . . . . . . . . 4-29 
 


4.4.2 	 Secondary Containment Requirements for Loading/Unloading Racks,
 


§112.7(h)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-33 
 


4.4.3	 Secondary Containment Requirements for Onshore Bulk Storage 
 


Containers, §112.8(c)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-38 
 


4.4.4	 Secondary Containment Requirements for Mobile/Portable Containers,
 


§112.8(c)(11) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-39 
 


4.4.5	 Secondary Containment Requirements for Bulk Storage Containers at
 


Production Facilities, §112.9(c)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-40 
 


4.4.6	 Secondary Containment Requirements for Onshore Drilling or Workover
 


Equipment, §112.10(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-41 
 


4.5	 Measures Required in Place of Secondary Containment . . . . . . . . . . . . . . . 4-42 
 


4.5.1 	 Integrity Testing of Bulk Storage Containers . . . . . . . . . . . . . . . . . . . . . . 4-42 
 


4.5.2	 Periodic Integrity and Leak Testing of the Valves and Piping . . . . . . . . . 4-43 
 


4.5.3	 Oil Spill Contingency Plan and Written Commitment of Resources . . . . 4-43 
 


4.5.4	 Role of the EPA Inspector in Reviewing Impracticability Determinations 4-45
 


OIL/WATER SEPARATORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 
 


5.1 	
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 
 


5.2 	 Overview of Provisions Applicable to Oil/Water Separators . . . . . . . . . . . . . 5-2 
 


5.3 	 Oil/Water Separators Used in Wastewater Treatment . . . . . . . . . . . . . . . . . . . 5-5 
 


5.3.1	 Description of Oil/Water Separator Use in Wastewater Treatment . . . . . . 5-5 
 


5.3.2	 Applicability of the SPCC Rule to Oil/Water Separators Used for Wastewater
 


Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-6 
 


5.3.3	 Wastewater Treatment Exemption Clarification for Dry Gas Production
 


Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-8 
 


5.4 	 Oil/Water Separators Used To Meet SPCC Secondary Containment
 


Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-8 
 


5.4.1	 Description of Oil/Water Separators Used to Meet SPCC Secondary
 


Containment Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-8 
 


5.4.2	 Applicability of the SPCC Rule to Oil/Water Separators Used to Meet Specific
 


SPCC Secondary Containment Requirements . . . . . . . . . . . . . . . . . . . . . 5-9 
 


5.5 	 Oil/Water Separators Used in Oil Production . . . . . . . . . . . . . . . . . . . . . . . . . 5-11 
 


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5.5.1	 Description of Oil/Water Separators Used in Oil Production .......... 5-11 
 

5.5.2	 Applicability of the SPCC Rule to Oil/Water Separators Used in Oil
 

Production ................................................ 5-13 
 

5.6 	 Documentation Requirements and the Role of the EPA Inspector . . . . . . . 5-15 
 


5.6.1 	 Documentation by Owner/Operator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-15 
 


5.6.2	 Role of the EPA Inspector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-16 
 


FACILITY DIAGRAMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 
 


6.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 
 


6.1.1 	 Purpose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 
 


6.1.2 	 Requirements for a Facility Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 
 


6.2 	 Preparing a Facility Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-2 
 


6.2.1 	 Level of Detail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3 
 


6.2.2.	 Facility Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3 
 


6.2.3 	 Oil Containers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3 
 


6.2.4 	 Mobile or Portable Containers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-4 
 


6.2.5	 Completely Buried Storage Tanks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-4 
 


6.2.6 	 	Piping and Manufacturing Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-5 
 


6.2.7 	 Use of State and Federal Diagrams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-7 
 


6.3 	 Facility Diagram Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-7 
 


6.3.1 	 Example #1: Bulk Storage and Distribution Facility . . . . . . . . . . . . . . . . . 6-7 
 


6.3.2 	 Example #2: Manufacturing Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-11 
 


6.3.3 	 Example #3: Oil Production Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-13 
 


6.4 	 Review of a Facility Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-16 
 


6.4.1 	 Documentation by Owner/Operator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-16 
 


6.4.2 	 Role of the EPA Inspector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-16 
 


INSPECTION, EVALUATION, AND TESTING ...................................... 7-1 
 


7.1 Introduction ..................................................... 7-1 
 


7.2	 	 Inspection, Evaluation, and Testing Under the SPCC Rule .............. 7-1 
 

7.2.1	 Summary of Inspection and Integrity Testing Requirements . . . . . . . . . . . 7-2 
 

7.2.2	 Regularly Scheduled Integrity Testing and Frequent Visual Inspection 
 

of Aboveground Bulk Storage Containers . . . . . . . . . . . . . . . . . . . . . . . . . 7-6 
 


7.2.3 	 Brittle Fracture Evaluation of Field-Constructed Aboveground Containers 7-8
 

7.2.4 	 Inspections of Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-9 
 

7.2.5	 Flowline Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-10 
 

7.2.6	 Role of Industry Standards and Recommended Practices in Meeting SPCC
 

Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-12 
 


7.3 Specific Circumstances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-16 
 

7.3.1	 Aboveground Bulk Storage Container for Which the Baseline Condition Is 
 

Known . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-16 
 

7.3.2	 Aboveground Bulk Storage Container for Which the Baseline Condition Is Not 

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Known . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-17 
 

7.3.3	 Deviation from Integrity Testing Requirements Based on Environmental
 

Equivalence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-19 
 

7.3.4	 Environmental Equivalence Scenarios for Shop-Built Containers . . . . . 7-20 
 

7.4 	 Documentation Requirements and Role of the EPA Inspector . . . . . . . . . . 7-22 
 

7.5	 Summary of Industry Standards and Regulations . . . . . . . . . . . . . . . . . . . . . 7-24 
 

7.5.1	 API Standard 653 – Tank Inspection, Repair, Alteration, and Reconstruction
 

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-25 
 

7.5.2 	 STI Standard SP-001 – Standard for the Inspection of Aboveground Storage 
 

Tanks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-27 
 

7.5.3 	 API Recommended Practice 575 – Inspection of Atmospheric and Low-
 

Pressure Storage Tanks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-29 
 

7.5.4	 API Recommended Practice 12R1 – Recommended Practice for Setting,
 

Maintenance, Inspection, Operation, and Repair of Tanks in Production
 

Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-30 
 

7.5.5	 API 570 – Piping Inspection Code: Inspection, Repair, Alteration, and
 

Rerating of In-service Piping Systems . . . . . . . . . . . . . . . . . . . . . . . . . . 7-31 
 

7.5.6 	 API Recommended Practice 574 – Inspection Practices for Piping System
 

Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-32 
 

7.5.7 	 API Recommended Practice 1110 – Pressure Testing of Liquid Petroleum
 

Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-33 
 

7.5.8 	 API Recommended Practice 579, Fitness-For-Service, Section 3 . . . . . 7-33 
 

7.5.9 	 API Standard 2610 – Design, Construction, Operation, Maintenance, and
 

Inspection of Terminal & Tank Facilities . . . . . . . . . . . . . . . . . . . . . . . . 7-34 
 

7.5.10 ASME B31.3 – Process Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-35 
 

7.5.11 ASME Code for Pressure Piping B31.4-2002 – Pipeline Transportation
 

Systems for Liquid Hydrocarbons and Other Liquids . . . . . . . . . . . . . . . 7-36 
 

7.5.12 DOT 49 CFR 180.605 – Requirements for Periodic Testing, Inspection, and
 

Repair of Portable Tanks and Other Portable Containers . . . . . . . . . . . . 7-37 
 

7.5.13 FAA Advisory Circular 150/5230-4A – Aircraft Fuel Storage, Handling, and
 

Dispensing on Airports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-38 
 

7.5.14 FAA Advisory Circular 150/5210-20 – Ground Vehicle Operations on Airports
 

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-38 
 

7.5.15 Suggested Minimum Requirements for PE-Developed Site-Specific Integrity 

APPENDICES 

Appendix A
 

Appendix B
 

Appendix C
 

Appendix D
 

Appendix E
 

Appendix F
 

Appendix G
 

Appendix H
 

Testing Program (Hybrid Testing Program) . . . . . . . . . . . . . . . . . . . . . . 7-39 
 

Text of CWA 311(j)(1)(c) 

Select Regulations - 40 CFR part 109, 110, and 112 

Summary of Revised Rule Provisions 

Sample Bulk Storage Facility SPCC Plan 

Sample Production Facility SPCC Plan 

Sample Contingency Plan 

SPCC Inspection Checklists 

Other Policy Documents 

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DISCLAIMER
 


This document provides guidance to EPA inspectors, as well as to owners and operators of 

facilities that may be subject to the requirements of the Spill Prevention, Control, and 

Countermeasure (SPCC) rule (40 CFR Part 112) and the general public on how EPA intends the 

SPCC rule to be implemented. The guidance is designed to implement national policy on these 

issues. 

The statutory provisions and EPA regulations described in this guidance document contain 

legally binding requirements. This guidance document does not substitute for those provisions or 

regulations, nor is it a regulation itself. In the event of a conflict between the discussion in this 

document and any statute or regulation, this document would not be controlling. Thus, it does not 

impose legally binding requirements on EPA or the regulated community, and might not apply to a 

particular situation based upon the circumstances. The word “should” as used in this Guide is 

intended solely to recommend or suggest, in contrast to “must” or “shall” which are used when 

restating regulatory requirements. Similarly, model SPCC Plans in Appendices D, E, and F, as well 

as examples of SPCC Plan language in the guidance, are provided as suggestions and illustrations 

only. While this guidance document indicates EPA's strongly preferred approach to assure 

effective implementation of legal requirements, EPA decisionmakers retain the discretion to adopt 

approaches on a case-by-case basis that differ from this guidance where appropriate. Any 

decisions regarding a particular facility will be made based on the statute and regulations. 

Interested parties are free to raise questions and objections about the substance of this 

guidance and the appropriateness of the application of this guidance to a particular situation. This 

guidance is a living document and may be revised periodically without public notice. This document 

will be revised, as necessary, to reflect any relevant future regulatory amendments. EPA welcomes 

public comments on this document at any time and will consider those comments in any future 

revision of this guidance document. 

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EPA OIL PROGRAM CONTACTS 

For more information on the Spill Prevention, Control, and Countermeasure rule, or to 

contact U.S. EPA headquarters and regional offices about this guidance or related issues, please 

refer to the following contact information. Contact information is provided for the National 

Response Center, the sole national point of contact for reporting all oil, chemical, radiological, 

biological, and etiological discharges into the environment anywhere in the United States and its 

territories. 

Superfund, TRI, EPCRA, RMP, and Oil Information Center 

The Superfund, TRI, EPCRA, RMP and Oil Information Center is a publicly accessible service that 

provides up-to-date information on several EPA programs. The Information Center does not provide 

regulatory interpretations, but maintains up-to-date information on the availability of publications 

and other resources. The Information Center is open Monday – Friday from 9:00 a.m. - 5:00 p.m. 

Eastern Time (except federal holidays). 

Toll free: (800) 424-9346 

In the Washington, DC, area: (703) 412-9810 

TDD (800) 553-7672 

TDD in the Washington, D.C. area: (703) 412-3323 

http://www.epa.gov/superfund/resources/infocenter/index.htm 

U.S. EPA Headquarters 

The EPA Office of Emergency Management (OEM) is responsible for EPA’s emergency prevention, 

preparedness, and response duties, including the Oil Program. 

Office of Emergency Management 

Regulatory and Policy Development Division (RPDD) 

Ariel Rios Building – Mail Code 5104A 

1200 Pennsylvania Avenue 

Washington, DC 20460 

www.epa.gov/oilspill 

oilinfo@epa.gov 

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U.S. EPA Regional Offices 

The Oil Program is administered through EPA headquarters and the ten EPA regions, each of 

which is responsible for the execution of EPA programs within several states or territories. Contact 

information for each of the Regional Oil Programs follows. 

Region 1 – CT, ME, MA, NH, RI, VT 

One Congress Street, Suite 1100 

Boston, MA 02114-2023 

Main Number: (617) 918-1111 

Region 2 – NJ, NY, PR, USVI 

2890 Woodbridge Avenue 

Building 209 (MS211) 

Edison, NJ 08837-3679 

Main Number: (732) 321-6654 

SPCC Coordinator: (732) 321-6654 

Region 3 – DE, DC, MD, PA, VA, WV 

1650 Arch Street (3HS32) 

Philadelphia, PA 19103-2029 

Region 3 SPCC/FRP Hotline: 215-814-3452 

Region 4 – AL, FL, GA, KY, MS, NC, SC, TN 

61 Forsyth Street 

Atlanta, GA 30365-3415 

Main Number: (404) 562-9900 

SPCC Coordinator: (404) 562-8705 

Region 5 – IL, IN, MI, MN, OH, WI 

77 West Jackson Boulevard (SE-5J) 

Chicago, IL 60604-3590 

Main Number: (312) 353-2000 

SPCC Coordinator: (312) 886-7187 

Region 6 – AR, LA, NM, OK, TX 

1445 Ross Avenue (6SF-RO) 

Dallas, TX 75202-2733 

Main Number: (214) 665-6444 

SPCC Coordinators: (214) 665-6489, (214)665-2785 

Region 7 – IA, KS, MO, NE 

Storage Tanks & Oil Pollution Branch 

901 North 5th Street 

Kansas City, KS 66101 

EPA Region 7 Operations Center (913) 551-7050 

SPCC Coordinator: (913) 551-7647/ (913) 551-7960 

Region 8 – CO, MT, ND, SD, UT, WY 

999 18th Street, Suite 300 (8EPR-SA) 

Denver, CO 80202-2466 

Main Number: (800) 227-8917 

SPCC Coordinator: (303) 312-6496 

Region 9 – AZ, CA, HI, NV, AS, GU 

75 Hawthorne Street (SFD9-2) 

San Francisco, CA 94105 

Main Number: (800) 231-3075 

SPCC Coordinator: (415) 947-8000 

Region 10 – AK, ID, OR, WA 

1200 6th Avenue (ECL-116) 

Seattle, WA 98101 

Main Number: (800) 424-4372 

SPCC Coordinator: (206) 553-1671 

Alaska 

U.S. EPA Alaska Operations Office 

222 West 7th Ave. #19 

Anchorage, AK 99513-7588 

SPCC Coordinator: (907) 271-5083 

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National Response Center 

The National Response Center (NRC) is the sole federal point of contact for reporting oil, chemical, 

radiological, biological, and etiological discharges into the environment anywhere in the United 

United States Coast Guard (G-OPF) - Room 2611 

2100 2nd Street, SW 

(800) 424-8802 

(202) 267-2675 

Fax: 202-267-1322

 TDD: 202-267-4477 

http://www.nrc.uscg.mil 

States and its territories. The NRC operates 24 hours a day, 7 days a week, 365 days a year. 

Washington, DC 20593-0001 

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ACRONYMS LIST 

AC Advisory Circular 

AFVO Animal Fat and/or Vegetable Oil 

API American Petroleum Institute 

ASME American Society of Mechanical Engineers 

ASNT American Society for Non-Destructive Testing 

AST Aboveground Storage Tank 

ASTM American Society for Testing and Materials 

BMP Best Management Practice 

BOP Blowout Preventer 

CERCLA Comprehensive Environmental Response, Compensation, and Liability Act 

CFR Code of Federal Regulations 

CRDM Continuous Release Detection Method 

CWA Clean Water Act of 1972 (Federal Water Pollution Control Act) 

DOI U.S. Department of Interior 

DOT U.S. Department of Transportation 

EO Executive Order 

EORRA Edible Oil Regulatory Reform Act 

E&P Exploration and Production 

EPA U.S. Environmental Protection Agency 

ERNS Emergency Response Notification System 

FDA Food and Drug Administration 

FAA Federal Aviation Administration 

FR Federal Register 

FRP Facility Response Plan 

GAO General Accounting Office 

GPR General Pretreatment Regulations 

IBC Intermodal Bulk Container 

ICP Integrated Contingency Plan 

IM Intermodal 

MIC Microbial Influenced Corrosion 

MMS Minerals Management Service 

MOU Memorandum of Understanding 

NACE National Association of Corrosion Engineers 

NCP National Contingency Plan 

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NDE Non-Destructive Examination 

NFPA National Fire Protection Association 

NRC National Response Center 

NPDES National Pollutant Discharge Elimination System 

OPA Oil Pollution Act of 1990 

OSHA U.S. Occupational Safety and Health Administration 

PE Professional Engineer 

PMAA Petroleum Marketers Association of America 

POTW Publicly Owned Treatment Work 

PSM Process Safety Management 

RA Regional Administrator 

RBI Risk-Based Inspection 

RP Recommended Practice 

RCRA Resource Conservation and Recovery Act 

RMS Release Management Systems 

SCADA Supervisory Control and Data Acquisition 

SPCC Spill Prevention, Control, and Countermeasure 

STI Steel Tank Institute 

SWANCC Solid Waste Agency of Northern Cook County 

UIC Underground Injection Control 

UL Underwriters Laboratory 

USCG U.S. Coast Guard 

UST Underground Storage Tank 

UT Ultrasonic Thickness 

UTS Ultrasonic Thickness Scans 

UTT Ultrasonic Thickness Testing 

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Chapter 1: Introduction 

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 INTRODUCTION

 In 2002, the U.S. Environmental Protection Agency (EPA) amended the Oil Pollution 

Prevention regulation (40 CFR part 112), which includes requirements for specific facilities to 

prepare, amend, and implement Spill Prevention, Control, and Countermeasure (SPCC) Plans. 

The regulation is largely performance-based (as requested in comments from the regulated 

community), which allows flexibility in meeting the rule requirements to prevent discharges of oil to 

navigable waters and adjoining shorelines. EPA developed this guidance document to assist 

regional inspectors in implementing the SPCC program and in understanding its applicability, and 

to help clarify the role of the inspector in reviewing a facility’s implementation of performancebased flexibility provisions, such as environmental equivalence and impracticability. 

1.1 SPCC Background

The Oil Pollution Prevention regulation, 

promulgated under the authority of §311 of the Clean 

Water Act (CWA), sets forth requirements for 

prevention of, preparedness for, and response to oil 

discharges at specific non-transportation-related 

facilities. To prevent oil from reaching navigable 

waters and adjoining shorelines, and to contain 

discharges of oil, the regulation requires these 

facilities to develop and implement SPCC Plans and 

establishes procedures, methods, and equipment 

requirements.

1.1.1 Purpose and Scope 

 Subparts A through C of part 112 are often referred to as the “SPCC rule.” Focusing on oil 

spill prevention, preparedness, and response, the SPCC rule is designed to protect public health, 

public welfare, and the environment from potential harmful effects of oil discharges to navigable 

waters and adjoining shorelines. The rule requires facilities that could reasonably be expected to 

discharge oil in quantities that may be harmful into navigable waters of the United States and 

adjoining shorelines to develop and implement SPCC Plans. The Plans ensure that these facilities 

put in place containment and countermeasures that will prevent oil discharges. The requirement to 

develop, implement, and revise the SPCC Plan, as well as train employees to carry it out, will allow 

owners and operators to achieve the goal of preventing, preparing for, and responding to oil 

discharges that threaten navigable waters and adjoining shorelines. 

§112.2

Spill Prevention, Control, and 

Countermeasure Plan; SPCC Plan, or Plan

means the document required by §112.3 

that details the equipment, workforce, 

procedures, and steps to prevent, control, 

and provide adequate countermeasures to 

a discharge. 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule.
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 Part 112 also includes requirements for Facility Response Plans (FRPs). EPA has 

established requirements that define who must prepare and submit an FRP and what must be 

included in the Plan. These requirements are found in Subpart D of 40 CFR part 112, which is 

often referred to as the “FRP rule.”1

 Although the SPCC and FRP rules are related, and certain 

SPCC-regulated facilities must also comply with FRP requirements, this guidance document 

concerns the prevention requirements of the SPCC rule (40 CFR part 112, subparts A, B, and C). 

 The SPCC rule carries out EPA’s authority under CWA §311. Pursuant to Executive Order 

11548, EPA was delegated the authority to regulate non-transportation-related onshore and 

offshore facilities that could reasonably be expected to discharge oil into navigable waters of the 

United States or adjoining shorelines (35 FR 11677, July 22, 1970). Executive Order 11548 was 

superceded by Executive Orders 11735 and 12777, respectively (38 FR 21243, August 7, 1973; 56 

FR 54757, October 22, 1991). The U.S. Department of Transportation (DOT) was delegated 

authority over transportation-related onshore facilities, deepwater ports, and vessels. A 

Memorandum of Understanding (MOU) between the Secretary of Transportation and the EPA 

Administrator, dated November 24, 1971 (36 FR 24080, December 18, 1971), defines nontransportation-related facilities and transportation-related facilities. (A significant portion of this 

MOU is included as Appendix A to 40 CFR part 112.) In addition, the U.S. Department of the 

Interior (DOI) regulates specific offshore facilities, including associated pipelines. The jurisdictional 

responsibilities of EPA, DOT, and DOI in relation to offshore facilities are further discussed in 

another Memorandum of Understanding, dated November 8, 1993. (This MOU is included as 

Appendix B to 40 CFR part 112.) 

1.1.2 Statutory Framework 

 The Federal Water Pollution Control Act of 1972, as amended, or Clean Water Act, is the 

principal federal statute for protecting navigable waters, adjoining shorelines, and the waters of the 

contiguous zone from pollution. Section 311 of the CWA addresses the control of oil and 

hazardous substance discharges, and provides the authority for a program to prevent, prepare for, 

and respond to such discharges. Specifically, §311(j)(1)(C) mandates regulations establishing 

procedures, methods, equipment, and other requirements to prevent discharges of oil from vessels 

and facilities and to contain such discharges. (See Appendix A of this guidance document for the 

text of CWA §311(j)(1)(C).) 

 1

 The FRP rule applies to a subset of SPCC facilities: those that (1) have 42,000 gallons or more of oil storage capacity and 

transfer oil over water to or from vessels, or (2) have 1,000,000 gallons or more of oil storage capacity and lack secondary containment, 

are located at a distance such that a discharge from the facility could cause injury to fish and wildlife and sensitive environments or shut 

down a public water intake, or have experienced a reportable oil spill in an amount greater than or equal to 10,000 gallons within the last 

5 years. See 40 CFR 112.20.
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 Under CWA §311(a)(1), “oil” is defined to 

mean “oil of any kind or in any form...” In 1975, EPA 

published a notice on the applicability of the SPCC 

rule to non-petroleum oils. The notice confirmed that 

all facilities processing and storing non-petroleum oils 

in the quantities and under circumstances set out in 

40 CFR part 112 are required to prepare and 

implement an SPCC Plan in accordance with that 

part (40 FR 28849, July 9, 1975). EPA stated that 

the broad and comprehensive definition of “oil” in the 

CWA is consistent with the expressed congressional 

intent to strengthen federal law for the prevention, 

control, and cleanup of oil spilled in the aquatic 

environment. Both EPA and the U.S. Coast Guard2

consistently interpreted and administered §311 as applicable to spills of non-petroleum-based oils, 

particularly because of the common physical and chemical properties of animal and vegetable oils 

and petroleum oils, and their common potential for adverse environmental impact when discharged 

into water. 

 The Oil Pollution Act of 1990 (OPA) streamlined and strengthened EPA’s ability to prevent, 

prepare for, and respond to catastrophic oil discharges. Specifically, OPA expands prevention and 

preparedness activities, improves response capabilities, ensures that shippers and owners or 

operators of facilities that handle oil pay the costs of discharges that do occur, expands research 

and development programs, and establishes an Oil Spill Liability Trust Fund. OPA §4202(a)(6) 

amended CWA §311(j) to require regulations to be promulgated that require owners or operators 

of certain vessels and facilities to prepare and submit Facility Response Plans (FRPs) for 

responding to a worst case discharge of oil and to a substantial threat of such a discharge (CWA 

§311(j)(5)). EPA published the FRP rule on July 1, 1994, as an amendment to 40 CFR part 112. 

The FRP requirement for onshore facilities applies to any facility that, “because of its location, 

could reasonably be expected to cause substantial harm to the environment by discharging into or 

on the navigable waters, adjoining shorelines, or the exclusive economic zone.” 

 In 1995, Congress enacted the Edible Oil Regulatory Reform Act (EORRA). The statute 

mandates that most federal agencies differentiate between and establish separate classes for 

various types of oils; specifically, animal fats and oils and greases, fish and marine mammal oils, 

oils of vegetable origin, and other oils and greases (including petroleum). In differentiating 

between these classes of oils, EORAA directed federal agencies to consider differences in these 

oils’ physical, chemical, biological, and other properties, and in their environmental effects. By an 

August 12, 1994, letter submitted on behalf of several agricultural organizations, EPA received a 

Petition for Reconsideration of the FRP rule as it applies to facilities that handle, store, or transport 

 2 DOT delegated authority over transportation-related facilities and vessels to the U.S. Coast Guard. In March 2003, the 

Coast Guard formally transferred from DOT to the Department of Homeland Security, but retains this CWA authority (Executive Order 

13286, 68 FR 10619, March 5, 2003).

§112.2

Oil means oil of any kind or in any form, 

including, but not limited to: fats, oils, or 

greases of animal, fish, or marine mammal 

origin; vegetable oils, including oils from 

seeds, nuts, fruits, or kernels; and, other oils 

and greases, including petroleum, fuel oil, 

sludge, synthetic oils, mineral oils, oil 

refuse, or oil mixed with wastes other than 

dredged spoil.

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule.
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animal fats or vegetable oils.3 On October 20, 1997, EPA denied the petition to amend the FRP 

rule (62 FR 54508) because it did not substantiate the petitioner’s claims that animal fats and 

vegetable oils differ from petroleum oils in properties and effects and concluded that the facts did 

not support a further differentiation between these groups of oils under the FRP rule. Instead, EPA 

found that a worst case discharge or substantial threat of a discharge of animal fats and vegetable 

oils to navigable waters, adjoining shorelines, or the exclusive economic zone could reasonably be 

expected to cause substantial harm to the environment, including wildlife that may be killed by the 

discharge. 

 However, in the June 30, 2000, amendments to the FRP rule, in response to EORRA 

requirements, EPA promulgated a separate approach for calculating planning volumes for a worst 

case discharge in the FRPs for animal fat and vegetable oil facilities (65 FR 40776). 

 EPA also published an advanced notice of proposed rulemaking requesting ideas from the 

public on how to differentiate among the SPCC requirements for facilities storing or using various 

categories of oil (64 FR 17227, April 8, 1999). In the 2002 revision of the SPCC rule, EPA 

provided new subparts to facilitate differentiation between categories of oil listed in EORRA; 

however, the requirements in each of the subparts are identical. 

1.2 Regulatory History

 The SPCC rule was initially promulgated in 1973, with modifications to the SPCC 

requirements proposed for public comment on several occasions in the 1990s. Incorporating many 

aspects of the earlier proposals, final revisions to the rule were published in the Federal Register

(FR) in July 2002. However, EPA extended the compliance dates in the SPCC rule for amending 

existing SPCC Plans and for implementing amended or new Plans developed under revised 40 

CFR part 112. EPA extended the dates to give owners and operators of affected facilities more 

time to understand the revised requirements, to amend and implement their SPCC Plans that 

comply with the revised requirements, and to understand the SPCC rule clarifications developed 

during settlement proceedings in response to legal challenges filed by the regulated community 

(see 69 FR 29728, May 25, 2004). 

1.2.1 Initial Promulgation 

The original SPCC rule proposal was published in the Federal Register on July 19, 1973 

(38 FR 19334). The original SPCC final rule was published in the Federal Register on December 

11, 1973, with an effective date of January 10, 1974 (38 FR 34164). The regulation established oil 

discharge prevention procedures, methods, and equipment requirements for non-transportationrelated facilities with an aboveground (non-buried) oil storage capacity greater than 1,320 gallons

 3 “Petition for Reconsideration and Stay of Effective Date,” August 12, 1994, submitted on behalf of the American Soybean 

Association, the Corn Refiners Association, the National Corn Growers Association, the Institute of Shortening & Edible Oils, the 

National Cotton Council, the National Cottonseed Products Association, and the National Oilseed Processors Association.
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(or greater than 660 gallons aboveground in a single tank) or a buried underground oil storage 

capacity greater than 42,000 gallons. Regulated facilities were also limited to those that, because 

of their location, could reasonably be expected to discharge oil into the navigable waters of the 

United States or adjoining shorelines. The rule included sections on general applicability, relevant 

definitions, and requirements for preparation of SPCC Plans; provisions for SPCC Plan 

amendments; civil penalty provisions; and requirements for the substance of the SPCC Plans. 

 Two early revisions were made to the original SPCC rule. On August 29, 1974, the 

regulation was amended (39 FR 31602) to set out EPA’s policy on civil penalties for violation of the 

CWA §311 requirements. On March 26, 1976, the rule was again amended (41 FR 12567), 

primarily to clarify the criteria for determining whether or not a facility is subject to the regulation. 

This rulemaking also clarified that SPCC Plans must be in a written form (§112.7, introductory 

paragraph) and specified procedures for developing SPCC Plans for mobile facilities.4

 

1.2.2 SPCC Task Force and GAO Recommendations 

In January 1988, a four-million gallon 

aboveground storage tank in Floreffe, Pennsylvania, 

experienced a brittle fracture of the tank shell, which 

then split apart, collapsed, and released approximately 

3.8 million gallons of diesel fuel. Of this amount, 

approximately 750,000 gallons were discharged into the 

Monongahela River. The spill temporarily contaminated 

drinking water sources, damaged the ecosystems of the 

Monongahela and Ohio rivers, and negatively affected 

private property and local businesses. Following the 

discharge, an SPCC Task Force was formed to 

examine federal regulations governing discharges from 

aboveground storage tanks. The Task Force, 

consisting of representatives from EPA headquarters 

and regions, other federal agencies, and the states, 

issued its findings and recommendations in May 1988. 

The findings focused on the prevention of catastrophic 

discharges and recommended changes to the SPCC 

program (EPA, “The Oil Spill Prevention, Control, and 

Countermeasures Program Task Force Report,” Interim 

Final Report, May 13, 1988).5

 4 Mobile facilities include onshore drilling or workover rigs, barge-mounted offshore drilling or workover rigs, and portable 

fueling facilities.

5 Available in EPA docket OPA-1991-0001.

Figure 1-1. Aboveground storage tank in 

Floreffe, Pennsylvania
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 Specifically, the Task Force recommended that EPA establish additional technical 

requirements for SPCC Plan preparation and implementation, including: 

• Adopting industry standards for new and relocated tanks; 

• Differentiating SPCC requirements based on facility size; 

• Modifying timeframes for SPCC Plan preparation, implementation, and review; 

• Requiring strengthened integrity testing and periodic inspection of tanks and 

secondary containment; 

• Requiring a more stringent attestation for a Professional Engineer to certify an 

SPCC Plan; 

• Ensuring that employees undergo response training; and 

• Modifying definitions and providing additional preamble discussion. 

The Task Force also recommended that EPA expand the scope of the regulation to include 

requirements for facility-specific contingency planning and to specify countermeasures to be 

employed if a discharge should extend beyond the site in an uncontrolled manner. To better 

identify violations and enforce compliance, the Task Force recommended that EPA strengthen its 

facility inspection program. The Task Force also found that EPA did not have an adequate 

inventory of facilities subject to the regulation, and that improvements in national response 

coordination may be possible. Finally, the Task Force commented on the role of state and local 

resources and other federal agencies in oil discharge prevention and response efforts, and also 

recommended funding research on the development of oil discharge removal and control 

technology. 

 In response to both the Monongahela River spill and an oil spill at an oil refinery in 

Martinez, California, in April 1988, the General Accounting Office (GAO) examined the adequacy 

of the federal regulations of aboveground oil storage tanks and the extent to which they addressed 

the unique problems of inland oil discharges. GAO’s report, “Inland Oil Spills: Stronger Regulation 

and Enforcement Needed to Avoid Future Incidents,” contained recommendations on regulations, 

inspections, enforcement, and government response that were similar to those of the SPCC Task 

Force (February 1989, GAO/RCED-89-65).6

 To amend the SPCC regulation, GAO made 

recommendations to the EPA Administrator that EPA require: 

• Aboveground oil storage tanks to be built and tested in accordance with industry 

and other specified standards; 

• Facilities to plan how to react to a spill that overflows facility boundaries; and 

• Storm water drainage systems to be designed and operated to prevent oil from 

escaping through them. Oil escaped through the drainage system during the oil 

spill in Martinez, California. 

 6 Available in EPA docket OPA-1991-0001.
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 For inspections, GAO recommended that EPA (1) strengthen its aboveground oil storage 

facility inspection program by coordinating with state and local authorities, developing procedures 

for conducting and documenting inspections, defining and implementing minimum training 

procedures for inspectors, and establishing a national policy for fining violators; and (2) consider 

advantages and disadvantages of supplementing EPA inspection resources with state and local 

inspection resources and requiring that facilities obtain certification from independent engineers 

that facilities are in compliance with the regulations. Finally, the report also included a 

recommendation to Congress that it amend the CWA to explicitly authorize the federal government 

to recover the costs of monitoring oil spill cleanups performed by private responsible parties, and 

to EPA that it consider re-establishing the oil spill research and development program. 

1.2.3 Proposed Revisions 

 Following the Monongahela River spill and recommendations of the SPCC Task Force and 

GAO, EPA proposed substantive revisions to the SPCC requirements on three occasions (1991, 

1993, and 1997) and solicited public comment on these revisions. Specifically: 

• On October 22, 1991 (56 FR 54612), EPA proposed changes in the applicability of 

the SPCC rule and in the required procedures for completing SPCC Plans, as well 

as the addition of a facility notification provision. The proposed rule also reflected 

changes in the jurisdiction of CWA §311 made by the 1977 and 1978 amendments 

to the Act. 

• On February 17, 1993 (58 FR 8824), EPA published an additional proposed rule to 

incorporate new requirements added by OPA that directed facility owners and 

operators to prepare plans for responding to a worst case discharge of oil and to a 

substantial threat of such a discharge (the FRP rule). EPA promulgated the FRP 

rule on July 1, 1994 (59 FR 34070). The 1993 proposed rule also included 

revisions to the SPCC requirements, including: (1) a requirement for an SPCC Plan 

to address training and methods of evaluating containers for protection against 

brittle fracture; (2) provisions for Regional Administrators to require amendments to 

an SPCC Plan and to require a Plan from an otherwise exempt facility when 

necessary to achieve the goals of the CWA; and (3) a requirement for Plan 

submission if an owner or operator invokes a waiver to certain technical 

requirements of the SPCC rule. 

• On December 2, 1997 (62 FR 63812), EPA proposed further revisions to the SPCC 

rule in an effort to reduce the information collection burden without creating an 

adverse impact on public health or the environment. The proposed revisions were 

intended to give facility owners and operators flexibility to use alternative formats 

for SPCC Plans; to allow the use of certain records maintained pursuant to usual 

and customary business practices, or pursuant to the National Pollutant Discharge 

Elimination System (NPDES) program, in lieu of records mandated by the SPCC 
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requirements; to reduce the information required to be submitted after certain 

discharges; and to extend the interval between SPCC Plan reviews by the facility 

owner/operator. At this time, EPA also proposed amendments to the FRP 

requirements, which were finalized on June 30, 2000 (65 FR 40776). 

1.2.4 Final Rule Revision 

 On July 17, 2002, EPA issued a final rule amending the Oil Pollution Prevention regulation, 

primarily with respect to the SPCC subparts of part 112 (67 FR 47042). The final rule became 

effective on August 16, 2002, and modified many aspects of the proposals described above. As a 

performance-based regulation, the rule provides flexibility to the regulated community in meeting 

many of the oil discharge prevention requirements and the overall goal of preventing oil spills that 

may impact navigable waters or adjoining shorelines. In addition, the final rule includes new 

subparts outlining the requirements for various classes of oil (pursuant to EORRA), revises the 

applicability of the regulation, amends the requirements for completing SPCC Plans, and makes 

other modifications. The final rule also contains a number of provisions designed to decrease 

regulatory burden on facility owners and operators subject to the rule, while preserving 

environmental protection. 

 In response to the final SPCC amendments, several members of the regulated community 

filed legal challenges to certain aspects of the rule.7

 Settlement discussions between EPA and the 

plaintiffs led to an agreement on all issues except the definition of navigable waters. On May 25, 

2004, EPA published a notice in the Federal Register (69 FR 29728) clarifying specific provisions 

of the SPCC rule that it developed in the course of settlement. The Federal Register notice 

clarified statements regarding loading/unloading racks and impracticability that were challenged by 

the plaintiffs. In addition, EPA clarified aspects of the wastewater treatment exemption and 

specified which definition of “facility” applies to §112.20(f)(1). EPA also announced the availability 

of a letter from EPA to the Petroleum Marketers Association of America (PMAA), which provides 

additional guidance on equivalent environmental protection with respect to requirements for 

integrity testing, security, and loading racks.8

 The specific amendments to the SPCC rule are discussed in more detail in Section 1.3, 

Revised Rule Provisions, below, as well as in Appendix C, Summary of Revised SPCC Rule 

Provisions. 

 7 See American Petroleum Institute v. Leavitt et al., No. 1;102CV02247 PLF and consolidated cases (D.D.C. filed November 

14, 2002). Lead plaintiffs in the cases were the American Petroleum Institute, Marathon Oil Co., and the Petroleum Marketers 

Association of America.

8 The Federal Register Notice and letter to PMAA are available on the Oil Program Web site, http://www.epa.gov/oilspill.
Chapter 1: Introduction 

U.S. Environmental Protection Agency 1-9 Version 1.1, 03/14/2006

1.2.5 Compliance Date Amendments 

 Following the 2002 final rule, on four occasions EPA extended the compliance dates for 

facilities to update (or for new facilities to prepare) and implement an SPCC Plan that complies 

with the revised requirements. The extensions provided additional time for the regulated 

community to understand the SPCC amendments and the implications of the settlement 

clarifications, and alleviated the need for individual extension requests. 

 EPA issued final rules in 2003, 2004, and 2006 (68 FR 1348, January 9, 2003; 68 FR 

18890, April 17, 2003; 69 FR 48794, August 11, 2004; and 71 FR 8462, February 17, 2006) that 

each extended the compliance dates in §112.3(a) and (b). The 2004 and 2006 final rules also 

amended the compliance dates for onshore and offshore mobile facilities (§112.3(c)). The current 

compliance dates in §112.3(a) and (b) for facilities are as follows: 

 

A facility starting operation... Must...

On or before August 16, 2002 Maintain the facility’s existing SPCC Plan. 

Amend and implement the SPCC Plan no later than 

October 31, 2007. 

After August 16, 2002, 

through October 31, 2007 

Prepare and implement an SPCC Plan no later than 

October 31, 2007. 

After October 31, 2007 Prepare and implement an SPCC Plan before beginning 

operations. 

Mobile facilities must prepare, implement, and maintain a Plan as required by the SPCC rule. They 

must amend and implement the Plan, if necessary to ensure compliance with the revised SPCC 

rule, on or before October 31, 2007. Mobile facilities that become operational after October 31, 

2007, must prepare and implement a Plan before starting operations (§112.3(c)). 

1.3 Revised Rule Provisions

 The 2002 revision to the SPCC rule clarifies the language and organization of the 

regulation, makes technical changes, and reduces regulatory burden. This section provides an 

overview of the rule’s organization and highlights some of the more substantive changes made to 

the rule. 

 For the inspector’s reference, Appendix B of this document includes the Oil Pollution 

Prevention regulation, 40 CFR part 112, in its entirety and current as of the publication of this 

document. Since the regulation is subject to change, this appendix is provided for informational 

purposes only. The Federal Register, the official daily publication for rules, proposed rules, and 

notices of federal agencies and organizations, is available electronically from the Government 

Printing Office Web site at http://www.gpoaccess.gov/fr/. General and permanent rules published 

in the Federal Register are also codified in the Code of Federal Regulations (CFR), available 
SPCC Guidance for Regional Inspectors 

U.S. Environmental Protection Agency 1-10 Version 1.1, 03/14/2006

electronically at http://www.gpoaccess.gov/cfr/. Inspectors implementing the SPCC program 

should always consult the aforementioned resources (or their equivalent) to obtain the current 

version of the SPCC rule. 

1.3.1 Rule Organization 

 Part 112 is divided into four subparts, according to the oil and facility type. Subparts A, B, 

and C address oil discharge prevention requirements and are commonly referred to as the “SPCC 

rule.” Subpart D, commonly referred to as the “FRP rule,” addresses facility response planning 

requirements in the event of an oil discharge, and includes the FRP requirements and facility 

response training and drill requirements. The part is organized as follows: 

Subpart A Applicability, definitions, and general requirements for all facilities and all 

types of oil 

Subpart B Requirements for petroleum oils and non-petroleum oils, except those 

covered in Subpart C 

Subpart C Requirements for animal fats and oils and greases, and fish and marine 

mammal oils; and for vegetable oils, including oils from seeds, nuts, fruits, 

and kernels 

Subpart D Response requirements 

 Pertaining to all oil and facility types, Subpart A contains key sections of the SPCC rule, 

including: 

§112.1 General Applicability 

§112.2 Definitions 

§112.3 Requirement to Prepare and Implement an SPCC Plan 

§112.4 Amendment of an SPCC Plan by Regional Administrator 

§112.5 Amendment of an SPCC Plan by Owners or Operators 

§112.7 General Requirements for SPCC Plans 
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 Additional requirements for specific facility types are given in §§112.8 through 112.12,9 and 

are found within subparts B and C. These facility types and their corresponding sections of the rule 

are: 

Onshore Facilities (excluding production facilities) §§112.8 and 112.12 

Oil Production Facilities (onshore) §112.9 

Oil Drilling and Workover Facilities (onshore) §112.10 

Oil Drilling, Production, or Workover Facilities (offshore) §112.11 

 The Oil Pollution Prevention regulation also contains several appendices, including 

Memoranda of Understanding and appendices referenced in the FRP rule (Substantial Harm 

Criteria, Determination of a Worst Case Discharge Planning Volume, Determination and Evaluation 

of Required Response Resources for Facility Response Plans, and a model Facility-Specific 

Response Plan). 

1.3.2 Summary of Major Revisions 

 The 2002 final SPCC rule is a performance-based regulation that allows owners, operators, 

and the certifying Professional Engineer (PE) flexibility in meeting many of the prevention 

requirements. Assisting inspectors in the evaluation of the proper use of environmental 

equivalence and impracticability is one of the primary objectives of this guidance document. The 

“environmental equivalence” provision allows facilities to deviate from specified substantive 

requirements of the SPCC rule (except secondary containment provisions) by implementing 

alternate measures, certified by a PE, that provide equivalent environmental protection. Deviations 

are not allowed for the administrative provisions of the rule, §§112.1 through 112.5, and for certain 

additional requirements in §112.7, such as recordkeeping and training provisions. Additionally, in 

situations where secondary containment is not practicable, the owner/operator must clearly explain 

the reason for the determination in the SPCC Plan; for bulk storage containers, conduct periodic 

integrity testing of containers and associated valves and piping; and prepare an oil spill 

contingency plan and a written commitment of manpower, equipment, and materials to 

expeditiously control and remove any quantity of oil discharged that may be harmful (§112.7(d)). 

 The 2002 final rule revised many of the rule provisions, both to provide regulatory relief and 

to make technical changes. The rule exempts many completely buried tanks, containers storing 

less than 55 gallons, and certain wastewater treatment operations/facilities; raises the regulatory 

threshold; and both reduces information required after a discharge and raises the regulatory trigger 

for its submission. In addition, the rule decreased the frequency of Plan review from every three 

years to every five years. 

 9 The 2002 SPCC rule includes requirements within subpart C that are not applicable or are inappropriate for animal fats and 

vegetable oils. As a result, §§112.13 through 112.15 are not included here. These sections were promulgated because EPA had not 

proposed differentiated SPCC requirements for public notice and comment.
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 Technical changes to the rule include requiring brittle fracture evaluation for fieldconstructed aboveground containers; strengthening the integrity testing requirements; finalizing 

additional general requirements for spill planning, preparedness, and reporting; adding a 

requirement for a facility diagram; clarifying the rule’s applicability to the operational use of oil; and 

making the PE certification and associated attestation more specific. Also, the rule allows 

alternative formats for SPCC Plans with a cross-reference and mandates specific time frames for 

employee training. 

 The specific amendments to each section of the SPCC rule are highlighted in Appendix C 

of this document, Summary of Revised SPCC Rule Provisions. Also, Chapter 2 of this document 

discusses in greater detail the applicability of the revised SPCC rule, including facilities, activities, 

and equipment subject to SPCC requirements. 

1.4 Using This Guidance

SPCC Guidance for Regional Inspectors is 

intended to assist EPA regional inspectors in 

implementing the revised SPCC rule, including 

environmental equivalence, impracticability, and 

integrity testing, as well as the role of the inspector in 

the review of these provisions. This guidance does not 

address all aspects of the SPCC rule. It is intended to 

establish a consistent understanding among regional 

EPA inspectors on how certain provisions of the rule 

may be applied. It is not, however, a substitute for the 

regulation itself. 

 Many of the terms used in this guidance document have specific regulatory definitions in 40 

CFR 112.2; however, other regulatory programs may define some of these terms differently. 

Please refer to §112.2 of the rule and associated preamble of the July 2002 Federal Register

publication for clarification of defined terms in the SPCC rule. An Acronyms List, provided at the 

beginning of this document, defines all acronyms used throughout the guidance. 

 This document is divided into seven main chapters and includes several appendices for the 

reader’s reference, as follows: 

Chapter 1: Introduction discusses the purpose and scope of the 40 CFR part 112, the 

regulatory history, and the July 2002 amendments. 

Chapter 2: Applicability of the SPCC Rule clarifies the facilities, activities, and equipment 

that are subject to the SPCC rule through an in-depth discussion of the rule and relevant 

scenarios. 

Throughout the document, excerpts of the 

SPCC rule that are relevant to a particular 

section of this document are provided in 

text boxes. This information is provided 

for informational purposes only. The 

reader should always refer to the full text 

of the current 40 CFR part 112 for the 

applicable regulatory language, available 

from the Government Printing Office Web 

site at http://www.gpoaccess.gov/fr/.
Chapter 1: Introduction 

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Chapter 3: Environmental Equivalence discusses the use of the “environmental 

equivalence” provision, which allows facilities to implement alternate measures based on 

site-specific considerations, as long as the measures provide equivalent environmental 

protection, in accordance with good engineering practice and as determined by a PE. 

Chapter 4: Secondary Containment and Impracticability Determinations discusses the 

secondary containment requirements and explains when an impracticability determination 

can be made and how the determination should be documented. 

Chapter 5: Oil/Water Separators addresses various scenarios involving oil/water 

separators with respect to the SPCC rule requirements. 

Chapter 6: Facility Diagrams provides guidelines on the necessary level of detail for 

facility diagrams included in SPCC Plans. This section also includes example facility 

diagrams for different types of facilities. 

Chapter 7: Inspections, Evaluation, and Testing explains the inspection, evaluation, and 

testing requirements for facilities subject to the SPCC rule, as well as how “environmental 

equivalence” may apply for the integrity testing requirements of the SPCC rule. 

The appendices include a complete copy of the relevant sections of the statutory authority from the 

Clean Water Act; the Oil Pollution Prevention regulation (40 CFR part 112); the Discharge of Oil 

regulation (40 CFR part 110); the Criteria for State, Local and Regional Oil Removal Contingency 

Plans (40 CFR part 109); a summary of revised rule provisions; inspector checklists; model SPCC 

Plans; and a model contingency plan. 
Chapter 2: Applicability 

APPLICABILITY OF THE SPCC RULE 

2.1 Introduction 

The SPCC rule regulates non-transportation-related onshore and offshore facilities that 

could reasonably be expected to discharge oil into navigable waters of the United States or 

adjoining shorelines. This chapter clarifies the facilities, activities, and equipment that are subject 

to the SPCC rule. It is the responsibility of the facility owner/operator to make the determination 

whether the facility is subject to the requirements of the SPCC rule. This determination is subject to 

review by the Regional Administrator or his delegated representative. 

2.1.1	 Summary of General Applicability 

Section 112.1 establishes the general 

applicability of the SPCC rule by describing both the 

facilities, activities, and equipment that are subject to 

the rule and those that are excluded. In general, 

SPCC-regulated facilities are non-transportationrelated, have aboveground oil storage capacity of 

more than 1,320 gallons on site, and could reasonably 

be expected to discharge oil to navigable waters or 

adjoining shorelines in quantities that may be harmful. 

Facilities owned and operated by federal government 

agencies are subject to the regulation to the same 

extent as any other facility (although the federal 

government is not subject to civil penalties). Likewise, 

facilities owned and operated by state and local 

governments are subject to the regulation. Section 

112.1(d) describes the facilities, activities, and equipment excluded from the rule based on 

jurisdiction or through exemptions or exclusions from storage capacity calculations. Exemptions 

pertain to whether a facility or part thereof is included in the SPCC-regulated universe, and 

exclusions from storage capacity determine which containers count when determining a facility’s 

total oil storage capacity. In addition to facilities that are excluded from the SPCC rule because 

they are not subject to EPA’s jurisdiction, §112.1(d) exempts: 

§112.1(b) 

...this part applies to any owner or operator 

of a non-transportation-related onshore or 

producing, gathering, storing, processing, 

refining, transferring, distributing, using, or 

consuming oil and oil products, which 

due to its location, could reasonably be 

expected to discharge oil in quantities that 

may be harmful, as described in part 110 

of this chapter, into or upon the navigable 

waters of the United States or adjoining 

shorelines... 

Note: The above text is an excerpt of the SPCC rule. 

full text of the rule. 

offshore facility engaged in drilling, 

Emphasis added. Refer to 40 CFR part 112 for the 

•	 Any facility where the storage capacity of completely buried storage tanks and 

associated piping and equipment does not exceed 42,000 gallons and the aggregate 

aboveground storage capacity does not exceed 1,320 gallons; 

•	 Any container with a storage capacity less than 55 gallons at a facility, whether or 

not subject to the requirements of the SPCC rule; and 

•	 Any facility or part thereof used exclusively for wastewater treatment. 

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Exclusions from storage capacity calculations include: 

•	 Containers with a storage capacity of less than 55 gallons; 

•	 Storage containers used exclusively in wastewater treatment; 

•	 Completely buried tanks and associated piping and equipment that are subject to all 

of the technical requirements under 40 CFR part 280 or 281; and 

•	 The capacity of any “permanently closed” aboveground storage container. 

Notwithstanding the exemptions and exclusions provided in §112.1(d), under §112.1(f) the 

Regional Administrator has discretion to require the owner or operator of any facility, subject to 

EPA’s jurisdiction under §311(j) Clean Water Act (CWA), to submit an SPCC Plan, or part of an 

SPCC Plan, in order to carry out the purposes of the CWA. 

This chapter further explains each of the applicability criteria listed in §112.1 and provides 

examples of how these criteria are applied. The remainder of this chapter is organized as follows: 

•	 Section 2.2 discusses the definition of “oil” and the regulated activities. 

•	 Section 2.3 discusses the difference between “transportation-related” and “nontransportation-related” facilities in determining jurisdiction of regulatory agencies. 

•	 Section 2.4 discusses the term “reasonable expectation of discharge to navigable 

waters in quantities that may be harmful.” 

•	 Section 2.5 addresses the storage capacity thresholds and the methods of 

calculating storage capacity. 

•	 Section 2.6 addresses the exemptions to the SPCC rule. 

•	 Section 2.7 discusses the process for a Regional Administrator to determine 

applicability, outside of §112.1(d) requirements. 

•	 Section 2.8 addresses the applicability of the rule requirements to oil-filled 

equipment (including manufacturing or process equipment), in contrast to bulk 

storage containers. 

•	 Section 2.9 discusses the applicability of Facility Response Plans (FRPs). 

•	 Section 2.10 describes the role of the EPA inspector. 

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2.2 Definition of Oil and Activities Involving Oil 

The SPCC rule applies to facilities with the 

potential to discharge “oil” in quantities that may be 

harmful to navigable waters and adjoining shorelines. 

The SPCC rule’s definition of oil originated from the 

Clean Water Act (CWA). Section 311(a)(1) of the 

CWA defines oil as “oil of any kind or in any form, 

including, but not limited to, petroleum, fuel oil, 

sludge, oil refuse, and oil mixed with wastes other 

than dredged spoil.” Petroleum oils include crude 

and refined petroleum products, asphalt, gasoline, 

fuel oils, mineral oils, naphtha, sludge, oil refuse, and 

oil mixed with wastes other than dredged spoil (67 FR 

47075). 

§112.2

Oil means oil of any kind or in any form, 

including, but not limited to: fats, oils, or 

greases of animal, fish, or marine mammal 

origin; vegetable oils, including oils from 

seeds, nuts, fruits, or kernels; and, other 

oils and greases, including petroleum, fuel 

oil, sludge, synthetic oils, mineral oils, oil 

refuse, or oil mixed with wastes other than 

dredged spoil. 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

The U.S. Coast Guard (USCG) compiled a list of substances it considers oil, based on the 

CWA definition. The list is available on the USCG Web site.1 Note, however, that the USCG list is 

not comprehensive and does not define “oil” for purposes of 40 CFR part 112. EPA may determine 

that a substance, chemical, material, or mixture is an oil even if it is not on the USCG list. 

2.2.1 Animal Fats and Vegetable Oils 

Oil covered under the SPCC regulation is further described in 40 CFR 112.2 as including 

“fats, oils, or greases of animal, fish, or marine mammal origin; vegetable oils, including oils from 

seeds, nuts, fruits, or kernels; and, other oils and greases, including petroleum, fuel oil, sludge, 

synthetic oils, mineral oils, oil refuse, or oil mixed with wastes other than dredged spoil.” Oil 

includes animal fats and vegetable oils. 

2.2.2 Synthetic Oils 

The SPCC rule applies to synthetic oils. Synthetic oils are used in a wide range of 

applications, including as heat transfer fluids, engine fluids, hydraulic and transmission fluids, 

metalworking fluids, dielectric fluids, compressor lubricants, and turbine lubricants. Synthetic oils 

are created by chemical synthesis rather than by refining petroleum crude or extracting from plant 

seeds. The base materials from which synthetic oils are synthesized include glycols, esters, 

polyalphaolefins, aromatics, silicone fluids, Group III base oils, and others. Because of their origin, 

synthetic oils are generally covered under subpart B of 40 CFR 112, which covers “petroleum oils 

and non-petroleum oils...” Certain oils are synthesized from plant material, and thus may be 

considered with animal fats and vegetable oils under subpart C of 40 CFR part 112, which, as 

1

 See the “List of Petroleum and Non-Petroleum Oils” on the USCG Web site at 
 

http://www.uscg.mil/vrp/faq/oil.shtml. 
 

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discussed below, applies to “animal fats and oils and greases, and fish and marine mammal oils; 

and...vegetable oils, including oils from seeds, nuts, fruits, and kernels.” 

2.2.3 Determination of “Oil” for Natural Gas and Hazardous Substances 

Natural Gas 

Natural gas (including liquid natural gas and liquid petroleum gas) is not considered an oil. 

EPA does not consider highly volatile liquids that volatilize on contact with air or water, such as 

liquid natural gas or liquid petroleum gas, to be oil (67 FR 47076). Petroleum distillate or oil that is 

produced by natural gas wells and stored at atmospheric pressure and temperature (commonly 

referred to as condensate or drip gas), however, is considered an oil. 

Dry gas production facilities are not subject to the SPCC rule. A dry gas production facility 

produces natural gas from a well (or wells) but does not also produce condensate or crude oil that 

can be drawn off the tanks, containers, or other production equipment at the facility. EPA has 

clarified that a dry gas production facility does not meet the description of an “oil production, oil 

recovery, or oil recycling facility” for which the wastewater treatment exemption would apply under 

§112.1(d)(6).2 See excerpt below: 


 


 


 


 


 


 


 


 


 


 


 


 


 

. . .” 67 FR
 


 

Notice Concerning Certain Issues Pertaining to the July 2002 Spill Prevention, Control, 

and Countermeasure (SPCC) Rule, (May 25, 2004) 

The Agency has been asked whether produced water tanks at dry gas facilities are eligible for the 

SPCC rule’s wastewater treatment exemption at 40 CFR 112.7(d)(6). A dry gas production facility is a 

facility that produces natural gas from a well (or wells) from which it does not also produce condensate or 

crude oil that can be drawn off the tanks, containers or other production equipment at the facility. 

The SPCC rule’s wastewater treatment exemption excludes from 40 CFR part 112 “any facility or 

part thereof used exclusively for wastewater treatment and not used to satisfy any requirement of this 

part.” However, for the purposes of the exemption, the “production, recovery, or recycling of oil is not 

wastewater treatment.” In interpreting this provision, the preamble to the final rule states that the Agency 

does “not consider wastewater treatment facilities or parts thereof at an oil production, oil recovery, or oil 

recycling facility to be wastewater treatment for purposes of this paragraph.” 

It is our view that a dry gas production facility (as described above) would not be excluded from 

the wastewater treatment exemption based on the view that it constitutes an “oil production, oil recovery, 

or oil recycling facility.” As discussed in the preamble to the July 2002 rulemaking, “the goal of an oil 

production, oil recovery, or oil recycling facility is to maximize the production or recovery of oil. 

47068. A dry gas facility does not meet this description.

 See 69 FR 29729, 29730. 

Wet gas production facilities are subject to the SPCC rule. In addition to natural gas, wet 

gas production facilities produce condensate or crude oil that can be drawn off the tanks, 

2

 “Notice Concerning Certain Issues Pertaining to the July 2002 Spill Prevention, Control, and
 


Countermeasure (SPCC) Rule,” 69 FR 29728, May 25, 2004.
 


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containers, or other production equipment at the facility. Since wet gas production facilities produce 

and store condensate, which is considered an oil, they are regulated under the SPCC rule. 

Hazardous Substances and Hazardous Waste 

The definition of “oil” in §112.2 includes “oil mixed with wastes other than dredged spoil.” 

Oils covered under the SPCC rule therefore include certain hazardous substances or hazardous 

wastes that are mixed with oil, as well as certain hazardous substances or hazardous wastes that 

are themselves oils. Containers storing these substances may also be covered by other 

regulations, such as the Resource Conservation and Recovery Act (RCRA), or the Comprehensive 

Environmental Response, Compensation, and Liability Act (CERCLA), also known as Superfund. 

Inspectors should evaluate whether containers storing hazardous substances or mixtures of wastes 

contain oil. Although the rule contains an exemption for completely buried tanks that are subject to 

all underground storage tank (UST) technical requirements of 40 CFR part 280 and/or a state 

program approved under part 281, tanks containing RCRA hazardous wastes are not subject to the 

UST rules, and therefore are not exempt under §112.1(d)(2)(i) or (4) if they contain oil. 

Hazardous substances that are neither oils nor mixed with oils are not subject to SPCC rule 

requirements. 

2.2.4 Activities Involving Oil 

Section 112.1(b) specifies that the owners or 

operators of facilities involved in one or more of the 

following oil-related activities are regulated under the 

SPCC rule, provided they meet the other applicability 

criteria in §112.1: “drilling, producing, gathering, 

storing, processing, refining, transferring, distributing, 

using, or consuming oil and oil products.” Table 2-1 

provides examples of these activities. 

§112.1(b) 

...this part applies to any owner or operator 

of a non-transportation-related onshore or 

drilling, 

producing, gathering, storing, 

processing, refining, transferring, 

distributing, using, or consuming oil and 

oil products.... 

Note: The above text is an excerpt of the SPCC rule. 

full text of the rule. 

offshore facility engaged in 

Emphasis added. Refer to 40 CFR part 112 for the 

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Table 2-1. Examples of oil-related activities that may be regulated under 40 CFR part 112. 

Activity 	 Examples of Oil-related Regulated Activities 

Drilling Drilling a well to extract crude oil or natural gas and associated products (such as wet 

natural gas) from a subsurface field. 

Producing Extracting product from a well and separating the crude oil and/or gas from other 

associated products (e.g., water, sediment). 

Gathering Collecting oil from numerous wells, tank batteries, or platforms and transporting it to a 

main storage facility, processing plant, or shipping point. 

Storing Storing oil in containers prior to use, while being used, or prior to further distribution in 

commerce. 

Processing Treating oil using a series of processes to prepare the oil for commercial use, 

consumption, further refining, manufacturing, or distribution. 

Refining Separating crude oil into different types of hydrocarbons through distillation, cracking, 

reforming, and other processes; separating animal fats and vegetable oils from free fatty 

acids and other impurities. 

Transferring Transferring oil between containers, such as between a railcar or tank truck and a bulk 

storage container, or between stock tanks and manufacturing equipment. 

Distributing Selling or marketing oil for further commerce or moving oil using equipment such as 

highway vehicles, railroad cars, or pipeline systems. Note that businesses commonly 

referred to as oil distributors and retailers commonly are also “storing” oil, as described 

above. 

Using Using oil for mechanical or operational purposes in a manner that does not significantly 

reduce the quantity of oil, such as using oil to lubricate moving parts, provide insulation, or 

for other purposes in electrical equipment, electrical transformers, and hydraulic 

equipment. 

Consuming 	 Consuming oil in a manner that reduces the amount of oil, such as burning as fuel in a 
 

generator. 
 

2.3	 “Non-transportation-related” Facilities – EPA/DOT Jurisdiction 

2.3.1 Definition of Facility 

The extent of a “facility” under SPCC depends on site-specific circumstances. Factors that 

may be considered relevant in delineating the boundaries of a facility for SPCC purposes may 

include, but are not limited to: 

•	 Ownership, management, and operation of the buildings, structures, equipment, 

installations, pipes, or pipelines on the site; 

•	 Similarity in functions, operational characteristics, and types of activities occurring at 

the site; 

•	 Adjacency; or 

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• 	 Shared drainage pathways (e.g., same 
 

receiving waterbodies). 
 

The facility owner or operator, or a 

Professional Engineer (PE) on behalf of the facility 

owner/operator, determines what constitutes the 

“facility.” Note that the facility determination for 

purposes of the SPCC rule should be the same as 

that used to determine FRP applicability. 

While the facility owner/operator has some 

discretion in defining the parameters of the facility, 

the boundaries of a facility should not be drawn to 

purposely avoid regulation under 40 CFR part 112. 

For example, two contiguous operational areas, each 

with 700 gallons in aboveground storage capacity,
 

that have the same owner, perform similar functions,
 

are attended by the same personnel, and are in other ways indistinguishable from each other,
 

would reasonably be expected to represent a single facility under the SPCC rule, and would
 

therefore be required to have an SPCC Plan, since the capacity of this facility is above the 1,320-
 

gallon aboveground threshold. These two operational areas would not be defined as two separate
 

facilities under the definition of “facility” in §112.2.
 

§112.2

Facility means any mobile or fixed, 

onshore or offshore building, structure, 

installation, equipment, pipe, or pipeline 

(other than a vessel or a public vessel) 

used in oil well drilling operations, oil 

production, oil refining, oil storage, oil 

gathering, oil processing, oil transfer, oil 

distribution, and waste treatment, or in 

which oil is used, as described in Appendix 

depend on several site-specific factors, 

including, but not limited to, the ownership 

or operation of buildings, structures, and 

equipment on the same site and the types 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

A to this part. The boundaries of a facility 

of activity at the site. 

Alternatively, a single facility may be composed of various oil-containing areas spread over 

a relatively large campus. For instance, different operational areas within a military base may be 

considered a single facility. The military base may not necessarily include single-family homes 

occupied by military personnel as part of the facility if these are considered personal space similar 

to civilian single-family residences. However, the facility may include larger military barracks for 

which a branch of the military controls, operates, and maintains the space. 

If a facility is regulated under the SPCC rule, it is the responsibility of the facility owner and 

operator to ensure that an SPCC Plan is prepared. A site may have multiple owners and/or 

operators, and therefore can have several facilities. Factors to consider in determining which owner 

or operator should prepare the Plan include who has control over day-to-day operations of the 

facility or particular containers and equipment, who trains the employee(s) involved in oil handling 

activities, who will conduct the required inspections and tests, and who will be responsible for 

responding to and cleaning up any discharge of oil. EPA expects that the owners and operators will 

cooperate to prepare one or more Plans, as appropriate. 

SPCC facilities include not only permanent facilities with fixed storage and equipment, but 

also those that have only standby, temporary, and seasonal storage as described under 

§112.1(b)(3), as well as construction facilities. Mobile facilities are addressed in §112.3(c), which 

allows such facilities to create a general Plan, instead of developing a new Plan each time the 

facility is moved to a new location. 

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2.3.2 Determination of Transportation-related and Non-transportation-related Facilities 

Facilities are divided into three categories: transportation-related facilities, 

non-transportation-related facilities, and complexes. The determination of transportation-related 

and non-transportation-related facilities has been established through a series of Executive Orders 

(EOs) and Memoranda of Understanding (MOUs) as described below. 

Onshore and certain offshore non-transportation-related facilities (and portions of a 

complex) are subject to the SPCC regulation, provided they meet the other applicability criteria set 

forth in §112.1. A facility with both transportation-related and non-transportation-related activities is 

a “complex” and is subject to the dual jurisdiction of EPA and DOT. The jurisdiction over a 

component of a complex is determined by the activity occurring at that component. An activity 

might at one time subject a facility to one agency’s jurisdiction, and a different activity at the same 

facility using the same structure or equipment might subject the facility to the jurisdiction of another 

agency. Which activity would be subject to EPA jurisdiction and which activity would be subject to 

DOT jurisdiction is defined by the 1971 DOT-EPA MOU. 

A 1971 MOU between EPA and DOT clarifies the types of facilities, activities, equipment, 

and vessels that are meant by the terms “transportation-related onshore and offshore facilities” and 

“non-transportation-related onshore and offshore facilities.” DOT delegated authority over vessels 

and transportation-related onshore and offshore facilities to the Commandant of the U.S. Coast 

Guard.3 Sections of the MOU between EPA and DOT are included in Appendix A of 40 CFR part 

112. Section 112.1(d)(1)(ii) specifically exempts from SPCC applicability any equipment, vessels, 

or facilities subject to the authority and control of the DOT as defined in this MOU. 

A 1994 MOU among the Secretary of the Interior, the Secretary of Transportation, and the 

Administrator of EPA establishes the jurisdictional responsibilities for offshore facilities, including 

pipelines. This MOU can be found in Appendix B of 40 CFR part 112. Section 112.1(d)(1)(iii) 

specifically exempts from SPCC applicability any equipment, vessels, or facilities subject to the 

authority of the DOT or DOI as defined in this MOU. 

Table 2-2 provides examples of transportation-related and non-transportation-related 

facilities as the concepts apply to the SPCC rule applicability. Some equipment, such as loading 

arms and transfer hoses, may be considered either transportation-related or 

non-transportation-related depending on their use. 

3

 The USCG was reorganized under the Department of Homeland Security in March 2003. 

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Table 2-2. Examples of transportation-related and non-transportation-related facilities from the 

1971 DOT-EPA Memorandum of Understanding. 

Transportation-related Facilities 

(DOT Jurisdiction) 

Non-Transportation-related Facilities 

(EPA Jurisdiction) 

• Onshore and offshore terminal facilities, • 

including transfer hoses, loading arms, and and production facilities 

other equipment used to transfer oil in bulk to • Oil refining and storage facilities 

or from a vessel, including storage tanks and • Industrial, commercial, agricultural, and public 

appurtenances for the reception of oily ballast facilities that use and store oil 

water or tank washings from vessels • 

• • Loading racks, transfer hoses, loading arms, 

equipment appurtenant to a nonoil in bulk to or from a vessel • 

and other equipment used to transfer oil in bulk 

to or from highway vehicles or railroad cars 

Highway vehicles, railroad cars, and pipelines 

• used to transport oil within confines of nonpipeline systems transportation-related facility 

• Highway vehicles and railroad cars that are 

used for the transport of oil 

Fixed or mobile onshore and offshore oil drilling 

Waste treatment facilities 

Transfer hoses, loading arms, and other 

transportation-related facility used to transfer 

Interstate and intrastate onshore and offshore 

2.3.3 EPA/DOT Jurisdiction Scenarios 

This section describes common scenarios that have raised jurisdictional questions regarding 

the distinction between transportation-related and non-transportation-related facilities for 

applicability of SPCC requirements. Inspectors should evaluate the intended activity carefully 

because the determination of jurisdiction is not always straightforward. 

Tank Trucks 

EPA regulates tank trucks as “mobile/portable containers” under the SPCC rule if they 

operate exclusively within the confines of a non-transportation-related facility. For example, a tank 

truck that moves around within the facility and only leaves the facility to obtain more fuel (oil) would 

be considered to distribute fuel exclusively at one facility. This tank truck would be subject to the 

SPCC rule if it, or the facility, contained above the regulatory threshold amount (see Section 2.5 of 

this document) and there was a reasonable expectation of discharge to navigable waters or 

adjoining shorelines. Similarly, an airport refueler or construction refueler that fuels exclusively at 

one site would be subject to the SPCC rule. However, if the tank truck distributed fuel to multiple 

off-site facilities, the tank truck would be transportation-related, and regulated by DOT. 

Tank trucks that are used in interstate or intrastate commerce can also be regulated if they 

are operating in a fixed, non-transportation mode. For example, if a home heating oil truck makes 

its deliveries, returns to the facility, and parks overnight with a partly filled fuel tank, it is subject to 

the SPCC rule if it, or the facility has a capacity above the threshold amount (see Section 2.5 of this 

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document), and there is a reasonable expectation of discharge to navigable waters or shorelines.4 

However, if the home heating oil truck’s fuel tank contains no oil when it is parked at the facility, 

other than any residual oil present in an emptied vehicle, it would be regulated only by DOT.5 For 

more information, refer to Chapter 4 of this document (Secondary Containment and Impracticability 

Determinations), which discusses secondary containment requirements. 

Railroad Cars 

DOT regulates railroad cars from the time the oil is offered for transportation to a carrier until 

the time that it reaches its destination and is accepted by the consignee. DOT jurisdiction includes 

railroad cars that are passing through a facility or are temporarily stopped on a normal route. EPA 

regulates railroad cars after the transportation process ends; that is, when the railroad cars are 

serving as non-transportation-related storage at an SPCC-regulated facility. EPA jurisdiction 

includes railroad cars that are at their final destination, and/or if loading or unloading has begun. If 

loading/unloading has begun, the railroad car itself may become the non-transportation-related 

facility even if no other containers at the property would qualify the property. To be considered a 

non-transportation-related facility, the railroad car must store oil in an amount above the regulatory 

threshold, and there must be a reasonable expectation of discharge to navigable waters 

(§112.1(d)).6 

EPA regulates railroad cars under the SPCC rule if they are operating exclusively within the 

confines of a non-transportation facility. A railroad car would be subject to the SPCC rule if it, or the 

facility, had a capacity above the regulatory threshold amount of oil, and there was a reasonable 

expectation of discharge to navigable waters or adjoining shorelines. 

Any Loading/Unloading Activities 

EPA regulates the activity of loading or unloading oil in bulk into storage containers (such as 

those on tank trucks or railroad cars), as well as all equipment involved in this activity (e.g., a hose 

or loading arm attached to a storage tank system). A “loading/unloading area” is any area of a 

facility where oil is transferred between bulk storage containers and tank trucks or railroad cars. 

These areas are subject to the general secondary containment requirements in §112.7(c). If a 

“loading/unloading rack” is present, the requirements of §112.7(h) apply to the loading/unloading 

rack area. For more information, refer to Chapter 4 of this document (Secondary Containment and 

Impracticability Determinations), which includes a discussion of secondary containment 

requirements for loading/unloading areas. 

4

 In this case, the facility would include the truck storage capacity in its aggregate capacity determination in 

order to determine whether it is above the 1,320 gallon aboveground threshold for SPCC applicability. 

5

 EPA addressed this scenario in a letter from Stephen Heare, Office of Emergency and Remedial
 


Response, to Melissa Young of Petroleum Marketers Association of America (2001). See Appendix H. 
 


6

 EPA addressed the applicability of the SPCC rule to railroad cars by addressing specific scenarios in a
 


letter to the Safety-Kleen Corporation in July 2000. See Appendix H.
 


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Marine Terminals 

A marine terminal is an example of a “complex” that is subject to U.S. Coast Guard (USCG) 

and EPA jurisdiction. The USCG regulates the pier structures, transfer hoses, hose-piping 

connection, containment, controls, and transfer piping associated with the transfer of oil between a 

vessel and an onshore facility. EPA regulates the tanks, internal piping, loading racks, and 

vehicle/rail operations that are completely within the non-transportation portion of the facility (33 

CFR part 154, Facilities Transferring Oil or Hazardous Material in Bulk). EPA jurisdiction begins at 

the first valve inside secondary containment. If there is no secondary containment, EPA jurisdiction 

begins at the valve or manifold adjacent to the storage tank (33 CFR 154.1020). 

Vessels (Ships/Barges) 

The U.S. Coast Guard regulates the loading or unloading of oil from a vessel to an onshore 

facility, as well as the oil-carrying ship and the connecting piping (33 CFR part 155, Oil or 

Hazardous Material Pollution Prevention Regulations for Vessels). In this scenario, a vessel is a 

ship or a barge. The oil passes from the USCG’s jurisdiction to that of the EPA when it passes the 

first valve of the secondary containment for the storage container. If there is no secondary 

containment, EPA’s jurisdiction begins at the first valve or manifold closest to the storage container. 

Storage tanks and appurtenances for the reception of oily ballast water or tank washings from 

vessels are under USCG jurisdiction. 

Motive Power 

Motive power containers are located in or on a motor vehicle, such as on-board bulk oil 

storage containers used solely to power the movement of a motor vehicle, or ancillary on-board, oilfilled operational equipment used solely to facilitate its operation. A motive power container can be 

considered non-transportation-related and subject to the SPCC rule. However, EPA does not 

believe that the intent of the SPCC rule was to regulate motive power containers, including oil-filled 

tanks used to fuel the propulsion of vehicles, such as buses, sport utility vehicles, construction 

vehicles, and farm equipment. 

Breakout Tanks 

Breakout tanks are usually used to relieve surges in an oil pipeline system or to receive and 

store oil transported by a pipeline for reinjection and continued transportation by pipeline. They are 

also sometimes used for bulk storage. A breakout tank may be regulated by EPA, DOT, or both 

depending on how the tank is used. For example, breakout tanks that are used solely to relieve 

surges in a pipeline and are not used for any non-transportation-related activity (i.e., pipeline-in and 

pipeline-out configuration, with no transfer to other equipment/mode of transportation such as a 

tank truck), would be subject to DOT jurisdiction. A bulk storage container used to store oil while 

also serving as a breakout tank for a pipeline or other transportation-related purpose would be 

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subject to both DOT and EPA jurisdiction.7 For more information, see the EPA and DOT joint 

memorandum dated February 4, 2000, which clarifies regulatory jurisdiction over breakout tanks.8 

2.4	 	 Reasonable Expectation of Discharge to Navigable Waters in 

Quantities That May Be Harmful 

2.4.1	 	 Definition of “Discharge” and “Discharge as Described in §112.1(b)” 

According to §112.1(b), the SPCC rule applies to facilities that could reasonably be 

expected to discharge oil in “quantities that may be harmful, as described in part 110 of this 

chapter...” The Discharge of Oil regulation at 40 CFR part 110 (also referred to as the “sheen rule”) 

defines a discharge of oil into or upon the navigable waters of the United States or adjoining 

shorelines in quantities that may be harmful under the CWA as that which: 

•	 	 Causes a sheen or discoloration on the surface of the water or adjoining shorelines; 

•	 Causes a sludge or emulsion to be deposited beneath the surface of the water or 

upon adjoining shorelines; or 

•	 	 Violates an applicable water quality standard. 

A discharge meeting any of the above criteria triggers requirements to report to the National 

Response Center (NRC). The failure to report such a discharge may result in criminal sanctions 

under the CWA. The appearance of a “sheen” on the surface of the water is often used as a simple 

way to identify harmful discharges of oil that should be reported. The appearance of a sheen, 

however, is not a necessary factor; the presence of a sludge or emulsion, or of another deposit of 

oil beneath the water surface, or the violation of an applicable water quality standard also indicates 

a harmful discharge. 

Section 311 of the CWA defines and prohibits certain discharges of oil. These requirements 

are also codified in 40 CFR part 112. As defined in §112.2, a “discharge” includes, but is not limited 

to, any spilling, leaking, pumping, pouring, emitting, emptying, or dumping of any amount of oil no 

matter where it occurs. It excludes certain discharges associated with §402 of the CWA and §13 of 

the River and Harbor Act of 1899. The primary distinction between the §112.2 and §112.1(b) 

definitions of discharge is that a discharge as described in §112.1(b) is a violation of §311 of the 

Clean Water Act, whereas a §112.2 discharge (i.e., one that does not impact a navigable water or 

adjoining shoreline) is not a violation. For example, if a tank leaks a puddle of oil into a facility’s 

basement, this would be considered a discharge of oil, but is not necessarily a violation of the CWA 

because the oil did not reach a navigable water or adjoining shoreline (and would not be a 

discharge as described in §112.1(b)). 

7

 See also the 1971 MOU between DOT and EPA (Appendix A of 40 CFR part 112), and EPA/DOT memo 
 

“Jurisdiction over Breakout Tanks/Bulk Oil Storage Tanks (Containers) at Transportation-Related and Non-
 

Transportation-Related Facilities” for specific examples of dual jurisdiction. See Appendices A and H. 
 

8

 See Appendix H. 

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The SPCC regulation includes requirements for corrective action as well as additional 

reporting requirements. For example, in §112.8(c)(10), a facility is required to promptly correct 

visible discharges that result in a loss of oil from a container. A discharge of any amount would 

need to be cleaned up, but would not be considered a violation of the spill prohibition (a discharge 

as described in §112.1(b)), unless it impacts a navigable water or adjoining shoreline. Additionally, 

if a facility discharged more than 42 gallons of oil in each of two discharges as described in 

§112.1(b) over a 12-month period, the facility would be required to report each spill to the NRC, 

clean up the spill, and submit a report to the Regional Administrator, and may be required to amend 

its Plan. The same is true if the facility has a single discharge as described in §112.1(b) of more 

than 1,000 gallons. For more information on these reporting requirements, see §112.4 of the rule. 

2.4.2 Reasonable Expectation of Discharge 

The SPCC rule applies only to facilities that, 

due to their location, can reasonably be expected to 

discharge oil as described in §112.1(b). The rule 

does not define the term “reasonably be expected.” 

The owner or operator of each facility must determine 

the potential for a discharge from his/her facility. 

According to §112.1(d)(1)(i), this determination must 

be based solely upon consideration of the 

geographical and locational aspects of the facility. An 

owner or operator should consider the location of the 

facility in relation to a stream, ditch, gully, or storm 

sewer; the volume of material likely to be spilled; 

drainage patterns; and soil conditions. An owner or 

operator may not consider constructed features, such 

as dikes, equipment, or other manmade structures that prevent, contain, hinder, or restrain a 

discharge as described in §112.1(b), when making this decision. 

§112.1(b) 

...this part applies to any owner or operator 

of a non-transportation-related onshore or 

producing, gathering, storing, processing, 

refining, transferring, distributing, using, or 

consuming oil and oil products, which due 

to its location, 

expected to discharge oil in quantities 

part 110 of this chapter.... 

Note: The above text is an excerpt of the SPCC rule. 

full text of the rule. 

offshore facility engaged in drilling, 

could reasonably be 

that may be harmful, as described in 

Emphasis added. Refer to 40 CFR part 112 for the 

A facility owner or operator, however, should consider the presence of manmade structures 

that may serve to convey discharged oil to navigable waters, such as sanitary or storm water 

drainage systems, even if they lead to a publicly owned treatment work (POTW) prior to ultimate 

discharge into navigable waters. The presence of a treatment system such as a POTW cannot be 

used to determine that the facility is not reasonably expected to discharge to navigable waters or 

adjoining shorelines. POTWs can fail to contain oil. They are not designed to handle oil discharges 

and are on occasion forced to bypass to receiving waterbodies during extreme weather events or 

when upsets occur in the treatment system. 

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The following factors may prove useful to consider in determining whether there is a 

reasonable expectation of discharge: 

•	 Whether a past discharge of oil reached a navigable water or adjoining shoreline, 

which indicates that another could be reasonably expected; 

•	 Whether the facility is adjacent to navigable waters and a discharge to the navigable 

waters could be reasonably expected; 

•	 Whether on-site conduits, such as sewer lines, storm sewers, and certain 

underground features (e.g., power or cable lines, or groundwater), could facilitate the 

transport of discharged oil off-site to navigable waters; 

•	 Whether a unique geological or geographic feature would facilitate the transport of 

discharged oil off-site to navigable waters; 

•	 Whether the facility is near a watercourse and intervening natural drainage; 

•	 Whether precipitation runoff could transport oil into navigable waters; and 

•	 The quantity and nature of oil stored. 

2.4.3	 Geographic Scope 

EPA revised the geographic scope of the SPCC regulation in 2002 to be more consistent 

with the CWA. Formerly, the geographic scope of the rule extended to navigable waters of the 

United States and adjoining shorelines. The rule reflects the full geographic scope of EPA’s 

authority to include a discharge: 

•	 Into or upon the waters of the contiguous zone; 

•	 In connection with activities under the Outer Continental Shelf Lands Act or the 

Deepwater Port Act of 1974; or 

•	 That may affect natural resources belonging to, appertaining to, or under the 

exclusive management authority of the United States (including resources under the 

Magnuson Fishery Conservation and Management Act). 

The rule’s scope includes discharges harmful not only to the public health and welfare, but 

also to the environment through the protection of natural resources. Such protection would apply to 

resources under the Magnuson Fishery Conservation and Management Act, a statute that 

establishes exclusive U.S. management authority over all fishing within the exclusive economic 

zone (inner boundary coterminous with the seaward boundary of each coastal state), and all 

anadromous fish throughout their migratory range except when in a foreign nation’s waters, and all 

fish on the continental shelf. 

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2.4.4 Definition of “Navigable Waters” 

Section 112.2 provides the SPCC rule’s definition of “navigable waters.” See the text box 

below. 

§112.2

Navigable waters 

or foreign commerce, including all waters subject to the ebb and flow of the tide; 

waters: 

paragraph (1) of this definition. 
 

requirements of the CWA (other than cooling ponds which also meet the criteria of this definition) are not 

waters of the United States. Navigable waters do not include prior converted cropland. Notwithstanding 

(1) The term includes: 

(i) All waters that are currently used, were used in the past, or may be susceptible to use in interstate 

(ii) All interstate waters, including interstate wetlands; 

(B) From which fish or shellfish are or could be taken and sold in interstate or foreign commerce; or, 

(C) That are or could be used for industrial purposes by industries in interstate commerce; 

(iv) All impoundments of waters otherwise defined as waters of the United States under this section; 

(v) Tributaries of waters identified in paragraphs (1)(i) through (iv) of this definition; 

(vi) The territorial sea; and 

(vii) Wetlands adjacent to waters (other than waters that are themselves wetlands) identified in 

(2) Waste treatment systems, including treatment ponds or lagoons designed to meet the 

means the waters of the United States, including the territorial seas. 

(iii) All other waters such as intrastate lakes, rivers, streams (including intermittent streams), mudflats, 

sandflats, wetlands, sloughs, prairie potholes, wet meadows, playa lakes, or natural ponds, the use, 

degradation, or destruction of which could affect interstate or foreign commerce including any such 

(A) That are or could be used by interstate or foreign travelers for recreational or other purposes; or 

the determination of an area’s status as prior converted cropland by any other Federal agency, for the 

purposes of the CWA, the final authority regarding CWA jurisdiction remains with EPA. 

Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112 for the full text of the rule. 

See “Joint Memorandum of U.S. Army Corps of Engineers and EPA providing clarifying 

guidance regarding the Supreme Court’s decision in Solid Waste Agency of Northern Cook County 

v. United States Army Corps of Engineers, 531 U.S. 159 (2001) (SWANCC)),” 9

 68 FR 1995, 

January 15, 2003. 

9

 There is currently pending a petition for review challenging the definition of "navigable waters" in 40 CFR 

112.2., American Petroleum Institute v. Leavitt, No. 1:102CV02247 PLF and consolidated cases (D.D.C. filed Nov. 14, 

2002). 

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2.5 Storage Capacity 

2.5.1 Capacity Thresholds 

The SPCC rule applies to a facility that has 

more than 42,000 gallons of completely buried oil 

storage capacity or more than 1,320 gallons of 

aggregate aboveground oil storage capacity, provided 

it meets the other applicable criteria set forth in 

§112.1. 

According to §112.1(b)(1) through (4), the rule 

is applicable to eligible facilities that have oil in 

aboveground containers; completely buried tanks; 

containers that are used for standby storage, for seasonal storage, or for temporary storage, or are 

not otherwise “permanently closed”; and “bunkered tanks” or “partially buried tanks” or containers in 

a vault. Containers include not only oil storage tanks, but also mobile or portable containers such 

as drums and totes, and oil-filled equipment such as electrical equipment (e.g., transformers, circuit 

breakers), manufacturing flow-through process equipment, and operational equipment. However, 

§112.1(d)(2) limits the applicability to facilities with oil capacity above specific threshold amounts. 

§112.1(d) 

Except as provided in paragraph (f) of this 

section, this part does not apply to: ... 

subject to the jurisdiction of EPA, meets 

both of the following requirements: 

oil. ... 

less of oil. ... 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

(i) The completely buried storage capacity 

(ii) The aggregate aboveground storage 

(2) Any facility which, although otherwise 

of the facility is 42,000 gallons or less of 

capacity of the facility is 1,320 gallons or 

Once a facility is subject to the rule, all aboveground containers and completely buried tanks 

are subject to the rule requirements (unless these containers are otherwise exempt from the 

regulation, as is the case for containers smaller than 

55 gallons). For example, a facility could have 10,000 

gallons of aggregate aboveground storage capacity in 

tanks and oil-filled equipment of 55 gallons or more, 

and a completely buried tank of 10,000 gallons that is 

not subject to all of the technical requirements of 40 

CFR part 280 or a state program approved under part 

281 (and therefore not exempt). Since the 

aboveground storage capacity exceeds 1,320 

gallons, all of the tanks and oil-filled equipment, 

including the buried tank, are subject to the SPCC 

rule. 

§112.2

Completely buried tank means any 

container completely below grade and 

covered with earth, sand, gravel, asphalt, 

bunkered tanks, or partially buried tanks 

are considered aboveground storage 

containers for purposes of this part. 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

or other material. Containers in vaults, 

2.5.2 Storage Capacity Calculation 

Sections 112.1(d)(2)(i) and (ii) clarify which containers are included and excluded when 

calculating total storage capacity at a facility in determining whether it exceeds the volume limits in 

the rule. These containers are discussed below and summarized in Table 2-3. 

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What to Count 

•	 All containers of oil with a capacity of 55 gallons or greater are to be counted (unless 

listed below) when calculating total oil storage capacity at a facility. 

What Not to Count 

•	 Permanently closed containers are not counted when calculating total oil storage 

capacity. “Permanently closed,” as defined in §112.2, refers to containers “for which 

(1) All liquid and sludge has been removed from each container and connecting line; 

and (2) All connecting lines and piping have been disconnected from the container 

and blanked off, all valves (except for ventilation valves) have been closed and 

locked, and conspicuous signs have been posted on each container stating that it is 

a permanently closed container and noting the date of closure.” 

•	 Completely buried tanks, as defined in §112.2, and connected underground piping, 

underground ancillary equipment, and containment systems that are currently 

subject to all of the technical requirements of 40 CFR part 280 or all of the technical 

requirements of a state program approved under 40 CFR part 281 are not counted. 

Such tanks must still be marked on the facility diagram as provided in §112.7(a)(3). 

“Completely buried tank” as defined in §112.2 refers to “any container completely 

below grade and covered with earth, sand, gravel, asphalt, or other material. 

Containers in vaults, bunkered tanks, or partially buried tanks are considered 

aboveground storage containers for purposes of this part.” 

Table 2-3. Summary of storage capacity calculation as described in §112.1(d)(2)(i) and (ii). 

Included Excluded 

Capacity of containers (e.g., bulk Capacity of completely buried tank and associated underground 

storage containers, oil-filled piping, ancillary equipment, and containment systems subject to all 

equipment, mobile/portable technical requirements of 40 CFR part 280 or a state-approved 

containers) with a capacity of 55 program under 40 CFR part 281 

gallons or greater Capacity of containers that are permanently closed 

2.5.3	 Definition of Storage Capacity 

Under the SPCC rule, if a container has the §112.2 

requisite capacity, it does not matter whether the Storage capacity of a container means the 

container is actually filled to that capacity. The shell capacity of the container. 

storage capacity of a container is defined as the shell Note: The above text is an excerpt of the SPCC rule. 

capacity of the container. If a certain portion of a See 40 CFR part 112 for the full text of the rule. 

container is incapable of storing oil because of its 

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integral design (e.g., mechanical equipment or other interior components take up space), then the 

shell capacity of the container is reduced to the volume the container might hold (67 FR 47081). 

Generally, the shell capacity is the rated design capacity rather than the working/operational 

capacity. 

2.5.4 	 Tank Re-rating 

Shell capacity should be used as the measure of storage capacity, unless changes are 

made to the design shell capacity in a permanent, non-reversible manner. For example, when the 

integral design of a container has been altered by actions such as drilling a hole in the side of the 

container so that it cannot hold oil above that point, shell capacity remains the measure of storage 

capacity because such alteration can be altered again at will to restore the former storage capacity. 

When the alteration is an action such as the installation of a double bottom or new floor to the 

container, the integral design of the container has changed, and may result in a reduction in shell 

capacity. 

An addition or modification to a field-erected storage tank should be performed in 

accordance with industry standards and the original design specifications. Relevant industry 

standards include American Petroleum Institute (API) Standard 653 “Tank Inspection, Repairs, 

Alteration, and Reconstruction” (API-653). This standard includes additions or modifications to shell 

penetrations such as overfill diverters. However, even where such modifications are done in 

accordance with standards, the tank may not be considered re-rated to a lower capacity; the 

capacity remains equal to the original rated shell capacity. An owner or operator may reduce the 

capacity of a tank only by changing the shell dimensions (i.e., by removing shell plate sections). 

Since SPCC requirements are based on shell capacity, modifying a vent, overflow, or other tank 

appurtenances that reduce the working fill capacity does not affect SPCC requirements, including 

facility capacity determination and secondary containment requirements. 

2.6 	 Exemptions to the Requirements of the SPCC Rule 

In addition to the criteria described 

above, §112.1(d) describes certain types of 

additional equipment and facilities that are 

exempted from SPCC rule requirements. 

2.6.1 	 Facilities Subject to Minerals 

Management Service Regulations 

Section 112.1(d)(3) excludes offshore oil 

drilling, production, or workover facilities that are 

subject to notices and regulations of the 

Minerals Management Service (MMS). MMS 

regulations require adequate spill prevention, 

§112.1(d)

Except as provided in paragraph (f) of this 

section, this part does not apply to: ... 

regulations of the Minerals Management Service, 

as specified in the Memorandum of 

Understanding between the Secretary of 

Transportation, the Secretary of the Interior, and 

the Administrator of EPA, dated November 8, 

1993 (Appendix B of this part). 

Note: The above text is an excerpt of the SPCC rule. Refer to 

40 CFR part 112 for the full text of the rule. 

(3) Any offshore oil drilling, production, or 

workover facility that is subject to the notices and 

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control, and countermeasures that are directed more specifically to the facilities subject to the 

regulations. The facilities are regulated by the Department of Interior as specified in the DOI-DOTEPA MOU (40 CFR part 112, Appendix B). 

2.6.2	 Underground Storage Tanks 

Under §112.1(d)(4), the SPCC rule exempts completely buried storage tanks, as well as 

connected underground piping, underground ancillary equipment, and containment systems, when 

such tanks are subject to all of the technical requirements of 40 CFR part 280 or a state program 

approved under 40 CFR part 281 (also known as the Underground Storage Tank regulations). 

Although these tanks are exempt from the SPCC requirements, they must still be marked on the 

facility diagram if the facility is otherwise subject to the SPCC rule (§112.7(a)(3)). 

The regulations at 40 CFR parts 280 and 281 

comprise the Underground Storage Tank (UST) 

Program, which requires owners and operators of 

new tanks and tanks already in the ground to 

prevent, detect, and clean up releases. The UST 

program defines USTs differently than the SPCC 

rule does. The UST Program considers an 

underground storage tank to be a tank and any 

underground piping that has at least 10 percent of its 

combined volume underground. However, under the 

SPCC rule, only completely buried tanks subject to 

all of the technical UST Program requirements are 

exempt from the rule. Any tanks that are not 

completely buried are considered aboveground 

storage tanks and subject to the SPCC rule. 

§112.1(d) 

Except as provided in paragraph (f) of this 

section, this part does not apply to: ... 

defined in §112.2, and connected 

underground piping, underground ancillary 

equipment, and containment systems, at 

technical requirements of part 280 of this 

chapter or a State program approved under 

part 281 of this chapter, except that such a 

otherwise subject to this part. 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

(4) Any completely buried storage tank, as 

any facility, that is subject to all of the 

tank must be marked on the facility diagram 

as provided in §112.7(a)(3), if the facility is 

The following are either excluded from the definition of UST or are exempt from the UST 

regulations at 40 CFR part 280 (and therefore may be subject to the SPCC rule, if the completely 

buried tanks contain oil): 

•	 Tanks with a capacity of 110 gallons or less; 

•	 Farm or residential tanks with a capacity of 1,100 gallons or less used for storing 

motor fuel for non-commercial purposes; 

•	 Tanks used for storing heating oil for consumptive use on the premises where 

stored; 

•	 Tanks storing non-petroleum oils, such as animal fat or vegetable oil; 

•	 Tanks on or above the floor of underground areas (e.g., basements or tunnels); 

•	 Septic tanks and systems for collecting storm water and wastewater; 

•	 Flow-through process tanks; 

•	 Emergency spill and overfill tanks that are expeditiously emptied after use; 

•	 Surface impoundments, pits, ponds, or lagoons; 

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•	 Any UST system holding RCRA hazardous waste; 

•	 Any equipment or machinery that contains regulated substances for operational 

purposes; 

•	 Liquid trap or associated gathering lines directly related to oil or gas production or 

gathering operations; 

•	 Pipeline facilities regulated under the Natural Gas Pipeline Safety Act of 1968, the 

Hazardous Liquid Pipeline Safety Act of 1979, or intrastate pipelines regulated under 

state laws comparable to the provisions of above laws;10 and 

•	 Any UST system that contains de minimis concentration of regulated substances. 

The following are examples of deferrals from the UST regulations (and therefore may be subject to 

the SPCC rule): 

•	 Wastewater treatment tank systems; 

•	 Any UST systems containing radioactive materials that are regulated under the 

Atomic Energy Act of 1954; 

•	 UST systems that are part of emergency generator systems at nuclear power 

generation facilities; 

•	 Airport hydrant fuel distribution systems; and 

•	 UST systems with field-constructed tanks. 

Note that additional and/or more stringent requirements may exist in a state-approved 

program under 40 CFR part 281 and that they may also impact SPCC applicability. For example, a 

state may choose to regulate a UST used for storing heating oil for consumptive use on the 

premises where stored. Thus, under the state program the UST is subject to all the technical 

requirements of a 40 CFR part 281 program and not regulated by the SPCC rule. Inspectors 

should consider any state UST program approved 

under 40 CFR part 281 when addressing applicability 

issues associated with completely buried tanks. 

2.6.3	 Wastewater Treatment Facilities 

The wastewater treatment exemption, 

outlined in §112.1(d)(6), excludes from the SPCC 

requirements facilities or parts of facilities that are 

used exclusively for wastewater treatment, and are 

not used to meet 40 CFR part 112 requirements. 

§112.1(d) 

Except as provided in paragraph (f) of this 

section, this part does not apply to: .. 

exclusively for wastewater treatment and not 

used to satisfy any requirement of this part. 

The production, recovery, or recycling of oil 

is not wastewater treatment for purposes of 

this paragraph. 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

(6) Any facility or part thereof used 

Many of the wastewater treatment facilities or 

parts thereof are subject to the National Pollutant Discharge Elimination System (NPDES) or state10 Although exempt from UST regulations, pipeline facilities regulated under the Natural Gas Pipeline Safety 

Act of 1968, the Hazardous Liquid Pipeline Safety Act of 1979, or intrastate pipelines regulated under state laws 

comparable to the provisions of above laws do not generally come within EPA’s jurisdiction and are not generally 

regulated under the SPCC rule. See Section 2.3.2 of this document. 

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equivalent permitting requirements that involve operating and maintaining the facility to prevent 

discharges. The NPDES or state-equivalent process ensures review and approval of the facility’s 

plans and specifications; operation/maintenance manuals and procedures; and Storm Water 

Pollution Prevention Plans, which may include Best Management Practice (BMP) Plans (67 FR 

47068). 

For the purposes of the exemption, the production, recovery, or recycling of oil is not 

considered wastewater treatment. These activities generally lack NPDES or state-equivalent 

permits and thus lack the protections that such permits provide. Additionally, the goal of an oil 

production, oil recovery, or oil recycling facility is to maximize the production or recovery of oil, while 

eliminating impurities in the oil, including water, whereas the goal of a wastewater treatment facility 

is to purify water (67 FR 47068-69). 

The exemption does not apply to a wastewater treatment facility or part thereof that is used 

to store oil; in that instance, the oil storage capacity must be counted as part of the total facility 

storage capacity (see 67 FR 47068). For example, if there is a 600-gallon storage container that 

contains oil removed from an exempt oil/water separator and a 1,000-gallon storage container on 

site, the total aboveground storage capacity for the facility would be 1,600 gallons, and the facility 

may potentially be regulated by the SPCC rule. 

In addition, the exemption does not apply to a wastewater treatment facility or parts thereof 

used to meet a 40 CFR part 112 requirement, including an oil/water separator used to meet any 

SPCC requirement. Examples of oil/water separators that are used to meet SPCC requirements 

include oil/water separators used to satisfy the secondary containment requirements of §112.7(c), 

§112.7(h)(1), and/or §112.8(c)(2). Oil/water separators used to satisfy secondary containment 

requirements of the rule do not count toward storage capacity. For more information, refer to 

Chapter 5 of this document (Oil/Water Separators), which clarifies how the SPCC rule applies to 

oil/water separators. 

2.7 Determination of Applicability by the Regional Administrator 

Section 112.1(f) allows the Regional 

Administrator (RA) to require preparation of an SPCC 

Plan or applicable part by the owner or operator of an 

otherwise exempted facility that is subject to EPA 

jurisdiction under CWA §311(j) of the CWA. This 

provision is designed to address gaps in other 

regulatory regimes that might best be remedied by 

requiring a facility to have an SPCC Plan. For 

example, a facility may be exempted from the SPCC 

rule because its storage capacity is below the 

regulatory threshold, but the facility may have been 

the cause of repeated discharges as described in §112.1(b). 

§112.1(f) 

Notwithstanding paragraph (d) of this 

section, the Regional Administrator may 

require that the owner or operator of any 

section 311(j) of the CWA prepare and 

implement an SPCC Plan, or any 

applicable part, to carry out the purposes 

of the CWA. 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

facility subject jurisdiction of EPA under 

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Factors the RA may consider in making a determination to require that a facility prepare an 

SPCC Plan include, but are not limited to, the physical characteristics of the facility; the presence of 

secondary containment; the discharge history of the facility; and the proximity of the facility to 

sensitive environmental areas such as wetlands, parks, or wildlife refuges. The RA might require 

an entire Plan, or might require only a partial Plan addressing secondary containment, for example, 

to prevent future discharges. 

Sections 112.1(f)(1) through (5) describe the process for an RA to determine applicability. 

The process includes specific time deadlines for both the RA and the facility owner or operator, as 

well as requirements for the type of information and delivery method. Table 2-4 lists the deadlines 

and responsibilities of the RA and the facility owner or operator to appeal the RA determination that 

he/she must prepare an SPCC Plan. 

Table 2-4. Process for an RA determination of SPCC applicability and appeals. 

Deadline Responsibility 

Determination 

N/A Regional Administrator (RA) makes a preliminary determination. 

RA must provide a written notice to the owner/operator stating the 

reasons why an SPCC Plan or applicable part of a Plan is 

needed. (§112.1(f)(1)) 

Within 30 days of receipt of notice of a Owner/operator must provide information and data and may 

potential need to prepare an SPCC consult with EPA about the need to prepare an SPCC Plan, or 

Plan (following preliminary applicable part. (§112.1(f)(2)) 

determination) 

Within 30 days of receipt of data Regional Administrator (RA) must make a final determination 

regarding whether the owner/operator is required to prepare and 

implement an SPCC Plan, or applicable part. (§112.1(f)(3)) 

Within 6 months of final determination Owner/operator must prepare the Plan, or applicable part. 

that facility needs a Plan (§112.1(f)(4)) 

Within 1 year of final determination that Owner/operator must implement the Plan, or applicable part. 

facility needs a Plan (§112.1(f)(4)) 

Appeals 

Within 30 days of receipt of final Owner/operator may appeal final determination to the 

determination that facility needs a Plan Administrator of EPA (and send a copy to the RA). (§112.1(f)(5)) 

Within 60 days of receiving the appeal The Administrator must render a decision on the appeal. 

or additional information submitted by (§112.1(f)(5)) 

owner/operator 

The EPA inspector plays an important role in assisting the RA in determining applicability. 

For example, an inspector may initially alert the RA of the need for an otherwise exempt facility to 

have an SPCC Plan. This may result from an inspection prompted by a citizen complaint or state 

referral, an oil spill, or awareness of other conditions that warrant closer examination. Following an 

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RA determination of the need for an SPCC Plan, the EPA inspector may perform a targeted 

inspection of the subject facility to verify compliance with SPCC requirements. 

2.8 SPCC Applicability for Different Types of Containers 

2.8.1 Bulk Storage Container 

A bulk storage container, as defined in 

§112.2, must follow specific requirements, as 

described under §§112.8(c), 112.9(c), and 

112.12(c) for onshore facilities. Examples of these 

requirements include, but are not limited to, 

secondary containment and fail-safe engineering, 

such as high level alarms, inspections, and 

testing. 

2.8.2 Oil-filled Equipment 

§112.2

Bulk storage container means any container 

for purposes including, but not limited to, the 

storage of oil prior to use, while being used, 

or prior to further distribution in commerce. 

Oil-filled electrical, operating, or 

manufacturing equipment is not a bulk 

storage container. 

Note: The above text is an excerpt of the SPCC rule. 

text of the rule. 

used to store oil. These containers are used 

Emphasis added. Refer to 40 CFR part 112 for the full 

The definition of bulk storage container in §112.2 specifically excludes oil-filled electrical, 

operating, and manufacturing equipment (“oil-filled equipment”). Therefore, oil-filled equipment is 

not subject to the bulk storage container requirements in §§112.8(c), 112.9(c), and 112.12(c). 

However, oil-filled equipment must meet the general requirements of §112.7. See generally 67 FR 

47054-47055. 

EPA believes it is good engineering practice to have some form of visual inspection or 

monitoring for this oil-filled equipment to prevent discharges as described in §112.1(b). For 

example, it is a challenge to comply with security requirements under §112.7(g) and 

countermeasures for discharge discovery under §112.7(a)(3)(iv)) without some form of inspection or 

monitoring program. Additionally, inspection and/or monitoring should be part of an effective 

contingency plan when a PE determines that secondary containment for this equipment is 

impracticable. 

Oil-filled Operational Equipment 

Oil-filled operational equipment includes an oil storage container (or multiple containers) in 

which the oil is present solely to support the function of the apparatus or the device. Oil-filled 

operational equipment does not include manufacturing equipment. 

Examples of oil-filled operational equipment include hydraulic systems, lubricating systems 

(including lubricating systems for pumps, compressors, and other rotating equipment), gear boxes, 

machining coolant systems, heat transfer systems, transformers, other electrical equipment, and 

other systems containing oil to enable operation. 

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Oil-filled Manufacturing Equipment 

Oil-filled manufacturing equipment is distinct from bulk storage containers in its purpose. 

Oil-filled manufacturing equipment stores oil only as an ancillary element of performing a 

mechanical or chemical operation to create or modify an intermediate or finished product. 

Examples of oil-filled manufacturing equipment may include reaction vessels, fermentors, high 

pressure vessels, mixing tanks, dryers, heat exchangers, and distillation columns. Under the SPCC 

rule, flow-through process vessels are generally considered oil-filled manufacturing equipment 

since they are not intended to store oil.11 Additionally, there may be oil-filled operational equipment 

(e.g., a hydraulic unit) at this type of facility to support the manufacturing equipment (see generally 

67 FR 47080). The PE reviewing and certifying the SPCC Plan should be familiar with processes 

taking place at the facility and should therefore determine whether a given process vessel is 

considered a bulk storage container or oil-filled manufacturing equipment. 

In cases where a container is used for the static storage of oil within a manufacturing or 

processing area, the PE may determine that the container is in fact a bulk storage container. 

Examples of oil storage within manufacturing areas include: 

•	 Storing an intermediate product for an extended period of time in a continuous or 

batch process; 

•	 Storing a raw product prior to use in a continuous or batch process; and 

•	 Storing a final product after a continuous or batch process. 

Storage tanks and containers located at the beginning or end of a process and used to store 

feedstock or finished products generally are considered bulk storage containers. In cases where oil 

storage is incidental to the manufacturing activity or process (e.g., where it is being transformed in a 

flow-through process vessel) the PE may determine that the container is part of the manufacturing 

equipment. 

2.9	 Determination of Applicability of Facility Response Plans 

A portion of the SPCC-regulated community may also be required to prepare a Facility 

Response Plan (FRP). According to §112.20, a facility that has the potential to cause substantial 

harm to the environment in the event of a discharge must prepare and submit an FRP. SPCC 

facilities must document whether they meet the FRP applicability criteria (40 CFR 112 Appendix C 

Section 3.0). Facilities may refer to the “Flowchart of Criteria for Substantial Harm,” Attachment C-I 

to Appendix C of 40 CFR part 112, to determine whether they need to prepare an FRP. The owner 

or operator must document his/her determination of whether the facility has the potential to cause 

11 The U.S. Occupational Safety and Health Administration’s Process Safety Management (PSM) regulation 

(29 CFR 1910.119) considers a single process “any group of vessels which are interconnected and separate vessels 

which are located such that a highly hazardous chemical could be involved in a potential release.” The PSM definition 

of process includes storage tanks, while the SPCC rule considers storage tanks as bulk storage containers and not 

manufacturing equipment. 

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substantial harm by completing the Attachment C-II form, “Certification of the Applicability of the 

Substantial Harm Criteria,” and maintaining the certification at the facility. Attachments C-I and C-II 

are provided in Appendix H of this document. 

2.10 Role of the EPA Inspector 

The EPA inspector is responsible for gathering information and data to determine 

compliance with SPCC requirements for those facilities that are regulated by the SPCC rule. 

During an SPCC inspection, EPA inspectors will check that the measures described in the SPCC 

Plan are implemented at the facility and will fully document all observations and other pertinent 

information. The Summary of Applicability Flowchart and Applicability Assessment Worksheet, 

provided as Figures 2-1 and 2-2, are two quick references provided for convenience to aid 

inspectors in assessing whether a facility is subject to the SPCC rule. 

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Figure 2-1. Summary of applicability flowchart. 

IS 

Yes 

Yes 

Yes 

subj i 

i l 

i 

) 

or 

Yes 

No 

No 

No 

No 

Is the facility or part of the facility (e.g. complex) 

considered non-transportation-related? 

Is the facility engaged in drilling, producing, 

gathering, storing, processing, refining, 

transferring, distributing, using, or consuming oil? 

The facility 

subject to SPCC. 

The facility IS NOT 

subject to SPCC. 

Is the total aggregate capacity of 

aboveground oil storage containers 

greater than 1,320 gallons of oil? 

(Do not include containers less than 55 

gallons, permanently closed containers, 

or storage containers used exclusively 

for wastewater treatment) 

Is the total aggregate capacity of 

completely buried storage tanks 

greater than 42,000 gallons of oil? 

(Do not include completely buried tanks 

ect to all techn cal requirements of 

40 CFR 280/281, conta ners ess than 

55 gallons, permanently closed 

conta ners, or storage containers used 

exclusively for wastewater treatment 

Could the facility reasonably be expected to 

discharge oil in quantities that may be harmful into 

navigable waters or adjoining shorelines? 

The intent of this flowchart is to show the general principles of applicability. Inspectors should 

always consult the Code of Federal Regulations and applicable MOUs. 

Definitions (40 CFR 112.2) 

Completely buried tank: Any container completely below grade and covered with earth, sand, gravel, asphalt, or other material. 

Containers in vaults, bunkered tanks, or partially buried tanks are considered aboveground storage containers for purposes of this part. 

Complex: A facility possessing a combination of transportation-related and non-transportation-related components that is subject to the 

jurisdiction of more than one Federal agency under section 311(j) of the CWA. 

Facility: Any mobile or fixed, onshore or offshore building, structure, installation, equipment, pipe or pipeline (other than a vessel or a 

public vessel) used in oil well drilling operations, oil production, oil refining, oil storage, oil gathering, oil processing, oil transfer, oil 

distribution, and waste treatment, or in which oil is used, as described in Appendix A to the SPCC rule. The boundaries of a facility 

depend on several site-specific factors, including, but not limited to, the ownership or operation of buildings, structures, and equipment on 

the same site and the types of activity at the site. 

Permanently closed: Any container or facility for which: (1) All liquid and sludge has been removed from each container and connecting 

line; and (2) All connecting lines and piping have been disconnected from the container and blanked off, all valves (except for ventilation 

valves) have been closed and locked, and conspicuous signs have been posted on each container stating that it is a permanently closed 

container and noting the date of closure. 

Storage capacity: Shell capacity of the container. 

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Figure 2-2. Applicability assessment worksheet. 

1 	 Is the facility or part of the facility considered non-transportation-related and engaged in one 

of the following activities? (Refer to Sections 2.2.4 and 2.3 of this chapter.)
 


Drilling, producing, gathering, storing, processing, refining, transferring, distributing,
 


using, or consuming oil.
 


Yes. Go to question 2.
 


No. The facility is not subject to the SPCC rule.
 


2 	 Could the facility reasonably be expected to discharge oil in quantities that may be harmful
 

into navigable waters or adjoining shorelines? (Refer to Section 2.4 of this chapter.)
 

Note: This determination must be based solely upon consideration of the geographical and location
 


aspects of the facility (such as proximity to navigable waters or adjoining shorelines, land contour,
 


drainage, etc.) and must exclude consideration of manmade features such as dikes, equipment or other
 


structures, which may serve to restrain, hinder, contain, or otherwise prevent a discharge.
 


Yes. Go to question 3.
 


No. The facility is not subject to the SPCC rule.
 


3a Is the total aggregate capacity of aboveground oil storage containers greater than 1,320 
 

gallons? (Refer to Sections 2.5 and 2.6 of this chapter.) 
 

Note: Exclude containers less than 55 gallons, permanently closed containers, and storage containers 
 

used exclusively in wastewater treatment.
 


Yes. The facility is subject to the SPCC rule.
 


No. Go to question 3b.
 


3b Is the total aggregate capacity of completely buried storage tanks greater than 42,000 
 

gallons? (Refer to Sections 2.5 and 2.6 of this chapter.) 
 

Note: Do not include completely buried tanks subject to all technical requirements of 40 CFR part 280
 


or 281, containers less than 55 gallons, permanently closed containers, or storage containers used
 


exclusively in wastewater treatment.
 


Yes. The facility is subject to the SPCC rule.
 


No. The facility is not subject to the SPCC rule.
 


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Chapter 3: Environmental Equivalence 

ENVIRONMENTAL EQUIVALENCE 

3.1 Introduction 

The environmental equivalence provision, contained in §112.7(a)(2), allows for deviations 

from specific requirements of the SPCC rule, as long as the alternative measures provide 

equivalent environmental protection. The environmental equivalence provision is a key mechanism 

of the performance-based SPCC rule. This flexibility enables facilities to achieve environmental 

protection in a manner that fits their unique circumstances. It also allows facilities to adopt more 

protective industry practices and technologies as they become available. The preamble to the 2002 

SPCC regulation refers to certain industry standards that may be useful and can be considered in 

implementing the required spill prevention measures. 

The facility owner or operator is responsible for the selection, documentation in the SPCC 

Plan, and implementation in the field of SPCC measures, including any environmentally equivalent 

measures. However, a Professional Engineer (PE), when certifying a Plan as per §112.3(d), must 

verify that these alternative methods are in accordance with good engineering practice, including 

consideration of industry standards, and provide environmental protection equivalent to the 

measures described in the SPCC rule. 

In the SPCC context, equivalent environmental protection means an equal level of 

protection of navigable waters and adjoining shorelines from oil pollution. This can be achieved in 

various ways, but a facility may not rely solely on measures that are required by other sections of 

the rule (e.g., implementing secondary containment) to provide environmentally equivalent 

protection. While environmental equivalence need not be a mathematical equivalence, it must 

achieve the same desired outcome, though not necessarily through the same mode of operation 

(see 67 FR 47095). 

The reason for deviating from a requirement of the SPCC rule, as well as a detailed 

description of how equivalent environmental protection will be achieved, must be stated in the 

SPCC Plan, as required in §112.7(a)(2). Possible rationales for a deviation include the owner or 

operator’s ability to show that the particular requirement is inappropriate for the facility because of 

good engineering practice considerations or other reasons, and that he/she can achieve equivalent 

environmental protection in an alternate manner. Thus, a requirement that may be essential for a 

facility storing gasoline may be less appropriate for a facility storing hot asphalt cement due to 

differences in the properties and behavior of the two products, and the facility owner or operator 

may be able to implement equivalent environmental protection through an alternate technology (67 

FR 47094, 47095). 

As mentioned above and as is the case for other technical elements of the SPCC Plan, the 

PE must review the selection and implementation of environmentally equivalent measures and 

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certify them as being consistent with good engineering practice (§112.3(d)). The selection of 

alternative measures may be based on various considerations, such as safety, cost, geographical 

constraints, the appropriateness of a particular requirement based on site-specific considerations, 

or other factors consistent with engineering principles. 

Alternative measures, however, cannot rely solely on measures that are already required by 

other parts of the rule because this would allow for approaches that provide a lesser degree of 

protection overall. For instance, as EPA noted in a May 2004 letter to the Petroleum Marketers 

Association of America (PMAA), the presence of sized secondary containment for bulk storage 

containers, which is required under §112.8(c) and other relevant parts of the SPCC rule, does not 

provide, by itself, an environmentally equivalent alternative to performing integrity testing of bulk 

storage containers.1

 Although secondary containment reduces the risk of a discharge from primary 

containment (the container or tank) to navigable waters and adjoining shorelines and can increase 

the effectiveness of another prevention or control measure, it does not serve the purpose of 

integrity testing, which is to identify potential leaks or failure of primary containment before a 

discharge occurs. 

EPA has indicated, however, that for certain shop-built containers – drums and small bulk 

storage containers, for example – for which internal corrosion poses minimal risk of failure, which 

are inspected at least monthly, and for which all sides are visible, visual inspection alone may 

suffice to meet the integrity testing requirements under §112.8(c)(6) or §112.12(c)(6) (67 FR 

47120). These are only examples; alternative measures that provide equivalent environmental 

protection may also be appropriate for other site-specific circumstances. See Chapter 7, 

Inspection, Evaluation, and Testing, for a discussion of “environmentally equivalent” integrity 

testing. 

The remainder of this chapter is organized as follows: 

•	 Section 3.2 summarizes substantive SPCC requirements subject to the 

environmental equivalence provision. 

•	 Section 3.3 clarifies certain policy areas and provides examples of deviations based 

on the implementation of environmentally equivalent alternatives. 

•	 Section 3.4 describes the role of the EPA inspector in reviewing deviations based on 

environmental equivalence. 

1

 See EPA letter to Daniel Gilligan of PMAA, available in Appendix H of this guidance, or at 
 

http://www.epa.gov/oilspill/pdfs/PMAA_letter.pdf. 
 

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3.2	 	 Substantive Requirements Subject to the Environmental 

Equivalence Provision 

Section 112.7(a)(2) of the SPCC rule allows deviations for most technical elements of the 

rule (§§112.7 through 112.12), with the exception of the secondary containment requirements of 

§§112.7(c) and 112.7(h)(1), as well as in relevant paragraphs of §§112.8, 112.9, 112.10, and 

112.12. Chapter 4 of this document discusses these secondary containment requirements in detail. 

§112.7(a)(2) 

ith all applicable requirements listed in this part. 

. 

must 

. 

ing 

the procedures in §112.4(d) and (e). 

Comply w Your Plan may deviate from the requirements in paragraphs 

(g), (h)(2) and (3), and (i) of this section and the requirements in subparts B and C of this part, except the secondary 

containment requirements in paragraphs (c) and (h)(1) of this section, and §§112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 

112.10(c), 112.12(c)(2), 112.12(c)(11), ... where applicable to a specific facility, if you provide equivalent 

environmental protection by some other means of spill prevention, control, or countermeasure Where your 

Plan does not conform to the applicable requirements in paragraphs (g), (h)(2) and (3), and (i) of this section, or the 

requirements of subparts B and C of this part, except the secondary containment requirements in paragraphs (c) and 

(h)(1) of this section, and §§112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 112.10(c), 112.12(c)(2), 112.12(c)(11), ... you 

state the reasons for nonconformance in your Plan and describe in detail alternate methods and how you will 

achieve equivalent environmental protection If the Regional Administrator determines that the measures described 

in your Plan do not provide equivalent environmental protection, he may require that you amend your Plan, follow 

Note: The above text is an excerpt of the SPCC rule. Emphasis added. Refer to 40 CFR part 112 for the full text of the rule. 

In addition to secondary containment requirements, deviations are not allowed for certain 

provisions of §112.7, including the general recordkeeping and training provisions. Additionally, 

deviations are not allowed for the administrative provisions of the rule, §§112.1 through 112.5. The 

SPCC rule already provides flexibility for the format of records that need to be maintained at the 

facility by allowing the use of ordinary and customary business records. Personnel training 

(§112.7(f)) and a discussion of conformance with any applicable, more stringent state rules 

(§112.7(j)) are essential for all facilities. 

Table 3-1 presents a list of the SPCC requirements eligible for consideration for 

environmental equivalence. 

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Table 3-1. Requirements eligible for environmental equivalence, by facility type. 

Section(s) 

Petroleum Oils and Animal Fats and 

Facility Type/Provision Non-Petroleum Oils Vegetable Oils 

All regulated facilities 

Security 112.7(g) 

Loading and unloading racks 112.7(h)(2) and 112.7(h)(3) 

Brittle fracture evaluation 112.7(i) 

Onshore facilities 

Facility drainage/undiked areas 112.8(b), 112.9(b), 112.10(b) 112.12(b) 

and 112.11(b) 

Type of bulk storage container 112.8(c)(1) and 112.9(c)(1) 112.12(c)(1) 

Drainage of diked areas 112.8(c)(3) 112.12(c)(3) 

Corrosion protection of buried storage tanks 112.8(c)(4) and 112.8(c)(5) 112.12(c)(4) and 

112.12(c)(5) 

Integrity testing and/or container inspection 112.8(c)(6) and 112.9(c)(3) 112.12(c)(6) 

Monitoring internal heating coils 112.8(c)(7) 112.12(c)(7) 

Engineering of bulk container installation 112.8(c)(8) and 112.9(c)(4) 112.12(c)(8) 

(overfill prevention) 

Monitoring treatment/disposal facilities 112.8(c)(9) and 112.9(d)(2) 112.12(c)(9) 

Removal of oil in diked areas and 112.8(c)(10) 112.12(c)(10) 

production facility drainage 

Piping 112.8(d), 112.9(d)(1), and 112.12(d) 

112.9(d)(3) 

Oil drilling and workover facilities 

Facility drainage/undiked areas (rig position) 112.10(b) N/A 

Blowout prevention and well control system 112.10(d) N/A 

Offshore facilities 

Offshore oil drilling and workover facilities 112.11(b) through 112.11(p) N/A 

3.3 Policy Issues Addressed by Environmental Equivalence 

This section provides additional guidance on environmentally equivalent measures for 

specific requirements on which the regulated community has raised questions. The examples 

discussed below are meant to clarify selected rule provisions and to illustrate how deviations based 

on environmentally equivalent alternatives may be implemented. Other circumstances not 

discussed here may also be addressed through the use of environmentally equivalent measures. 

The examples in this section address environmental equivalence as it relates to: 

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Section 3.3.1 Security 

Section 3.3.2 Facility Drainage 

Section 3.3.3 Corrosion Protection and Leak Testing of Completely Buried Metallic 

Storage Tanks 
 

Section 3.3.4 Overfill Prevention 
 

Section 3.3.5 Piping 
 

Section 3.3.6 Evaluation, Inspection, and Testing 
 

Although briefly discussed in Section 3.3.6, deviations from inspection and testing 

requirements based on environmental equivalence are discussed in greater detail in Chapter 7 of 

this guidance document. 

3.3.1 Security 

Section 112.7(g) of the SPCC rule outlines security requirements for facilities, including 

fencing and lighting, and the use of control equipment and procedures. The security requirements 

are meant to prevent discharges of oil, as defined in §112.1(b), that could result from acts of 

vandalism or other unauthorized access to oil-filled containers or equipment. Note that unlike other 

provisions under §112.7, the security provisions in paragraph (g) do not apply to oil production 

facilities. 

A facility owner or operator may 

achieve the security objective through 

alternative measures, as appropriate for 

the facility, if these measures provide 

environmental protection equivalent to the 

measures described in the SPCC rule. 

As described in §112.7(a)(2), if 

alternative security measures are used, 

the Plan must state the reasons for 

nonconformance, and provide a 

description of the alternative measures, 

how they are implemented, and how they 

will achieve environmentally equivalent 

protection to prevent a discharge as 

described in §112.1(b). This description 

may include a discussion of how these 

measures help deter vandals, prevent 

unauthorized access to containers and 

equipment that could be involved in an oil 

discharge, or are otherwise equivalent to 

the SPCC security requirements. 

§112.7(g) 

Security (excluding oil production facilities). 

not in production or is unattended. 

i 

etc.); and 

vandalism. 

CFR part 112 for the full text of the rule. 

(3) Lock the starter control on each oil pump in the “off” 

(1) Fully fence each facility handling, processing, or storing 

oil, and lock and/or guard entrance gates when the facility is 

(2) Ensure that the master flow and drain valves and any 

other valves permitting direct outward flow of the container’s 

contents to the surface have adequate security measures so 

that they remain in the closed position when in non-operating 

or non-standby status. 

position and locate it at a site accessible only to authorized 

personnel when the pump is in a non-operating or nonstandby status. 

(4) Securely cap or blank-flange the loading/unloading 

connections of oil pipelines or facility piping when not in 

service or when in standby service for an extended time. This 

security practice also applies to piping that is emptied of 

liquid content either by draining or by inert gas pressure. 

(5) Provide facility lighting commensurate w th the type and 

location of the facility that will assist in the: 

(i) Discovery of discharges occurring during hours of 

darkness, both by operating personnel, if present, and by 

non-operating personnel (the general public, local police, 

(ii) Prevention of discharge occurring through acts of 

Note: The above text is an excerpt of the SPCC rule. Refer to 40 

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Fencing. Section 112.7(g)(1) requires that owners or operators fully fence the facility and/or 

guard gates when the facility is not in production or attended. Two examples of scenarios 

discussed in a letter to PMAA2

 regarding environmentally equivalent alternatives to fencing the 

entire footprint of a facility are discussed below. 

Case #1 – Fencing areas directly 

involved in oil handling, processing, and 

storage. [Demonstrates environmental 

equivalence.] For certain facilities where oil-filled 

containers and equipment are located within 

discrete areas, securing only those parts of the 

facilities that could be involved in an oil discharge 

may provide an effective level of protection. This 

alternative may be preferable for very large 

facilities where fencing the entire footprint of the 

facility would require installing and monitoring very Figure 3-1. Fencing around storage area.

long lengths of fencing. In such cases, installing a 

fence around the discrete areas of a facility where oil containers are located (Figure 3-1), or around 

the equipment needed to operate such containers (Figure 3-2), may adequately deter vandals or 

prevent access by unauthorized personnel, and thus may provide environmental protection 

equivalent to the §112.7(g)(1) requirement to fully fence the facility to prevent a discharge as 

described in §112.1(b) from these containers. Note that in the second case (i.e., where a fence is 

placed only around the equipment used to operate containers), security measures may also be 

required around the containers themselves, or other equipment and appurtenances connected to 

the containers. 

Case #2 – Placing master disconnect 

panel controlling power to all pumps, 

appurtenances (which could result in a 

discharge such as from a bottom water drain), 

and containers within an enclosed “pump 

house.” [Does not demonstrate environmental 

equivalence.] Certain facilities may equip an 

enclosed pump house with a master disconnect 

switch that cuts off electrical power to the pumps 

when the facility is unattended. Such disconnect 

may provide equivalent protection for the pumps 

and associated equipment that require power to Figure 3-2. Fencing around a dispenser pump. operate and would meet the §112.7(g)(3) 

requirement to lock starter controls on oil pumps in the “off” position and restrict access to 

2 Available on EPA’s Web site at http://www.epa.gov/oilspill/pdfs/PMAA_letter.pdf or in Appendix 

H of this guidance. 

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authorized personnel only. However, if containers, piping, or appurtenances are also present, the 

disconnect would not restrict access to equipment that can be operated without electrical power. 

Therefore, it would not provide environmental protection equivalent to fencing. Additional security 

measures would therefore be required for equipment that can be operated without electrical power. 

Lighting. Section 112.7(g)(5) states that facilities must provide lighting to assist in the 

discovery of discharges occurring during hours of darkness and help prevent discharges caused by 

acts of vandalism. Note that the rule requires lighting that is “commensurate with the type and 

location of the facility.” Thus, for unattended facilities that are located away from inhabited areas 

(for example, farm fields or certain isolated facilities) appropriate lighting may consist of lights that 

are turned on intermittently. For example, lighting that uses motion-activated detectors may be an 

appropriate means of meeting the lighting requirements, while avoiding undue attention to the 

presence of oil containers. Alternatively, an environmentally equivalent approach may combine an 

alarm system that detects the presence of trespassers, with portable lights used to perform regular 

rounds of the facility. Whatever approach the owner or operator implements, the SPCC Plan 

should discuss how lighting provided at the facility is adequate for the type and location of the 

facility, or how the facility is achieving environmentally equivalent protection through other means. 

The security requirements may also be met through other means, depending on facilityspecific circumstances. For example, a facility that is attended by a security guard on a 24-hour 

basis may use closed-circuit cameras to detect and investigate unauthorized access to unfenced 

portions of the facility. In another example, a facility such as an electrical substation that is 

remotely located with limited access and monitored through use of a Supervisory Control and Data 

Acquisition (SCADA) system, may provide environmentally equivalent security by its configuration 

since the site’s inaccessibility may be considered a powerful deterrent to unauthorized access and 

the SCADA system serves to detect oil discharges remotely without requiring lighting to assist 

visual detection. 

3.3.2 Facility Drainage 

Section 112.8(b) describes facility drainage provisions for onshore facilities that handle 

petroleum oils and non-petroleum oils other than animal fats and/or vegetable oils. Section 

112.12(b) provides the corresponding requirements for facilities that handle animal fats and/or 

vegetable oils. The description of the design capacity of facility drainage systems is also addressed 

under §§112.7(a)(3) and 112.7(b). 

Diked Storage Area Provisions 

The objective of the drainage requirements is to provide design specifications for the 

secondary containment systems employed at the facility to prevent oil-contaminated water from 

escaping the facility and becoming a discharge as described in §112.1(b). 

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Sections 112.8(b)(1) and 112.8(b)(2) 

specify requirements for the design of drainage 

systems for dikes used as a means of 

secondary containment. (See Chapter 4 for a 

more detailed discussion of secondary 

containment requirements.) 

Under §112.8(b)(1) and 112.8(b)(2), the 

SPCC regulation requires that when the facility 

owner/operator uses valves to drain a dike or 

berm, the valves must be of manual, 

open-and-closed design, unless the facility 

drainage system is equipped to control oil 

discharges. The facility owner or operator, and 

the PE certifying a Plan, may consider 

alternative technologies specifically engineered 

to prevent oil from escaping the facility 

containment and drainage control system, 

while normally allowing drainage of 

uncontaminated water. When implemented 

and maintained properly, such systems may 

provide environmental protection equivalent to 

using a manually operated valve and visually 

monitoring discharge from dikes. Certain 

valves will automatically shut off upon detecting 

oil. These types of systems have been 

installed at electrical substations, for example, 

to drain uncontaminated rainwater under 

normal conditions, while also preventing oil 

from escaping the containment system in the 

event of a discharge from transformers or other 

oil-filled electrical equipment. The material 

expands upon contact with oil, effectively plugging the drainage system. The valve is not actuated, 

but rather the drainage system becomes plugged upon contact with the oil, thus providing an 

equivalent measure of environmental protection. 

§§112.8(b) ) Facility Drainage. 

by 

ejectors and must inspect the condition of the 

discharged. 

the drainage of 

and (iv) of this section 

areas wi

 You 

must not locate catchment basins in areas subject to 

periodic flooding. 

(b)(3) of this section, equip the final discharge of all 

i 

described in §112.1(b) in case there is an equipment 

Note: The above text is an excerpt of the SPCC rule. 

the rule. 

(1) Restrain drainage from 

(2) Use valves of manual, open-and-closed design, for 

 and 112.12(b 

diked storage areas 

valves to prevent a discharge into the drainage system 

or facility effluent treatment system, except where 

facility systems are designed to control such discharge. 

You may empty diked areas by pumps or ejectors; 

however, you must manually activate these pumps or 

accumulation before starting, to ensure no oil will be 

diked areas. You may not use flappertype drain valves to drain diked areas. If your facility 

drainage drains directly into a watercourse and not into 

an on-site wastewater treatment plant, you must 

inspect and may drain uncontaminated retained 

stormwater, as provided in paragraphs (c)(3)(ii), (iii), 

(3) Design facility drainage systems from undiked 

th a potential for a discharge (such as where 

piping is located outside containment walls or where 

tank truck discharges may occur outside the loading 

area) to flow into ponds, lagoons, or catchment basins 

designed to retain oil or return it to the facility. 

(4) If facility drainage is not engineered as in paragraph 

ditches inside the facility w th a diversion system that 

would, in the event of an uncontrolled discharge, retain 

oil in the facility. 

(5) Where drainage waters are treated in more than 

one treatment unit and such treatment is continuous, 

and pump transfer is needed, provide two “lift” pumps 

and permanently install at least one of the pumps. 

Whatever techniques you use, you must engineer 

facility drainage systems to prevent a discharge as 

failure or human error at the facility. 

Emphasis added. Refer to 40 CFR part 112 for the full text of 

To be most effective, however, EPA recommends that the systems have a fail-safe design to 

automatically prevent any oil from escaping the containment area in the event of a system 

malfunction. The PE certifying the Plan should verify the adequacy of the system to prevent oil 

discharges to navigable waters and adjoining shorelines, considering factors such as the type of oil 

and its compatibility with the system selected, the amount of precipitation, maintenance 

requirements, flow paths, and proximity to navigable waters. The SPCC Plan should also describe 

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procedures for maintaining these systems and checking their effectiveness by routine inspections 

and inspections following heavy rain events to ensure that they are operational. 

Undiked Storage Area Provisions 

Sections 112.8(b)(3) and 112.8(b)(4) specify performance requirements for systems used to 

drain undiked areas with the potential for a discharge. These two provisions apply only when the 

facility chooses to use a facility drainage system to meet general secondary containment 

requirements under §112.7(c) or a more specific requirement under §112.8(c), §112.9(c), 

§112.10(c) or §112.12(c). Where the facility drainage cannot be engineered as described in 

§112.8(b)(3), the SPCC rule requires that the facility equip the final discharge points of all ditches 

within the facility with a diversion system that would, in the event of a discharge, retain the oil at the 

facility as described in §112.8(b)(4). Additional requirements in §112.8(b)(5) pertain more 

specifically to engineering multiple treatment units for these drainage systems. 

For parts of a facility that could be involved in a discharge and where secondary 

containment requirements are met through the use of a drainage system rather than a dike or berm, 

the SPCC rule generally requires facility drainage to flow into a system, such as a pond, lagoon, or 

catchment basin, designed to retain the oil or return it to the facility. Other measures may be 

implemented to achieve the drainage control objective, based on good engineering practice and 

subject to PE review and certification. For example, directing undiked facility drainage into an 

impoundment system located within a neighboring facility may be considered equivalent to keeping 

it within the facility’s confines (as required in §112.8(b)(4)) if the neighboring facility owner has 

agreed to allow use of the impoundment and as long as the impoundment is designed and 

managed such that it is capable of handling a potential discharge from both facilities before it 

becomes a discharge as described in §112.1(b). 

Alternatively, a facility owner or operator may engineer the facility drainage system intended 

to meet general secondary containment requirements of §112.7(c) to flow into an oil/water 

separator designed to remove oil resulting from facility operations. Chapter 5 of this guidance 

document describes the requirements, depending on their function, that apply to oil/water 

separators at SPCC-regulated facilities. The SPCC Plan should discuss how the oil/water 

separator provides environmental equivalence, and any procedures necessary to maintain proper 

operating conditions and the effectiveness of the system (such as maintenance of the filtration 

systems). Note that the oil/water separator should be designed to handle the anticipated flow rate 

and volumes of oil and water. Furthermore, the oil/water separator should be inspected or checked 

periodically (including after heavy rain events) to ensure that it is working effectively and that it is 

not holding significant quantities of oil for extended periods of time. For the oil/water separator to 

provide equivalent environmental protection under §112.8(b)(3) and (b)(4), the PE must verify that 

the oil/water separator is adequately designed and operated to effectively retain any discharge as 

described in §112.1(b). 

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Drainage at Production Facilities 

Similar deviations from SPCC drainage 

control requirements are possible for other types of 

facilities. Section 112.9(b), for example, outlines 

drainage requirements for production facilities. They 

include sealing dike drains or drains of equivalent 

measures required under §112.7(c)(1) for tank 

batteries and separation and treating areas at all 

times except when draining uncontaminated 

rainwater. The PE may specify alternative 

measures, such as the technologies described 

above for electrical substations, that would provide 

equivalent environmental protection by retaining oil 

within the diked area in the event of a discharge. 

(See the above discussion in Section 3.3.2, Diked 

Storage Area Provisions.) Here also, the Plan must 

describe the measure in detail and how it provides 

environmentally equivalent protection when implemented in the field, as required by §112.7(a)(2). 

§112.9(b) 

Oil production facility drainage. 

discharge as described in §112.1(b), close and 

seal at all times drains of dikes or drains of 

equivalent measures required under 

Prior to drainage, 

and return it to storage or dispose of it in 

accordance wi 

road ditches), and oil traps, sumps, or skimmers, 

You must promptly 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

(1) At tank batteries and separation and treating 

areas where there is a reasonable possibility of a 

§112.7(c)(1), except when draining 

uncontaminated rainwater. 

you must inspect the diked area and take action 

as provided in §112.8(c)(3)(ii), (iii), and (iv). You 

must remove accumulated oil on the rainwater 

th legally approved methods. 

(2) Inspect at regularly scheduled intervals field 

drainage systems (such as drainage ditches or 

for an accumulation of oil that may have resulted 

from any small discharge. 

remove any accumulations of oil. 

Wherever a facility owner or operator chooses to deviate from the drainage control 

provisions by using an alternative measure that provides equivalent environmental protection, the 

SPCC Plan must state the reasons for nonconformance and describe the alternative measure in 

detail, including how it achieves equivalent environmental protection when implemented 

(§112.7(a)(2)). 

3.3.3 Corrosion Protection and Leak Testing of Completely Buried Metallic Storage Tanks 

Section 112.8(c) describes requirements 

that apply to bulk storage containers at facilities 

that store, use, or process petroleum and other 

non-petroleum oils. Similar provisions are included 

in §112.12(c) for facilities that store, use, or 

process animal fats and/or vegetable oils. The 

various subparagraphs under these sections 

address requirements that apply to different types 

of bulk storage containers, appurtenances, and 

related activities. 

compatible with local soil conditions. You must 

storage tanks. 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

§§112.8(c)(4) and 112.12(c)(4) 

Protect any completely buried metallic storage tank 

installed on or after January 10, 1974 from 

corrosion by coatings or cathodic protection 

regularly leak test such completely buried metallic 

Subparagraph (c)(4) requires that facility owners or operators protect buried metallic storage 

tanks from corrosion and regularly perform leak test on the tanks. Completely buried storage tanks 

are exempted from SPCC requirements, as provided in §112.1(d)(2)(i), when the tanks are subject 

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to all of the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR 

part 281. Tanks subject to 40 CFR part 280 or a state program approved under 40 CFR part 281 

must follow those requirements. Completely buried tanks that are subject to SPCC requirements 

must meet the provisions outlined in §112.8(c)(4) or §112.12(c)(4). 

Completely buried tanks subject to the SPCC rule include, but are not limited to, tanks with 

capacity of 110 gallons or less, heating oil tanks, and tanks located inside basements or tunnels. 

Corrosion protection and leak detection for completely buried tanks that meet the corresponding 

(corrosion protection and leak detection) testing requirements of 40 CFR part 280 or 40 CFR part 

281 are considered environmentally equivalent to §§112.8(c)(4) and 112.12(c)(4). See Chapter 2 

for more information on the applicability of the SPCC rule to completely buried storage tanks. 

3.3.4 	 Overfill Prevention 

Sections 112.8(c)(8) and 112.12(c)(8) 

require that each container installation be 

engineered to avoid discharges during filling 

activities. At least one of the following systems is 

required: 

• 	 High level alarm with audible or 
 

visual signal; 
 

• 	 High liquid level pump cutoff 
 

device; 
 

• 	 Direct audible or code signal 
 

communication between container 
 

gauger and pumping station; 
 

• 	 Fast response system for 
 

determining the liquid level, such 
 

as digital computer, telepulse, or 
 

direct vision gauge, provided that 
 

someone is present to monitor
 


gauges and the overall filling
 


operation; and
 


accordance with good engineering practice to avoid 

discharges. You must provide at least one of the 

ith an audible or visual 

surveillance station. In smaller facilities an audible 

station. 

liquid level of each bulk storage container such as 

digital computers, telepulse, or direct vision gauges. 

to monitor gauges and the overall filling of bulk 

storage containers. 

devices to ensure proper operation. 

NOTE: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

(i) High liquid level alarms w 

(ii) High liquid level pump cutoff devices set to stop 

(iii) Direct audible or code signal communication 

§§112.8(c)(8) and 112.12(c)(8) 

Engineer or update each container installation in 

following devices: 

signal at a constantly attended operation or 

air vent may suffice. 

flow at a predetermined container content level. 

between the container gauger and the pumping 

(iv) A fast response system for determining the 

If you use this alternative, a person must be present 

(v) You must regularly test liquid level sensing 

• 	 Regular tests of liquid level sensing devices to ensure proper operation. 

The selection of an overfill prevention system should be based on good engineering practice 

(§112.7 introductory paragraph), considering methods that are appropriate for the types of activities 

and circumstances. While an audible/visual alarm or fast response system may be appropriate for 

a large, stationary storage tank, a simpler overfill prevention system may be appropriate for a small 

tank. In certain cases (e.g., for relatively small containers that can be readily monitored), a filling 

procedure can be established in place of physical overfill prevention devices, which could be 

considered environmentally equivalent. The procedure must be adequate to prevent a discharge 

(as required under §112.8(c)(8)) when considering factors such as the container size; filling rate; 

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ability of the person performing the filling operation to continuously monitor product level in the 

container; reaction time; capacity of the secondary containment and/or catchment basin; and 

proximity of the tank to floor drains, sumps, and other means through which oil could escape. For 

example, a filling procedure for a small container may involve placing a drain cover on any floor 

drain, ensuring that valves used to control drainage from the secondary containment are closed or 

that sorbent material has been deployed around the container area, verifying that the container that 

will receive the product has sufficient free capacity, and visually monitoring the product level 

throughout the transfer operation. 

In cases where a facility owner or operator uses an overfill prevention approach other than 

the systems described in the SPCC rule, the Plan must describe the approach and how it provides 

environmentally equivalent protection (§112.7(a)(2)). Where the alternative approach relies on 

procedures instead of, or in addition to, a physical device, the Plan should clearly describe the 

procedures and facility personnel involved in filling operations should be able to demonstrate an 

understanding of the procedures and proper field implementation. As part of the description of the 

environmentally equivalent measure required under §112.7(a)(2), the PE may reference other 

facility documents in the SPCC Plan which discuss relevant established Best Management 

Practices (BMPs), pollution prevention training and/or procedures in more detail, rather than 

restating this information in the SPCC Plan. 

Additional supporting documentation should 

be on-site and available for review during an 

inspection. 

3.3.5 Piping 

Requirements that apply to piping at 

onshore facilities that handle petroleum oils 

are described in §112.8(d). Similar 

requirements are described in §112.12(d) for 

piping at facilities that handle animal fats 

and/or vegetable oils. 

These provisions of the SPCC rule 

require that facilities generally protect buried 

piping against corrosion; cap or blank-flange 

the terminal connection of piping that is not in 

service; design pipe supports to minimize 

abrasion and corrosion; and regularly inspect 

all aboveground valves, piping, and 

appurtenances. The rule also requires 

integrity and leak testing of all piping at the 

time of installation, modification, construction, 

relocation, or replacement. Finally, the rule 

§§112.8(d) ) 

process. 

or after August 16, 2002, wi 

piping installations or otherwi 

or a State program approved under part 281 of this 

If 

additional examination and corrective action as indicated 

expansion joints, valve glands and bodies, catch pans, 

pipeline supports, locking of valves, and metal surfaces. 

construction, relocation, or replacement. 

transfer operations. 

NOTE: The above text is an excerpt of the SPCC rule. Refer to 

40 CFR part 112 for the full text of the rule. 

(1) Provide buried piping that is installed or replaced on 

(2) Cap or blank-flange the terminal connection at the 

 and 112.12(d 

Facility-transfer operations, pumping, and facility 

th a protective wrapping and 

coating. You must also cathodically protect such buried 

se satisfy the corrosion 

protection standards for piping in part 280 of this chapter 

chapter. If a section of buried line is exposed for any 

reason, you must carefully inspect it for deterioration. 

you find corrosion damage, you must undertake 

by the magnitude of the damage. 

transfer point and mark it as to origin when piping is not 

in service or is in standby service for an extended time. 

(3) Properly design pipe support to minimize abrasion 

and corrosion and allow for expansion and contraction. 

(4) Regularly inspect all aboveground valves, piping, and 

appurtenances. During the inspection you must assess 

the general condition of items, such as flange joints, 

You must also conduct integrity and leak testing of 

buried piping at the time of installation, modification, 

(5) Warn all vehicles entering the facility to be sure that 

no vehicle will endanger aboveground piping or other oil 

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requires warning all vehicles entering the facility to ensure that they will not endanger aboveground 

piping (or other oil transfer operations). Types of facility piping addressed by this provision include, 

but are not limited to: 

•	 Transfer piping to and from bulk storage containers, both aboveground and buried; 

•	 Transfer piping associated with manufacturing equipment, both aboveground and 

buried; and 

•	 Piping associated with operational equipment. 

An EPA study into the causes of oil releases indicates that the operational piping portion of 

an underground storage tank system is twice as likely as the tank portion to be the source of a 

discharge.3 Piping failures are caused equally by poor workmanship, improper installation, 

corrosion, or other forms of deterioration. The SPCC piping requirements aim to prevent oil 

discharges from aboveground or buried piping due to corrosion, operational accidents, or collision. 

Accordingly, equivalent environmental protection may be achieved through alternative measures 

that reduce or eliminate the risks of corrosion to buried piping or the risk of damage to aboveground 

piping. 

The following sections discuss examples of deviations from prevention requirements related 

to corrosion and other types of piping damage. 

Protecting Buried Piping from Corrosion Damage 

EPA recommends that a PE certifying an SPCC Plan consult appropriate industry standards 

(consulting a qualified corrosion professional may also be appropriate) when evaluating the 

adequacy of cathodic protection and corrosion prevention systems at the facility. Where the PE 

determines that cathodic protection of new piping is not appropriate considering site-specific 

conditions, facility configuration, and other engineering factors (e.g., where the installation of a 

corrosion system would accelerate corrosion of existing unprotected equipment), the PE may 

specify other measures to assess and ensure the continued fitness-for-service of piping. 

For example, the owner or operator of a facility could, instead of cathodically protecting 

underground piping, use double-wall piping combined with an interstitial leak detection system (67 

FR 47123). The SPCC requirement (cathodic protection) averts discharges by preventing container 

corrosion, while the alternative method (leak detection system and double-wall piping) detects and 

contains leakage so it may be addressed before it can become a discharge as described in 

§112.1(b). 

Alternatively, the facility owner or operator may implement a comprehensive monitoring, 

detection, and preventive maintenance program for piping and appurtenances where effective 

cathodic protection is not reasonably achievable to detect and address potential discharges. The 

3 “Causes of Release from Underground Storage Tank Systems: Attachments,” September 1987, 

EPA 510-R-92-702. 

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PE that certifies the Plan should develop and/or review such a program, which may combine 

inspection, monitoring and leak testing elements with preventive maintenance, contingency 

measures, and recordkeeping. Examples of these elements are outlined for piping systems in API 

Standard 570, “Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of In-Service 

Piping Systems,” 

Table 3-2 summarizes key elements of an API-570 inspection program as they relate to the 

evaluation of buried piping that is not cathodically protected (refer to Chapter 7 of this document for 

an overview of API-570). Such a program provides a means of assessing the suitability of piping to 

contain oil and to predict potential failures prior to their occurrence. 

Table 3-2. Summary of inspection and leak testing elements of an API-570 program as they apply 

to unprotected buried piping (refer to the full text of API 570 for details). 

Inspection and Leak Testing 

Elements Summary 

Pipe-to-Soil Potential Survey Conduct pipe-to-soil potential survey along the pipe route to assess 

corrosion potential at a five-year interval. Excavate sites where active 

corrosion cells are located to determine the extent of corrosion damage. 

Pipe Coating Holiday* Survey Conduct pipe coating holiday survey as needed based on results of other 

evaluations. 

Soil Corrosivity Perform soil corrosivity evaluation at a five-year interval for piping buried 

in lengths greater than 100 feet. 

External and Internal Determine external condition of buried piping that is not cathodically 

Inspection Intervals protected by pigging or by excavating according to frequency indicated in 

API-570 standard table. Adjust inspection of internal corrosion of buried 

piping based on results of internal inspections of aboveground portion. 

Leak Testing Intervals Alternatively, or in addition to inspection, perform leak testing with 

pressure at least 10 percent greater than maximum operating pressure at 

an interval half that of inspections indicated in the standard for buried 

piping that is not cathodically protected. Alternatively, perform 

temperature-corrected volumetric or pressure test methods, or use 

acoustic emission examination and addition of tracer fluid. 

* “Holiday” means any discontinuity, bare, or thin spot in a painted area. 

Where a piping inspection and testing program is used to provide environmental protection 

equivalent to cathodic protection, its scope and frequency should be developed and/or reviewed by 

the PE certifying the Plan to be in accordance with good engineering practice, considering industry 

standards. For facilities with shorter lengths of piping or where the distance to receiving waters or 

adjoining shorelines is greater, the program may emphasize certain elements over others, such as 

frequent leak testing of buried piping. Chapter 7 provides references to industry standards that 

specifically discuss leak testing, including API Recommended Practice 1110, “Pressure Testing of 

Liquid Petroleum Pipelines.” However, since leak testing only detects leaks, rather than predicting 

them, good engineering practice would suggest that testing should occur at a greater frequency 

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than would otherwise be required if other prevention systems, such as cathodic protection and 

coatings, were in place. 

If alternative measures are used to meet the SPCC corrosion protection requirements, 

§112.7(a)(2) requires that the Plan state the reasons for nonconformance and explain how the 

alternative measures provide environmental protection equivalent to coating and cathodically 

protecting new piping. In order to be considered equivalent environmental protection to cathodic 

protection, EPA suggests that a comprehensive inspection and preventive maintenance program 

needs to be implemented to effectively detect and address piping deterioration before it can result 

in a discharge as described in §112.1(b). The inspector should verify that the alternative method is 

described in detail in the Plan, and that the Plan specifies the scope and frequency of tests and 

inspections and/or refers to the relevant industry standards. The EPA inspector should also review 

records maintained under normal business practice that document the tests and inspections. 

Preventing Physical Damage to Aboveground Piping 

Warnings to vehicles entering the facility may be given verbally, posted on signs, or other 

appropriate means. Alternatively, protecting the equipment from the possibility of a collision by 

installing fencing, barriers, curbing or other physical obstacles may be considered to provide 

equivalent environmental protection. Whatever method is implemented at the facility, it must be 

properly documented in the SPCC Plan in accordance with §112.7(a)(2). 

3.3.6 Evaluation, Inspection, and Testing 

The SPCC rule sets requirements for the evaluation, inspection, and testing of various parts 

of a facility that could be involved in a discharge. The requirements are described in Chapter 7 of 

this guidance document. 

The evaluation, inspection, and testing requirements are aimed at detecting oil leaks, spills, 

or other potential integrity problems before they can result in a discharge as described in §112.1(b). 

The rule provides flexibility in the manner in which the evaluations, inspections, and tests are 

performed by allowing the use of methods consistent with good engineering practice, as determined 

by the PE certifying the Plan, considering industry standards. 

While the rule describes the general nature and expected scope for evaluations, 

inspections, and tests, the requirements are eligible for the environmental equivalence provisions 

under §112.7(a)(2), and a facility owner or operator can therefore implement alternative measures if 

he/she states in the Plan the reason for nonconformance and describes in detail the alternative 

measures and how the alternative measures provide environmental protection equivalent to that 

provided by the required evaluation, inspection, or test. 

The use of environmental equivalence for evaluation, inspection, and testing requirements is 

discussed in Chapter 7 of this guidance document, along with the background information on 

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relevant regulatory requirements, industry standards, and recommended practices, which is 

necessary for discussing alternatives to these provisions. 

3.4 Review of Environmental Equivalence 

Any substitution of a prevention and control measure required by the rule with an 

environmentally equivalent measure must be documented in the SPCC Plan, as required in 

§112.7(a)(2). This documentation is reviewed by the EPA inspector during inspections to ensure 

that the facility is in compliance with the regulatory requirements. 

The EPA inspector may refer to the list in Table 3-3 at the end of this chapter to identify and 

review technical rule requirements that are eligible for deviation through the environmental 

equivalence provision. 

Environmentally equivalent measures are not available for the general and specific 

secondary containment provisions of the SPCC rule. Instead, §112.7(d) provides a separate 

means of deviating from secondary containment requirements through a determination of 

impracticability when secondary containment is not practicable. Environmentally equivalent 

deviations are also not available for the general recordkeeping and training provisions in §112.7. 

The rule already provides flexibility in the manner of recordkeeping by allowing the use of ordinary 

and customary business records. The rule also does not specify how the training of oil-handling 

personnel is conducted, or whom to designate as a person accountable for oil discharge prevention 

(§112.7(f)). 

3.4.1 SPCC Plan Documentation 

For each environmental equivalent measure, the SPCC Plan must state the reason for 

nonconformance within the relevant section of the Plan, as required in §112.7(a)(2). The Plan must 

also describe the alternative measure in detail and explain how the measure provides 

environmental protection equivalent to that provided by the SPCC provision. 

The facility owner or operator must ensure that alternative measures are adequate for the 

facility; that equipment, devices, or materials are designed for the intended use; and that the 

equipment, devices, or materials are properly implemented and maintained to provide effective 

environmental protection (§§112.3(d) and 112.7). EPA emphasizes that the environmental 

equivalence provision is not intended to be used as a means to avoid complying with the rule or 

simply as an excuse for not meeting requirements the owner or operator believes are too costly. 

The alternative measure chosen must represent good engineering practice and must achieve 

environmental protection equivalent to the SPCC rule requirement as required in §112.7(a)(2). 

Technical deviations, like other substantive technical portions of the Plan requiring the application 

of engineering judgement, are subject to PE certification (67 FR 47095). 

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In cases where operational procedures are used as environmentally equivalent alternatives 

to SPCC requirements, the Plan must state the reasons for nonconformance and describe in detail 

the alternate methods and how this will achieve equivalent environmental protection (§112.7(a)(2)). 

The description should provide the details of how the procedures are implemented at the facility, 

including detailing the steps involved in each activity, required equipment, personnel training, and 

records that need to be maintained to document and verify implementation. Records that would be 

kept as part of usual and customary business practices are generally considered acceptable forms 

of documentation, but should be referenced in the Plan and available for an inspector’s review 

during an inspection. These records must be maintained with the Plan for a period of three years 

(§112.7(e)). Certain industry standards, for example API Standards 570 and 653, may specify that 

records are to be maintained for more than three years. 

The two examples below illustrate documentation of environmentally equivalent measures 

that may be provided in a hypothetical SPCC Plan. 

Example #1: Documentation of Environmentally Equivalent Protection for Integrity Testing 

(§112.8(c)(6)) – Tank Elevated off the Ground 

Bulk Storage Tanks – 40 CFR 112.8(c)(6) 

ABC Oil is deviating from the integrity testing provision of §112.8(c)(6) for storage tank #3; based on good 

engineering practice after considering the tank installation and alternative measures, the requirements of Steel 

Tank Institute (STI) Standard SP-001, and alternative measures implemented by the facility. Tank #3 is a 

4,500-gallon UL142 aboveground horizontal tank elevated on built-in saddles, and all sides of the tank are 

visible. Tank #3 is not insulated, and the outside surface of the tank shell can therefore be observed on an 

ongoing basis. The tank is located over a concrete floor, which functions as a release prevention barrier and 

has properly sized containment in accordance with §112.8(c)(2). Under SP-001, the tank is considered a 

Category 1 tank (aboveground storage tank with spill control and with continuous release detection method) 

and therefore requires periodic inspection of the tank. The personnel performing these inspections are 

knowledgeable of storage facility operations, characteristics of the liquid stored, the type of aboveground 

storage tank and its associated components. Facility personnel perform monthly and annual inspections, as 

described in Section 3.4 of the Plan and in accordance with the provisions and the checklists presented in SP001. The scope of inspections and procedures is covered in the training provided to employees involved in 

handling oil at the facility. The routine inspections focus specifically on detecting any change in conditions or 

signs of product leakage from the tank, piping system, and appurtenances. 

In accordance with inspection procedures outlined in this Plan, if signs of leakage or deterioration from the 

tank are observed by facility personnel, the tank is to be inspected by a tank inspector certified by the 

American Petroleum Institute or STI to assess its suitability for continued service, according to SP-001. 

Facility personnel who conduct inspections are qualified in accordance with SP-001. The tank’s physical 

configuration, combined with monthly and annual inspections, ensures that any small leak that could develop 

in the tank shell will be detected before it can become significant, escape secondary containment, and reach 

the environment. This approach provides environmental protection equivalent to the non-destructive shell 

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evaluation component of integrity testing required under §112.8(c)(6) since it provides an appropriate and 

effective means of assessing the condition of the tank and its suitability for continued service. 

Example #2: Documentation of Environmentally Equivalent Protection for Drainage of Diked 

Areas (§112.8(b)(1) and §112.8(b)(2)) 

Facility Drainage – 40 CFR 112.8(b)(1) and 40 CFR 112.8(b)(2) 

The dike structure in Area A contains three oil-filled transformers (see list of equipment and oil storage 

capacity in the Plan). The dike is equipped with a [TRADEMARK] drain shutoff system specifically engineered 

to prevent oil from escaping the containment structure while allowing water to flow through during normal 

conditions. The system uses hydrophobic and oleofilic material to block the flow of water upon reacting to the 

presence of oil. Documentation of the performance of this system and the manufacturer’s suggested 

replacement interval are maintained as an appendix to this Plan. 

Employee supervision is not required under regular operating conditions to drain uncontaminated rainwater 

that has accumulated in the dike. This method deviates from the rule requirements, which generally require 

that a dike be drained under direct visual supervision using valves of manual, open-and-closed design. 

The diked area is inspected monthly by facility personnel as part of the scheduled inspection of bulk storage 

tanks, as per the checklist presented in Appendix A. This inspection includes looking for accumulation of 

water and presence of oil within the diked area, and examining, and replacing, as warranted, the silt filter and 

[TRADEMARK] elements. Facility personnel also examine the system, and replace components as needed, 

within 48 hours of any rainfall greater than 3 inches. Replacement of the silt filter and/or other elements of the 

[TRADEMARK] system are noted on the monthly inspection sheets, which are maintained at the facility for 

three years. All maintenance is performed following the manufacturer’s specifications. Maintenance 

requirements are covered in the employee training program. 

In the event that the filter clogs and storm water accumulates within the diked area, facility personnel will 

follow required procedures for dike drainage as follows: 

1) Inspect the retained rainwater to ensure that it does not contain oil (it will not cause a 

discharge to [Insert Name of Waterbody] or adjoining shorelines which is the nearest 

navigable water to the facility). 

2) Open the bypass valve, allow drainage, and reseal the valve. 

3) Record event in log. 

The above examples provide a sufficient level of detail to allow the EPA inspector to 

understand what the facility is doing to meet the objectives of the SPCC rule with regard to the 

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Chapter 3: Environmental Equivalence 

given provision, and to verify implementation of the measure(s) in the field. A Plan that simply 

notes the use of an alternative measure without supporting descriptions would not be considered 

sufficient. An example of insufficient documentation is given below. 

Example #3: Insufficient Documentation of Environmentally Equivalent Protection for 

Integrity Testing (§112.8(c)(6)) 

Bulk Storage Tanks – 40 CFR 112.8(c)(6) 

No integrity testing is needed on tank 3A as this is an elevated shop-built storage tank and all sides are visible. 

The outside of the tank is to be inspected on a regular schedule. 

In contrast to the two previous examples, Example #3 does not provide sufficient detail to 

ascertain whether the approach provides environmentally equivalent protection. In particular, it 

does not describe how environmental equivalence is achieved, who performs the inspection, what 

is inspected, and at what frequency. 

3.4.2	 Role of the EPA Inspector 

Like other technical aspects of the SPCC Plan, the selection and implementation of 

environmentally equivalent measures must be reviewed by the certifying PE for consistency with 

good engineering practice (§112.3(d)). For each case where an environmentally equivalent 

measure is used, the EPA inspector should verify that the Plan includes: 

•	 The reasons for nonconformance; 

•	 A detailed description of the alternative measure; and 

•	 An explanation describing how the alternative measure provides protection that is 

environmentally equivalent. 

Additionally, the inspector should verify implementation of the alternative measure in the field. 

The explanation describing how an alternative measure achieves environmental 

equivalence does not need to demonstrate “mathematical equivalency,” but the alternative measure 

does need to provide equivalent protection of the environment against a discharge as described in 

§112.1(b). The Plan should describe how the alternative measure prevents, controls, or mitigates a 

discharge, as well as the procedures or equipment used to implement the alternative measure and 

ensure its continued effectiveness, particularly in terms of the measure’s practical impacts on field 

operations, employee training, monitoring, and equipment maintenance. 

By certifying an SPCC Plan, a PE attests that the Plan has been prepared in accordance 

with good engineering practice, that it meets the requirements of 40 CFR part 112, and that it is 

adequate for the facility. EPA encourages innovative techniques for preventing discharges, but 

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these techniques need to effectively protect the environment. EPA believes that, in general, PEs 

will seek to protect themselves from liability by certifying only measures that do provide equivalent 

environmental protection (67 FR 47095). If alternative measures are certified by a PE as being 

environmentally equivalent, are properly documented, and are appropriately implemented in the 

field, they should generally be considered acceptable by EPA regional inspectors. 

The inspector should note whether the alternative measures meet the standards of common 

sense, and appear to agree with recognized industry standards or, where such standards are not 

used, are in accordance with good engineering practice. The inspector should assess 

implementation of the alternative measures, including whether they appear to have been altered or 

differ from the measures described in the Plan and certified by the PE, have not been implemented 

correctly, require maintenance that has not occurred, appear to be inadequate for the facility, or 

otherwise do not meet the overall oil spill prevention objective of the SPCC rule. 

If the inspector questions the appropriateness of alternative measures, he/she should fully 

document all observations and other pertinent information for further review by the regional staff. 

Follow-up action by the EPA inspector may include requesting additional information from the 

facility owner or operator on the implementation of the equivalent measure. The EPA Regional 

Administrator retains the authority to require amendment for deviations, as he/she can for any other 

part of a Plan. If the Regional Administrator determines that the measures described in the SPCC 

Plan do not provide equivalent environmental protection, then the procedures for requiring a Plan 

amendment under §112.4(d) and (e) and/or an enforcement action may be initiated as deemed 

appropriate. 

Table 3-3 lists the SPCC provisions that may be met through environmentally equivalent 

measures, and provides guidance on the kinds of questions an inspector should consider when 

reviewing environmentally equivalent measures in an SPCC Plan and during a site inspection. The 

table provides a list of evaluation questions for each section of the rule, means of verifying 

compliance during an on-site review, and elements that should be considered in cases where the 

facility installation does not conform with the methods described in the SPCC rule. The EPA 

inspector should use the part(s) of the table that are relevant to the facility being inspected. 

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Chapter 3: Environmental Equivalence 

Table 3-3. SPCC requirements for environmentally equivalent measures under §112.7(a)(2). 

Rule Element Relevant 

Section(s) 

ALL FACILITIES 

Security 112.7(g)(1) 

112.7(g)(2) 

112.7(g)(3) 

112.7(g)(4) 

112.7(g)(5) 

Loading and 112.7(h)(1) 

unloading racks 

112.7(h)(2) 

Evaluation 

Is the facility fully fenced? 

Are entrance gates locked and/or 

guarded when the facility is not in 

production or is unattended? 

Are adequate measures provided to 

ensure that master flow and drain 

valves and other valves that permit 

direct outward flow of the 

container’s contents to the surface 

remain in closed position when in 

non-operating or non-standby 

status? 

Is the starter control for each oil 

pump accessible only to authorized 

personnel, and kept locked in “off” 

position, when the pump is in nonoperating or non-standby status? 

Are the loading/unloading 

connections of oil pipelines or 

facility piping securely capped or 

blank-flanged when not in service, 

or when in standby for an extended 

period? 

Is facility lighting appropriate, 

considering the facility type and 

location, to assist in the discovery of 

discharges occurring in hours of 

darkness and to discourage acts of 

vandalism? 

No deviation allowed based on 

environmental equivalence. 

Are loading/unloading racks 

equipped with an interlocked 

warning light or physical barrier 

system, warning signs, wheel 

chocks, or a vehicle brake interlock 

system to prevent vehicles from 

departing before complete 

disconnection of oil transfer lines? 

Verification Basis for Environmental Equivalence 

During Site Visit 

Visual 

Plan review 

Visual 

Plan review 

Visual 

Plan review 

Visual 

Plan review 

Visual 

Plan review 

Visual 

Plan review 

Does the Plan state the reason for nonconformance? 
 

Does the Plan describe in sufficient detail an alternative 
 

measure? 
 

Is the alternative measure appropriate for the facility? 
 

Does it provide equivalent environmental protection? 
 

Is the alternative measure being implemented as 
 

described? 
 

Does the Plan state the reason for nonconformance? 
 

Does the Plan describe in sufficient detail an alternative 
 

measure? 
 

Is the alternative measure appropriate for the facility? 
 

Does it provide equivalent environmental protection? 
 

Is the alternative measure being implemented as 
 

described? 
 

Does the Plan state the reason for nonconformance? 
 

Does the Plan describe in sufficient detail an alternative 
 

measure? 
 

Is the alternative measure appropriate for the facility? 
 

Does it provide equivalent environmental protection? 
 

Is the alternative measure being implemented as 
 

described? 
 

Does the Plan state the reason for nonconformance? 
 

Does the Plan describe in sufficient detail an alternative 
 

measure? 
 

Is the alternative measure appropriate for the facility? 
 

Does it provide equivalent environmental protection? 
 

Is the alternative measure being implemented as 
 

described? 
 

Does the Plan state the reason for nonconformance? 
 

Does the Plan describe in sufficient detail an alternative 
 

measure? 
 

Is the alternative measure appropriate for the facility? 
 

Does it provide equivalent environmental protection? 
 

Is the alternative measure being implemented as 
 

described? 
 

Does the Plan state the reason for nonconformance? 
 

Does the Plan describe in sufficient detail an alternative 
 

measure? 
 

Is the alternative measure appropriate for the facility? 
 

Does it provide equivalent environmental protection? 
 

Is the alternative measure being implemented as 
 

described? 
 

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Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

prior to filling and departure of the 

vehicles? 

i 

Visual 

ffi 

measure? 

ion? 

I 

described? 

aboveground 

112.7(i) Has the facility conducted an 

fi 

ion, 

i 

f 

If a fi 

f l 

Visual 

Inspecti 

Plan description of 

ffi 

measure? 

ion? 

I 

described? 

i 

Relevant 

112.7(h)(3) Are the lowermost drain and all 

outlets of tank car or tank truck 

inspected for signs of discharge 

Are the drain and outlets t ghtened, 

adjusted, or replaced as necessary 

to prevent liquid discharges while in 

transit? 

Review of procedures 

described in the Plan 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

Field-constructed 

containers 

evaluation of eld-constructed 

aboveground containers 

undergoing repair, alterat 

reconstruct on, or change in service 

that might af ect the risk of a 

discharge or failure? 

eld-constructed aboveground 

container has discharged oil or 

ailed due to britt e fracture failure or 

on and testing 

records 

Brittle fracture 

evaluation records 

standard by which the 

brittle fracture 

evaluation is 

conducted 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

other catastrophe, has the container 

been evaluated and has 

appropriate act on been taken? 

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Chapter 3: Environmental Equivalence 

Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

ALL FACILITIES, EXCEPT OIL PRODUCTION 

Facility Drainage 112.8(b)(1) 

and 

OR 

and 

Diked areas 

Is the facility drainage system or 

effl 

If 

If 

acti 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

f 

draining? 

and 

OR 

and 

discharge 

Does the facility have ponds, 

If 

throughout the facility designed to 

fl i 

looding? 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

OR 

If the facility uses more than one Visual 

Plan review ffi 

measure? 

transfer, does the facility have at ion? 

I 

described? 

OR 

ion of 

i 

conditions)? 

Visual 

Plan review 

i 

ion 

ffi 

measure? 

ion? 

I 

described? 

lowed based on 

OR 

Relevant 

112.8(b)(2) 

112.12(b)(1) 

112.12(b)(2) 

uent treatment system designed 

to control oil discharges? not, is 

drainage from diked storage areas 

restricted by valves? 

Are dikes equipped with manual 

valves of open-closed design? 

 pumps or ejectors are used to 

empty the dikes, are they manually 

vated? 

Records of drainage 

events 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

Is accumulated rainwater inspected 

or the presence of oil prior to 

112.8(b)(3) 

112.8(b)(4) 

112.12(b)(3) 

112.12(b)(4) 

Undiked areas with potential for a 

lagoons, or catchment basins 

designed to capture water from 

other areas with a potential for a 

discharge? so, are such systems 

designed to retain or return oil to 

the facility? If not, are ditches 

ow into a divers on system that 

would retain oil in the facility in the 

event of a discharge? 

If the facility has catchment basins, 

are they located outside areas 

subject to periodic f 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.8(b)(5) 

treatment unit to treat its drainage 

water, and this treatment is 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

112.12(b)(5) 

continuous and requires pump 

least two “lift” pumps? 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

Bulk Storage 

Containers 

112.8(c)(1) 

112.12(c)(1) 

Are the material and construct 

containers used for the storage of 

oil compatible with the product 

stored and condit ons of storage 

(temperature, pressure, and soil 

Standards of 

construct on (tank 

label), construct 

documents and asbuilt specifications 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.8(c)(2) No deviation al 

environmental equivalence. 

112.12(c)(2) 

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Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

OR 

does the facility keep adequate 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

OR 

1974? If 

ion? 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

OR 

Visual 

Plan review 

Inspecti 

ffi 

measure? 

ion? 

I 

described? 

buried or bunkered metallic tanks 

Visual 

Plan review ffi 

OR If so, 

ion? 

Records measure? 

ion? 

I 

described? 

OR f 

combine visual inspecti 

ive shell 

Plan review 

Inspecti ffi 

measure? 

ion? 

I 

described? 

f 

i 

or accumulation or oil? 

OR 

Does 

f Does 

i 

Visual 

ffi 

measure? 

ion? 

I 

described? 

Relevant 

112.8(c)(3) 

112.12(c)(3) 

Does the facility prevent 

unsupervised drainage of rainwater 

into a storm drain or open 

watercourse, or bypassing the 

facility treatment system? If so, 

records of dike drainage event? 

Records of drainage 

events 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.8(c)(4) 

112.12(c)(4) 

Does the facility have completely 

buried metallic storage tanks that 

were installed after January 10, 

 so, are these tanks 

protected from corrosion by 

coatings or cathodic protect 

Installation records 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.8(c)(4) 

112.12(c)(4) 

Does the facility have completely 

buried metallic storage tanks that 

were installed after January 10, 

1974? Are leak tests performed 

regularly on these tanks? 

on and testing 

records 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.8(c)(5) Does the facility have partially Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

112.12(c)(5) 

used for the storage of oil? 

are these tanks protected from 

corrosion by coatings or cathodic 

protect 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.8(c)(6) 

112.12(c)(6) 

Does the facility test each 

aboveground container (including 

oundation and supports) for 

integrity on a regular schedule, and 

whenever a container undergoes 

material repairs? Do the tests 

on with 

another non-destruct 

on and testing 

records 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

testing technique? Does the facility 

requently inspect the outside of 

each aboveground container for 

signs of deteriorat on, discharges, 

112.8(c)(7) 

112.12(c)(7) 

Does the facility have containers 

with internal heating coils? 

the facility monitor the steam return 

and exhaust lines for contamination 

rom internal heating coils? 

the facility pass the steam return or 

exhaust lines through a settling 

tank, skimmer, or other separation 

or retent on system? 

Container 

specifications 

Review of procedures 

described in the Plan 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

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Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

OR 

ff device. 

communicati 

Visual 

procedures described 

ffi 

measure? 

ion? 

I 

described? 

f 

to monitor filling operations. 

Are liquid level sensing devices 

OR 

Are effluent treatment facilities Inspecti 

ion 

program described in 

Plan 

ffi 

measure? 

ion? 

I 

described? 

OR 

discharges? 

I i 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

ions? 

lowed based on 

OR 

Piping 

OR 

If 

If 

buried piping? If so, does the facility 

f ion and 

i 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

ion as 

Relevant 

112.8(c)(8) 

112.12(c)(8) 

Are containers equipped with at 

least one of the following? 

- High liquid level alarm with audible 

or visual signal connected to a 

constantly attended station. 

- High liquid pump cuto 

- Direct audible or code signal 

on between container 

Review of test 

in the Plan 

Test records 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

gauger and pumping station. 

- In the case of bulk storage 

containers, a fast response system 

or determining the liquid level 

(computers, telepulse, direct vision 

gauges), combined with the 

continuous presence of personnel 

regularly tested to ensure proper 

operation? 

112.8(c)(9) 

112.12(c)(9) 

inspected frequently to detect 

possible system upsets? 

on and testing 

records 

Review of inspect 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.8(c)(10) 

112.12(c)(10) 

Are there visible discharges from 

containers, including seams, 

gaskets, piping, pumps, valves, 

rivets, and bolts? If so, is the facility 

promptly addressing such 

s there accumulat on of oil in diked 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

areas? If so, is the facility promptly 

removing such accumulat 

112.8(c)(11) No deviation al 

environmental equivalence. 

112.12(c)(11) 

112.8(d)(1) 

112.12(d)(1) 

Does the facility have buried piping 

installed after August 16, 2002? 

so, is this piping protected against 

corrosion by wrapping and coating? 

 this piping cathodically protected? 

Does the facility have any exposed 

inspect it or deteriorat 

undertake addit onal examination 

Installation records 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

and corrective act 

appropriate? 

U.S. Environmental Protection Agency 3-25 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

OR 

l 

connecti 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

OR 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

OR 

NOTE: Inspection program must 

address conditi 

fl 

I ion records 

Description of 

inspection program 

ffi 

measure? 

ion? 

I 

described? 

I 

OR 

l 

they will not endanger aboveground 

Visual 

ffi 

measure? 

ion? 

I 

described? 

Relevant 

112.8(d)(2) 

112.12(d)(2) 

Does the facility have piping that is 

not in service or is in standby 

service for an extended period of 

time? If so, is the termina 

on at the transfer point 

capped or blank-flanged, and is it 

marked as to origin? 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.8(d)(3) 

112.12(d)(3) 

Are pipe supports properly 

designed to minimize abrasion and 

corrosion and to allow for expansion 

and contraction? 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.8(d)(4) 

112.12(d)(4) 

Are aboveground valves, piping, 

and appurtenances regularly 

inspected? 

ons of items such as 

ange joints, expansion joints, valve 

glands and bodies, catch pans, 

pipeline supports, locking of valves, 

and metal surfaces. 

nspect 

within the Plan, or 

reference to industry 

standard. 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

s buried piping tested for integrity 

and leaks when installed, 

constructed, relocated, or replaced? 

112.8(d)(5) 

112.12(d)(5) 

Are all vehic es entering the facility 

appropriately warned to ensure that 

piping and other oil transfer 

operations? 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

U.S. Environmental Protection Agency 3-26 Version 1.0, 11/28/2005 
Chapter 3: Environmental Equivalence 

Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

ONSHORE OIL PRODUCTION FACILITIES 

Drainage Visual 

Plan review ffi 

ti 

measure? 

ion? 

I 

described? 

I Plan review 

ffi 

measure? 

properly? ion? 

I 

described? 

(2) i 

i 

Visual 

I ion records 

I ion program 

schedule and scope 

ions 

ffi 

measure? 

ion? 

I 

described? 

ion of 

i 

conditions)? 

Visual 

ion 

) 

Visual indication of 

ffi 

measure? 

ion? 

I 

described? 

lowed based on 

I 

periodically and on a regular 

schedule? 

f 

Inspecti 

I ion program 

including scope and 

f 

inspections 

ffi 

measure? 

ion? 

I 

described? 

ions 

is delayed in making a schedule 

round 

low equalizing 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

i 

ion 

Relevant 

112.9(b)(1) Are drains of dikes or other 

containment measures for tank 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

batteries and separation/treating 

areas closed and sealed at all 

mes, except when draining 

uncontaminated rainwater? 

Records of drainage 

events Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.9(b)(1) s accumulated water inspected 

prior to drainage? And is 

accumulated oil removed and either 

Records of drainage 

events 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

returned to storage or disposed of Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.9(b) Are f eld drainage systems and oil 

traps, sumps, or skimmers regularly 

inspected for accumulat on of oil? 

nspect 

nspect 

described in the Plan, 

including the 

of such inspect 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

Bulk Storage 

Containers 

112.9(c)(1) Are the material and construct 

containers used for the storage of 

oil compatible with the product 

stored and condit ons of storage 

(temperature, pressure, and soil 

Construct 

standards (tank 

labels, as-build 

specifications, etc. 

incompatibility, i.e., 

excessive corrosion 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.9(c)(2) No deviation al 

environmental equivalence. 

112.9(c)(3) s each container visually inspected 

NOTE: Inspections must cover 

oundation and support of each 

container that is on or above the 

ground surface. 

on and testing 

records 

nspect 

described in the Plan, 

requency of such 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.9(c)(4) Are tank battery installat 

engineered to prevent discharges? 

- Container capacity is adequate to 

prevent overfill if the gauger/pumper 

- Equipped with overf 

lines between containers 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

- Adequate vacuum protect on to 

prevent container collapse during 

transfer of oil 

- High level sensors if the facility is 

subject to a computer product 

control system 

U.S. Environmental Protection Agency 3-27 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

Are all aboveground valves and 

upon a regular schedule? 

l 

fi 

gauge valves. 

Inspecti 

I ion program 

including f 

and scope of 

inspections 

ffi 

measure? 

ion? 

I 

described? 

112.9(d)(2) 

i 

Plan review 

Inspecti ffi 

measure? 

ion? 

I 

described? 

112.9(d)(3) 

fl 

Inspection and 

ffi 

Program of flowline measure? 

ion? 

I 

described? 

Relevant 

Transfer 

operations 

112.9(d)(1) 

piping inspected periodically and 

NOTE: Inspections must cover 

items such as f ange joints, valve 

glands and bodies, drip pans, pipe 

supports, pumping well polish rod 

stuf ng boxes, and bleeder and 

on and testing 

records 

nspect 

described in the Plan, 

requency 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

Are saltwater disposal facilities 

inspected, part cularly following a 

sudden change in atmospheric 

temperature? 

on and testing 

records 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

Does the facility have a program of 

owline maintenance? maintenance records. 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

maintenance 

described in the Plan, 

including the scope 

and frequency of 

maintenance 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

U.S. Environmental Protection Agency 3-28 Version 1.0, 11/28/2005 
Chapter 3: Environmental Equivalence 

Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

Mobile drilling or 

workover 

equipment 

I Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

lowed based on 

Blowout 112.10(d) 

well led? 

Visual 

Plan review 

ffi 

measure? 

ion? 

I 

described? 

Drainage I 

sump? 

Visual 

Plan review 

icable. 

If i 

overflow? 

Visual 

l 

procedures described 

ffi 

measure? 

ion? 

I 

described? 

If 

I 

available? 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

If 

the facility have in place a regularly 

inspecti 

If i 

Visual 

inspecti 

program described in 

ffi 

measure? 

ion? 

I 

described? 

Relevant 

ONSHORE OIL DRILLING AND WORKOVER FACILITIES 

112.10(b) s the equipment located so as to 

prevent a discharge? 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

Containment 112.10(c) No deviation al 

environmental equivalence. 

prevention 

If drilling below any casing string, or 

during workover operations, are a 

blowout prevention assembly and 

 control system instal 

Are the blowout assembly and well 

control system capable of 

controlling well-head pressure? 

Installation record 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

OFFSHORE OIL DRILLING, PRODUCTION AND WORKOVER FACILITIES 

112.11(b) s oil drainage collection equipment 

used to prevent and control small 

discharges? Are facility drains 

directed toward a central collection 

See below for cases where a sump is not pract 

112.11(b) a sump is not pract cable, is oil 

removed from collection equipment 

as often as necessary to prevent 

Oil remova 

in the Plan 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility?

 Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.11(c) a sump system is employed, are 

the sizes of pump and sump 

adequate? s a spare pump 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.11(c) a sump system is employed, does 

scheduled preventive maintenance 

on and testing program to 

assure reliable operation? 

 required by the condit ons, are a 

redundant automatic sump pump 

and control devices provided? 

Preventive 

maintenance 

on and testing 

the Plan 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

U.S. Environmental Protection Agency 3-29 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

112.11(d) 

ion risk 

l 

Visual 

Description of 

inspection and 

schedule and scope 

ions. 

ffi 

measure? 

ion? 

I 

described? 

i 

low? 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

) 

i 

Visual 

Plan review ffi 

measure? 

low? 

ion? 

I 

described? 

ion? 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

i 

polluti 

Plan review 

ffi 

measure? 

ion? 

I 

described? 

Pollution i 

basis? 

Inspecti 

Description of 

inspecti 

program in Plan, 

including scope and 

f 

ffi 

measure? 

ion? 

I 

described? 

Relevant 

Separators and 

Treaters 

Does the facility have areas where 

separators and treaters are 

equipped with dump valves which 

predominantly fail in the closed 

position and where the pollut 

is high? If so, is the facility specially 

equipped to prevent the discharge 

of oil, including: 

- Extending the f are line to a diked 

area if the separator is near shore? 

- Equipping the separator with a 

high liquid level sensor that will 

automatically shut in wells 

producing to the separator, or 

installing parallel redundant dump 

valves? 

maintenance of 

separators and heater 

treaters (including 

dump valves) in the 

Plan, including the 

of such inspect 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

Containers 112.11(e) Are atmospheric storage or surge 

containers equipped with high liquid 

level sensing devices that act vate 

an alarm or control the f 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.11(f Are pressure containers equipped 

with high and low pressure sensing 

devices that act vate an alarm or 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

control the f Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.11(g) Are containers equipped with 

suitable corrosion protect 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.11(h) Does the Plan contain a written 

procedure for inspect ng and testing 

on control equipment and 

systems? 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

prevention 

equipment and 

systems 

112.11(i) Are the pollut on prevention 

equipment and systems tested and 

inspected on a scheduled periodic 

Are the procedures documented in 

the Plan? 

on and testing 

records 

on and testing 

requency 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

U.S. Environmental Protection Agency 3-30 Version 1.0, 11/28/2005 
Chapter 3: Environmental Equivalence 

Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

112.11(i) Is the facility using simulated 

inspecting human and equipment 

polluti 

Descripti 

program in Plan ffi 

measure? 

ion? 

I 

described? 

112.11(j) I ivation or Plan review 

ffi 

devices described in sufficient measure? 

ion? 

I 

described? 

Blowout 112.11(k) 

If 

system capable of controlling wellVisual 

Plan review ffi 

measure? 

ion? 

I 

described? 

Flowlines Visual 

Plan review ffi 

flowlines? measure? 

ion? 

I 

described? 

Are all fl 

high pressure sensing device and 

If 

Visual 

Plan review ffi 

measure? 

i i 

lowlines? ion? 

I 

described? 

Piping I 

ion, 

i 

ion? 

Visual 

Plan review ffi 

measure? 

ion? 

I 

described? 

I 

ivities such 

Inspection and 

described in Plan 

ffi 

measure? 

as fi 

ion? 

I 

described? 

Relevant 

discharges for testing and 

on control and 

countermeasure systems? 

on of testing Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

Well shut-in 

valves 

s the method of act 

control of well shut-in valves and 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

details? Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

Prevention 

If drilling below any casing string or 

during workover assembly, is a 

blowout preventer (BOP) assembly 

and well control system installed? 

the BOP assembly and well control 

head pressure that may be 

encountered? 

Installation records 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.11(l) Are manifolds (headers) equipped 

with check valves on individual 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.11(m) owlines equipped with a 

shut-in valve at the wellhead? 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

not, s a pressure rel ef system 

provided for f 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.11(n) s all piping appurtenant to the 

facility protected from corros 

such as with protect ve coating or 

cathodic protect 

Installation records 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

112.11(o) s sub-marine piping adequately 

protected against environmental 

stresses and other act 

maintenance program 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

shing operations? Installation records Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

U.S. Environmental Protection Agency 3-31 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

Rule Element 

Section(s) 

Evaluation Verification 

During Site Visit 

Basis for Environmental Equivalence 

112.11(p) 

f 

schedule? 

i 

Inspecti 

ion 

described in Plan, 

including scope and 

f 

inspecti 

ffi 

measure? 

ion? 

I 

described? 

Relevant 

Does the facility have a program to 

inspect or test sub-marine piping for 

ailures according to a regular 

Does the facility maintain a record 

of these inspect ons or tests? 

on and testing 

records 

Review of inspect 

or testing program 

requency of 

ons or tests 

Does the Plan state the reason for nonconformance? 

Does the Plan describe in su cient detail an alternative 

Is the alternative measure appropriate for the facility? 

Does it provide equivalent environmental protect 

s the alternative measure being implemented as 

U.S. Environmental Protection Agency 3-32 Version 1.0, 11/28/2005 
Chapter 4: Secondary Containment and Impracticability 

SECONDARY CONTAINMENT AND IMPRACTICABILITY 

DETERMINATIONS 

4.1 Introduction 

The purpose of the SPCC rule is to prevent discharges of oil into navigable waters of the 

United States and adjoining shorelines. One of the primary ways through which the rule sets out to 

do this is the secondary containment requirements. A secondary containment system provides an 

essential line of defense in the event of a failure of an oil container (primary containment), such as a 

bulk storage container, a mobile or portable container, pipes or flowlines, or other oil-filled 

operational equipment. The system provides temporary containment of spilled oil until the 

appropriate response actions are taken to abate the source of the discharge and remove oil from 

areas where it has accumulated before the oil reaches navigable waters and adjoining shorelines. 

The secondary containment requirements are divided into two categories: 

•	 General provisions address the potential for oil discharges from all regulated parts 

of a facility. Containment method, design, and capacity are determined by good 

engineering practice to contain an oil discharge until cleanup occurs. 

•	 Specific provisions address the potential of oil discharges from specific parts of a 

facility where oil is stored or handled. The containment design, sizing, and freeboard 

requirements are specified by the SPCC rule to address a major container failure. 

The general secondary containment requirements are intended to address the most likely oil 

discharge from bulk storage containers; mobile/portable containers; production tank battery, 

treatment, and separation installations; a particular piece of oil-filled operational or process 

equipment; (non-rack) transfer activity; or piping in accordance with good engineering practice. The 

specific secondary containment requirements are intended to address a major container failure (the 

entire contents of the container and/or compartment) associated with a bulk storage container; 

single compartment of a tank car or tank truck at a loading/unloading rack; mobile/portable 

containers; and production tank batteries, treatment, and separation installations. These specific 

provisions (see Table 4.1 in Section 4.2) explicitly provide requirements for sizing, design, and 

freeboard that need to be addressed in the SPCC Plan. 

The purpose of this chapter is to clarify the relationships among the various general and 

specific secondary containment requirements of the SPCC rule, and to demonstrate how these 

requirements apply. This chapter also discusses the rule’s impracticability determination provision, 

which may be used when a facility owner/operator is incapable of installing secondary containment 

by any reasonable method. The additional requirements that accompany an impracticability 

determination, the documentation needed to support such a determination, and the role of the EPA 

U.S. Environmental Protection Agency 4-1	 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

inspector in reviewing secondary containment requirements and impracticability determinations are 

also discussed. 

The remainder of this chapter is organized as follows: 

•	 Section 4.2 provides an overview of the SPCC rule’s secondary containment 

provisions, both general and specific. It also discusses related issues, such as 

active versus passive measures, the “sufficiently impervious” requirement, and 

facility drainage. The role of the EPA inspector in evaluating compliance with the 

rule provisions is discussed for each of these subjects. 

•	 Section 4.3 describes the impracticability determination provision. 

•	 Section 4.4 discusses how the impracticability determination may be used in certain 

circumstances. 

•	 Section 4.5 describes required measures when secondary containment is 

impracticable. 

•	 Section 4.6 describes the role of the EPA inspector in reviewing impracticability 

determinations. 

4.2 	 Overview of Secondary Containment Provisions 

The SPCC rule includes several different secondary containment provisions intended to 

address the various activities or locations at a facility in which oil is handled. This section 

differentiates among the general and specific secondary containment provisions. 

Table 4-1 lists all the secondary containment provisions of the SPCC rule for different types 

of facilities. 

U.S. Environmental Protection Agency 4-2	 Version 1.0, 11/28/2005 
Chapter 4: Secondary Containment and Impracticability 

Table 4-1. Secondary containment provisions in 40 CFR part 112. 

Type of Facility Secondary Containment Rule Section(s) 

General containment (areas with potential for 
 

discharge, e.g., piping, oil-filled operating and 112.7(c)
 All Facilities manufacturing equipment, and non-rack 
 

related transfer areas) 
 

Loading/unloading racks*,** 112.7(h)(1) 
 

Bulk storage containers* 112.8(c)(2) or 112.12(c)(2) 
 

Onshore Storage Mobile or portable oil containers* 112.8(c)(11) or 112.12(c)(11) 

Bulk storage containers, including tank 
 

Onshore Production batteries, separation, and treating facility 112.9(c)(2) 
 

installations* 
 

Onshore Oil Drilling and Mobile drilling or workover equipment 112.10(c) Workover 
 

Offshore Oil Drilling, 
 

Production, and Oil drilling, production, or workover equipment 112.7(c) 
 

Workover 
 

* Sized secondary containment requirement, as discussed in Section 4.2.2. 

** Although this requirement applies to all facilities, loading and unloading rack equipment is often not present at typical 

production facilities, as discussed in Section 4.4.2. 

Figures 4-1 through 4-4 illustrate the relationships between the secondary containment 

requirements at various types of facilities. EPA inspectors should use the flowchart that 

corresponds to the type of facility he or she is visiting (see the uppermost box in each flowchart). 

Types of containers, equipment, and activities or areas where oil is handled are identified in the 

second row of the flowchart, with reference to the appropriate secondary containment rule 

provision. The flowcharts note the use of impracticability determinations and additional design 

considerations for other areas with the potential for discharge. 

U.S. Environmental Protection Agency 4-3 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

Figure 4-1. Secondary containment provisions in 40 CFR part 112 related to onshore storage 

facilities (§§112.7 and 112.8 or 112.12). 

U.S. Environmental Protection Agency 4-4 Version 1.0, 11/28/2005 
Chapter 4: Secondary Containment and Impracticability 

Figure 4-2. Secondary containment provisions in 40 CFR part 112 related to onshore production 

facilities (§§112.7 and 112.9). 

U.S. Environmental Protection Agency 4-5 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

Figure 4-3. Secondary containment provisions in 40 CFR part 112 related to onshore oil drilling 

and workover facilities (§§112.7 and 112.10). 

U.S. Environmental Protection Agency 4-6 Version 1.0, 11/28/2005 
Chapter 4: Secondary Containment and Impracticability 

Figure 4-4. Secondary containment provisions in 40 CFR part 112 related to offshore oil drilling, 

production, and workover facilities (§§112.7 and 112.11). 

U.S. Environmental Protection Agency 4-7 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

4.2.1 General Secondary Containment Requirement 

At a regulated facility, all areas with 

the potential for a discharge are subject to 

the general secondary containment 

provision, §112.7(c). These areas may have 

bulk storage containers; mobile/portable 

containers; production tank batteries, 

treatment, and separation installations; 

pieces of oil-filled operational or 

manufacturing equipment; loading/unloading 

areas (also referred to as transfer areas); 

piping; and may include other areas of a 

facility where oil is present. The general 

secondary containment provision requires 

that these areas be designed with 

appropriate containment and/or diversionary 

structures to prevent a discharge that may 

be harmful (a discharge as described in 

§112.1(b)). “Appropriate containment” 

should be designed to address the most 

§112.7(c) 

ing 

contain oil; 

. 

Note: The above text is an excerpt of the SPCC rule. Refer to 40 

CFR part 112 for the full text of the rule. 

(1) For onshore facilities: 

(ii) Curbing; 

(v) Spill diversion ponds; 

(vi) Retention ponds; or 

(vii) Sorbent materials. 

(2) For offshore facilities: 

(i) Curbing or drip pans; or 

Provide appropriate containment and/or diversionary 

structures or equipment to prevent a discharge as 

described in §112.1(b). The entire containment system, 

including walls and floor, must be capable of containing oil 

and must be constructed so that any discharge from a 

primary containment system, such as a tank or pipe, will 

not escape the containment system before cleanup occurs. 

At a minimum, you must use one of the follow 

prevention systems or its equivalent: 

(i) Dikes, berms, or retaining walls sufficiently impervious to 

(iii) Culverting, gutters, or other drainage systems; 

(iv) Weirs, booms, or other barriers; 

(ii) Sumps and collection systems 

likely discharge from the primary 

containment system such that the discharge will not escape containment before cleanup occurs. 

Section 112.7(c) lists several methods of providing secondary containment, which are 

described in Table 4-2. These methods are examples only; other containment methods may be 

used, consistent with good engineering practice. For example, a facility could use an oil/water 

separator, combined with a drainage system, to collect and retain discharges of oil within the 

facility. Certification of the SPCC Plan verifies that whatever secondary containment methods are 

selected are appropriate for the facility and that they follow good engineering practice. 

) 

i 

Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 112 for the full text of the rule. 

Discharge as described in §112.1(b is a discharge “in quantities that may be harmful, as described in part 110 

of this chapter [40 CFR part 110], into or upon the navigable waters of the United States or adjoining shorelines, 

or into or upon the waters of the contiguous zone, or in connection w th activities under the Outer Continental 

Shelf Lands Act or the Deepwater Port Act of 1974, or that may affect natural resources belonging to, 

appertaining to, or under the exclusive management authority of the United States (including resources under the 

Magnuson Fishery Conservation and Management Act)...” 

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Table 4-2. Example methods of secondary containment listed in §112.7(c). 

Secondary Description of Examples Containment Method 

Dikes, berms, or Types of permanent engineered barriers, such as raised earth embankments or 

retaining walls concrete containment walls, designed to hold oil. Normally used in areas with 

sufficiently impervious to potential for large discharges, such as single or multiple aboveground storage 

contain oil tanks and certain piping. Temporary dikes and berms may be constructed after 

a discharge is discovered as an active containment measure (or a 

countermeasure) so long as they can be implemented in time to prevent the 

spilled oil from reaching surface waters. Please see Section 4.2.6, Passive 

Versus Active Measures of Secondary Containment. 

Curbing Typically consists of a permanent reinforced concrete or an asphalt apron 

surrounded by a concrete curb. Can also be of a uniform, rectangular crosssection or combined with mountable curb sections to allow access to 

loading/unloading vehicles and materials handling equipment. Can be used 

where only small spills are expected and also used to direct spills to drains or 

catchment areas. Temporary curbing may be constructed after a discharge is 

discovered as an active containment measure (or a countermeasure) so long as 

it can be implemented in time to prevent the spilled oil from reaching surface 

waters. Please see Section 4.2.6, Passive Versus Active Measures of 

Secondary Containment. 

Culverting, gutters, or Types of permanent drainage systems designed to direct spills to remote 
 

other drainage systems 
 containment or treatment areas. Ideal for situations where spill containment 

structures cannot or should not be located immediately adjacent to the potential 

spill source. 

Weirs Dam-like structures with a notch through which oil may flow to be collected. 

Generally used in combination with skimmers to remove oil from the surface of 

water. 

Booms Form a continuous barrier placed as a precautionary measure to contain/collect 

oil. Typically used for the containment, exclusion, or deflection of oil floating on 

water, and is usually associated with an oil spill contingency or facility response 

plan to address oil spills that have reached surface waters. Beach booms are 

designed to work in shallow or tidal areas. Sorbent-filled booms can be used for 

land-based spills. There are very limited applications for use of booms for landbased containment of discharged oil. 

Barriers Spill mats, storm drain covers, and dams used to block or prevent the flow of oil. 

Temporary barriers may be put in place prior to a discharge or after a discharge 

is discovered. These are both considered effective active containment 

measures (or countermeasures) as long as they can be implemented in time to 

prevent the spilled oil from reaching navigable waters and adjoining shorelines. 

Please see Section 4.2.6, Passive Versus Active Measures of Secondary 

Containment. 

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Secondary 

Containment Method Description of Examples 

Spill diversion ponds 

and retention ponds 

Designed for long-term or permanent containment of storm water capable to 

capture and hold oil or runoff and prevent it from entering surface water bodies. 

discharge is discovered as an active containment measure (or countermeasure) 

There are very limited 

appropriate excavation equipment required to rapidly construct the ponds. 

Please see Section 4.2.6, Passive Versus Active Measures of Secondary 

Containment. 

Sorbent materials 

pads, pillows, socks, and mats) used to recover liquids through the mechanisms 

of absorption, adsorption, or both. Materials include clay, vermiculite, 

active containment measure (or countermeasure) to contain and collect smallvolume discharges before they reach waterways. Please see Section 4.2.6, 

Passive Versus Active Measures of Secondary Containment. 

Drip pans Used to isolate and contain small drips or leaks until the source of the leak is 

(usually drums), uncoupling of hoses during bulk transfer operations, and for 

pumps, valves, and fittings. 

Sumps and collection A permanent pit or reservoir and the troughs/trenches connected to it that 

collect oil. 

4.2.2	 

While all parts of a regulated facility with potential for a discharge are, at a minimum, subject 

to the general secondary containment requirements of §112.7(c), areas where certain types of 

containers, activities, or equipment are located may be subject to additional, more stringent 

The 

SPCC rule specifies a required minimum size for secondary containment for the following areas: 

•	 

•	 Loading/unloading racks; 

•	 

•	 

treating vessels/equipment. 

Temporary spill diversion ponds and retention ponds may be constructed after a 

as long as they can be implemented in time to prevent the spilled oil from 

reaching navigable waters and adjoining shorelines. 

applications for use of temporary spill diversion and retention ponds for landbased containment of discharged oil due to the timely availability of the 

Insoluble materials or mixtures of materials (packaged in forms such as spill 

diatomaceous earth, and man-made materials. Used to isolate and contain 

small drips or leaks until the source of the leak is repaired. Commonly used 

with material handling equipment, such as valves and pumps. Also used as an 

repaired. Drip pans are commonly used with product dispensing containers 

systems 

Specific Secondary Containment Requirements 

containment requirements, including specifications for minimum capacity (see Table 4-1.) 

Bulk storage containers; 

Mobile or portable bulk storage containers; and 

Production facility bulk storage containers, including tank batteries, separation, and 

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The applicable requirements for each of these types of containers or equipment are 

discussed in more detail in Section 4.4 of this chapter. In general, provisions for sized secondary 

containment require that the chosen containment method be sized to contain the largest single oil 

compartment or container plus “sufficient freeboard” to contain precipitation, as discussed in 

Section 4.2.4 below. Specific freeboard sizing requirements apply to all of the areas listed above 

except loading/unloading racks. 

EPA inspectors should note that the “largest single compartment” may consist of containers 

that are permanently manifolded together. Permanently manifolded tanks are tanks that are 

designed, installed, or operated in such a manner that the multiple containers function as a single 

storage unit (67 FR 47122). Accordingly, the total capacity of manifolded containers is the design 

capacity standard for the sized secondary containment provisions (plus freeboard in certain cases). 

4.2.3	 Role of the EPA Inspector in Evaluating Secondary Containment Methods 

The EPA inspector should evaluate whether the secondary containment system is adequate 

for the facility, and whether it is maintained to contain any oil discharges to navigable waters and 

adjoining shorelines. Some items that the inspector should look for include: 

For a dike, berm, or other engineered secondary containment system: 

•	 Capacity of the system to contain oil as determined by the Professional Engineer 

(PE) in accordance with good engineering practice and the requirements of the rule; 

•	 Cracks in containment system materials (e.g., concrete, liners, coatings, earthen 

materials); 

•	 Discoloration; 

•	 Presence of spilled or leaked material (standing liquid); 

•	 Corrosion of the system; 

•	 Erosion of the system; 

•	 Level of precipitation in diked area and available capacity versus design capacity; 

•	 Dike or berm permeability; 

•	 Presence of debris; 

•	 Operational status of drain valves or other drainage controls; 

•	 Location/status of pipes, inlets, and drainage around and beneath containers; 

•	 Excessive vegetation that may inhibit visual inspection and assessment of berm 

integrity; 

•	 Large-rooted plant systems (e.g., shrubs, cacti, trees) that could affect the berm 

integrity; 

•	 Holes or penetrations to the containment system created by burrowing animals; and 

•	 Drainage records for rainwater discharges from containment areas. 

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For retention and drainage ponds: 

•	 Capacity of the system to contain oil as determined by the PE in accordance with 

good engineering practice and the requirements of the rule; 

•	 Erosion of the system; 

•	 Cracks in containment system materials (e.g., concrete, liners, coatings, earthen 

materials); 

•	 Discoloration; 

•	 Design capacity versus available capacity; 

•	 Presence of spilled or leaked liquid; 

•	 Presence of debris; 

•	 Stressed vegetation; 

•	 Evidence of water seeps from the system; and 

•	 Operational status of drain valves or other drainage controls. 

Some of the items listed above are discussed in more detail in later sections of this 

guidance document. 

4.2.4	 Sufficient Freeboard 

The SPCC rule does not specifically define the term “sufficient freeboard,” nor does it 

describe how to calculate this volume. The 1991 proposed amendment to the SPCC rule 

recommended the use of industry standards and data on 25-year storm events to determine the 

appropriate freeboard capacity. Numerous commenters on the 1991 proposal questioned the 25-

year storm event recommendation and suggested alternatives, such as using 110 percent of 

storage tank capacity or using other characteristic storm events. EPA addressed these comments 

in the preamble to the 2002 rule: 

We believe that the proper standard of “sufficient freeboard” to contain precipitation is that 

amount necessary to contain precipitation from a 25-year, 24-hour storm event. That 

standard allows flexibility for varying climatic conditions. It is also the standard required for 

certain tank systems storing or treating hazardous waste. (67 FR 47117) 

However, EPA did not set this standard as a requirement for freeboard capacity. Therefore, 

the use of precipitation data from a 25-year, 24-hour storm event is not enforceable as a standard 

for containment freeboard. In the preamble, EPA stated: 

While we believe that the 25-year, 24-hour storm event standard is appropriate for most 

facilities and protective of the environment, we are not making it a rule standard because of 

the difficulty and expense for some facilities of securing recent information concerning such 

storm events at this time. 

Ultimately EPA determined that, for freeboard, “the proper method of secondary 

containment is a matter of engineering practice so [EPA does] not prescribe here any particular 

method” (67 FR 47101). However, where data are available, the facility owner/operator (and 

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certifying PE) should consider the appropriateness of the 25-year, 24-hour storm event precipitation 

level as a matter of good engineering practice. 

EPA recognizes that a “110 percent of storage tank capacity” rule of thumb may be a 

potentially acceptable design criterion in many situations, and that aboveground storage tank 

regulations in many states require that secondary containment be sized to contain at least 110 

percent of the volume of the largest tank. However, in some areas, 110 percent of storage tank 

capacity may not provide enough volume to contain precipitation from storm events. Some states 

require that facilities consider storm events when designing secondary containment structures, and 

in certain cases these requirements translate to more stringent sizing criteria than the 110 percent 

rule of thumb. Other important factors may be considered in determining necessary secondary 

containment capacity. According to practices recommended by industry groups such as the 

American Petroleum Institute (API), these factors include: 

• Local precipitation conditions (rainfall and/or snowfall); 

• Height of the existing dike wall; 

• Size of tank/container; 

• Safety considerations; and 

• Frequency of dike drainage and inspection. 

The following examples (Figure 4-5 and Figure 4-6) present secondary containment size 

calculations for hypothetical oil storage areas. The certifying PE determines what is sufficient 

freeboard for precipitation for secondary containment and should document how the determination 

was made along with supporting calculations in the SPCC Plan. 

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lons 

i 

precipitation. 

i 

dike. 

; 

been reported in the past. 3 

. 

1. 

2 

3 3 

3

 / 900 ft2 

i 3 3 

3 / 900 ft2 

2. 

2 

3 3 

3

 / 900 ft2 

4.5 inches / 12 inches 

calculated using the 110% criterion. 

certified in the Plan. 

Figure 4-5. Sample calculation of containment size, using two design criteria. 

20,000 gal 

45 ft 

20 ft 

Height: ? 

The follow ng example compares two different design criteria: one based on the volume of the tank and one based on 

Scenario: 

A 20,000-gallon horizontal tank is placed w thin an engineered secondary containment structure, such as a concrete 

The tank is 35 feet long by 10 feet in diameter. The secondary containment area provides a 5-foot buffer on all 

sides (i.e., dike dimensions are 45 feet x 20 feet). 

Given the dike footprint, we want to determine the wall height necessary to provide sufficient freeboard for 

precipitation, based on (1) the tank storage capacity (2) actual precipitation data. Several storm events in the recent 

past caused precipitation in amounts between 3.6 and 4.0 inches at this location, although greater amounts have also 

Note: The factor for converting cubic feet to gallons is 7.48 gallons/ft 

Calculation of secondary containment capacity, based on a design criterion of 110% of tank storage 

capacity: 

Containment surface area = 45 ft x 20 ft = 900 ft 

Tank volume, based on 100% of tank capacity = 20,000 gallons 

Tank volume, in cubic feet = 20,000 gallons / 7.48 gallons/ft = 2,674 ft 

Wall height that would contain the tank’s volume = 2,674 ft = 2.97 ft 

Containment capacity w th freeboard, based on 110% of tank capacity = 22,000 gallons 

Containment capacity, in cubic feet = 22,000 gallons / 7.48 gallons/ft = 2,941 ft 

Wall height equivalent to 110% of storage capacity = 2,941 ft = 3.27 feet 

Height of freeboard = 3.27 ft - 2.97 ft = 0.3 ft = 3.6 inches 

Therefore, a dike design based on a criterion of 110% of tank capacity provides a dike wall height of 3.27 feet. 

Calculation of secondary containment capacity, based on rainfall criterion: 

After a review of historical precipitation data for the vicinity of the facility, the PE determined that a 4.5 inch rain event 

is the most reasonable design criterion for this diked area. 

Containment surface area = 45 ft x 20 ft = 900 ft 

Tank volume, based on 100% of tank capacity = 20,000 gallons 

Tank volume, in cubic feet = 20,000 gallons / 7.48 gallons/ft = 2,674 ft 

Wall height that would contain the tank’s volume = 2,674 ft = 2.97 ft 

The height of the dike would need to be 3.35 feet (2.97 ft + 4.5 in). 

= .375 ft + 2.97 ft = 3.35 ft 

Therefore, a dike design based on a 4.5 inch rain event provides a dike wall height of 3.35, or 0.9 inch higher than 

Conclusion: As noted from the comparison of the two design criteria illustrated above, the dike heights are similar. 

The adequacy of the secondary containment freeboard is ultimately an engineering determination made by the PE and 

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lons 

lons 

ing scenario and 

Notes: 

– 3 

. 

– i 

B D2 

diameter. 

1. 

i 3 

2. 

B(10 ft)2 3 

within the dike, is: 3 

ithin the dike 3 

/volume of largest tank within the dike 

3 .1.8 in 

ith the freeboard volume 

associated wi 

Figure 4-6. Sample secondary containment calculations, for multiple tanks in a containment area. 

20,000 gal 

2 @ 10,000 gal 

60 ft 

36 ft 

1.5 ft 

The EPA inspector has questioned the adequacy of the secondary containment based on the follow 

wants to verify how much precipitation the dike area can hold and compare it to available precipitation data to 

determine if 112% is an adequate design criterion for this facility. 

Scenario: 

A 60 ft x 36 ft concrete dike surrounds one 20,000-gallon horizontal tank (10 ft diameter and 35 ft length) and two 

10,000-gallon vertical tanks (each 10 ft diameter and 15 ft height). The dike walls are 18 inches (1.5 feet) tall. The 

SPCC Plan states that secondary containment is designed to hold 112% of the volume of the largest container. 

 The factor for converting gallons to cubic feet is 7.48 gallons/ft 

The volume displaced by a cylindrical vertical tank is the tank volume w thin the containment structure and is equal to 

the tank footprint multiplied by height of the concrete dike. The tank footprint is equal to /4, where D is the tank 

Calculate total dike capacity: 

Total capacity of the concrete dike 

= length x w dth x height = 60 ft x 36 ft x 1.5 ft = 3,240 ft = 24,235 gallons 

Calculate net dike capacity, considering displacement from other tanks within the dike: 

The total capacity of the concrete dike is reduced by the volume “displaced” by other tanks inside the 

containment structure. The displacement is: 

= number of tanks x footprint x height of dike wall 

= 2 x /4 x 1.5 ft = 235.6 ft = 1,762 gallons 

The net dike capacity, i.e., the volume that would be available in the event of a failure of the largest tank 

= Total volume – tank displacement = 24,235 – 1,762 = 22,473 gallons = 3,004 ft 

3. Calculate the amount of available freeboard provided by the dike, given the net dike capacity: 

The available freeboard volume is: 

= Net dike capacity – volume of largest tank w 

= 22,473 – 20,000 = 2,473 gallons = 331 ft 

This is equivalent, expressed in terms of the capacity of the largest tank, to: 

= Net dike capacity 

= 22,473 / 20,000 = 112% 

This available freeboard volume provides a freeboard height: 

= Available freeboard volume / dike surface area 

= 331 ft / (60 ft x 36 ft) = 0.15 ft 

Therefore, this dike provides sufficient freeboard for 1.8 inches of precipitation. 

Conclusion: 

The EPA inspector should review the Plan and/or inquire about the precipitation event considered in determining that 

“sufficient freeboard for precipitation” is provided. The adequacy of the secondary containment freeboard is ultimately 

an engineering determination made by the PE and is certified in the Plan. This example serves only as a guide on 

doing the calculations for certain circumstances in which the inspector has concerns w 

th the secondary containment design. 

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4.2.5	 Role of the EPA Inspector in Evaluating Sufficient Freeboard 

When reviewing an SPCC Plan, the EPA inspector should evaluate whether the size of 

secondary containment is adequate to meet the freeboard requirement. When examining the 

secondary containment measures for bulk storage containers, mobile or portable oil containers, and 

production facility bulk storage containers, the inspector should ensure that the Plan documents 

that the secondary containment capacity can hold the entire capacity of the largest single container, 

plus sufficient freeboard to contain precipitation. Whatever method is used to calculate the amount 

of freeboard that is “sufficient” for the facility and container configuration should be documented in 

the Plan. 

To determine whether secondary containment is sufficient, the EPA inspector may: 

• 	 Verify that the Plan specifies the capacity of secondary containment along with 

supporting documentation, such as calculations for comparing freeboard capacity to 

the volume of precipitation in an expected storm event. 

–	 If calculations are not included with the Plan, and the inspector suspects the 

secondary containment is inadequate, the inspector may request supporting 

documentation from the owner/operator.1 

–	 If diked area calculations appear inadequate, review local precipitation data 

such as data from airports or the National Weather Service,2

 as needed. 

• 	 Review operating procedures, storage tank design, and/or system controls for 

preventing inadvertent overfilling of oil storage tanks that could affect the available 

capacity of the secondary containment structure. 

• 	 Confirm that the secondary containment capacity can reasonably handle the 

contents of the largest tank on an ongoing basis (i.e., including during rain events). 

• 	 During the inspection, verify that the containment structures and equipment are 

maintained and that the SPCC Plan is properly implemented. 

4.2.6	 Passive Versus Active Measures of Secondary Containment 

In some situations, permanent containment structures, such as dikes, may not be feasible 

(i.e., for certain electrical equipment). Section 112.7(c) allows for the use of certain types of active 

containment measures (countermeasures or spill response capability), which prevent a discharge to 

navigable waters or adjoining shorelines. Active containment measures are those that require 

deployment or other specific action by the owner or operator. These measures may be deployed 

either before an activity involving the handling of oil starts, or in reaction to a discharge so long as 

the active measure is designed to prevent an oil spill from reaching navigable water or adjoining 

1

 Industry guidance recommends that facility owners/operators include any secondary containment capacity 

calculations and/or design standards with the Plan. API Bulletin D16, “Suggested Procedure for Development of Spill 

Prevention Control and Countermeasure Plans,” contains example calculations to which inspectors may refer. 

2

 National Weather Service, Hydrometeorological Design Studies Center, Current Precipitation Frequency 
 

Publications, available at http://www.nws.noaa.gov/oh/hdsc/currentpf.htm#N2. 
 

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shorelines. Passive measures are permanent installations and do not require deployment or action 

by the owner/operator. 

Active measures (countermeasures) include, but are not limited to: 

• 	 Placing a properly designed storm drain cover over a drain to contain a 

potential spill in an area where a transfer occurs, prior to the transfer activity. 

Storm drains are normally kept uncovered; deployment of the drain cover prior to the 

transfer activity may be an acceptable active measure to prevent a discharge from 

reaching navigable waters or adjoining shorelines through the drainage system. 

•	 Placing a storm drain cover over a drain in reaction to a discharge, before the 

oil reaches the drain. If deployment of a drain cover can reliably be achieved in 

time to prevent a discharge of oil from reaching navigable waters or adjoining 

shorelines, this may be an acceptable active measure. This method may be risky, 

however, and is subject to a good engineering 

judgement on what is realistically and reliably 

achievable, even under adverse circumstances. L Tip 

•	 Using spill kits in the event of an oil discharge. Active – The containment 

measure involves a certain 

The use of spill kits, strategically located and ready action by facility personnel 

for deployment in the event of an oil discharge, may before or after the discharge 

occurs. These actions are 

be an acceptable active measure, in certain also referred to as spill 

circumstances, to prevent a spill from reaching	 	 countermeasures. 

navigable waters or adjoining shorelines. This	 	 Passive – The containment 

method may be risky and is subject to good measure remains in place

regardless of the facility engineering judgement, considering the volume most operations and therefore 

likely expected to be discharged and proximity to does not require facility 

navigable waters or adjoining shorelines. personnel to act. 

•	 Use of spill response capability (spill response teams) in the event of an oil 

discharge. This method differs from activating an oil spill contingency plan (such as 

required in §112.7(d)) because the response actions are specifically designed to 

contain an oil discharge prior to reaching navigable waters or adjoining shorelines. 

This may include the emergency construction/deployment of dikes, curbing, 

diversionary structures, ponds, and other temporary containment methods (such as 

sorbent materials) so long as they can be implemented in time to prevent the spilled 

oil from reaching navigable waters or adjoining shorelines. This method may be 

risky and is subject to good engineering judgement. 

•	 Closing a gate valve that controls drainage from an area prior to a discharge. 

If the gate valve is normally kept open, closing it before an activity that may result in 

an oil discharge may be an acceptable active measure to prevent a spill from 

reaching navigable waters or adjoining shorelines. 

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The efficacy of active containment measures to prevent a discharge depends on their 

technical effectiveness (e.g., mode of operation, absorption rate), placement and quantity, and 

timely deployment prior to or following a discharge. For discharges that occur only during manned 

activities, such as those occurring during transfers, an active measure (e.g, sock, mat, other 

portable barrier, or land-based response capability) may be appropriate, provided that the measure 

is capable of containing the oil discharge volume and rate, and is timely and properly 

constructed/deployed. Ideally, in order to further reduce the potential for a discharge to reach 

navigable waters or adjoining shorelines, the active 

measure should be deployed prior to initiating the 

activity with potential for a discharge. L Tip 

Land-Based Response Capability is used to 

describe any active measure that is deployed/ 

For certain active measures, however, such as implemented immediately upon discovery of a 

discharge before the discharge reaches the use of “kitty litter” or other loose sorbent material, it navigable waters or adjoining shorelines. 

may be impractical to pre-deploy the measure. In such Contingency Plan is used to describe cases, the sorbent material should be readily available	 	 measures for controlling, containing, and 

so that it can immediately be used before the spill can	 	 recovering oil that has been discharged into or 

upon navigable waters or adjoining shorelines spread. Portable tanks can be equipped with a spill kit in such quantities as may be harmful. 

to be used in the event of a discharge during transfers. 

The spill kit should be sized, however, to effectively 

contain the volume of oil that could be discharged. Most commercially available spill kits are 

intended for relatively small volumes (up to approximately 150 gallons of oil). EPA generally 

believes that active containment measures can be used to satisfy the general secondary 

containment requirement when they are capable of containing the most likely discharge volume. 

Elements to consider may include the capacity of the containment measure, effectiveness, and 

timely implementation, and the availability of personnel and equipment to implement the active 

measure effectively at the facility. For example, a most likely discharge of 600 gallons would 

require deploying more than 900 “high-capacity” sorbent pads (20 inches by 20 inches) since each 

pad absorbs less than 0.7 gallons of oil. The same spill volume would require nine sorbent 

blankets, each measuring 38 inches by 144 feet and weighing approximately 40 pounds. The rapid 

deployment of such response equipment and material would be difficult to achieve under most 

circumstances, particularly if only a few individuals are present when the discharge occurs, or 

during adverse conditions (e.g., rainfall, fire). 

The secondary containment approach implemented at a facility need not be “one size fits 

all.” Different approaches may be taken for the same activity at a given facility, depending on the 

material and location. For example, the SPCC Plan may specify that drain covers and sorbent 

material be pre-deployed prior to transfers of low viscosity oils in certain areas of a facility located in 

close proximity to navigable waters or drainage structures. For other areas and/or other products 

(e.g., highly viscous oils), the Plan may specify that sufficient spill response capability (spill 

response teams) are available for use in the event of a discharge, so long as personnel and 

equipment are available at the facility and these measures can be effectively implemented in a 

timely manner to prevent oil from reaching navigable waters and adjoining shorelines. 

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Additionally, oil-filled operational equipment (e.g., electrical transformers, capacitors, 

switches) poses unique challenges, and permanent (passive) containment structures, such as 

dikes, may not always be feasible. This type of oil-filled operational equipment is only subject to the 

general secondary containment provision, and the owner/operator may use the flexibility of active 

containment measures as described above. However, this method of containment may be risky 

because it requires the ability to detect a discharge, and these measures must be implemented 

effectively and in a timely manner to prevent oil from reaching navigable waters and adjoining 

shorelines, as required by §112.7(a)(3)(iii) and (c). The owner/operator may determine that these 

methods prove impracticable for a facility with oil-filled operational equipment (e.g., because of 

timeliness of a response). When secondary containment is impracticable, the certified SPCC Plan 

must document the reasons for impracticability; use a contingency plan in lieu of secondary 

containment; and provide a written commitment of manpower, equipment, and materials to 

expeditiously control and remove any quantity of oil discharged that may be harmful (§112.7(d)). 

In certain circumstances, sorbents, such as socks, booms, pads, or loose materials, may be 

used to complement passive measures. Where berms around transfer areas are open on one side 

for access, and where the ground surface slopes away from the opening and from drains, for 

example, sorbent material may be effective in preventing small quantities of oil from escaping the 

bermed area in the event of a discharge. 

Active measures are not appropriate for all situations with the potential for an oil discharge. 

As noted above, active measures often have limited absorption or containment capacity. 

Additionally, storage tanks, piping, and other containers pose a risk of discharge during off-hour 

periods when facility personnel are generally not on-site or are too few in number to detect a 

discharge in a timely manner and deploy the containment measure(s). Pre-deployment of active 

measures in a “fixed” configuration may be problematic since sorbent materials or portable barriers 

are typically not engineered for long-term deployment, and their performance may be affected by 

precipitation, ultraviolet light degradation, or cold temperature. Moreover, in some cases, the 

deployment of an active measure can interfere with other systems; for example, by impeding the 

proper operation of drainage structures (e.g., drain cover). For these reasons, EPA generally 

believes that dikes/berms, curbing, spill diversion ponds, or other similarly fixed, engineered 

structures remain the most effective means of spill control and containment for oil storage 

containers. 

The SPCC Plan must describe the procedures used to deploy the active measures, explain 

how the use of active measures is appropriate to the situation, and explain the methods for 

discharge discovery that will be used to determine when deployment of the active measures is 

appropriate (§112.7(a)(3)(iii) and (iv)). It should, for instance, discuss whether active measures will 

be put in place before a potential discharge event (e.g., a boom placed around a vehicle before 

fueling activities begin) or whether the active measures will be deployed quickly after a spill occurs 

as a countermeasure (e.g., sorbents on hand to contain a spill should one occur). EPA also 

recommends that the Plan describe the amount of materials available and the location where they 

are stored, and the manpower required to adequately deploy the material in a timely fashion. Both 

the amount and location of materials should be determined based on good engineering practice, 

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taking into consideration the potential volume of a discharge and the time necessary to deploy the 

measure to prevent a discharge to navigable waters or adjoining shorelines. Some of this 

information may already be described in other existing documents at the facility (i.e., BMPs) in 

which case, these documents should be referenced in the SPCC Plan and available at the time of 

an inspection. 

There is a subtle but important difference between active containment measures 

(countermeasures, including land-based response capability) and an oil spill contingency plan as 

described in §112.7(d). Active secondary containment (as opposed to permanent or passive 

containment structures) requires a deployment action; it is put in place prior to or immediately upon 

discovery of an oil discharge. The purpose of these measures is to contain an oil discharge before 

it reaches navigable waters or adjoining shorelines; alternatively, a contingency plan, for SPCC 

purposes, is a detailed oil spill response plan developed when any form of secondary containment 

is determined to be impracticable. A contingency plan addresses controlling, containing, and 

recovering an oil discharge in quantities that may be harmful to navigable waters or adjoining 

shorelines. The purpose of a contingency plan should be both to outline response capability or 

countermeasures to limit the quantity of a discharge reaching navigable waters or adjoining 

shorelines (if possible), and to address response to a discharge of oil that has reached navigable 

waters or adjoining shorelines. 

Evaluating the ability of active secondary containment measures deployed after a discharge 

to prevent oil from reaching navigable waters and adjoining shorelines involves considering the time 

it would take to discover the discharge, the time for the discharge to reach navigable waters or 

adjoining shorelines, and the time necessary to deploy the active secondary containment measure. 

For some active containment measures such as the use of sorbent materials, the amount of oil the 

secondary containment measure can effectively contain, including the potential impact of 

precipitation on sorption capacity, is a critical factor. EPA would expect good engineering practice 

to indicate that active secondary containment measures may be used to satisfy the general 

secondary containment requirements of §112.7(c). Generally, active containment measures may 

not be appropriate for satisfying the specific containment requirements for a major container failure. 

Furthermore, even when used to comply with §112.7(c), EPA recommends that active measures be 

limited to those situations where the PE has determined that the mostly likely discharge is a small 

volume. 

4.2.7	 	 Role of the EPA Inspector in Evaluating the Use of Active Measures of Secondary 

Containment 

Inspectors should carefully evaluate the use of active measures and determine if the 

equipment and personnel are available for deployment of this secondary containment method. The 

EPA inspector should inspect the facility to determine whether the active measures are appropriate 

for the facility – i.e., the inspector should note whether material storage locations are reasonable 

given the time necessary to deploy measures, and whether the amount of available materials is 

sufficient to handle the anticipated discharge volume. In addition, the inspector should document 

whether the facility is keeping the necessary records. 

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Upon inspection, a facility owner/operator should be able to demonstrate that facility 

personnel are able to carry out the deployment procedure as written. The EPA inspector should 

verify that the facility’s SPCC Plan contains the following items, and that items in the Plan are 

observed in the field and/or verified through discussions with facility personnel. Questions for the 

EPA inspector to consider in determining the adequacy of active measures are also provided below. 

• 	 Explanation showing why the use of active measures is appropriate. 

S What is the PE-determined expected/most likely potential discharge volume, 

and is the active measure appropriately sized to contain the spill? 

S What is the discharge detection method and is it appropriate? 

S How much time is required to deploy the selected active measure? 

S Given these factors, is the active measure a reasonable approach? 

•	 Detailed description of deployment procedures. 

S Will active measures be put in place before a potential discharge event or 

after a spill occurs? 

S If measures are to be activated after a spill occurs, does the Plan describe 

the method of discharge detection? 

S	 	 Are the equipment and personnel available to deploy/implement the proposed 

active containment measure in an effective/timely manner to prevent oil from 

reaching navigable waters or adjoining shorelines? 

S	 Does the Plan identify drainage pathways and the appropriate deployment 

location for the active measures? 

•	 Description of all necessary materials and the location where they are stored (i.e., 

location of drain covers, spill kits, or other spill response equipment). 

S In cases where spill kits or sorbent materials are to be used, does the Plan 

describe the amount of materials available? 

S	 	 Are inventory and/or maintenance logs provided to ensure that spill response 

equipment/materials are currently in good working condition (i.e., not 

damaged, expired, or used up)? 

S	 Are the equipment/materials located such that personnel can realistically get 

to the equipment and deploy it quickly enough to prevent a discharge to 

navigable waters or adjoining shorelines? That is, are the material and 

equipment accessible (not locked, key is available), and are they located 

close enough to the potential source of discharge? 

•	 Description of facility staff responsible for deploying active measures. 

S Are training records up to date? 

S Have the personnel involved in activities for which the active measures might 

be deployed been trained (i.e., in location of materials, drainage conditions)? 

S Is there sufficiently trained facility staff present at all times to effectively 

deploy the measures in the event of a discharge? 

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4.2.8 “Sufficiently Impervious” 

Section 112.7(c) states that the entire secondary containment system, “including walls and 

floor, must be capable of containing oil and must be constructed so that any discharge from a 

primary containment system ... will not escape containment before cleanup occurs.” With respect to 

bulk storage containers at onshore facilities (except production facilities), §§112.8(c)(2) and 

112.12(c)(2) state that diked areas must be “sufficiently impervious to contain oil.” The purpose of 

the secondary containment requirement is to prevent discharges as described in §112.1(b); 

therefore, effective secondary containment methods must be able to contain oil until the oil is 

cleaned up. EPA does not specify permeability or retention time performance criteria for these 

provisions. Instead, EPA gives the owner/operator and the certifying PE flexibility in determining 

how best to design the containment system to prevent a discharge as described in §112.1(b). This 

determination is based on a good engineering practice evaluation of the facility configuration, 

product properties, and other site-specific conditions. For example, EPA believes that a sufficiently 

impervious retaining wall, or dike/berm, including the walls and floors, must be constructed so that 

any discharge from a primary containment system will not escape the secondary containment 

system before cleanup occurs and before the discharge reaches navigable waters and adjoining 

shorelines (§§112.7(c), 112.8(c)(2) and 112.12(c)(2)). Ultimately, the determination of 

imperviousness should be verified by the certifying PE. 

The preamble to the 2002 SPCC rule states that “a complete description of how secondary 

containment is designed, implemented, and maintained to meet the standard of sufficiently 

impervious is necessary” (67 FR 47102). Therefore, pursuant to §112.7(a)(3)(iii) and (c), the Plan 

should address how the secondary containment is designed to effectively contain oil until it is 

cleaned up. Control and/or removal of vegetation may be necessary to maintain the 

imperviousness of the secondary containment and to allow for the visual detection of discharges. 

The owner or operator should monitor the conditions of the secondary containment structure to 

ensure that it remains impervious to oil. Repairs of excavations or other penetrations through 

secondary containment need to be conducted in accordance with good engineering practice. 

The earthen floor of a secondary containment system may be considered “capable of 

containing oil” until cleanup occurs, or “sufficiently impervious” under §§112.7(c), 112.8(c)(2), and 

112.12(c)(2), respectively, if there is no subsurface conduit to navigable waters allowing the oil to 

reach navigable waters before it is cleaned up. Should oil reach navigable waters or adjoining 

shorelines, it is a reportable discharge under 40 CFR part 110. The suitability of earthen material 

for secondary containment systems may depend on the properties of both the product stored and 

the soil. For example, compacted local soil may be suitable to contain a viscous product, such as 

liquid asphalt cement, but may not be suitable to contain gasoline. Permeability through the wall (or 

wall-to-floor interface) of the structure may result in an immediate discharge as described in 

§112.1(b). 

In certain geographic locations the native soil (e.g., clay) may be determined as sufficiently 

impervious by the PE. However, there are many more instances where good engineering practice 

would generally not allow the use of a facility’s native soil alone as secondary containment because 

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the soil is not homogenous. In fact, certain state requirements may restrict the use of soil as a 

means of secondary containment, and many state regulations explicitly forbid the discharge of oil 

on soil. Pennsylvania’s Storage Tank and Spill Prevention Act, for example, requires that facilities 

take immediate steps to prevent injury from any discharge of a substance that has the potential to 

flow, be washed or fall into waters, and endanger downstream users. The Act requires that residual 

substances be removed, within 15 days, from the ground or affected waters. Discharges to soil and 

groundwater may also violate other federal regulations. In addition, the EPA inspector should 

strongly urge facility owners and operators to investigate and comply with all state and local 

requirements. An inspector who notices potential violations under other statutes or regulations 

should contact the appropriate authorities for follow-up with the facility. 

In summary, any of the owner/operator’s determinations specifying whether secondary 

containment structures are capable of containing oil until it is cleaned up (“sufficiently impervious”) 

should be made based on good engineering practice and may consider site-specific factors. 

4.2.9	 Role of the EPA Inspector in Evaluating “Sufficiently Impervious” 

The EPA inspector should determine whether the facility’s secondary containment is 

sufficiently impervious, based on a review of the SPCC Plan and on an observation of site 

conditions. The EPA inspector may ask to see any calculations/engineering justifications used in 

determining levels of imperviousness; this information, including calculations, should be maintained 

with the Plan to facilitate the inspector’s review. To determine whether secondary containment is 

sufficiently impervious, the inspector may consider the following: 

• 	 Whether the SPCC Plan describes how secondary containment is designed, 

implemented, and maintained. The certification of the Plan’s adequacy is the 

responsibility of the PE and a determination of sufficient imperviousness may be 

based strictly on geotechnical knowledge of soil classification and best engineering 

judgment. The inspector may also review records of hydraulic conductivity tests, if 

such tests were conducted to ascertain the imperviousness of the secondary 

containment structure. The inspector may also review drainage records that are 

required to be kept by the facility owner/operator in accordance with §112.8(c)(3), 

§112.9(b)(1), or §112.12(c)(3). If, for example, facility personnel never drain the 

outdoor containment, then the inspector may pose follow-up questions to clarify how 

the facility removes precipitation after heavy rainfall, since lack of rainfall 

accumulation could indicate that the water is escaping the containment structure 

through the walls or floor. 

• 	 For bulk storage facilities (excluding production) subject to §112.8 or §112.12, 

procedures on how the facility minimizes and evaluates the potential for corrosion of 

container bottoms/bases that cannot be visually inspected. Corrosion of container 

bottom is addressed in part by integrity testing of bulk storage containers under 

§112.8(c)(6) or §112.12(c)(6). If a facility owner/operator cannot certify that the 

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material under the container is sufficiently impervious (whether earthen or 

manmade), the inspector should consider: 

–	 Whether the inspection and integrity testing program in the Plan includes an 

internal inspection in the scope of the container integrity testing program in 

accordance with industry standards. This internal inspection should include 

the bottom plate. Since the bottom plate cannot be examined from the 

underside, the only inspection available is to assess the fitness of the bottom 

plate via an internal inspection. (See Chapter 7 of this document for more 

information on integrity testing.) 

–	 Whether the facility has the ability to detect oil discharges from a container 

bottom in order to commence cleanup before a discharge escapes the 

containment systems. 

• 	 Evidence of stained soil or stressed vegetation outside the containment area as well 

as at nearby outfalls or other areas affected by runoff from the secondary 

containment structure. For example, at onshore production facilities, there may be 

oil stains or white areas and white salt crystal deposits on the outside of berm walls 

and on the ground surface farther away from the berm. These deposits may indicate 

that produced water has flowed through the secondary containment and that the 

structure may not be sufficiently impervious. 

• 	 How the secondary containment is constructed (materials and method of 

construction). Look for the type of soil (if soil is used). Floor and walls constructed 

of sandy material, for example, may not be appropriate to hold refined products such 

as gasoline. If earthen material is used, EPA recommends that it have a high clay 

content and be properly compacted, not simply formed into a mound. Untreated 

cinder blocks used for containment should be closely evaluated by an inspector due 

to their porous nature. 

• 	 If a facility considers the earthen floor of a secondary containment system to be 

sufficiently impervious, the inspector should consider any underground pathway that 

could lead to navigable waters. 

4.2.10 Facility Drainage (Onshore Facilities) 

Control of Drainage from Dikes and Berms 

When containment methods such as dikes and berms are used to satisfy the secondary 

containment requirements of the rule such as §§112.7(c) and 112.8(c)(2), the specific facility 

drainage requirements also apply. The specific requirements for diked areas at onshore facilities 

(except production) are found in §§112.8(b)(1), 112.8(b)(2), 112.12(b)(1), and 112.12(b)(2); for 

diked areas at onshore production facilities they are found in §112.9(b)(1). Drainage from diked 

storage areas can be accomplished by several means such as valves, manually activated pumps, 

or ejectors. If dikes are drained using valves, they must be of manual design to prevent an 

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uncontrolled discharge outside of the dike, such as into a facility drainage system or effluent 

treatment system, except where facility systems are designed to control such a discharge 

(§§112.8(b)(1) and 112.12(b)(1)). At oil production facilities, drains on secondary containment 

systems (both dikes and other equivalent measures required under §112.7(c)(1)) must be closed 

and sealed at all times, except when draining uncontaminated rainwater (§112.9(b)(1)). Although 

not required by the rule, owners and operators should strongly consider locking valves controlling 

dike or remote impoundment areas, especially when they can be accessed by non-facility 

personnel. 

For diked areas serving as 

secondary containment for bulk 

storage containers, §§112.8(c)(3) 

and 112.12(c)(3) require that storm 

water accumulations be inspected 

for the presence of oil and records 

of the drainage events must be 

maintained. Section 112.9(b)(1) 

requires that oil production facilities 

comply with the same drainage 

procedures for diked areas as other 

types of onshore facilities under 

§112.8(c)(3)(ii) through (iv). EPA 

inspectors should evaluate facility 

records to verify compliance with the 

drainage procedures described in 

§112.8(c)(3). Any storm water 

discharge records maintained at the 

facility in accordance with the 

NPDES rules in §122.41(j)(2) or 

122.41(m)(3) are acceptable under 

§§112.8(c)(3)(iv) and 

112.12(c)(3)(iv). 

§§112.8(b) ) Facility drainage. 

ith a 

You must not locate 

catchment basins in areas subject to periodic flooding. 

ith 

Note: The above text is an excerpt of the SPCC rule. Refer to 40 CFR part 

112 for the full text of the rule. 

 and 112.12(b 

(1) Restrain drainage from diked storage areas by valves to prevent 

a discharge into the drainage system or facility effluent treatment 

system, except where facility systems are designed to control such 

discharge. You may empty diked areas by pumps or ejectors; 

however, you must manually activate these pumps or ejectors and 

must inspect the condition of the accumulation before starting, to 

ensure no oil will be discharged. 

(2) Use valves of manual, open-and-closed design, for the drainage 

of diked areas. You may not use flapper-type drain valves to drain 

diked areas. If your facility drainage drains directly into a 

watercourse and not into an on-site wastewater treatment plant, you 

must inspect and may drain uncontaminated retained stormwater, as 

provided in paragraphs (c)(3)(ii), (iii), and (iv) of this section. 

(3) Design facility drainage systems from undiked areas w 

potential for a discharge (such as where piping is located outside 

containment walls or where tank truck discharges may occur outside 

the loading area) to flow into ponds, lagoons, or catchment basins 

designed to retain oil or return it to the facility. 

(4) If facility drainage is not engineered as in paragraph (b)(3) of this 

section, equip the final discharge of all ditches inside the facility w 

a diversion system that would, in the event of an uncontrolled 

discharge, retain oil in the facility. 

(5) Where drainage waters are treated in more than one treatment 

unit and such treatment is continuous, and pump transfer is needed, 

provide two “lift” pumps and permanently install at least one of the 

pumps. Whatever techniques you use, you must engineer facility 

drainage systems to prevent a discharge as described in §112.1(b) in 

case there is an equipment failure or human error at the facility. 

Facility Drainage Control 

When secondary containment requirements are addressed through facility drainage 

controls, the requirements in §112.8(b)(3) and (4), or §112.12(b)(3) and (4) apply. For example, a 

facility may choose to use the existing storm drainage system to meet secondary containment 

requirements by channeling discharged oil to a remote containment area to prevent a discharge as 

described in §112.1(b). The facility drainage system must be designed to flow into ponds, lagoons, 

or catchment basins designed to retain oil or return it to the facility. Catchment basins must not be 

located in areas subject to periodic flooding (§§112.8(b)(3) and 112.12(b)(3)). 

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A facility does not have to address the undiked area requirements of §112.8(b)(3) and (4) or 

§112.12(b)(3) and (4) if the facility does not use drainage systems to meet one of the secondary 

containment requirements in the SPCC rule. For example, if the SPCC Plan documents the use of 

an active containment measure (such as a combination of sorbents and a spill mat), which is 

effective to prevent a discharge as described in §112.1(b), then secondary containment has been 

provided and it is not necessary to alter drainage systems at the facility. The facility drainage 

system design requirements in §112.8(b)(3) and (4) or §112.12(b)(3) and (4) apply only when the 

facility uses these drainage systems to comply with the secondary containment provisions of the 

rule such as §§112.7(c) and 112.8(c)(2). 

The EPA inspector should determine if the facility’s documentation in the Plan identifies 

whether the final ponds, lagoons, or catchment basins are designed/sized to meet the appropriate 

general and/or specific secondary containment requirements. The following examples help to 

illustrate how to determine the appropriate size of the ponds, lagoons, or catchment basins: 

• 	 General Secondary Containment. A facility owner/operator may use a storm water 

drainage system that flows to a containment pond to address the general containment 

requirements of §112.7(c) for a piece of operational equipment (including electrical oil-filled 

equipment). The pond/drainage system should be designed to contain the volume of oil 

likely to be discharged as determined according to good engineering practice and 

documented in the SPCC Plan. The capacity of the secondary containment required is that 

which is necessary to meet the general containment requirement based on a likely 

discharge (not necessarily a major container failure). 

• 	 Specific Secondary Containment. If a facility owner/operator uses a storm water drainage 

system that flows to a catchment basin to comply with the specific containment 

requirements of §112.8(c)(2) for a bulk storage container, the pond/drainage system must 

be designed to contain the capacity of the largest bulk storage container (with appropriate 

freeboard for precipitation) as dictated by the rule’s requirements. The specific containment 

requirement is based on a major container failure in which the entire capacity of the 

container is discharged. 

• 	 General and Specific Secondary Containment. In a case where a drainage system to a 

final catchment basin is used to meet multiple secondary containment needs for the facility, 

including compliance with both general and specific containment requirements, the system’s 

design will need to meet the most stringent rule requirement (typically the specific secondary 

containment requirement). 

The facility drainage requirements of §§112.8(b) and 112.12(b) are design standards for 

secondary containment (not additional secondary containment requirements) and are therefore 

eligible for deviations that provide equivalent environmental protection in compliance with 

§112.7(a)(2) and as determined appropriate by a PE. Chapter 3 of this guidance document, 

Environmental Equivalence, includes a further discussion on ways to evaluate whether facility 

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drainage systems that deviate from the specified design standards are “environmentally equivalent” 

and comply with §112.7(a)(2). 

4.2.11 Role of the EPA Inspector in Evaluating Onshore Facility Drainage 

The EPA inspector should review the facility’s SPCC Plan to ensure that the drainage 

procedures are documented and records are maintained. The inspector should also examine the 

facility to determine whether the drainage procedures are implemented as described in the SPCC 

Plan and whether they are appropriate for the facility. If a facility uses drainage systems to meet 

one or more secondary containment requirements, the inspector should evaluate whether the final 

ponds, lagoons, or catchment basins are designed/sized in accordance with the appropriate general 

and/or specific secondary containment requirements. The inspector should also evaluate the 

facility records to verify compliance with the drainage procedures described in §112.8(c)(3). 

4.3 Overview of the Impracticability Determination Provision 

EPA recognizes that, although engineered 

passive containment systems (such as dikes and 

drainage systems) or active secondary 

containment approaches are preferable, they may 

not always be practicable. If a facility 

owner/operator finds that containment methods 

are “impracticable,” alternative modes of 

protection to prevent and contain oil discharges 

are available. The impracticability provision found 

in §112.7(d) allows facility owners/operators to 

substitute a combination of other measures in 

place of secondary containment: (1) periodic 

integrity testing of bulk storage containers and 

periodic integrity testing and leak testing of the 

valves and piping associated with the containers; 

(2) unless they have submitted a Facility 

Response Plan (FRP) under §112.20, an oil spill 

contingency plan; and (3) a written commitment of 

manpower, equipment, and materials required to 

control and remove any quantity of oil discharged that may be harmful. 

§112.7(d) 

paragraphs (c) and (h)(1) of this section, and 

112.14(c) to prevent a discharge as described in 

ing: 

ing the 

provisions of part 109 of this chapter. 

harmful. 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

If you determine that the installation of any of the 

structures or pieces of equipment listed in 

§§112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 112.10(c), 

112.12(c)(2), 112.12(c)(11), 112.13(c)(2), and 

§112.1(b) from any onshore or offshore facility is 

not practicable, you must clearly explain in your 

Plan why such measures are not practicable; for 

bulk storage containers, conduct both periodic 

integrity testing of the containers and periodic 

integrity and leak testing of the valves and piping; 

and, unless you have submitted a response plan 

under §112.20, provide in your Plan the follow 

(1) An oil spill contingency plan follow 

(2) A written commitment of manpower, equipment, 

and materials required to expeditiously control and 

remove any quantity of oil discharged that may be 

If an impracticability determination is made, the SPCC Plan must clearly describe why 

secondary containment measures are impracticable and how the specified additional measures are 

implemented (§112.7(d)). See Section 4.5 of this chapter for more information on the additional 

measures. The option of determining impracticability assumes that it is feasible to effectively and 

reliably implement a contingency plan. Facilities should be aware that an impracticability 

determination may affect the applicability of the FRP requirements under 40 CFR part 112 subpart 

D. In addition, an impracticability determination may affect the calculation of the worst case 

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discharge volume, which may impact the amount of resources required to respond to a worst case 

discharge scenario. 

4.3.1	 	 Meaning of “Impracticable” 

The impracticability determination is intended to be used when a facility owner/operator is 

incapable of installing secondary containment by any reasonable method. Considerations include 

space and geographical limitations, local zoning ordinances, fire codes, safety, or other good 

engineering practice reasons that would not allow for secondary containment (67 FR 47104). EPA 

clarified in a Federal Register notice that economic cost may be considered as one element in a 

decision on alternative methods, consistent with good engineering practice for the facility, but may 

not be the only determining factor in claiming impracticability (see text box below). 

and Countermeasure (SPCC) Rule 


 


 


 


 

responding.) ... 
 


 


 


 


 

or
 

other good engineering practice reasons.”
 

Notice Concerning Certain Issues Pertaining to the July 2002 Spill Prevention, Control, 

“The Agency did not intend with [preamble language at 67 FR 47104] to opine broadly on the 

role of costs in determinations of impracticability. Instead, the Agency intended to make the narrower 

point that secondary containment may not be considered impracticable solely because a contingency 

plan is cheaper. (This was the concern that was presented by the commenter to whom the Agency was 

In addition, with respect to the emphasized language enumerating considerations for 

determinations of impracticability, the Agency did not intend to foreclose the consideration of other 

pertinent factors. In fact, in the response-to-comment document for the SPCC amendments 

rulemaking, the Agency stated that “... for certain facilities, secondary containment may not be 

practicable because of geographic limitations, local zoning ordinances, fire prevention standards, 

The above text is an excerpt from 69 FR 29728 (May 25, 2004). 

4.4	 	 Selected Issues Related to Secondary Containment and 

Impracticability Determinations 

Section 112.7(d) lists the provisions of the SPCC rule for which facility owners or operators 

may determine impracticability. Issues related to the use of impracticability determinations for 

selected secondary containment requirements are discussed below. Requirements under each 

provision are summarized below, along with a discussion of selected issues. Only secondary 

containment requirements can be determined to be impracticable; for most other technical 

requirements, the rule provides flexibility to facility owners or operators to implement alternative 

measures that provide equivalent environmental protection (see Chapter 3 of this guidance 

document for more information on the environmental equivalence provision). 

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4.4.1 General Secondary Containment Requirements, §112.7(c) 

The secondary containment requirements found in §112.7(c) apply to any area within a 

regulated facility where a discharge may occur. Piping, flowlines, non-bulk containers such as oilfilled operational equipment and manufacturing equipment, and non-rack transfer areas are subject 

to the general secondary containment requirements. A discussion of issues related to secondary 

containment for piping and flowlines, transfer areas, and certain oil-filled equipment follows. 

Piping and Flowlines 

Examination of discharge reports from the Emergency Response Notification System 

(ERNS) shows that discharges from valves, piping, flowlines, and appurtenances are much more 

common than catastrophic tank failure or discharges from tanks (67 FR 47124). To prevent a 

discharge as described in §112.1(b), all piping, including buried piping and flowlines, at regulated 

facilities must comply with the general secondary containment requirements contained in §112.7(c). 

In certain cases, secondary containment for piping will be possible. Section 112.7(c) 

provides flexibility in the method of secondary containment: active measures including land-based 

response capability, sorbent materials, drainage systems, and other equipment are acceptable. 

Section 112.7(c) does not prescribe a specific containment size for piping and flowlines; however, 

good engineering practice prescribes that containment size should be based on the magnitude of a 

reasonable discharge scenario, taking into consideration the specific features of the facility and 

operation. A determination of adequate secondary containment should consider the reasonably 

expected sources, maximum flow rate, duration of a discharge, and detection capability. The EPA 

inspector should ensure that the secondary containment method for piping and flowlines is 

documented in the SPCC Plan and that the PE has certified that the method is appropriate for the 

facility according to good engineering practice. If active methods of containment are selected, the 

facility personnel should be able to demonstrate that they can effectively deploy these measures to 

contain a potential spill before it reaches navigable waters or adjoining shorelines. 

EPA acknowledges that in many cases, secondary containment may not be practicable for 

flowlines and gathering lines. For example, a production facility in a remote area may have many 

miles of flowlines and gathering lines, around which it would not be practicable to build permanent 

containment structures. For instance, it may not be possible to install secondary containment 

around flowlines running across a farmer’s or rancher’s fields since berms may become severe 

erosional features of the fields and can impede access to the fields by farm/ranch tractors and other 

equipment. Similarly, it may be impracticable to construct secondary containment around flowlines 

that run along a fence line or county road due to space limitations or intrusion into a county’s 

property or right-of-way. At unmanned facilities, the use of active secondary containment methods 

is not possible because there is limited capability to detect a discharge and deploy active measures 

in a timely fashion. If secondary containment is not practicable, facility owners/operators may make 

an impracticability determination and comply with the additional regulatory requirements described 

in §112.7(d). 

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The preamble of the 2002 SPCC rule (67 FR 47078) states that the contingency plan 

required when secondary containment is not practicable for flowlines and gathering lines should rely 

on strong maintenance, corrosion protection, testing, recordkeeping, and inspection procedures to 

prevent and quickly detect discharges from such lines. It should also ensure quick availability and 

deployment of response equipment. The integrity testing program for piping and valves should also 

be developed in accordance with good engineering practice, in order to prevent a discharge as 

described in §112.1(b). A flowline maintenance program is required for production facilities under 

§112.9(d)(3). (See Chapter 7 of this document for a summary of the recommended key elements of 

a flowline maintenance program.) It is especially important that facility owners or operators who 

determine that secondary containment is impracticable implement a comprehensive flowline 

maintenance program. If an impracticability determination is made for flowlines or gathering lines, 

EPA inspectors should extensively and carefully review the adequacy of the flowline maintenance 

program. According to practices recommended by industry groups such as API, a comprehensive 

piping program should include the following elements: 

•	 Prevention measures that avert the discharge of fluids from primary containment; 

•	 Detection measures that identify a discharge or potential for a discharge; 

•	 Protection measures that minimize the impact of a discharge; and 

•	 Remediation measures that mitigate discharge impacts by relying on limited or 

expedited cleanup. 

In order for a contingency plan to be effective, it is essential for discharges to be detected in 

a timely manner. Good engineering practice may require that unmanned facilities where secondary 

containment is impracticable be inspected more frequently than would be required at a typical 

unmanned facility where secondary containment is provided. For facilities that do not have a 

Facility Response Plan (FRP) pursuant to §112.20, if it is not feasible to effectively and reliably 

implement a contingency plan, owners/operators must determine how to comply with the applicable 

secondary containment requirements in §112.7(c). A contingency plan or FRP is required when a 

determination of impracticability is made, pursuant to §112.7(d). 

Transfer Areas 

A transfer operation is one in which oil is moved from or into some form of transportation, 

storage, equipment, or other device, into or from some other or similar form of transportation, such 

as a pipeline, truck, tank car, or other storage, equipment, or device (67 FR 47130). Areas where 

oil is transferred but no loading or unloading rack is present are subject to §112.7(c), and thus 

appropriate containment and/or diversionary structures are required. EPA does not require 

specifically sized containment for transfer areas; however, containment size must be based on 

good engineering practice (§112.3(d)). 

The containment requirement at §112.7(c) applies to both loading and unloading areas. 

Examples of activities that occur within transfer areas include: 

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• 	 Unloading oil from a truck to a heating oil tank; 

• 	 Loading oil into a vehicle from a dispenser; and 

• 	 Transferring crude oil from an oil production tank battery into tank trucks. 

Secondary containment size should be based on the magnitude of a most likely discharge, 

taking into consideration the specific features of the facility and operation. Specific features of 

different loading/unloading operations include the hardware, procedures, and personnel who are 

able to take action to limit the volume of a discharge. EPA recommends that a determination of 

adequate secondary containment consider: 

• 	 The reasonably expected sources and causes of a discharge. This could be a 

failed hose connection; failed valve; overfill of a container, tank truck, or railroad tank 

car; or breach of a container. Determination would be based on the type of transfer 

operation, facility experience and spill history, potential for human error, etc. 

• 	 The reasonably expected maximum rate of discharge. This will be dependent on 

the mode of failure. It may be equal to the maximum rate of transfer or the leakage 

rate from a breached container. 

• 	 The ability to detect and react to the discharge. This will be dependent on the 

availability of monitoring instrumentation for prompt detection of a discharge and/or 

the proximity of personnel to detect and respond to the discharge. 

• 	 The reasonably expected duration of the discharge. This will be dependent on 

the availability of manual or automatic isolation valves, the proximity of qualified 

personnel to the operation, and other factors that may limit the volume of a 

discharge. 

• 	 The time it would take a discharge to impact navigable waters or adjoining 

shorelines. This could depend on the proximity to waterways and storm drains, and 

the slope of the ground surface between the loading area and the waterway or drain. 

An example calculation of secondary containment size, based on these considerations, is 

provided in Figure 4-7. 

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Figure 4-7. Sample calculation of appropriate secondary containment capacity at a transfer area. 

i 
 

operation.
 

Details: 

•	 gallons per minute. 

•	 

•	 

•	 

i 

estimate of the response time. 


 


 

Scenario: 

A fuel truck is loading oil into a heating oil tank at a regulated facility, w th an attendant present throughout the 

The truck is loading at a rate of 

The reasonably expected source and cause of a discharge is a ruptured hose connection. 

A shutoff valve is present on the loading line and is accessible to the attendant. 

An evaluation determines that the discharge will not impede the attendant’s access to the shutoff 

valve and that he can safely close the valve w thin 10 seconds of the hose connection rupture, 

based on past experience under similar circumstances; 15 seconds is assumed to be a conservative 

Calculations: 

The maximum reasonably expected discharge would be calculated to be 150 gallons: 

[(150 gal/min) x (1 min/60 sec) x (15 sec)] = 37.5 gallons 

Conclusion: 

Secondary containment volume should be at least 37.5 gallons. A larger volume for secondary containment would be 

needed if time required to safely close the shutoff valve takes longer than 10 seconds. 

A number of other factors may also affect the appropriate volume for secondary containment 

at loading and unloading areas. These factors include a variable rate of transfer; the ability to 

control a discharge from a breached container, if such a breach is reasonably expected to occur; 

the availability of personnel in close proximity to the operations and the necessary time to respond; 

the presence or absence of monitoring instrumentation to detect a discharge; the type and location 

of valving that may affect the probable time needed to stop the discharge; and the presence or 

absence of automatic valve actuators. These are a few examples of the factors that a PE may 

consider when reviewing the adequacy of secondary containment systems at a facility. The EPA 

inspector may consider the same factors when assessing the adequacy of secondary containment. 

Secondary containment structures, such as dikes or berms, may not be appropriate in areas 

where vehicles continuously need access; however, curbing, drainage systems, active measures, 

or a combination of these systems can adequately fulfill the secondary containment requirements of 

§112.7(c). A facility owner or operator may implement methods for secondary containment other 

than dikes or berms. For example, a transfer truck loading area at an onshore oil production facility 

may be designed to drain discharges away to a topographically lower area using a crescent or 

eyebrow-shaped berm. EPA acknowledges that in certain situations, secondary containment at 

transfer areas may be impracticable due to geographic limitations, fire codes, etc. In these cases, 

owners/operators may determine that secondary containment is impracticable under §112.7(d), and 

must clearly explain the reasons why secondary containment is not practicable and comply with the 

additional regulatory requirements. 

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Oil-Filled Equipment 

Secondary containment may be impracticable for oil-filled equipment (e.g., vaulted 

transformers, hydraulic units associated with an elevators/lifts, pad-mounted transformers at 

customer sites, and oil-filled cable systems) that are not readily accessible or cross properties 

belonging to different owners. In these cases, the SPCC Plan must clearly explain the reasons why 

secondary containment is not practicable and comply with the additional regulatory requirements 

under §112.7(d). For more information on oil-filled operational equipment, refer to Section 2.8.2 of 

this guidance document. 

4.4.2	 Secondary Containment Requirements for Loading/Unloading Racks, §112.7(h)(1) 

Section 112.7(h) applies to areas at regulated 

facilities where traditional loading/unloading racks for 

tank cars and tank trucks are located. Loading and 

unloading racks are subject to the specific secondary 

containment requirements in §112.7(h)(1). 

EPA inspectors should evaluate compliance 

with the requirements of §112.7(h) for equipment 

traditionally considered to be “loading racks.” While 

the SPCC rule does not provide a definition for the 

term “rack,” the type of equipment for which these 

requirements would typically apply has the following 

characteristics: 

§112.7(h) 

Facility tank car and tank truck 

loading/unloading rack (excluding 

offshore facilities). 

handle discharges, use a quick drainage 

compartment of a tank car or tank truck 

Note: The above text is an excerpt of the 

full text of the rule. 

(1) Where loading/unloading area 

drainage does not flow into a catchment 

basin or treatment facility designed to 

system for tank car or tank truck loading 

and unloading areas. You must design 

any containment system to hold at least 

the maximum capacity of any single 

loaded or unloaded at the facility. 

SPCC rule. Refer to 40 CFR part 112 for the 

• 	 The equipment is a permanent structure 

for loading or unloading a tank truck or tank car that is located at a regulated facility. 

• 	 The equipment may be comprised of piping assemblages, valves, loading arms, 

pumps, or a similar combination of devices. 

• 	 The system is necessary to load or unload tank trucks or tank cars. 

• 	 The system may also include shut-off devices and overfill sensors. 

EPA clarified that the provisions of §112.7(h) apply only in instances where a rack structure 

is present. (See text box below.) 

Loading racks can be located at any type of facility; however, the loading areas associated 

with a production tank battery generally do not have the equipment described above, which is often 

associated with a “loading rack.” Loading/unloading areas utilizing a single hose and connection or 

standpipe are not considered “racks.” 

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and Countermeasure (SPCC) Rule 

Under this interpretation, 

provision applies if 

loading or unloading racks present.” 

Notice Concerning Certain Issues Pertaining to the July 2002 Spill Prevention, Control, 

“[W]e interpret §112.7(h) only to apply to loading and unloading ‘racks.’ 

if a facility does not have a loading or unloading ‘rack,’ §112.7(h) does not apply. Thus, in stating that 

section 112.7(h) applies to ‘all facilities, including production facilities,’ the Agency only meant that the 

 a ’facility’ happens to have a loading or unloading rack present. The Agency did not 

mean to imply that any particular category of facilities, such as production facilities, are likely to have 

The above text is an excerpt from 69 FR 29728 (May 25, 2004). 

Where drainage from the areas surrounding a loading/unloading rack does not flow into a 

catchment basin or treatment facility designed to handle discharges, facility owners and operators 

must use a quick drainage system (§112.7(h)(1)). A “quick drainage system” is a device that drains 

oil away from the loading/unloading area to some means of secondary containment or returns the 

oil to the facility. Section 112.7(h)(1) requires a sized secondary containment system: the 

containment must hold at least the maximum capacity of any single compartment of a tank car or 

tank truck loaded or unloaded at the facility. 

Loading and unloading activities that take place beyond the rack area are not subject to the 

requirements of §112.7(h), but are subject, where applicable, to the general containment 

requirements of §112.7(c). For more information on these requirements, see Section 4.4.1, 

Transfer Areas. 

Letter to Petroleum Marketers Association of America 

place beyond the rack area would not be subject to the requirements of 40 CFR §112.7(h) (but, of course, 

Found at l 

“[T]he Agency does not interpret §112.7(h) to apply beyond activities and/or equipment associated 

with tank car and tank truck loading/unloading racks. Therefore, loading and unloading activities that take 

would be subject, where applicable, to the general containment requirements of 40 CFR §112.7(c)).” 

The above text is an excerpt from a letter to Daniel Gilligan, President, Petroleum Marketers Association of America, from Marianne 

Lamont Horinko, Assistant Administrator, EPA, May 25, 2004. www.epa.gov/oi spill/pdfs/PMAA_letter.pdf. 

Figures 4-8 and 4-9 illustrate how SPCC secondary containment requirements apply at two 

facilities with loading/unloading areas and with equipment that may be considered 

loading/unloading racks. In Figure 4-8, the facility has two separate and distinct areas for transfer 

activities. One is a tank truck unloading area and the other contains a tank truck loading rack. The 

unloading area contains no rack structure, so the secondary containment requirements of §112.7(c) 

apply. The requirements of §112.7(h)(1) apply to the area surrounding the loading rack. It should 

be noted that the presence of a loading rack at one location of a facility does not subject other 

loading or unloading areas in a separate part of the facility to the requirements of §112.7(h). 

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In Figure 4-9, the tank truck loading rack and unloading area are co-located. In this 

situation, the more stringent provision applies; the area is subject to the sized secondary 

containment requirements of §112.7(h)(1). 

EPA acknowledges that in certain situations, the sized secondary containment requirements 

of §112.7(h)(1) at loading/unloading racks may be impracticable due to geographic limitations, fire 

codes, etc. In these cases, the owner or operator may determine that secondary containment is 

impracticable as provided in §112.7(d). Under that provision, the SPCC Plan must clearly explain 

the reasons why secondary containment is not practicable, and comply with the additional 

regulatory requirements. 

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Figure 4-8. Facility with separate unloading area and loading rack. The tank truck unloading area is 

subject to §112.7(c). The tank truck loading rack is subject to §112.7(h)(1). 

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Figure 4-9. Facility with co-located unloading area and loading rack. This containment area is 

designed to meet the more stringent §112.7(h)(1) provision. 

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4.4.3	 	 Secondary Containment Requirements for Onshore Bulk Storage Containers, 

§112.8(c)(2) 

Under the SPCC rule, a bulk storage container 

is any container used to store oil with a capacity of 55 

gallons or more (§§112.1(d)(5) and 112.2). Bulk 

storage containers are used for purposes including, but 

not limited to, the storage of oil prior to use, while being 

used, or prior to further distribution in commerce. Oilfilled pieces of electrical, operating, or manufacturing 

equipment are not considered bulk storage containers. 

Bulk storage containers at a regulated facility 

must comply with the specific secondary containment 

requirements of §112.8(c)(2). For bulk storage 

containers, secondary containment must hold the entire 

capacity of the largest single container and sufficient 

freeboard to contain precipitation. (For more 

information on sufficient freeboard, see the discussion 

in Section 4.2.4 of this chapter.) Secondary containment is required for all facilities with bulk 

storage containers, large or small, manned or unmanned, and for facilities with bulk storage 

containers that also have oil-filled equipment (specific secondary containment requirements do not 

apply to oil-filled equipment). 

Construct all bulk storage container 

of the largest single container and sufficient 

You must 

ensure that diked areas are sufficiently 

containment curbs, and pits are commonly 

drainage trench enclosure that must be 

basin or holding pond. 

Note: The above text is an excerpt of the SPCC 

rule. Refer to 40 CFR part 112 for the full text of the 

§§112.8(c)(2) and 112.12(c)(2) 

installations so that you provide a secondary 

means of containment for the entire capacity 

freeboard to contain precipitation. 

impervious to contain discharged oil. Dikes, 

employed for this purpose. You may also 

use an alternative system consisting of a 

arranged so that any discharge will terminate 

and be safely confined in a facility catchment 

rule. 

Section 112.8(c)(2) considers the use of dikes, containment curbs, and pits as secondary 

containment methods, or an alternative system consisting of a drainage trench enclosure that must 

be arranged so that any discharge will terminate and be safely confined in a facility catchment basin 

or holding pond. Dikes contain oil in the immediate vicinity of the storage container. Remote 

impoundment drains discharge to an area located away from the container. Examples of design 

considerations and requirements for these types of containment are set forth in the National Fire 

Protection Association (NFPA) 30 Flammable and Combustible Liquids Code. 

The owner or operator may determine that secondary containment is impracticable under 

§112.7(d), when he/she, or the PE certifying the Plan, determines that it is not practicable to design 

a secondary containment system that can hold the capacity of the largest single container plus 

sufficient freeboard. The EPA inspector should verify that the SPCC Plan clearly explains why 

secondary containment is not practicable, and that the facility is complying with the additional 

regulatory requirements, such as conducting both periodic integrity testing of the containers and 

periodic integrity and leak testing of the valves and piping (§112.7(d)). For further information on 

the additional regulatory requirements, see Section 4.5 of this guidance. 

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4.4.4	 Secondary Containment Requirements for Mobile/Portable Containers, §112.8(c)(11) 

Mobile or portable oil storage containers operating 

exclusively within the confines of a non-transportation-related 

facility with a capacity to store 55 gallons or more of oil are 

regulated under the SPCC rule and must comply with the 

secondary containment requirements of §112.8(c)(11) (or 

§112.12(c)(11) in the case of a facility that stores or handles 

animal fats or vegetable oils). 

The 1971 Memorandum of Understanding between
 

EPA and the Department of Transportation (DOT) states that 

“highway vehicles and railroad cars which are used for the 

transport of oil exclusively within the confines of a nontransportation-related facility and which are not intended to 

transport oil in interstate or intrastate commerce” are considered non-transportation-related, and 

therefore fall under EPA’s regulatory jurisdiction. For example, some oil refinery tank trucks and 

fueling trucks dedicated to a particular facility (such as a construction site, military base, or similar 

large facility) fall under this category. Other examples of mobile portable containers include, but are 

not limited to, 55 gallon drums, skid tanks, totes, and intermodal bulk containers. 

Position or locate mobile or portable 

oil storage containers to prevent a 

discharge as described in §112.1(b). 

of containment, such as a dike or 

catchment basin, sufficient to contain 

compartment or container with 

sufficient freeboard to contain 

precipitation.
 

Note: The above text is an excerpt of the 

SPCC rule. Refer to 40 CFR part 112 for 

the full text of the rule. 

§§112.8(c)(11) and 112.12(c)(11) 

You must furnish a secondary means 

the capacity of the largest single 

Vehicles used to store oil, operating as on-site fueling vehicles at locations such as 

construction sites, military, or civilian remote operations support sites, or rail sidings are generally 

considered non-transportation-related. Indicators describing when a vehicle is intended to be used 

as a storage tank (and therefore considered non-transportation-related) include, but are not limited 

to: 

•	 The vehicle is not licensed for on-road use; 

•	 The vehicle is no longer mobile (i.e., hard-piped or permanently parked); 

•	 The vehicle is fueled on-site and never moves off-site; and 

•	 The vehicle is parked on a home-base facility and is filled up off-site but then returns 

to the home base to fuel other equipment located exclusively within the home-base 

facility, and only leaves the site to obtain more fuel. 

According to §§112.8(c)(11) and 112.12(c)(11), mobile or portable containers must be 

positioned or located to prevent a discharge to navigable waters as described in §112.1(b). The 

provision requires that the secondary containment be sized to hold the capacity of the largest single 

compartment or container with sufficient freeboard to contain precipitation. 

The appropriate containment methods for mobile containers may vary depending on the 

activity in which the container is engaged at a given time. Thus, secondary containment 

requirements may be met differently depending upon the type of operation being performed, as 

described in the examples below. 

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When mobile containers are in a stationary, unattended mode and not under the direct 

oversight or control of facility personnel, the requirements of §§112.8(c)(11) and 112.12(c)(11) may 

be met through the use of permanent secondary containment methods, such as dikes, curbing, 

drainage systems, and catchment basins. In order to comply with this requirement, an 

owner/operator may designate an area of the facility in which to locate mobile containers when not 

in use; this area must be designed, following good engineering practices, to hold the capacity of the 

largest single compartment or container with sufficient freeboard to contain precipitation. The area 

designated for mobile equipment must be identified on the facility diagram provided within the 

SPCC Plan (§112.7(a)(3)). 

When mobile containers are involved in activities such as normal fuel transfer, on-site 

movement, or preparation for such activities in “stand-by” mode, the requirements of §112.8(c)(11) 

do not apply because the container is not “positioned” and therefore the less stringent requirements 

of §112.7(c) apply. This requirement may be satisfied through the use of drainage systems that 

could ultimately control spilled oil. Alternatively, other measures listed in the general secondary 

containment provision under §112.7(c) may be used, including active measures such as sorbents, 

booms, or response actions that prevent an oil discharge from reaching navigable waters and 

adjoining shorelines. In these cases, a member of the facility personnel should (as determined by 

good engineering practice) be in physical control and attending to the mobile or portable storage 

container. When the mobile refueler is not engaged in one of the activities listed above, it must be 

positioned to prevent a discharge and provided with secondary containment large enough for the 

single compartment or container with sufficient freeboard for precipitation (§112.8(c)(11)). 

Mobile containers, such as drums, skids, and totes, must also comply with the requirements 

of §112.8(c)(11) or §112.12(c)(11) according to good engineering practice. For these types of 

containers, the EPA inspector should verify that the secondary containment methods are 

appropriate. For example, an oil-filled drum positioned for use at a construction site must be 

equipped with secondary containment sized in accordance with §112.8(c)(11). The facility owner or 

operator may determine that it is impracticable to provide sized secondary containment in 

accordance with §112.8(c)(11), when the container is in stationary or unattended mode, or the 

general containment of §112.7(c), pursuant to §112.7(d). The SPCC Plan must properly explain 

why secondary containment is impracticable, and document the implementation of the additional 

regulatory requirements of §112.7(d). 

4.4.5	 Secondary Containment Requirements for Bulk 

Storage Containers at Production Facilities, 

§112.9(c)(2) 

The secondary containment requirements of 

§112.9(c)(2) apply to all tank battery, separation, and treating 

facility installations at a regulated production facility. This 

specific secondary containment requirement does not apply 

to the entire lease area, but only to tanks, vessels, and 

§112.9(c)(2) 

ith a 

container and sufficient freeboard to 

confine drainage from undiked areas in 

a catchment basin or holding pond. 

Note: The above text is an excerpt of the 

SPCC rule. Refer to 40 CFR part 112 for 

the full text of the rule. 

Provide all tank battery, separation, 

and treating facility installations w 

secondary means of containment for 

the entire capacity of the largest single 

contain precipitation. You must safely 

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containers in the tank battery, separation, and treatment areas. 

Section 112.9(c)(2) is a specific secondary containment requirement; the containment 

structure or measure must be able to contain the entire capacity of the largest single container and 

sufficient freeboard to contain precipitation. (Refer to Section 4.2.4 of this chapter for more 

information on calculating sufficient freeboard.) Additionally, pursuant to §112.9(c)(2), if facility 

drainage is used as a method of secondary containment for bulk storage containers, drainage from 

undiked areas must be safely confined in a catchment basin or holding ponds. Secondary 

containment should be sufficiently impervious to contain oil; refer to Section 4.2.8 of this chapter for 

more information. The undiked drainage requirements of §112.9(c)(2) do not apply to other areas 

of the facility or lease, such as truck transfer or wellhead or flowline areas because they are not 

bulk storage containers. According to the 2002 rule preamble, “the [secondary containment] 

requirement applies to oil leases of any size. Secondary containment is not required for the entire 

leased area, merely for the contents of the largest single container in the tank battery, separation, 

and treating facility installation, with sufficient freeboard to contain precipitation.” (67 FR 47128). 

The facility owner/operator may determine that it is impracticable to provide sized secondary 

containment in accordance with §112.9(c)(2). Pursuant to §112.7(d), the SPCC Plan must clearly 

explain why secondary containment is not practicable, and document how the additional regulatory 

requirements of §112.7(d) are implemented. Owners or operators of unmanned facilities may need 

to determine how to effectively implement a contingency plan. This may involve additional site 

inspections, or some other method as determined appropriate by a Professional Engineer. 

L Tip 

Because a pit used as a form of secondary containment may pose a threat to birds and wildlife if oil is 

present in the pit, EPA encourages owners or operators who use a pit to take measures to mitigate the 

effect of the pit on birds and wildlife. Such measures may include netting, fences, or other means to keep 

birds or animals away. In some cases, pits may also cause a discharge as described in §112.1(b). The 

discharge may occur when oil spills over the top of the pit or when oil seeps through the ground into the 

groundwater, and then to navigable waters or adjoining shorelines. Therefore, EPA recommends that an 

owner or operator not use pits in an area where such pit may prove a source of such discharges. Should 

the oil reach navigable waters or adjoining shorelines, it is a reportable discharge under 40 CFR 110.6. 

(67 FR 47116) 

4.4.6 	 Secondary Containment Requirements for Onshore Drilling or Workover Equipment, 

§112.10(c) 

Section 112.10(c) applies to onshore oil drilling and 

workover facilities. Areas with drilling and workover equipment 

are required to provide catchment basins or diversion structures to 

intercept and contain discharges of fuel, crude oil, or oily drilling 

fluids. This provision contains no specific sizing requirement, and 

no freeboard requirement; it is essentially very similar to the 

general containment requirement of §112.7(c). 

§112.10(c) 

Provide catchment basins or 

diversion structures to intercept 

and contain discharges of fuel, 

Note: The above text is an excerpt of 

112 for the full text of the rule. 

crude oil, or oily drilling fluids. 

the SPCC rule. See 40 CFR part 

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The facility owner/operator may determine that it is impracticable to provide secondary 

containment in accordance with §112.10(c). Pursuant to §112.7(d), the SPCC Plan must clearly 

explain why secondary containment is not practicable, and document how the additional regulatory 

requirements of §112.7(d) are implemented. 

4.5 Measures Required in Place of Secondary Containment 

Pursuant to §112.7(d), if secondary containment is impracticable for any area where 

secondary containment requirements apply, facility owners or operators must clearly explain in the 

SPCC Plan why such secondary containment is impracticable and implement additional 

requirements. This section describes these additional requirements. 

4.5.1 Integrity Testing of Bulk Storage Containers 

When a facility owner or operator shows that secondary containment around a bulk storage 

container is impracticable, he or she must conduct periodic integrity testing of the container 

(§112.7(d)). Integrity testing is any means to measure the strength (structural soundness) of the 

container shell, bottom, and/or floor to contain oil. Integrity testing should be done in accordance 

with good engineering practice, considering applicable industry standards. For a thorough 

discussion of integrity testing, see Chapter 7 of this document. Chapter 7 describes the scope and 

frequency of inspections and tests, considering industry standards and the characteristics of the 

container. When there is no secondary containment around a container, however, good 

engineering practice should indicate a more stringent integrity testing schedule than would be 

required for a container if secondary containment were in place. Although the 2002 revised SPCC 

rule does not incorporate specific inspection frequency, certain industry standards require more 

frequent and/or more intensive inspection of containers when they do not have secondary 

containment.3 

The EPA inspector should verify that the Plan describes the integrity testing of bulk storage 

containers, in particular for those containers for which secondary containment is impracticable. The 

inspector should also review testing records to ensure that the inspection program is implemented 

as described. 

4.5.2 Periodic Integrity and Leak Testing of the Valves and Piping 

When the facility owner or operator determines that secondary containment for bulk storage 

containers is impracticable, he/she must also perform periodic integrity and leak testing of valves 

and piping associated with the containers for which secondary containment is impracticable 

(§112.7(d)). Leak testing determines the liquid tightness of valves and piping and whether they 

may discharge oil. Leak testing should be performed in accordance with appropriate industry 

3

 The Steel Tank Institute’s “Standard for the Inspection of Aboveground Storage Tanks,” SP001, 3rd 
 

Edition, Steel Tank Institute, July 2005 (summarized in Chapter 7 of this document) requires more frequent 
 

inspections of tanks that do not have adequate secondary containment. 
 

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standards. Chapter 7 provides an overview of integrity and leak testing of valves and piping. As for 

integrity testing, good engineering practice may suggest a more stringent leak testing schedule than 

would be required if secondary containment were in place. The PE certifies that the extent of this 

testing is in accordance with good engineering practice, including consideration of applicable 

industry standards (§112.3(d)). 

The EPA inspector should verify that the Plan describes the integrity and leak testing of 

valves and piping associated with containers for which secondary containment is impracticable. 

The inspector should also review testing records to ensure that the testing program is implemented 

as described. 

4.5.3	 Oil Spill Contingency Plan and Written Commitment of Resources 

Unless he or she has submitted a Facility Response Plan under §112.20, an owner or 

operator who claims that secondary containment is impracticable must include with the SPCC Plan 

an oil spill contingency plan following the provisions of 40 CFR part 109 and a written commitment 

of manpower, equipment, and materials required to expeditiously control and remove any quantity 

of oil that may be harmful (§112.7(d)). 

The requirements for the content of contingency plans are given in 40 CFR part 109, Criteria 

for State, Local, and Regional Oil Removal Contingency Plans. The elements of the contingency 

plan are outlined in §109.5, and include: 

•	 Definition of the authorities, responsibilities, and duties of all persons, organizations, 

or agencies that are to be involved or could be involved in planning or directing oil 

removal operations. 

•	 Establishment of notification procedures for the purpose of early detection and timely 

notification of an oil discharge. 

•	 Provisions to ensure that full resource capability is known and can be committed 

during an oil discharge situation. 

•	 Provisions for well-defined and specific actions to be taken after discovery and 

notification of an oil discharge. 

•	 Specific and well-defined procedures to facilitate recovery of damages and 

enforcement measures as provided for by state and local statutes and ordinances. 

Please refer to the model contingency plan found in Appendix F of this document for an 

example contingency plan prepared in compliance with the SPCC rule and 40 CFR part 109.

 As described in 67 FR 47105, a ‘‘written commitment’’ of manpower, equipment, and 

materials means either a written contract or other written documentation showing that the 

owner/operator has made provision for items needed for response purposes. According to 40 CFR 

109.5, the commitment includes: 

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•	 Identification and inventory of applicable equipment, materials, and supplies that are 

available locally and regionally; 

•	 An estimate of the equipment, materials, and supplies that would be required to 

remove the maximum oil discharge to be anticipated; 

•	 Development of agreements and arrangements in advance of an oil discharge for the 

acquisition of equipment, materials, and supplies to be used in responding to such a 

discharge; 

•	 Provisions for well-defined and specific actions to be taken after discovery and 

notification of an oil discharge, including specification of an oil discharge response 

operating team consisting of trained, prepared, and available operating personnel; 

•	 Predesignation of a properly qualified oil discharge response coordinator who is 

charged with the responsibility and delegated commensurate authority for directing 

and coordinating response operations and who knows how to request assistance 

from federal authorities operating under current national and regional contingency 

plans; 

•	 A preplanned location for an oil discharge response operations center and a reliable 

communications system for directing the coordinated overall response actions; 

•	 Provisions for varying degrees of response effort depending on the severity of the oil 

discharge; and 

•	 Specification of the order of priority in which the various water uses are to be 

protected where more than one water use may be adversely affected as a result of 

an oil discharge and where response operations may not be adequate to protect all 

uses. (67 FR 47105) 

For a contingency plan to satisfy the requirements of §112.7(d), facilities must be able to 

implement the contingency plan. Activation of the contingency plan is contingent upon the 

discharge of oil being detected. As part of evaluating the adequacy of the contingency plan 

developed to satisfy requirements of §112.7(d), the EPA inspector should consider the time it takes 

facility personnel to detect and mitigate a discharge to navigable waters and adjoining shorelines. 

For example, at an unmanned facility, effective implementation of the contingency plan may involve 

enhanced discharge detection methods such as more frequent facility visits and inspections, or the 

use of spill detection equipment. 

4.5.4	 Role of the EPA Inspector in Reviewing Impracticability Determinations 

Like other technical aspects of the SPCC Plan, determinations of impracticability must be 

reviewed by the PE certifying the Plan in accordance with §112.3(d) to ensure that they are 

consistent with good engineering practice. The inspector should verify that the Plan has been 

certified by the PE and that the additional measures specified in §112.7(d) are documented in the 

Plan, as explained below. 

By certifying a Plan, a PE attests that the Plan has been prepared in accordance with good 

engineering practice, that it meets the requirements of 40 CFR part 112, and that it is adequate for 

the facility. Thus, if impracticability determinations and the corresponding alternative measures and 

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Chapter 4: Secondary Containment and Impracticability 

contingency plan have been reviewed by the certifying PE and are properly documented, they 

should generally be considered acceptable by regional EPA inspectors. However, if an 

impracticability determination and/or the additional required measures do not meet the standards of 

common sense, appear to be at odds with recognized industry standards, do not meet the overall 

objective of oil spill response/prevention, or appear to be inadequate for the facility, appropriate 

follow-up action may be warranted. In this case, the EPA inspector should clearly document the 

concerns (including photographs and drawings of the facility configuration, flow direction, and 

proximity to navigable waters) to assist RA review and follow-up. This may include requesting 

additional information from the facility owner or operator to justify the impracticability determination. 

An owner/operator making a determination of impracticability should have considered all 

appropriate options for secondary containment, and the documentation presented in support of the 

impracticability determination should include a discussion of the reasons why the various 

reasonable options are impracticable. 

The example below provides an example of an inadequate impracticability determination. 

The supporting discussion provided in the example does not provide a sufficient discussion of the 

reasons why the concrete dike is not practicable. It also fails to address, even in general terms, 

whether means of secondary containment other than a concrete dike may be practicable (e.g., 

remote impoundment, drainage systems, or active measures). Finally, the discussion does not 

provide information on the measures that are provided in lieu of secondary containment and how 

the facility intends to implement the contingency plan, commit manpower and equipment to 

respond, and perform the required testing on the bulk storage containers and associated piping and 

appurtenances. Refer to §112.7(c) and (d) for a list of available secondary containment options as 

well as the additional measures required in the SPCC Plan when a determination of impracticability 

is made. 

Bad Example: Bulk Storage Containers 

Bulk Storage Tanks – 40 CFR 112.8(c)(2) 

XYZ Oil has determined that secondary containment is impracticable for the two bulk storage 

tanks located to the east of the maintenance building. There is not sufficient space to build a 

concrete dike because of the proximity to the property line. XYZ Oil is therefore implementing 

a contingency plan for this portion of the facility. 

For comparison, the following example provides an adequate impracticability determination. 

The supporting discussion provided in the example clearly explains why various methods of 

secondary containment measures are not practicable, and documents the measures that the facility 

has implemented in lieu of secondary containment. 

Good Example: Bulk Storage Containers 

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Bulk Storage Tanks – 40 CFR 112.8(c)(2) 

XYZ Oil has determined that secondary containment is impracticable for the two bulk storage 

tanks located to the east of the maintenance building. There is not sufficient space to 

accommodate a dike or berm with the required containment capacity due to minimum 

setbacks and maximum dike height. A dike or berm with the required capacity would either 

encroach on the neighbor’s property and/or exceed a 6-feet safe wall height (OSHA 

Flammable and combustible liquids regulation, 29 CFR 1910.106). The facility also lacks the 

space necessary for remote impoundment. Other measures listed under §112.7(c) such as 

the use of sorbents would not be a reliable and effective means of secondary containment 

since the volumes involved may exceed the sorbent capacity. 

The tanks are currently in good condition and do not need to be replaced. However, tanks of 

double-wall design may be considered as potential replacement in the future. 

Because secondary containment for these two bulk storage tanks is impracticable, XYZ Oil 

has provided in this SPCC Plan the additional elements required under 40 CFR 112.7(d), 

namely: 

• 	 Periodic integrity testing of bulk storage containers, and periodic integrity and leak testing of 

valves and piping (see Section 2.7 of the SPCC Plan). 

• 	 A written commitment of manpower, equipment, and materials required to expeditiously 

control and remove any quantity of oil discharged that may be harmful (see Appendix F of the 

SPCC Plan). 

• 	 An Oil Spill Contingency Plan following the provisions of 40 CFR part 109 (see Appendix G of 

the SPCC Plan). 

In addition to verifying that the SPCC Plan clearly describes the reason why secondary 

containment measures are not practicable and documents the implementation of the additional 

measures required in §112.7(d), the EPA inspector should verify that: 

• 	 The facility’s contingency plan can be implemented as written; 

• 	 The equipment for response is available; 

• 	 The commitment of manpower, equipment, and materials is documented; 

• 	 The contingency plan describes the location of drainage systems, containment 

deployment locations, and oil collection areas (including recovered oil storage 

capability); 

• 	 There are procedures for early detection of oil discharges; and 

• 	 There is a defined set of response actions. 

Figure 4-10 provides a checklist an EPA inspector can review to verify that all the criteria of 

§109.5 are included in a facility’s oil spill contingency plan. The EPA inspector may also refer to the 

checklist included in Figure 4-11 at the end of this chapter when identifying and reviewing technical 

rule requirements that are eligible for the impracticability provision. 

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Figure 4-10. Checklist of required components of state, local, and regional oil removal contingency 

plans. Please refer to the complete text of 40 CFR §109.5. 

109.5–Development and implementation criteria for state, local, and regional oil removal Yes No 
 

contingency plans* 
 

Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to be involved in 
 

planning or directing oil removal operations. 
 

Establishment of notification procedures for the purpose of early detection and timely notification of an oil discharge including: 

(1) 	 The identification of critical water use areas to facilitate the reporting of and response to oil discharges. 

(2) 	 A current list of names, telephone numbers and addresses of the responsible persons (with alternates) 

and organizations to be notified when an oil discharge is discovered. 

(3) Provisions for access to a reliable communications system for timely notification of an oil discharge, and 

the capability of interconnection with the communications systems established under related oil removal 

contingency plans, particularly State and National plans (e.g., NCP). 

(4) 	 An established, prearranged procedure for requesting assistance during a major disaster or when the 

situation exceeds the response capability of the State, local or regional authority. 

Provisions to assure that full resource capability is known and can be committed during an oil discharge situation including: 

(5) 	 The identification and inventory of applicable equipment, materials and supplies which are available 
 

locally and regionally. 
 

(6) 	 An estimate of the equipment, materials and supplies which would be required to remove the maximum 

oil discharge to be anticipated. 

(7) 	 Development of agreements and arrangements in advance of an oil discharge for the acquisition of 
 

equipment, materials and supplies to be used in responding to such a discharge. 
 

Provisions for well defined and specific actions to be taken after discovery and notification of an oil discharge including: 

(8) 	 Specification of an oil discharge response operating team consisting of trained, prepared and available 

operating personnel. 

(9) 	 Predesignation of a properly qualified oil discharge response coordinator who is charged with the 

responsibility and delegated commensurate authority for directing and coordinating response operations 

and who knows how to request assistance from Federal authorities operating under existing national 

and regional contingency plans. 

(10) 	 A preplanned location for an oil discharge response operations center and a reliable communications 

system for directing the coordinated overall response operations. 

(11) 	 Provisions for varying degrees of response effort depending on the severity of the oil discharge. 

(12) 	 Specification of the order of priority in which the various water uses are to be protected where more than 

one water use may be adversely affected as a result of an oil discharge and where response operations 

may not be adequate to protect all uses. 

Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided for by State 
 

and local statutes and ordinances. 
 

* The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the 

National Contingency Plan (NCP). 

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Figure 4-11. Checklist of SPCC requirements eligible for impracticability determinations. 

SPCC Guidance for Regional Inspectors 

) 

General 112.7(c) Are appropriate containment and/or diversionary Visual. 

Containment structures provided? impracticable? 

equipment, and materials? associated valves and piping

Loading/unloading Racks 

112.7(h)(1) Visual. 

impracticable? 

tank car or tank truck loaded there? 

equipment, and materials? 

Bulk Storage 112.8(c)(2) Visual. Containers 

OR sufficient freeboard to contain precipitation? 

impracticable? 

112.12(c)(2) equipment, and materials? 

associated valves and piping

112.8(c)(11) ithin a 

dike, catchment basin or other means of secondary 

Visual. 

impracticable? 

OR 

container and sufficient freeboard to contain 

112.12(c)(11) precipitation? equipment, and materials? 

associated valves and piping

Rule Element 

Relevant 

Section(s Evaluation Verification Noncon

ALL FACILITIES 

Does the Plan explain why s

Is the containment system capable of containing oil and Is a Contingency Plan (or FRconstructed so that any discharge from the primary containment system will not escape before cleanup 

Does the Plan include a writt

occurs? Does the facility conduct per

storage containers and integ

Does the loading/unloading rack area drainage flow 

into a catchment basin or treatment facility? 

Does the Plan explain why s

If not, is a quick drainage system used? Is the secondary containment system sized to contain 

Is a Contingency Plan (or FRDoes the Plan include a writt

the maximum capacity of any single compartment of a 

ALL FACILITIES, EXCEPT OIL PRODUCTION 

Is the secondary containment system sized to contain Does the Plan explain why s

the entire capacity of the largest single container and 

Is a Contingency Plan (or FR

Are dikes sufficiently impervious to contain oil? Does the Plan include a writt

Does the facility conduct perstorage containers and integ

Are mobile or portable oil containers located w Does the Plan explain why s

containment large enough to contain the largest single Is a Contingency Plan (or FR

Does the Plan include a writtDoes the facility conduct perstorage containers and integ

U.S. Environmental Protection Agency 4-48 
) 

Drainage 112.9(c)(2) Visual. 

catchment basin or holding pond? impracticable? 

equipment, and materials? associated valves and piping

Bulk Storage 112.9(c)(2) Visual. Containers installations provided wi impracticable? 

freeboard to contain precipitation? 

equipment, and materials? associated valves and piping

Drainage 112.10(c) 

to intercept and contain discharges of fuel, crude oil, or 

Visual. 

impracticable? equipment, and materials? associated valves and piping

Chapter 4: Secondary Containme

Relevant 

Rule Element Section(s Evaluation Verification Noncon

ONSHORE OIL PRODUCTION FACILITIES 

Is drainage from undiked areas safely confined in a Does the Plan explain why s

Is a Contingency Plan (or FRDoes the Plan include a writtDoes the facility conduct perstorage containers and integ

Are all tank battery, separation, and treatment facility Does the Plan explain why s

th secondary containment that 

can contain the largest single container and sufficient Is a Contingency Plan (or FR

Does the Plan include a writtDoes the facility conduct perstorage containers and integ

ONSHORE OIL DRILLING AND WORKOVER FACILITIES 

Are catchment basins or diversion structures provided Does the Plan explain why s

oily drilling fluids? Is a Contingency Plan (or FR

Does the Plan include a writtDoes the facility conduct perstorage containers and integ

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Chapter 5: Oil/Water Separators 

OIL/WATER SEPARATORS 

5.1 Introduction 

The wastewater treatment exemption in §112.1(d)(6) excludes from SPCC requirements 

facilities or parts of facilities that are used exclusively for wastewater treatment, as long as they are 

not used to meet other requirements of 40 CFR part 112. This chapter clarifies the applicability of 

this exemption to oil/water separators (including equipment, vessels, and containers that are not 

specifically called “oil/water separators” but 

perform oil/water separation, such as water 

clarifiers at wastewater treatment plants). §112.1(d) 

Except as provided in paragraph (f) of this 

section, this part does not apply to: ... (6) Any The intended use of an oil/water facility or part thereof used exclusively for 

separator determines whether the separator is wastewater treatment and not used to satisfy 

any requirement of this part. The production, subject to the SPCC regulations and, if so, what recovery, or recycling of oil is not wastewater provisions are applicable. As outlined in Table treatment for purposes of this paragraph.

5-1 below, oil/water separators may be used for 

Note: The above text is an excerpt of the SPCC rule. several different purposes: to treat wastewater, Refer to the full text of 40 CFR part 112. 

to meet secondary containment requirements of 

40 CFR part 112, or as part of the oil production 

process. Only oil/water separators used exclusively to treat wastewater and not used to satisfy any 

requirement of part 112 are exempt from all SPCC requirements. Oil/water separators used in oil 

production and to meet the secondary containment requirements of the rule are not exempt. 

Table 5-1. SPCC rule applicability for various uses of oil/water separators. 

Wastewater Treatment Secondary Containment Oil Production 

Separators are exempt from all Separators that are used as part Separators that are bulk storage 

SPCC requirements in of a secondary containment containers, subject to the 

accordance with §112.1(d)(6) and system and are not intended for provisions of §§112.9(c) or 

do not count toward facility oil storage or use do not 112.11(b) and (d), are not exempt 

storage capacity. themselves require secondary and count toward the facility 

containment, and do not count storage capacity. 

toward facility storage capacity. 

However, they are subject to the 

design specifications (e.g., 

capacity) for the secondary 

containment requirements with 

which they are designed to 

comply. 

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The remainder of this chapter is organized as follows: 

•	 Section 5.2 summarizes the provisions of the SPCC rule that apply to the three uses 

of oil/water separators identified above. 

•	 Section 5.3 discusses the use of an oil/water separator for wastewater treatment 

and the exemption for this use. 

•	 Section 5.4 addresses the use of an oil/water separator as secondary containment 

and the applicable SPCC requirements. 

•	 Section 5.5 discusses the use of an oil/water separator in oil production and the 

applicable SPCC requirements. 

•	 Section 5.6 describes required documentation for oil/water separators and the role 

of the EPA inspector in reviewing facilities with oil/water separators. 

5.2 	 Overview of Provisions Applicable to Oil/Water Separators 

Section 112.1(d)(6) addresses oil/water separators used for wastewater treatment. 

Facilities or equipment used exclusively for wastewater treatment, and which do not satisfy any 

requirements of the SPCC rule, are exempt from the SPCC rule requirements. These oil/water 

separators do not count toward facility storage capacity. Whether a wastewater treatment facility or 

part thereof is used exclusively for wastewater treatment or used to satisfy an SPCC requirement 

will often be a facility-specific determination based upon the activities carried out at the facility and 

upon its configuration. 

Drainage systems that satisfy the secondary containment requirements of the SPCC rule 

may use oil/water separators to recover oil and return it to the facility (see Chapter 4 of this 

document for a description of secondary containment requirements). Examples of oil/water 

separators that are used to meet SPCC requirements include oil/water separators used to satisfy 

the secondary containment requirements of §§112.7(c), 112.7(h)(1), 112.8(c)(2), 112.8(c)(11), 

112.12(c)(2), and/or 112.12(c)(11). Additionally, the drainage provisions in §§112.8(b) and 112.9(b) 

set forth design specifications for secondary containment at a facility. Oil/water separators may be 

used as part of a facility drainage system to meet the secondary containment requirements of the 

rule. Oil/water separators used to satisfy these rule requirements are subject to applicable 

secondary containment requirements, but they do not count toward storage capacity. 

As stated in §112.1(d)(6), production, 

recovery, and recycling of oil are not considered 

wastewater treatment and, thus, are not eligible 

for the wastewater treatment exemption. For 

purposes of §112.1(d)(6), this means recovery 

and recycling of crude oil at facilities associated 

with, and downstream of, production facilities, 

such as saltwater disposal and injection 

§112.9(c)(2) 

Provide all tank battery, separation, and 

means of containment for the entire capacity of 

the largest single container and sufficient 

safely confine drainage from undiked areas in 

a catchment basin or holding pond. 

Note: The above text is an excerpt of the SPCC rule. 

Refer to the full text of 40 CFR part 112. 

treating facility installations with a secondary 

freeboard to contain precipitation. You must 

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Chapter 5: Oil/Water Separators 

facilities. Section 112.9(c)(2) includes 

requirements for oil/water separators (e.g., gun 

barrels, heater-treaters) used at onshore oil 

production facilities. This provision specifically 

identifies the secondary containment and 

drainage requirements for all tank battery, 

separation, and treating facility installations, 

including oil/water separators. Examples of 

oil/water separators associated with oil 

production, separation, and treatment include 

free water knock-outs, two- and three-phase 

separators, and gun barrels. 

Sections 112.11(b) and (d) include the 

applicable provisions for oil/water separators 

located at offshore oil production facilities. 

Figure 5-1 helps determine the use of an 

oil/water separator at SPCC-regulated facilities 

and identifies the corresponding rule 

requirements or exemptions based upon each 

use. 

§112.11(b)

Use oil drainage collection equipment to 

prevent and control small oil discharges 

around pumps, glands, valves, flanges, 

expansion joints, hoses, drain lines, 

separators, treaters, tanks, and associated 

drains toward a central collection sump to 

sumps are not practicable, you must remove 

oil contained in collection equipment as often 

as necessary to prevent overflow. 

Note: The above text is an excerpt of the SPCC rule. 

Refer to the full text of 40 CFR part 112. 

§112.11(d) 

At facilities with areas where separators and 

treaters are equipped with dump valves which 

predominantly fail in the closed position and 

where pollution risk is high, specially equip the 

You 

must prevent the discharge of oil by: 

the separator is near shore; 

producing to the separator; or 

Note: The above text is an excerpt of the SPCC rule. 

Refer to the full text of 40 CFR part 112. 

(1) Extending the flare line to a diked area if 

(2) Equipping the separator with a high liquid 

(3) Installing parallel redundant dump valves. 

equipment. You must control and direct facility 

prevent the facility from having a discharge as 

described in §112.1(b). Where drains and 

facility to prevent the discharge of oil. 

level sensor that will automatically shut in wells 

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Figure 5-1. Applicable requirements for an oil/water separator. 
Chapter 5: Oil/Water Separators 

5.3 Oil/Water Separators Used in Wastewater Treatment 

5.3.1 Description of Oil/Water Separator Use in Wastewater Treatment 

Oil/water separators used to pre-treat wastewater are usually of two kinds: standard gravity 

separators or enhanced gravity separators.1 Standard gravity separators, as illustrated in Figure 5-

2 (separator designs may vary), are liquid containment structures that provide sufficient hydraulic 

retention time to allow oil droplets to rise to the surface. The oil forms a separate layer that can 

then be removed by skimmers, pumps, or other methods. The wastewater outlet is located below 

the oil level so that water leaving the separator is free of the oil that accumulates at the top of the 

unit. The inlet is often fitted with diffusion baffles to reduce turbulent flow that might prevent 

effective separation of the oil and might re-suspend settled pollutants. 

Figure 5-2. Standard gravity oil/water separator. 

Enhanced gravity separators allow the separation of smaller oil droplets within confined spaces. 

These separators use a variety of coalescing media and small diameter cartridges that enhance 

laminar flow and separation of smaller oil droplets that accumulate on the separator surface for 

removal. Figure 5-3 shows coalescing plates in the middle compartment (separator designs may 

vary). 

1

 Other types of separators include vortex separators, which combine gravity with centrifugal 

forces. 

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Figure 5-3. Enhanced gravity oil/water separator. 

Oil/water separators are flow-through equipment in which wastewater enters the separator 

and treated water exits the separator on a continual basis. To be effective, the oil/water separator 

is sized appropriately in order for the unit to separate and contain the intended oil capacity, in 

addition to the flow-through wastewater quantity. Also, the design flow rate of the oil/water 

separator is carefully considered when specifying a wastewater treatment system, as a flow rate 

above the maximum rate of the separator will cause the discharge of accumulated oil and/or 

untreated wastewater. The specifications from oil/water separator manufacturers typically outline 

these and other design factors to consider, along with operation and maintenance requirements, to 

ensure that the oil/water separator is correctly constructed and operated for its intended use. 

5.3.2	 	 Applicability of the SPCC Rule to Oil/Water Separators Used for Wastewater 

Treatment 

Section 112.1(d)(6) exempts “any facility or part thereof” that is used exclusively for 

wastewater treatment and is not used to meet any other requirement of the rule (excluding oil 

production, recovery, and recycling facilities). Certain components of wastewater treatment 

facilities, such as treatment systems at publicly owned treatment works (POTWs) and industrial 

wastewater treatment facilities treating oily wastewater, likely meet the two criteria for this 

exemption. 

POTWs and other wastewater treatment facilities may have bulk storage containers and oilfilled equipment, as well as exempt oil/water separators. The capacity of the bulk storage 

containers and oil-filled equipment is counted to determine whether the facility is subject to the 

requirements of the SPCC rule. Only the oil/water separator capacity does not count toward the 

overall storage capacity of the facility. Thus, the presence of an oil/water separator at an otherwise 

regulated facility does not exempt the entire facility from the SPCC rule requirements. At 

wastewater treatment facilities, storage capacity to be counted includes bulk storage containers, 

hydraulic equipment associated with the treatment process, containers used to store oil that feed an 

emergency generator associated with wastewater treatment, and slop tanks or other containers 

used to store oil resulting from treatment. Any separate container used to store oil recovered by the 

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Chapter 5: Oil/Water Separators 

separation process or any other equipment or containers at a regulated facility that do not qualify for 

the wastewater treatment exemption are required to meet all applicable SPCC requirements (67 FR 

47069). 

Oil/water separators used exclusively for wastewater treatment are flow-through separators 

and are not engaged in a static process in an isolated container. For example, a bulk storage 

container containing an oil and water mixture, and from which water is drawn from the bottom, does 

not constitute wastewater treatment. 

Examples of oil/water separators that may be considered wastewater treatment and may be 

eligible for the exemption of §112.1(d)(6) include: 

• Oil/water separators at a wastewater treatment facility; 

• Oil/water separators at an active groundwater remediation site; 

• Grease traps that intercept and congeal oil and grease from liquid waste; and 

• Oil/water separators in landfill leachate collection systems. 

Oil/water separators exempted from the SPCC rule may, however, be subject to other 

federal, state, and local regulations. In addition, a separate container storing oil removed from an 

exempt separator is considered a bulk storage container and is subject to the SPCC rule 

requirements. 

Many of these exempted wastewater treatment oil/water separators are within wastewater 

treatment facilities or parts thereof subject to the National Pollutant Discharge Elimination System 

(NPDES) requirements under section 402 of the Clean Water Act (CWA). NPDES (or an approved 

state permit program) ensures review and approval of the facility’s wastewater treatment plans and 

specifications, operation/maintenance manuals and procedures, and requires a Storm Water 

Pollution Prevention Plan, which may include a Best Management Practice (BMP) Plan. 

 BMPs are additional conditions that may supplement effluent limitations in NPDES permits. 

In addition, other affected facilities need a BMP Plan for storm water runoff control under an 

NPDES permit. Under §402(a)(1) of CWA, BMPs may be imposed when the Administrator 

determines that such conditions are necessary to carry out the provisions of the Act.2 

Additionally, some facilities may be subject to pretreatment standards promulgated under 

§307(b) of CWA. Pretreatment standards apply to “indirect discharges” that go first to a POTW via 

a collection system before being discharged to navigable waters, and they concern pollutants that 

pass through POTWs untreated or interfere with the operation of POTWs. The General 

Pretreatment Regulations for Existing or New Sources of Pollution, found at 40 CFR part 403, 

prohibits an indirect discharger from introducing into a POTW a pollutant that passes through or 

interferes with treatment processes at the POTW, and also sets the framework for the 

2

 See discussion of authority for NPDES and BMP provisions in the preamble to the 2002 revised 

SPCC rule, 67 FR 47068. 

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implementation of categorical pretreatment standards. Specifically, 40 CFR 403.5(b)(6) prohibits 

the introduction into a POTW of “petroleum, oil, nonbiodegradable cutting oil, or products of mineral 

oil origin in amounts that will cause interference or pass through.” 

5.3.3	 	 Wastewater Treatment Exemption Clarification for Dry Gas Production Facilities 

As EPA stated in a Federal Register notice (69 FR 29728), produced water tanks at dry gas 

facilities are eligible for the wastewater treatment exemption. Gas facilities that do not produce 

condensate or crude oil (i.e., dry gas facilities) do not meet the description of “oil production, oil 

recovery, or oil recycling facilities.” Therefore, produced water tanks used exclusively for 

wastewater treatment at such facilities are eligible for the exemption. Tanks that are eligible for the 

exemption do not count toward storage capacity. 

At 69 FR 29730, EPA stated that “...[in] verifying that a particular gas facility is not an ‘oil 

production, oil recovery, or oil recycling facility,’ the Agency plans to consider, as appropriate, 

evidence at the facility pertaining to the presence or absence of condensate or crude oil that can be 

drawn off the tanks, containers or other production equipment at the facility, as well as pertinent 

facility test data and reports (e.g., flow tests, daily gauge reports, royalty reports or other production 

reports required by state or federal regulatory bodies).” 

5.4 	 Oil/Water Separators Used to Meet SPCC Secondary Containment 

Requirements 

5.4.1	 	 Description of Oil/Water Separators Used to Meet SPCC Secondary Containment 

Requirements 

Oil/water separators can be used to meet the SPCC requirements for secondary 

containment in §§112.7(c), 112.7(h)(1), 112.8(c)(2), 112.8(c)(11), 112.12(c)(2), and/or 

112.12(c)(11). Additionally, §§112.8(b), 112.9(b), and 112.12(b) set forth design specifications for 

drainage associated with secondary containment provisions at the facility. Properly designed, 

maintained, and operated oil/water separators may be used as part of a facility drainage system to 

meet the secondary containment requirements of the rule. 

Standard gravity and enhanced gravity separators (Figures 5-2 and 5-3), or other types of 

oil/water separators (separator designs may vary), may be used to meet secondary containment 

requirements. In this application, the separators are expected to have oil and water present in the 

system when there is an oil discharge or oil-contaminated precipitation runoff within the drainage 

area. Generally, these separators should be monitored on a routine schedule and collected oil 

should be removed as appropriate in accordance with procedures in the SPCC Plan. 

When designing oil/water separators to be used as secondary containment (see Chapter 4 

for a discussion of secondary containment requirements), good engineering practice would normally 

indicate that a Professional Engineer (PE) would consider: 

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•	 	 The drainage area that flows to the separator; 

•	 	 The corresponding anticipated flow rate of the drainage system to the separator; and 

•	 	 The appropriate capacity of the oil/water separator for oil and for wastewater. 

Many oil/water separators used for secondary containment are installed in areas where they 

may receive considerable flow from precipitation. If the flow rate exceeds the maximum design rate 

of the separator, the separator may discharge accumulated oil and/or untreated wastewater; 

therefore, it may be an inappropriate choice for secondary containment and may result in a 

discharge to navigable waters and adjoining shorelines. The specifications from the oil/water 

separator manufacturer outline these and other design factors as important items to consider when 

specifying the use of a given oil/water separator for a given application. Additionally, the 

manufacturer specifies the maintenance requirements for these separators that would ensure 

proper operation of these devices. 

When oil/water separators are used to meet SPCC requirements they must be properly 

operated and maintained to ensure that the unit will perform correctly and as intended under the 

potential discharge scenarios it is aimed to address (e.g., §§112.7(c), 112.8(c)(2), and 

112.12(c)(2)). The required oil/water separator capacity should always be available (i.e., oil should 

not continually accumulate in the separator over a period of time such that the required storage 

capacity would not be available if an oil release were to occur within the drainage area). The use of 

oil/water separators as a method of containment may be risky as they have limited drainage 

controls to prevent a discharge of oil and rely heavily on proper maintenance. 

5.4.2	 	 Applicability of the SPCC Rule to Oil/Water Separators Used to Meet Specific SPCC 

Secondary Containment Requirements 

Section 112.7(c) requires “appropriate containment and/or diversionary structures or 

equipment to prevent a discharge as described in §112.1(b).” An oil/water separator may be used 

to satisfy this requirement for onshore or offshore facilities. This separator must be constructed to 

contain oil and prevent an escape of oil from the system prior to cleanup in order to comply with the 

secondary containment provision for which it is intended (§112.7(c)). A description explaining how 

an oil/water separator complies with secondary containment provisions, and how it is operated and 

maintained, should be included in the SPCC Plan. BMPs or O&M manuals which detail operation 

and maintenance procedures for oil/water separators used specifically for secondary containment 

may be referenced in the SPCC Plan and maintained separately. 

Section 112.7(h)(1) requires “a quick drainage system” for areas where a tank car or tank 

truck loading or unloading rack is present. An oil/water separator may be used as part of a quick 

drainage system to meet this requirement. This containment system must hold at least the 

maximum capacity of any single compartment of a tank car or tank truck loaded or unloaded at the 

facility (§112.7(h)(1)). 

Sections 112.8(b), 112.9(b), and 112.12(b) set forth design specifications for drainage 

systems associated with secondary containment at onshore facilities. Environmentally equivalent 

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measures can be used to satisfy these requirements (see Chapter 3 for a discussion of the 

environmental equivalence provision). In order to comply with secondary containment 

requirements, facilities might use ponds, lagoons, or catchment basins as part of the design criteria 

for facility drainage systems. However, an oil/water separator might serve as an environmentally 

equivalent measure to the ponds, lagoons, or catchment basins required by §§112.8(b)(3) and 

112.12(b)(3). In this instance, EPA recommends that the oil/water separator be designed to handle 

the flow rate and volume of oil and water expected to be generated by facility operations. When 

certifying a facility’s SPCC Plan, the PE must verify that the oil/water separator is adequately 

designed, maintained, and operated to provide environmentally equivalent protection (in 

accordance with §112.7(a)(2)) under the potential discharge scenarios it is aimed to address, in 

order to comply with the corresponding secondary containment provision. 

Sections 112.8(c)(2), 112.8(c)(11), 112.12(c)(2), and 112.12(c)(11) require that all bulk 

storage containers be provided with secondary containment for “the entire capacity of the largest 

single container and sufficient freeboard to contain precipitation.” An oil/water separator may be 

used for this purpose, but it must be appropriately sized to meet the requirements of the rule 

provision for which it is intended to comply. The oil/water separator must be capable of handling 

both the oil and precipitation that come into the separator from the general drainage area, and from 

any accidental discharge from the largest bulk storage container located within the drainage area 

for which the separator provides secondary containment (§112.8(c)(2), 112.8(c)(11), 112.12(c)(2), 

and 112.12(c)(11)). Good engineering practice would suggest that the use of oil/water separators 

for the specific secondary containment provisions be on a very limited basis and typically with 

smaller capacity container storage areas (e.g., drum storage area). For more information on 

specific secondary containment requirements for bulk storage containers, see Chapter 4 of this 

document. 

The capacity of an oil/water separator used to meet secondary containment requirements 

does not count toward a facility’s overall storage capacity. Any volume of oil that would flow into the 

oil/water separator would come from another source within the drainage area that is already 

generally counted in the facility storage capacity determination. Containers used to store recovered 

oil after oil/water separation, however, represent additional oil storage and count toward a facility’s 

total storage capacity. These include slop tanks or other containers used to store waste oil. 

The SPCC rule does not require redundant secondary containment around oil/water 

separators used for secondary containment (i.e., tertiary containment is not required). 

5.5 Oil/Water Separators Used in Oil Production 

5.5.1 Description of Oil/Water Separators Used in Oil Production 

Oil production oil/water separators are used at both onshore and offshore facilities. 

Separators and other separation equipment, such as heater-treaters and gun barrels, are used 

during oil production to separate the well stream into individual well fluids after they are extracted 

from the production well. Different processes and equipment may be used to separate the mixture 

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into oil/emulsion, water, and gas fractions. All such equipment is considered a bulk storage 

container needing specific secondary containment. For purposes of this guidance, this chapter 

focuses on those pieces of equipment that separate water from oil and the equipment through 

which these fluids flow. 

There is quite a variety of production equipment used to separate and treat produced fluids. 

Some are operated under low pressure conditions, while others are operated at high pressure. A 

process called “free-water knockout,” illustrated in Figure 5-4, is generally used to separate large 

volumes of water from oil and gas generated from the well. Gun barrels, also called wash tanks, 

are generally found in older or marginal fields and are used to provide quiet retention time for the 

water to settle out of the produced well fluids (see Figure 5-5). A two-phase separator separates 

the well fluids into a liquid (oil, emulsion,3

 or water) and a gas. The liquid exits the bottom of the 

separator and the gas exits the top, as shown in Figure 5-6. Three-phase separators separate well 

fluids into oil/emulsion, gas, and water. Gas exits from the top, oil/emulsion from the middle, and 

water from the bottom of this type of vertical three-phase separator (Figure 5-7). Three-phase 

separators are generally used when there is free water in the well fluids. If there is little or no free 

water, a two-phase separator might be used instead. Another type of equipment used to separate 

produced fluids, especially fluid emulsions, is termed a “heater-treater.” Heater-treaters use heat, 

electricity, and/or chemicals to reduce the emulsion viscosity and to separate out free oil, water, and 

gas in oil production. The designs of oil/water separators may differ from the examples provided. 

Figure 5-4. Low pressure free-water knockout. 

3

 An emulsion is a colloidal suspension of a liquid within another liquid. In this case, small droplets 

of oil are dispersed through water. 

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Gun barrel oil/water 

separator. 

Figure 5-7. Three-phase oil/water 

Figure 5-6. Two-phase oil/water separator.

separator. 

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In separators used for oil production, the momentum of the fluid flow is absorbed at the inlet, 

thereby reducing the fluid viscosity and allowing oil, gas, and water to separate out of solution. Gas 

then rises and flows out at the top of the separator, while oil and water fall to the lower portion of the 

vessel and coalesce in separate areas. With the appropriate settling time, the more dense free 

water settles beneath the less dense oil. Liquid levels are maintained by float-actuated control 

valves or dump valves. As the different pre-set liquid levels are reached, dump valves discharge 

water and oil from the separator to appropriate storage areas: 

•	 Water is discharged from the bottom of the separator to a water tank; 

•	 Oil is discharged out at a higher level to a oil storage tank; and 

•	 Gas flows continuously out at the top of the separator to sales, a meter run, a flare, 

or a recovery system. 

5.5.2	 Applicability of the SPCC Rule to Oil/Water Separators Used in Oil Production 

The SPCC rule’s wastewater treatment exemption specifically states that the production of 

oil is not wastewater treatment for the purposes of §112.1(d)(6). The focus of the separation 

process in oil production is on removing water from oil, as opposed to removing oil from water. 

Additionally, as stated in the preamble to the 2002 revised SPCC rule, production facilities 

generally lack NPDES or state-equivalent permits or prevention requirements, and thus lack the 

protections that such permits provide. Furthermore, Underground Injection Control (UIC) permits 

do not have prevention requirements for production facilities. Production facilities are normally 

unmanned and therefore lack constant human oversight and inspection. Produced water generated 

in the production process normally contains saline water as a contaminant in the oil, which in 

addition to the toxicity of the oil might aggravate environmental conditions in the case of a discharge 

(67 FR 47068). In some areas of the United States, produced water is fresh and may be 

discharged under a NPDES permit for beneficial use (e.g., irrigation, water for livestock). 

The goal of an oil production, oil recovery, or oil recycling facility is to maximize the 

production or recovery of oil, while eliminating impurities in the oil, including water, whereas the 

goal of a wastewater treatment facility is to purify water. Neither an oil production facility nor an oil 

recovery or recycling facility treats water; instead, it treats oil. For purposes of the wastewater 

treatment exemption, produced water is not considered wastewater, and treatment of produced 

water is not considered wastewater treatment. Therefore, a facility that stores, treats, or otherwise 

uses produced water remains subject to the rule. At oil drilling, oil production, oil recycling, or oil 

recovery facilities, treatment units subject to the rule include open oil pits or ponds associated with 

oil production operations, oil/water separators (e.g., gun barrels), and heater-treater units. Open oil 

pits or ponds function as another form of bulk storage container and are not used for wastewater 

treatment (67 FR 47068,9). Although the ratio of water to oil can be relatively high, the quantity of 

oil involved can be still be substantial and pose a threat of a discharge to navigable waters and 

adjoining shorelines. 

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Oil/water separators used in the production of oil (e.g., heater-treaters and gun barrels) and 

other separation and treatment facility installations, are subject to the specific secondary 

containment requirements for oil production facility bulk storage containers in §112.9(c)(2). 

Therefore, oil/water separators used in oil production are considered bulk storage containers and 

are subject to the applicable SPCC requirements under §112.9(c): 

•	 Oil/water separators used in onshore oil production are subject to the provisions of 

§112.9(c). For example, oil/water separators used in onshore oil production must 

have secondary containment designed to contain the capacity of the largest single 

container and sufficient freeboard to contain precipitation (§112.9(c)(2)). If specific 

secondary containment is determined to be impracticable for the equipment, the 

SPCC Plan must document the reason for impracticability and comply with the 

additional regulatory requirements in §112.7(d). 

•	 Oil/water separators used in offshore oil production are subject to the provisions of 

§112.11(b) and (d) to prevent a discharge of oil. However, if other provisions of the 

rule (except secondary containment) can be met through alternative methods that 

provide environmental equivalence for this equipment, then the Plan must include a 

description in accordance with §112.7(a)(2). 

•	 Vessels and equipment, such as glycol dehydrators and inline heaters, that treat only 

gas and that do not separate, treat, or contain oil, are not subject to the SPCC rule. 

Oil/water separators used in oil production count toward the total storage capacity of the 

facility and must be considered when determining if a facility is regulated by the SPCC rule in 

accordance with §112.1(b) and (d)(2) and the definition of storage capacity in §112.2. In 

determining applicability of any container for calculating the total facility storage capacity, the 

preamble to the 2002 rule states: 

The keys to the definition are the availability of the container for drilling, producing, 

gathering, storing, processing, refining, transferring, distributing, using, or consuming oil, 

and whether it is available for one of those uses or whether it is permanently closed. 

Containers available for one of the above described uses count towards storage capacity, 

those not used for these activities do not. Types of containers counted as storage capacity 

would include some flow-through separators, tanks used for “emergency” storage, 

transformers, and other oil-filled equipment. (67 FR 47081) 

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5.6 	 Documentation Requirements and the Role of the EPA Inspector 

5.6.1	 Documentation by Owner/Operator 

Oil/water separators used exclusively for wastewater treatment are exempt from all SPCC 

requirements, and no documentation is required for this equipment in the SPCC Plan. 

For oil/water separators used to meet SPCC secondary containment requirements, the 

SPCC Plan should discuss the separator design capacity, configuration, maintenance, operation, 

and other elements of the drainage systems that ensure proper functioning and containment of the 

oil as required by §112.7(a)(3)(iii). Examples of elements that this discussion should include are: 

•	 The presence and configuration of valves to prevent the accidental release of oil; 

•	 Routine visual inspection of the oil/water separator, its contents, and discharges of 

effluent; 

•	 Preventive maintenance of facility equipment affecting discharge, including the 

removal of settled pollutants and collected oil; 

•	 A drainage area that flows to the oil/water separator and corresponding anticipated 

flow rate of the drainage system to the separator; 

•	 Appropriate capacity of the oil/water separator for oil and for wastewater; 

•	 Provisions for adequate separate storage capacity (based on the containment sizing 

required by the rule) to contain oil recovered in the oil/water separator; and 

•	 Documentation associated with the maintenance and inspection of oil/water 

separators. 

A separate bulk storage container used to store oil following separation in any oil/water 

separator (i.e., wastewater treatment, secondary containment, or oil production) is subject to all 

applicable requirements of 40 CFR part 112, including §§112.8(c) or 112.9(c), as appropriate. 

For oil/water separators used in oil production, the oil/water separators are considered bulk 

storage containers to be included in the SPCC Plan. The location of these containers must be 

indicated on the facility diagram and discussed in the general requirements in accordance with 

§112.7(a)(3). For more information on facility diagrams, refer to Chapter 6 of this document. The 

facility owner/operator may determine that the sized secondary containment required for these 

oil/water separators is impracticable, pursuant to §112.7(d). If impracticability is determined for 

sized secondary containment, the SPCC Plan must clearly explain why secondary containment is 

not practicable and provide an oil spill contingency plan following the provisions of 40 CFR part 109. 

In addition, such facilities must conduct integrity and leak testing of bulk containers and associated 

valves and piping, and provide a written commitment of manpower, equipment, and materials to 

respond to oil discharges (§112.7(d)). For more information on impracticability, refer to Chapter 4 

of this document. 

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5.6.2 Role of the EPA Inspector 

As with other aspects of the SPCC Plan, the certifying PE will review the use of and 

applicable requirements for oil/water separators at a facility and ensure that they are consistent with 

good engineering practice. 

The EPA inspector will verify that any oil/water separators at a facility that are not addressed 

in the SPCC Plan are in fact used exclusively for wastewater treatment and not to meet any 

requirement of part 112. This review considers the intended and actual use of the separator. The 

EPA inspector should consider the intended use of the separator at the facility (e.g., wastewater 

treatment, secondary containment, oil production, recovery, or recycling), any flow diagrams 

illustrating the use of the separator, and the design specifications of the unit in evaluating the 

proper application of the wastewater exemption. The EPA inspector may also consider the flowthrough capacity of the separator, the emulsion of oil present within the separator, and the design 

specifications of the unit in evaluating the use of the oil/water separator. 

For oil/water separators used to meet SPCC secondary containment requirements, the EPA 

inspector will verify that the Plan includes, for each oil/water separator used as secondary 

containment, a discussion of the separator design capacity, configuration, maintenance, and 

operation, as well as other elements of the drainage systems that ensure proper functioning and 

containment of the oil in accordance with §112.7(a)(3)(iii). Inspectors should note the risk 

associated with this form of containment and should evaluate the design, maintenance, operation, 

and efficacy of oil/water separator systems used for containment very carefully. Generally, these 

separators should be monitored on a routine schedule, and collected oil should be removed as 

appropriate and in accordance with the drainage procedures in the Plan. 

Oil/water separators used in the production of oil (e.g., heater-treaters and gun barrels) and 

other separation and treatment facility installations, are subject to the specific secondary 

containment requirements for oil production facility bulk storage containers in §112.9(c)(2). The 

SPCC Plan must address this equipment and include the storage capacity of the equipment in the 

storage capacity calculations (§112.1(b) and (d)(2) and the definition of storage capacity in §112.2.) 

If sized secondary containment is determined to be impracticable for the equipment, the SPCC Plan 

must document the reason for impracticability and comply with the additional regulatory 

requirements in §112.7(d). 

By certifying the SPCC Plan, a PE attests that the Plan has been prepared in accordance 

with good engineering practice and with the requirements of 40 CFR part 112, and that the Plan is 

adequate for the facility. Thus, if the wastewater treatment exemption is certified by the PE or if 

other oil/water separator uses are properly documented, they most likely will be considered 

acceptable by EPA inspectors. However, if the documented uses of the oil/water separators do not 

meet the standards of common sense, appear to be incorrect, deviate from the use described in the 

Plan, are not maintained or operated in accordance with the Plan, or simply do not operate 

correctly, further follow-up action may be warranted. This may include a request for more 

information or a Plan amendment in accordance with §112.4(d). 

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Chapter 6: Facility Diagrams 

FACILITY DIAGRAMS 

6.1 Introduction 

Section 112.7(a)(3) of the SPCC rule requires that facility owners and operators include in 

the SPCC Plan a diagram of the facility that identifies the location and contents of oil containers, 

connecting piping, and transfer stations. The diagram helps to ensure safe and efficient response 

actions, effective spill prevention and emergency planning, ease of Plan review by an EPA 

inspector, and proper implementation of the Plan by facility personnel. This chapter explains the 

requirement for a facility diagram, provides guidelines on the necessary level of detail, and includes 

several facility diagrams as examples. 

6.1.1 Purpose 

The facility diagram is an important component of an SPCC Plan because the diagram is 

used for prevention, planning, inspection, management, and response considerations. EPA and 

facility inspectors, responders, and facility personnel need to be aware of the location of all 

containers, piping, and transfer areas subject to the SPCC rule. The facility diagram may also 

assist response efforts by helping responders determine the flow pathway of discharged oil and 

take more effective measures to control the flow of oil. This may avert damage to sensitive 

environmental areas; may protect drinking water sources; and may help prevent discharges to other 

conduits, to a treatment facility, or to navigable waters or adjoining shorelines. The diagram may 

also serve to address the rule requirements by describing, pictorially, the capacity and type of oil in 

each container, the associated discharge/drainage controls, and the flow path of a discharge 

(§112.7(a)(3)(i) and (iii) and 112.7(b), respectively). Additionally, the diagram may be attached to a 

facility inspection checklist to identify areas, containers, or equipment subject to inspection. 

Diagrams may also help federal, state, or facility personnel avoid certain hazards and identify the 

location of facility response equipment. Finally, by 

informing responders of the location and content 

of containers, a facility diagram helps to ensure 

their safety in conducting response actions and to 

protect property. 

6.1.2 Requirements for a Facility Diagram 

A description of the physical layout of a 

facility, including a facility diagram, is one of the 

general requirements for an SPCC Plan. The 

2002 revisions to the SPCC rule added a new 

specific requirement in §112.7(a)(3) for a facility 

diagram to be included in the Plan. Section 

§112.7(a)(3) 

Describe in your Plan the physical layout of the 

must mark the location and contents of each 

completely buried tanks that are otherwise 

exempted from the requirements of this part 

also include all transfer stations and 

connecting pipes. ... 

Note: The above text is an excerpt of the SPCC rule. 

Refer to 40 CFR part 112 for the full text of the rule. 

facility and include a facility diagram, which 

container. The facility diagram must include 

under §112.1(d)(4). The facility diagram must 

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112.7(a)(3) requires that the facility diagram include the location and contents of each container, 

completely buried tanks (even if exempted from the SPCC requirements), transfer areas (i.e., 

stations), and connecting pipes. In addition to the requirement for a facility description and 

diagram, §112.7(a)(3) lists additional items to be addressed in an SPCC Plan, including the type of 

oil in each container and its capacity; discharge prevention measures; discharge or drainage 

controls; countermeasures for discharge discovery, response, and cleanup; methods of disposal of 

recovered materials; and specific contact information. Please see §112.7(a)(3) for these 

requirements in their entirety. 

6.2	 Preparing a Facility Diagram 

Facility diagrams provided as part of an SPCC Plan often illustrate the following information: 

Required by §112.7(a)(3):1 

•	 Aboveground and underground storage tanks (including content and capacity 

•	 Mobile portable containers (including content and capacity); 

•	 Hydraulic operating systems or manufacturing equipment; 

•	 Oil-filled electrical transformers, circuit breakers, or other equipment (including 

content and capacity); 

•	 Any other oil-filled equipment (including content and capacity); 

•	 Oil pits or ponds (at production facilities); 

•	 Oil/water separators (e.g., at tank batteries, separation, and treating facility 

installations associated with production facilities); 

•	 Fill ports and connecting piping (scale of drawing permitting); 

•	 Oil transfer areas; and 

•	 Loading racks/unloading areas. 

Recommended: 

•	 Secondary containment structures, including oil/water separators used for 

containment; 

•	 Storm drain inlets and surface waters that could be affected by a discharge; 

•	 Direction of flow in the event of a discharge (which can serve to address the SPCC 

requirement under §112.7(b)); 

•	 Legend that indicates scale and identifies symbols used in the diagram; 

•	 Location of response kits and firefighting equipment; 

•	 Location of valves or drainage system control that could be used in the event of a 

discharge to contain oil on the site; 

•	 Compass direction; and 

1

 Containers that have a capacity of less than 55 gallons, are permanently closed, or are otherwise exempt 

from the rule (with the exception of exempted underground storage tanks) are not required to be listed on the facility 

diagram. 

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• Topographical information and area maps. 

In addition, for purposes of emergency response, EPA recommends, but does not require, that an 

owner/operator mark on a facility diagram containers that store Clean Water Act (CWA) hazardous 

substances (listed in 40 CFR part 116, Designation of Hazardous Substances) and label the 

contents of these containers (67 FR 47097). 

While recognizing that SPCC Plans and their associated diagrams are facility-specific and 

prepared with a certain amount of PE discretion, the following information is meant to facilitate a 

common understanding of what EPA inspectors may expect to see in a facility diagram. The 

remainder of this section provides guidelines for the recommended level of detail, how specific 

containers and systems may be addressed, and the use of alternate facility diagrams for meeting 

the requirements of §112.7(a)(3). 

6.2.1 Level of Detail 

The facility diagram should provide sufficient detail for the facility personnel to undertake 

prevention activities, for EPA to perform an effective inspection, and for responders to take effective 

measures. As with other aspects of the SPCC Plan, the facility diagram is to be prepared in 

accordance with good engineering practice and reviewed by the PE as part of Plan certification. 

Thus, the level of detail provided and the approach taken for preparing an adequate facility diagram 

is primarily at the discretion of the certifying PE. 

6.2.2. Facility Description 

Section 112.7(a)(3) requires that the Plan include a description of the physical layout of the 

facility. In addition to marking the location and contents of each oil storage container at the facility, 

this description may include information on the facility location, type, size, and proximity to 

navigable waters, as well as other relevant information. This general facility description is often 

supplemented with a more specific description of containers subject to the SPCC rule to 

complement what is required on the facility diagram (e.g., storage capacity and content). 

6.2.3 Oil Containers 

The facility diagram must include all containers (including oil-filled equipment) that store 55 

gallons or more of oil and must include information indicating the contents of these containers 

(§112.7(a)(3)). The 2002 revisions to the SPCC rule established a minimum container size of 55 

gallons. Pursuant to §112.1(d)(5), the rule does not apply to containers of less than 55 gallons, and 

therefore they do not need to be included on the facility diagram. 

In situations where diagrams become complicated due to the presence of multiple oil 

storage containers or complex piping/transfer areas at the facility, it may be difficult to indicate the 

contents and capacity of the containers on the diagram itself. In order to simplify the diagram, the 

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PE may choose to include that information on a separate log or sheet maintained in the Plan, 

similar to the description outlined below for mobile/portable containers. 

6.2.4 Mobile or Portable Containers 

The owner/operator must state the contents and location of each container on the diagram 

of the facility (§112.7(a)(3)). For portable containers (e.g., drums and totes), the facility 

owner/operator may note the general contents of each container and provide more detailed content 

information on a separate sheet or log, as well as other information, such as container capacity, that 

the PE determines to be appropriate to adequately describe the facility. If the contents of a 

container change frequently, the contents may be recorded on a separate sheet or log, or on the 

diagram (67 FR 47097). In this case, the diagram should note that contents vary. Additionally, the 

PE may choose to identify an area on the facility diagram (e.g., a drum storage area) and include a 

separate log that can be updated by facility personnel. The PE should develop a reasonable 

estimate of the number of containers in the area and the capacity of the containers, and consider 

routine movement of the containers for the Plan. This estimate can be used to determine 

applicability of the rule thresholds and provide a general description of the mobile/portable 

containers in the Plan. The PE should also include a procedure for maintaining the log, in order to 

avoid PE certification of technical amendments of the Plan as the number of mobile/portable 

containers changes at the facility. 

Mobile containers should be marked on the facility diagram in their out-of-service or 

designated storage area or where they are most frequently located, such as a warehouse drum 

storage area. The facility owner/operator and certifying PE determine how best to represent 

mobile/portable containers on the facility diagram, such as by developing a log or indicating primary 

storage areas. If mobile containers are moved throughout the facility and do not immediately return 

to a specified location easily identified on the facility diagram, the exact location could be addressed 

on a separate sheet or log. This log would complement the facility diagram and the SPCC Plan by 

providing further information on the specific location and contents of mobile and portable 

containers. In addition, the diagram must identify the final location of mobile or portable containers 

(as required in §112.7(a)(3)) that return to a specific designated area to comply with the specific 

secondary containment requirements in §112.8(c)(11). (See Chapter 4 of this document for a 

discussion of secondary containment requirements.) 

6.2.5 Completely Buried Storage Tanks 

A facility diagram must include the location and contents of all containers required to be 

addressed in the SPCC Plan (67 FR 47097 and §112.7(a)(3)). This includes exempt underground 

storage tanks (USTs) as well as USTs that are subject to SPCC requirements at the facility. The 

rationale for this requirement is to help response personnel to easily identify dangers from either fire 

or explosion, or from physical impediments during response activities. For example, exempted 

tanks may include completely buried USTs and piping systems at a gasoline service station that are 

subject to all technical requirements of either 40 CFR part 280 or an approved state UST program 

under 40 CFR part 281. 

U.S. Environmental Protection Agency 6-4 Version 1.0, 11/28/2005 
Chapter 6: Facility Diagrams 

As discussed in Chapter 2 of this document, a facility may have USTs that are subject to 

SPCC requirements because they are deferred from compliance with some or all of the technical 

requirements of 40 CFR part 280 (e.g., UST systems with field constructed tanks, any UST system 

that stores fuel solely for use by an emergency power generator, airport hydrant fuel distribution 

systems). Any USTs at a facility that are subject to SPCC requirements must also be marked on 

the facility diagram (§112.7(a)(3)). (See the preamble to the 1991 proposed rule, 56 FR 54612, 

October 22, 1991.) 

6.2.6 Piping and Manufacturing Equipment 

The facility diagram must also include all transfer stations (i.e., any location where oil is 

transferred) and connecting pipes (§112.7(a)(3)). Associated piping and manufacturing equipment 

present at an SPCC-regulated facility may be difficult to represent on a facility diagram, due to their 

relative location, complexity, or design. Recognizing this, EPA allows flexibility in the way the 

facility diagram is drawn. An owner/operator may represent such systems in a less detailed manner 

on the facility diagram in the SPCC Plan as long as more detailed diagrams of the systems are 

maintained at the facility and referenced on the diagram. Examples of more detailed diagrams may 

include blueprints, engineering diagrams, or diagrams developed to comply with other local, state, 

or federal requirements. 

The scale and level of detail of the facility diagram may make it difficult to show small 

transfer lines within containment structures. Schematic representations that provide a general 

overview of the piping service (e.g., supply/return) may provide sufficient information when 

combined with a description of the piping in the Plan. Alternatively, overlay diagrams showing 

different portions of the piping system may be used where the density and/or complexity of the 

piping system would make a single diagram difficult to read. 

Examples of ways that manufacturing equipment may be represented include a box that 

identifies the equipment and its location, or a simplified process flow diagram. Figure 6-1, which is 

an excerpt of a complete facility diagram (Figure 6-4) included later in Section 6.4, provides an 

example showing how manufacturing equipment may be represented in a facility diagram. For 

areas of complicated piping, which often include different types, numbers, and lengths of pipes, the 

facility diagram may show a simplified box labeled “piping” or show a single line that identifies the 

service (e.g., supply/return), as long as more detailed diagrams are available at the facility. Figure 

6-2 provides an example showing how a complex piping area may be represented in a facility 

diagram, and is also an excerpt of the example facility diagram presented in Figure 6-4. 

U.S. Environmental Protection Agency 6-5 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

Figure 6-1. Example showing how manufacturing equipment 

could be represented in a facility diagram. Note that more 

detailed diagrams would need to be available at the facility. 

Figure 6-2. Example showing how a complex piping area could be represented in a facility 

diagram. Note that more detailed diagrams would need to be available at the facility. 

U.S. Environmental Protection Agency 6-6 Version 1.0, 11/28/2005 
Chapter 6: Facility Diagrams 

6.2.7 Use of State and Federal Diagrams 

Some state and federal regulations may require a diagram with similar or overlapping 

requirements, whereas others do not. SPCC is a federal program that specifies minimum 

requirements, which states may supplement with more stringent requirements. A facility diagram 

prepared for a state or federal plan or for other purposes (construction permits, facility 

modifications, or other pollution prevention requirements) may be used in an SPCC Plan if it meets 

the requirements of the SPCC rule. 

6.3 Facility Diagram Examples 

This section includes example facility diagrams for three fictitious SPCC-regulated facilities. 

These three examples illustrate how certain containers and equipment could be represented in a 

facility diagram; the examples are provided for the purpose of illustration only. Preparation of a 

facility diagram is a site-specific effort, and the diagram prepared for a given facility should reflect 

the level of detail needed to adequately describe the facility configuration. The level of detail and/or 

approach taken for the examples below may not necessarily be appropriate for a given facility. 

It is important to note that facility diagrams, like the other elements of an SPCC Plan, must 

be prepared in accordance with good engineering practice, and must be reviewed by the PE 

certifying the Plan (§112.3(d)). Section 112.7(a)(3) requires the facility diagram to show, at a 

minimum, the location and contents of oil containers; completely buried storage tanks, including 

those that may otherwise be exempt from the rule; and transfer areas (i.e., stations) and connecting 

pipes. The facility owner or operator may also include on the diagram additional structures and 

equipment, and may use the diagram to illustrate other elements that may be relevant to the SPCC 

Plan and to emergency response. For instance, a diagram may also show the discharge and 

drainage controls that are described in the SPCC Plan, the predicted flow path for discharged oil 

based on topography, areas on which to focus inspections, fire-fighting resources, spill response 

kits, and/or evacuation routes. 

Example facility diagrams are presented below for a bulk storage and distribution facility, a 

manufacturing facility, and an oil production facility. 

6.3.1 Example #1: Bulk Storage and Distribution Facility 

Figure 6-3 is an example of a diagram for a bulk storage and distribution facility, which has a 

tank farm, a loading rack and an unloading area, and other oil containers and oil-filled equipment. 

This diagram corresponds to the model SPCC Plan for a bulk storage distribution facility that is 

provided in Appendix D of this guidance document. Because it has fewer tanks and less complex 

operations than a manufacturing facility, for example, this facility requires a less detailed facility 

diagram than the example provided in Figure 6-4. 

As required by §112.7(a)(3), this diagram includes all containers with an oil storage capacity 

of 55 gallons or greater. In addition to listing the contents directly on the diagram, the diagram 

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SPCC Guidance for Regional Inspectors 

provides a reference to a supplementary table that contains the volume and content of the storage 

tanks shown on the diagram (appended to the diagram as Table B-1). At the discretion of the PE 

who reviewed and certified the Plan, the example facility diagram also depicts secondary 

containment methods and includes a reference to calculations of containment capacity provided in 

other parts of the SPCC Plan. Also, a separate log (Table B-2) identifies the contents of the drums 

in the storage warehouse. Please refer to Section 6.2.3 of this document for more information. 

U.S. Environmental Protection Agency 6-8 Version 1.0, 11/28/2005 
Figure 6-3. Example facility diagram, including loading and unloading areas. 
SPCC Guidance for Regional Inspectors 

Table B-1. Volume and contents of tanks and containers identified on the facility diagram. Please 

see facility diagram to identify the areas below. 

Tank/Container 
 

Area 1 
 

Tank 1 
 

Tank 2 
 

Tank 3 
 

Tank 4 
 

Tank 5 
 

Tank 6 
 

Main Office Building 

Tank H 

Drum Storage Warehouse 

Up to 30 drums 

Rev. 06/14/05 

Volume (gallons) Contents 

25,000 

25,000 

25,000 

25,000 

30,000 

30,000 

2,000 

55 (each) 

Product A – #2 fuel oil 

Product A – #2 fuel oil 

Product B – #6 fuel oil 

Product B – #6 fuel oil 

Product C – Kerosene 

Product C – Kerosene 

Heating oil 

Various oil products 

(lubricating oil, engine oil, 

used oil, etc.) 

Table B-2. Drum storage warehouse log. 

Date 

6/14/05 

6/14/05 

6/14/05 

Number and Type Contents 

of Container 

15 drums lubrication oil 

5 drums engine oil 

10 drums used oil 

Capacity 

55 x 15 = 825 

55 x 5 = 275 

55 x 10 = 550 

Location at 

facility 

Drum storage 

warehouse 

Drum storage 

warehouse 

Drum storage 

warehouse 

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Chapter 6: Facility Diagrams 

6.3.2 Example #2: Manufacturing Facility 

Figure 6-4 is an example facility diagram for a large manufacturing facility with a variety of 

containers and equipment, including piping, oil-filled equipment (i.e., manufacturing equipment and 

transformers), and completely buried storage tanks. As required by §112.7(a)(3), this diagram 

includes all containers with a storage capacity of 55 gallons or greater. In addition to listing the 

contents directly on the diagram, it includes a reference to a crosswalk that contains the volume 

and content of the storage containers shown on the diagram (appended to the diagram as Table 

B-3). Also, while not required, the diagram marks the location of containers that store CWA 

hazardous substances and labels those containers. EPA would further recommend that the specific 

volume and specific contents of the 4,000-gallon solvent tank be included in the crosswalk. 

Additionally, the diagram notes the location and content of completely buried storage tanks that, 

although otherwise exempt from the SPCC rule because they meet all the technical requirements of 

40 CFR part 280 or an approved state UST program under 40 CFR part 281, must still be included 

in the diagram in accordance with §112.7(a)(3). 

This diagram also includes an example of how manufacturing equipment and complex 

piping may be represented on a facility diagram. The diagram references the more detailed 

diagrams and plans of the piping and manufacturing equipment that are available separately at the 

facility. For more information on ways to represent these systems, please see Section 6.2.6, Piping 

and Manufacturing Equipment, above. 

Finally, while not required to be included in the diagram, this example facility diagram also 

includes a reference to the calculation of diked storage provided in other parts of the SPCC Plan 

and depicts wastewater treatment systems, secondary containment, and oil/water separators. 

U.S. Environmental Protection Agency 6-11 Version 1.0, 11/28/2005 
Figure 6-4. Example facility diagram, including manufacturing equipment, complex piping, and completely buried 
Chapter 6: Facility Diagrams 

Table B-3. Volume and contents of tanks and containers identified on the facility diagram. Please 

see facility diagram to identify the areas below. 

Tank/Container Volume (gallons) 

Area A – Raw Material Bulk Storage 

Tank 1 
 

Tank 2 
 

Tank 3 
 

Tank 4 
 

Tank 5 
 

Tank 8 
 

Tank 9 
 

Area B – Finished Product Bulk Storage 

Tank 6 

Tank 7 

Area C – Electrical Equipment 

Transformer E1 
 

Transformer E2 
 

Area D 

Liquid Product Accumulation 
 

Tank 
 

Process Area 

Primary Reactor 
 

Distillation 
 

Direct Contact Cooling 
 

Stripping 
 

Pump/Tank 
 

Condenser Liquifier 
 

Underground Storage Tanks 

Tank 9 (otherwise exempt 

from SPCC requirements) 

Tank 10 (otherwise exempt 

from SPCC requirements) 

Tank 11 

Rev. 04/21/05 

6.3.3 Example #3: Oil Production Facility 

4,000 

4,000 

20,000 

20,000 

20,000 

6,000 

40,000 

20,000 

20,000 

235 

235 

10,000 

500 

500 

500 

500 

300 

500 

8,000 

8,000 

2,000 

Contents 

Product A – #2 fuel oil 

Product A – #2 fuel oil 

Product B – #6 fuel oil 

Product B – #6 fuel oil 

Product B – #6 fuel oil 

Product C – Kerosene 

Solvent – Toluene 

Product D – proprietary oil 

Product D – proprietary oil 

Silicon-based dielectric fluid 

Silicon-based dielectric fluid 

Product D – proprietary oil 

intermediate oil product 

intermediate oil product 

intermediate oil product 

intermediate oil product 

intermediate oil product 

intermediate oil product 

gasoline 

gasoline 

heating oil 

Figure 6-5 is an example facility diagram for a small oil production facility with two extraction 

wells and a production tank battery. As required by §112.7(a)(3), this diagram includes all 

containers with a storage capacity of 55 gallons or greater and transfer areas. Because the facility 

has a relatively large footprint, the direction of flow is best displayed on a separate figure that shows 

the general location of the site relative to receiving waterbodies (Figure 6-6). 

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SPCC Guidance for Regional Inspectors 

Figure 6-5. Example facility diagram for a production facility. 

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Chapter 6: Facility Diagrams 

Figure 6-6. Example general facility location diagram for a production facility. 

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SPCC Guidance for Regional Inspectors 

6.4 	 Review of a Facility Diagram 

6.4.1 	 Documentation by Owner/Operator 

By certifying an SPCC Plan, a PE attests that he/she is familiar with the requirements of 40 

CFR part 112, that the Plan has been prepared in accordance with good engineering practice, 

following the requirements of 40 CFR part 112, that the Plan is adequate for the facility, and that he 

or his agent visited the facility. Thus, if an SPCC Plan is certified by a PE and the facility diagram is 

consistent with the rule requirements, it will most likely be considered acceptable by regional 

inspectors. However, if the diagram does not meet these standards of common sense, the facility 

design has changed, the supporting drawings for a simplified diagram are not available at the 

facility, or the diagram appears to be inadequate for the facility, appropriate follow-up action may be 

warranted. This may include a request for more information or a Plan amendment in accordance 

with §112.4(d). 

6.4.2 	 Role of the EPA Inspector 

The inspector should verify that the diagram accurately represents the facility layout and 

provides sufficient detail as outlined in §112.7(a)(3), and use it as a guide for the containers and 

piping inspected during the site visit. 

The EPA inspector should verify that the diagram included in the Plan includes: 

•	 Location and contents of each container (except those below the de minimis 

container size of 55 gallons as described in Section 6.2.3, above). 

•	 Completely buried tanks, including those that are otherwise exempt from the SPCC 

rule by §112.1(d)(4). 

•	 All transfer stations and connecting pipes (allowing the flexibility as described in 

Section 6.2.6, above). 

Although EPA generally stated in both the preamble of the 2002 SPCC rule (67 FR 47097) 

and in §112.7(a)(3) that all facility transfer stations and connecting pipes that handle oil must be 

included in the diagram, it is reasonable to allow flexibility on the method of depicting concentrated 

areas of piping and manufacturing equipment on the facility diagram. These areas may be 

represented in a more simplified manner, as long as more detailed diagrams (such as blueprints, 

engineering diagrams, or process charts) are available at the facility. The inspector may ask to 

review more detailed diagrams of piping and manufacturing equipment if further information is 

needed during a site inspection. 

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Chapter 7: Inspection, Evaluation, and Testing

U.S. Environmental Protection Agency 7-1 Version 1.1, 2/3/06

INSPECTION, EVALUATION, AND TESTING

7.1 Introduction

Regularly scheduled inspections, evaluations, and testing by qualified personnel are critical

parts of discharge prevention. Their purpose is to prevent, predict, and readily detect discharges. 

They are conducted not only on containers, but also on associated piping, valves, and

appurtenances, and on other equipment and components that could be a source or cause of an oil

release. Activities may involve one or more of the following: an external visual inspection of

containers, piping, valves, appurtenances, foundations, and supports; a non-destructive shell test to

evaluate integrity of certain containers; and additional evaluations, as needed, to assess the

equipment’s fitness for continued service. The type of activity and its scope will depend on the

exercise of good engineering practice; not every action will necessarily be applicable to every

facility and container, and additional inspections may be required in some cases. An inspection,

evaluation, and testing program that complies with SPCC requirements should specify the

procedures, schedule/frequency, types of equipment covered, person(s) conducting the activities,

recordkeeping practices, and other elements as outlined in this chapter.

The remainder of this chapter is organized as follows:

• Section 7.2 provides an overview of the SPCC inspection, evaluation, and testing

requirements.

• Section 7.3 discusses specific cases, including the use of environmentally

equivalent measures.

• Section 7.4 discusses the role of the EPA inspector in reviewing a facility’s

compliance with the rule’s inspection, evaluation, and testing requirements.

• Section 7.5 summarizes industry standards, code requirements, and recommended

practices (RPs) that apply to different types of equipment.

7.2 Inspection, Evaluation, and Testing under the SPCC Rule

Various provisions of the SPCC rule relate to the inspection, evaluation, and testing of

containers, associated piping, and other oil-containing equipment. Different requirements apply to

different types of equipment and to different types of facilities. The requirements are generally

aimed at preventing discharges of oil caused by leaks, brittle fracture, or other forms of container

failure by ensuring that containers used to store oil have the necessary physical integrity for

continued oil storage. The requirements are also aimed at detecting container failures (such as

small pinhole leaks) before they can become significant and result in a discharge as described in

§112.1(b). 
SPCC Guidance for Regional Inspectors

1

 Integrity testing is any means to measure the strength (structural soundness) of a container shell, bottom, and/or

floor to contain oil, and may include leak testing to determine whether the container will discharge oil. Integrity testing

is a necessary component of any good oil discharge prevention plan. It will help to prevent discharges by testing the

strength and imperviousness of containers, ensuring they are suitable for continued service under current and

anticipated operating conditions (e.g., product, temperature, pressure). Testing may also help facilities determine

whether corrosion has reached a point where repairs or replacement of the container is needed, and thus avoid

unplanned interruptions in facility operations. (67 FR 47120)

U.S. Environmental Protection Agency 7-2 Version 1.1, 2/3/06

7.2.1 Summary of Inspection and Integrity Testing Requirements

Table 7-1 summarizes the provisions that apply to different types of equipment and facilities. 

Some inspection and testing provisions apply to bulk storage containers at onshore facilities (other

than production facilities). Inspection and/or testing requirements also apply to other components

of a facility that might cause a discharge (such as vehicle drains, foundations, or other equipment or

devices). Other inspection requirements also apply to oil production facilities. In addition,

inspection, evaluation, and testing requirements are required under certain circumstances, such as

when an aboveground field-constructed container undergoes repairs, alterations, or a change in

service that may affect its potential for a brittle fracture or other catastrophe, or in cases where

secondary containment for bulk storage containers is impracticable (§112.7(d), as described in

Chapter 4 of this document.) Facility owners and operators must also maintain corresponding

records to demonstrate compliance (§§112.8(c)(6), 112.8(d)(4), 112.9(b)(2), 112.9(c)(3), and

112.9(d)(1) and (2)) per §112.7(e).

Table 7-1. Summary of SPCC inspection, evaluation, testing, and maintenance program provisions.

Facility Component Section(s) Action Method, Circumstance, and Required Action 

General Requirements Applicable to All Facilities

Bulk storage with no

secondary

containment and for

which an

impracticability

determination has

been made

112.7(d) Test Integrity testing.1

 Periodically.

However, because there is no secondary containment,

good engineering practice may suggest more frequent

testing than would otherwise be scheduled.

Valves and piping

associated with bulk

storage containers

with no secondary

containment and for

which an

impracticability

determination has

been made

112.7(d) Test Integrity and leak testing of valves and piping

associated with containers that have no secondary

containment as described in §112.7(c). Periodically.
Chapter 7: Inspection, Evaluation, and Testing

Facility Component Section(s) Action Method, Circumstance, and Required Action 

2

 Certain industry standards require recordkeeping beyond three years.

U.S. Environmental Protection Agency 7-3 Version 1.1, 2/3/06

Recordkeeping

requirement

112.7(e) Record Keep written procedures and a signed record of

inspections and tests for a period of three years.2

Records kept under usual and customary business

practices will suffice. For all actions.

Lowermost drain and

all outlets of tank car

or tank truck

112.7(h)(3) Inspect Visually inspect. Prior to filling and departure of tank

car or tank truck.

Field-constructed

aboveground

container

112.7(i) Evaluate Evaluate potential for brittle fracture or other

catastrophic failure. When the container undergoes a

repair, alteration, reconstruction or a change in service

that might affect the risk of a discharge or failure due

to brittle fracture or other catastrophe, or has

discharged oil or failed due to brittle fracture failure or

other catastrophe. Based on the results of this

evaluation, take appropriate action.

Subpart B: Onshore Facilities – Petroleum and Other Non-Petroleum Oils

Subpart C: Onshore Facilities (Excluding Production Facilities) – Animal Fats and Vegetable Oils

Onshore Facilities (Excluding Production)

Diked areas 112.8(b)(1) &

112.8(b)(2) or

112.12(b)(1) &

112.12(b)(2)

&

112.8(c)(10) or

112.12(c)(10)

Inspect Visually inspect content for presence of oil. Prior to

draining. You must promptly remove any

accumulations of oil in diked areas.

Buried metallic

storage tank

installed on or after

January 10, 1974 

112.8(c)(4) or

112.12(c)(4)

Test Leak test. Regularly.

Aboveground bulk

storage container

112.8(c)(6) or

112.12(c)(6)

Test Test container integrity. Combine visual inspection

with another testing technique (such as nondestructive shell testing). Following a regular

schedule and whenever material repairs are made. 

Aboveground bulk

storage container

112.8(c)(6) or

112.12(c)(6)

&

112.8(c)(10) or

112.12(c)(10)

Inspect Inspect outside of container for signs of deterioration

and discharges. Frequently. Promptly correct visible

discharges which result in a loss of oil from the

container, including but not limited to seams, gaskets,

piping, pumps, valves, rivets, and bolts. 
SPCC Guidance for Regional Inspectors

Facility Component Section(s) Action Method, Circumstance, and Required Action 

U.S. Environmental Protection Agency 7-4 Version 1.1, 2/3/06

Bulk storage

container supports

and foundation

112.8(c)(6) or 

112.12(c)(6)

Inspect Inspect container’s supports and foundations.

Following a regular schedule and whenever material

repairs are made.

Diked area 112.8(c)(6) or

112.12(c)(6)

&

112.8(c)(10) or

112.12(c)(10)

Inspect Inspect for signs of deterioration, discharges, or

accumulation of oil inside diked areas. Frequently. 

You must promptly remove any accumulations of oil in

diked areas.

Steam return and

exhaust lines

112.8(c)(7) or

112.12(c)(7)

Monitor Monitor for contamination from internal heating coils. 

On an ongoing basis.

Liquid level sensing

devices

112.8(c)(8)(v)

or

112.12(c)(8)(v)

Test Test for proper operation. Regularly.

Effluent treatment

facilities

112.8(c)(9) or

112.12(c)(9)

Observe Detect possible system upsets that could cause a

discharge. Frequently.

Buried piping 112.8(d)(1) or

112.12(d)(1)

Inspect Inspect for deterioration. Whenever a section of

buried line is exposed for any reason. If you find

corrosion damage, you must undertake additional

examination and corrective action as indicated by the

magnitude of the damage. 

Buried piping 112.8(d)(4) or

112.12(d)(4)

Test Integrity and leak testing. At the time of installation,

modification, construction, relocation, or replacement.

All aboveground

valves, piping, and

appurtenances

112.8(d)(4) or

112.12(d)(4)

Inspect During the inspection, assess general condition of

items, such as flange joints, expansion joints, valve

glands and bodies, catch pans, pipeline supports,

locking of valves, and metal surfaces. Regularly.

Onshore Production Facilities

Diked area 112.9(b)(1) Inspect Visually inspect content. Prior to draining. You must

remove accumulated oil on the rainwater and return it

to storage or dispose of it in accordance with legally

approved methods.

Field drainage

systems, oil traps,

sumps, and

skimmers

112.9(b)(2) Inspect Detect accumulation of oil that may have resulted from

any small discharge. Inspect at regularly scheduled

intervals. You must promptly remove any

accumulations of oil. 

Aboveground

containers

112.9(c)(3) Inspect Visually inspect to assess deterioration and

maintenance needs. Periodically and on a regular

schedule.
Chapter 7: Inspection, Evaluation, and Testing

Facility Component Section(s) Action Method, Circumstance, and Required Action 

U.S. Environmental Protection Agency 7-5 Version 1.1, 2/3/06

Foundations or

supports of each

container that is on or

above the surface of

the ground

112.9(c)(3) Inspect Visually inspect to assess deterioration and

maintenance needs. Periodically and on a regular

schedule.

All aboveground

valves and piping

associated with

transfer operations

112.9(d)(1) Inspect During the inspection, assess general condition of

flange joints, valve glands and bodies, drip pans, pipe

supports, pumping well polish rod stuffing boxes,

bleeder and gauge valves, and other such items. 

Periodically and on a regular schedule.

Saltwater disposal

facilities

112.9(d)(2) Inspect Inspect to detect possible system upsets capable of

causing a discharge. Often, particularly following a

sudden change in atmospheric temperature.

Offshore Oil Drilling, Production, and Workover Facilities

Flowlines 112.9(d)(3) Inspect Have a program of flowline maintenance to prevent

discharges from each flowline. Each program may

have its own specific and individual inspection, testing,

and/or evaluation requirements and frequencies as

determined by the PE.

Sump system (liquid

removal system and

pump start-up device)

112.11(c) Inspect

and Test

Use preventive maintenance inspection and testing

program to ensure reliable operation. Regularly

scheduled.

Pollution prevention

equipment and

systems

112.11(h) & (i) Inspect

and Test

Prepare, maintain, and conduct testing and inspection

of the pollution prevention equipment and systems

commensurate with the complexity, conditions, and

circumstances of the facility and any other appropriate

regulations. You must use simulated discharges for

testing and inspecting human and equipment pollution

control and countermeasure systems. On a scheduled

periodic basis.

Sub-marine piping 112.11(p) Inspect

and Test

Inspect and test for good operating conditions and for

failures. Periodically and according to a schedule.

The SPCC rule is a performance-based regulation. Since each facility may present unique

characteristics and since methodologies may evolve as new technologies are developed, the rule

does not prescribe a specific frequency or methodology to perform the required inspections,

evaluations, and tests. Instead, it relies on the use of good engineering practice, based on the

professional judgement of the Professional Engineer (PE) who certifies the SPCC Plan considering

industry standards. In addition, recommended practices, safety considerations, and requirements

of other federal, state, or local regulations may be considered in the development and PE

certification of the SPCC Plan. Section 112.3(d) specifically states that the PE certification of a

Plan attests that “procedures for required inspections and testing have been established.” Thus, in
SPCC Guidance for Regional Inspectors

U.S. Environmental Protection Agency 7-6 Version 1.1, 2/3/06

§§112.8(c)(6) and 112.12(c)(6) 

Test each aboveground container for integrity on

a regular schedule, and whenever you make

material repairs. The frequency of and type of

testing must take into account container size and

design (such as floating roof, skid-mounted,

elevated, or partially buried). You must combine

visual inspection with another testing technique

such as hydrostatic testing, radiographic testing,

ultrasonic testing, acoustic emissions testing, or

another system of non-destructive shell testing.

You must keep comparison records and you

must also inspect the container’s supports and

foundations. In addition, you must frequently

inspect the outside of the container for signs of

deterioration, discharges, or accumulation of oil

inside diked areas. Records of inspections and

tests kept under usual and customary business

practices will suffice for purposes of this

paragraph.

Note: The above text is only a brief excerpt of the rule. Refer

to 40 CFR part 112 for the full text of the rule.

certifying an SPCC Plan, a PE is also certifying that the inspection program it describes is

appropriate for the facility and is consistent with good engineering practice. Section 112.3(d) also

states that the Plan must be prepared in accordance with good engineering practice, including

consideration of applicable industry standards, and with the requirements of 40 CFR part 112. 

The preamble to the 2002 revised SPCC rule lists examples of industry standards and

recommended practices that may be relevant to determining what constitutes good engineering

practice for various rule provisions. These industry standards are summarized in Tables 7-2 and 7-

3 (Section 7.2.6) and further discussed in Section 7.5. It is important to note, however, that the

industry standards may be more specific and more stringent than the requirements in the SPCC

rule. For example, EPA does not prescribe a particular schedule for testing. This is because “good

engineering practice” and relevant industry standards change over time. In addition, site-specific

conditions at an SPCC-regulated facility play a significant role in the development of appropriate

inspections and tests and the associated schedule for these activities. For example, the American

Petroleum Institute (API) Standard 653, “Tank Inspection, Repair, Alteration, and Reconstruction,”

includes a cap on the maximum interval between external and internal inspections, and provides

specific criteria for alternative inspection intervals based on the calculated corrosion rate. API 653

also provides an internal inspection interval when the corrosion rates are not known. Similarly, the

Steel Tank Institute (STI) Standard SP-001, 3rd Edition, provides specific intervals for external and

internal inspection of shop-built containers based on container size and configuration.

Integrity testing requirements for the SPCC rule may be replaced by environmentally

equivalent measures as allowed under §112.7(a)(2) and reviewed by the PE who certifies the Plan. 

Chapter 3 of this guidance provides a general discussion of environmental equivalence, while

Section 7.3 discusses its particular relevance to inspection, evaluation, and testing requirements.

7.2.2 Regularly Scheduled Integrity Testing 

and Frequent Visual Inspection of

Aboveground Bulk Storage

Containers

Section 112.8(c)(6) of the SPCC rule

specifies the inspection and testing

requirements for aboveground bulk storage

containers at onshore facilities that store, use, or

process petroleum oils and non-petroleum oils

(except animal fats and vegetable oils). Section

112.12(c)(6) contains the same requirements for

facilities with animal fats and vegetable oils. 

The provision sets two distinct

requirements for aboveground bulk storage

containers: 
Chapter 7: Inspection, Evaluation, and Testing

3

 According to STI SP-001, a field-erected aboveground storage tank (AST) is a welded metal AST erected on the site

where it will be used. For the purpose of the standard, ASTs are to be inspected as field-erected ASTs if they are

either: (a) an AST where the nameplate indicates that it is a field-erected AST, and limited to a maximum shell height

of 50 feet and maximum diameter of 30 feet; or (b) an AST without a nameplate that is more than 50,000 gallons and

has a maximum shell height of 50 feet and a maximum diameter of 30 feet. A shop-fabricated AST is a welded metal

AST fabricated in a manufacturing facility or an AST not otherwise identified as field-erected with a volume less than

or equal to 50,000 gallons. (STI SP-001, “Standard for the Inspection of Aboveground Storage Tanks,” July 2005)

4

 Hydrostatic testing is allowed per §112.8(c)(6); however, hydrotesting the container may actually result in container

failure during the test and should be performed in accordance with industry standards and using the appropriate test

media.

5

 Examples of material repairs include removal or replacement of the annular plate ring; replacement of the container

bottom; jacking of a container shell; installation of a 12-inch or larger nozzle in the shell; replacement of a door sheet

or tombstone in the shell, or other shell repair; or such repairs that might materially change the potential for oil to be

discharged from the container.

U.S. Environmental Protection Agency 7-7 Version 1.1, 2/3/06

(1) Regularly scheduled integrity testing; and

(2) Frequent visual inspection of the outside of the container. 

Regularly scheduled integrity testing. The integrity testing requirements are distinct from,

and are in addition to, the requirement to frequently inspect the outside of an aboveground storage

container (“visual inspection,” see below). The integrity testing requirement applies to large (fieldconstructed or field-erected) and small (shop-built)3

 aboveground containers; aboveground

containers on, partially in (partially buried, bunkered, or vaulted tanks), and off the ground wherever

located; and to aboveground containers storing any type of oil. 

Generally, visual inspection alone is not sufficient to test the integrity of the container as

stated in §§112.8(c)(6) and 112.12(c)(6); it must be combined with another testing technique and 

must include the container’s supports and foundations. Testing techniques include but are not

limited to:

• Hydrostatic testing;4

• Radiographic testing;

• Ultrasonic testing;

• Acoustic emissions testing; and

• Another system of non-destructive shell testing.

The SPCC rule requires that integrity testing of aboveground bulk storage containers be

performed on a regular schedule, as well as when material repairs5

 are made, because such repairs

might increase the potential for oil discharges. As stated in the preamble to the final 2002 rule,

“Testing on a ‘regular schedule’ means testing per industry standards or at a frequency sufficient to

prevent discharges. Whatever schedule the PE selects must be documented in the Plan” (67 FR

47119). The frequency of integrity tests should reflect the particular conditions of the container,

such as the age, service history, original construction specifications, prior inspection results, and

the existing condition of the container. It may also consider the degree of risk of a discharge to

navigable waters and adjoining shorelines. For example, where secondary containment is

inadequate (none provided, insufficient capacity or insufficiently impervious) and adequate
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secondary containment would be impracticable, §112.7(d) requires, among other measures,

periodic integrity testing of bulk storage containers. Given the higher potential of a discharge

reaching navigable waters or adjoining shorelines, however, the PE may decide, based on good

engineering practice, that more frequent integrity tests would be needed than for containers that

have adequate secondary containment. This approach of establishing an increased inspection

frequency for an aboveground container without secondary containment is used in the STI SP-001

standard.

Frequent visual inspection. There must be a frequent inspection of the outside of the

container for signs of deterioration, discharges, or accumulations of oil inside diked areas

(§112.8(c)(6)). This visual inspection is intended to be a routine walk-around. EPA expects that the

walk-around, which will occur on an ongoing routine basis, can generally be conducted by properly

trained facility personnel, as opposed to the more intensive but less frequent visual inspection

component of the non-destructive examination conducted by qualified testing/inspection personnel. 

Qualifications of these personnel are outlined in tank inspection standards, such as API 653 and

STI SP-001. A facility owner or operator can, for example, visually inspect the outside of bulk

storage containers on a daily, weekly, and/or monthly basis, and supplement this inspection with

integrity testing (see above) performed by a certified inspector, with the scope and frequency

determined by industry standards or according to a site-specific inspection program developed by

the PE. 

Oil-filled electrical, operating, and manufacturing devices or equipment are not considered

bulk storage containers; therefore, the integrity testing requirements in §§112.8(c)(6) and

112.12(c)(6) do not apply to those devices or equipment. However, EPA recommends that even

where not specifically required by the rule, it is good engineering practice to frequently inspect the

outside of oil-filled operational, electrical, and manufacturing equipment to determine whether it

could cause a discharge. For example, in a food manufacturing process, certain containers that

contain edible oil (such as reactors, fermentors, or mixing tanks) are considered oil-filled

manufacturing equipment and are not required to undergo integrity testing. Since a discharge as

described in §112.1(b) can occur from manufacturing, discharge discovery and thus visual

inspection procedures outlined in an SPCC Plan should include this equipment as well as other oilfilled equipment to prevent such a discharge as part of the facility’s countermeasures per

§112.7(a)(3)(iv) for discharge discovery. Although oil-filled equipment is not subject to the integrity

testing requirements under §112.8(c)(6) or §112.12(c)(6), EPA recommends routine inspections at

least visually to detect discharges as part of the facility’s countermeasures per §112.7(a)(3)(iv) for

discharge discovery.

7.2.3 Brittle Fracture Evaluation of Field-Constructed Aboveground Containers

Brittle fracture is a type of structural failure in larger field-constructed aboveground steel

tanks characterized by rapid crack formation that can cause sudden tank failure. This, along with

catastrophic failures such as those resulting from lightning strikes, seismic activity, or other such

events, can cause the entire contents of a container to be discharged to the environment. A review

of past failures due to brittle fracture shows that they typically occur (1) during an initial hydrotest,
Chapter 7: Inspection, Evaluation, and Testing

6

 McLaughlin, James E. 1991. “Preventing Brittle Fracture of Aboveground Storage Tanks – Basis for the Approach

Incorporated into API 653.” Case Studies: Sessions III and IV of the IIW Conference: Fitness for Purpose of Welded

Structures. October 23-24, 1991, Key Biscayne, Florida, USA. Cosponsored by the American Welding Society,

Welding Research Institute, Welding Institute of Canada, and International Institute of Welding. Published by the

American Welding Society, Miami, Florida. Pages 90-110.

U.S. Environmental Protection Agency 7-9 Version 1.1, 2/3/06

§112.7(i)

If a field-constructed aboveground container

undergoes a repair, alteration, reconstruction, or

a change in service that might affect the risk of a

discharge or failure due to brittle fracture or

other catastrophe, or has discharged oil or failed

due to brittle fracture failure or other

catastrophe, evaluate the container for risk of

discharge or failure due to brittle fracture or

other catastrophe, and as necessary, take

appropriate action.

Note: The above text is only a brief excerpt of the rule. 

Refer to 40 CFR part 112 for the full text of the SPCC rule.

(2) on the first filling in cold weather, (3) after a change to lower temperature service, or (4) after a

repair/modification. Storage tanks with a maximum shell thickness of one-half inch or less are not

generally considered at risk for brittle fracture.6

 Brittle fracture was most vividly illustrated by the

splitting and collapse of a 3.8 million gallon (120-foot diameter) tank in Floreffe, Pennsylvania,

which released approximately 750,000 gallons of oil into the Monongahela River in January 1988.

Section 112.7(i) of the SPCC rule

requires that field-constructed aboveground

containers that have undergone a repair or

change in service that might affect the risk of a

discharge due to brittle fracture or other

catastrophe, or have had a discharge associated

with brittle fracture or other catastrophe, be

evaluated to assess the risk of such a discharge.

Unless the original design shell thickness of the

tank is less than one-half inch (see API 653,

Section 5, and STI SP-001, Appendix B),

evidence of this evaluation should be

documented in the facility’s SPCC Plan.

In summary, industry standards discuss methods for assessing the risk of brittle fracture

failure for a field-erected aboveground container and for performing a brittle fracture evaluation

including API 653, “Tank Inspection, Repair, Alteration, and Reconstruction,” API RP 920

“Prevention of Brittle Fracture of Pressure Vessels,” and API RP 579, “Fitness-for-Service.” These

standards include a decision tree or flowchart for use by the owner/operator and PE in assessing

the risk of brittle fracture. STI SP-001 also addresses brittle fracture failures for smaller diameter

field-erected tanks with a wall thickness less than one-half inch.

7.2.4 Inspections of Piping

For onshore facilities, the SPCC rule specifies the following inspection and testing

requirements for piping. Buried piping at non-production facilities that has been installed or

replaced on or after August 16, 2002, must have a protective wrapping and coating and be

protected from corrosion cathodically or by other means, as per §§112.8(d)(1) and 112.12(d)(1). 

Any exposed line must be inspected for deterioration, and, if corrosion damage is found, additional

inspection or corrective action must be taken as needed.

Aboveground piping, valves, and appurtenances at non-production facilities must be

regularly inspected, as per §§112.8(d)(4) and 112.12(d)(4) and in accordance with industry
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standards. Buried piping must be integrity and leak tested at the time of installation, modification,

construction, relocation, or replacement.

Aboveground valves and piping associated with transfer operations at production facilities

must be inspected periodically and on a regular schedule, as per §112.9(d)(1) and in accordance

with industry standards. A program of flowline maintenance is required by §112.9(d)(3) and is

described in the following section of this document. 

For offshore facilities, §112.11(n) specifies that all piping appurtenant to the facility must be

protected from corrosion, such as with protective coatings or cathodic protection. Section 112.11(p)

requires that sub-marine piping appurtenant to the facility be maintained in good operating condition

at all times, and that such piping be inspected or tested for failures periodically and according to a

schedule.

In addition, if the owner/operator determines that these required measures are not

practicable, periodic integrity and leak testing of valves and piping must be conducted, as per

§112.7(d).

7.2.5 Flowline Maintenance

The objective of the SPCC flowline maintenance program requirement (§112.9(d)(3)) is to

help prevent oil discharges from production flowlines, e.g., the piping that extends from the

pump/well head to the production tank battery. Common causes of such discharges include

mechanical damage (i.e., impact, rupture) and corrosion. A flowline maintenance program aims to

manage the oil production operations in a manner that reduces the potential for a discharge. It

usually combines careful configuration, inspection, and ongoing maintenance of flowlines and

associated equipment to prevent and mitigate a potential discharge. EPA recommends that the

scope of a flowline maintenance program include periodic examinations, corrosion protection,

flowline replacement, and adequate records, as appropriate. EPA suggests that facility

owner/operators conduct inspections either according to industry standards or at a frequency

sufficient to prevent a discharge as described in §112.1(b). EPA is aware that API attempted to

develop an industry standard for flowline maintenance, but the standard has not been finalized. 

However, according to practices recommended by industry groups, such as API, a comprehensive

piping (flowline) program should include the following elements:

• Prevention measures that avert the discharge of fluids from primary containment;

• Detection measures that identify a discharge or potential for a discharge;

• Protection measures that minimize the impact of a discharge; and

• Remediation measures that mitigate discharge impacts by relying on limited or

expedited cleanup.

If a standard for flowline maintenance is developed, inspectors are encouraged to review this

standard. At present, the details below serve to guide the inspector in reviewing the scope of a

flowline maintenance program. If an impracticability determination under §112.7(d) is made for
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flowlines for secondary containment required by §112.7(c), EPA inspectors should extensively

review the adequacy of the flowline maintenance program along with the contingency plan (67 FR

47078).

A flowline maintenance program should ensure that flowlines, associated equipment, and

safety devices are kept in good condition and would operate as designed in the event of a

discharge. The PE certifying the Plan will typically establish the scope and frequency of

inspections, tests, and preventive maintenance based on industry standards, manufacturer’s

recommendations, and other such sources of good engineering practice. 

General Spill Prevention

The maintenance program should ensure that the equipment is configured and operated to

prevent discharges. Adequate supports and signage should be maintained to help prevent

mechanical damage to aboveground flowlines. Finally, the maintenance program should ensure

the proper operation of safety devices such as low-pressure sensors and safety shut-down valves

to mitigate the extent of a spill in the event of a flowline rupture.

Corrosion Protection

Internal corrosion may be prevented through the use of compatible materials (PVC,

fiberglass, coatings) or by the addition of corrosion inhibitors. External corrosion may be prevented

through the use of compatible materials, coatings/wrappings, and/or cathodic protection.

Periodic Examination

Visual observation of the flowlines by facility personnel should be included as part of any

flowline maintenance program and is of paramount importance for those facilities with flowlines that

have no secondary containment and rely on rapid spill detection to implement a contingency plan in

a timely manner. Facility personnel may “walk the flowlines” or perform aerial fly-overs, if they are

located aboveground, to detect any evidence of leakage. The visual inspection should cover the

piping, flange joints, valves, drip pans, and supports, and look for signs of corrosion, deterioration,

leakage, malfunction, and other problems that could lead to a discharge. The frequency of

inspections can vary according to their scope, the presence of secondary containment, and the

detection capability needed to ensure prompt implementation of a contingency plan (if no

containment is present), and may include daily, monthly, quarterly, or annual inspections. Regular

visual inspection may be supplemented by periodic integrity testing using non-destructive

evaluation methods, such as ultrasonic or other techniques to determine remaining wall thickness,

or hydrostatic testing at a pressure above normal operating pressure. This guidance document

refers to some relevant industry standards that describe methods used to test the integrity of piping,

such as API 570 and ASME B31.4.

Flowline Replacement and Recordkeeping
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The facility’s SPCC Plan should describe how the flowlines are configured, monitored, and

maintained to prevent discharges. The program is to be implemented in the field, and facility

personnel responsible for the maintenance of the equipment should be aware of the flowline

locations and be familiar with maintenance procedures, including replacement of damaged and/or

leaking flowlines. Records of inspections and tests kept under usual and customary business

practices should be prepared and made available for review, as required by the rule (§112.7(e)).

If an impracticability determination is made for flowlines, the flowline maintenance program 

should be shown to be adequate along with the contingency plan (67 FR 47078).

7.2.6 Role of Industry Standards and Recommended Practices in Meeting SPCC

Requirements 

The SPCC rule does not require the use of a specific industry standard for conducting

inspections, evaluations, and integrity testing of bulk storage containers and other equipment at the

facility. Rather, the rule provides flexibility in the facility owner/operator’s implementation of the

requirement, consistent with good engineering practice, as reviewed by the PE certifying the Plan.

To develop an appropriate inspection, evaluation, and testing program for an SPCCregulated facility, the PE must consider applicable industry standards (§112.3(d)(1)(iii)). If the

facility owner or operator uses a specific standard to comply with SPCC requirements, the standard

should be referenced in the Plan. Where no specific and general industry standard exists to inform

the determination of what constitutes good engineering practice for a particular inspection or testing

requirement, the PE should consider the manufacturer’s specifications and instructions for the

proper use and maintenance of the equipment, appurtenance, or container. If neither a specific and

objective industry standard nor a specific and objective manufacturer’s instruction apply, the PE

may also call upon his/her professional experience to develop site-specific inspection and testing

requirements for the facility or equipment as per §112.3(d)(1)(iv). The inspection and testing

program must be documented in the Plan (§112.7(e)). A checklist is provided as Table 7-5 at the

end of this chapter to assist inspectors in reviewing the relevant industry standards based on the

equipment observed at an SPCC-regulated facility. 

In the preamble to the 2002 SPCC rule, EPA provides examples of industry standards that

may constitute good engineering practice for assessing the integrity of different types of containers

for oil storage (67 FR 47120). Compliance with other industry standards and federal requirements

may also meet SPCC inspection, evaluation, and testing requirements. The U.S. Department of

Transportation (DOT) regulates containers used to transport hazardous materials, including certain

oil products. For example, mobile/portable containers that leave a facility are subject to the DOT

construction and continuing qualification and maintenance requirements (49 CFR part 178 and

49 CFR part 180). These DOT requirements may be used by the facility owner and operator and by

the certifying PE as references of good engineering practice for assessing the fitness for service of

mobile/portable containers. 
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Industry standards typically apply to containers built according to a specified design (API

653, for example, applies to tanks constructed in accordance with API 650 or API 12C); the

standards describe the scope, frequency, and methods for evaluating the suitability of the

containers for continued service. This assessment usually considers performance relative to

specified minimum criteria, such as ability to maintain pressure or remaining shell thickness. The

integrity testing is usually performed by inspectors licensed by the standard-setting organizations

(e.g., American Petroleum Institute, Steel Tank Institute).

Table 7-2 summarizes key elements of industry standards (and recommended practices)

commonly used for testing aboveground storage tanks (ASTs). Table 7-3 summarizes key

elements of standards (and recommended practices) used for testing piping and other equipment. 

Section 7.5 of this chapter provides a more detailed description of the standards listed in the tables. 

Other industry standards exist for specific equipment or purposes. Many of these are crossreferenced in API 653, including publications and standards from other organizations such as the

American Society for Testing and Materials (ASTM), the American Society for Non-Destructive

Testing (ASNT), and the American Society of Mechanical Engineers (ASME). Other organizations,

such as the National Fire Protection Association (NFPA), the National Association of Corrosion

Engineers (NACE), and the Underwriters Laboratory (UL), also provide critical information on all

container types and appurtenances. 
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Table 7-2. Summary of industry standards and recommended practices (RP) for ASTs.

API 653 STI SP-001 API RP 575 API RP 12R1

Equipment

covered

Field-fabricated,

welded, or riveted

ASTs operating at

atmospheric

pressure and built

according to API

650.

ASTs including

shop-fabricated

and field-erected

tanks and portable

containers and

containment

systems. 

Atmospheric and

low-pressure ASTs.

Atmospheric ASTs

employed in oil and

gas production,

treating, and

processing.

Scope Inspection and

design; fitness for

service; risk.

Determined by the

type of material

stored within the

tank and the

operating

temperature.

Inspection of tanks

by the owner/

operator and

certified inspectors.

Inspection and

repair of tanks.

Setting, connecting,

maintaining,

operating, inspecting,

and repairing tanks.

Inspection

interval

Certified

inspections:

Dependent on

tank’s service

history. Intervals

from 5 to 20 years.

Owner inspections:

monthly.

Certified

inspections:

Inspection intervals

and scope based

on tank size and

configuration. 

Owner inspections:

monthly, quarterly,

and yearly.

Same as API 653. Scheduled and

unscheduled internal

and external

inspections

conducted as per

Table 1 of the

Recommended

Practice. 

Inspection

performed by

Certified inspector,

tank owner.

Certified inspector,

either by API or

STI.

Same as API 653. Competent person or

qualified inspector, as

defined in

recommended

practice.

Applicable

section of this

document

Section 7.5.1 Section 7.5.2 Section 7.5.3 Section 7.5.4
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Table 7-3. Summary of industry standards and recommended practices (RP) for piping, valves,

and appurtenances.

API 570 API RP 574 API RP 1110 ASME B31.3 ASME B31.4

Equipment

covered

In-service

aboveground

and buried

metallic piping

Piping, tubing,

valves and

fittings in

petroleum

refineries and

chemical plants

Liquid

petroleum

pipelines

(pressure

testing)

Process piping

for oil,

petrochemical,

and chemical

processes

Pressure piping

for liquid

hydrocarbons

and other

liquids

Scope Inspection,

repair,

alteration, and

rerating

procedures

Inspection

practices

Procedures,

equipment, and

factors to

consider during

pressure testing

Minimum safety

requirements

for design,

examination,

and testing

Safe design,

construction,

inspection,

testing,

operation, and

maintenance

Inspection

interval

Based on

likelihood and

consequence

of failure (“riskbased”),

maximum of

10 years

Based on five

factors

– As part of

quality control

function

Not specified

Inspection

performed

by

Certified piping

inspector

Authorized

piping inspector

– Qualified

Inspector, as

defined in

standard

Qualified

Inspector, as

defined in

standard

Applicable

section of

this

document

Section 7.5.5 Section 7.5.6 Section 7.5.7 Section 7.5.10 Section 7.5.11

“-“ means that the standard provides no specific information for the element listed.
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7.3 Specific Circumstances

Integrity testing (a combination of visual inspection and another testing technique) is

required for all aboveground bulk storage containers located at onshore facilities (except production

facilities), unless the facility owner/operator implements an environmentally equivalent method (as

described in Chapter 3 and in Section 7.3.4, below) and documents the deviation in the SPCC Plan. 

Typically, visual inspection is combined with non-destructive shell testing in order to adequately

assess the container condition. EPA has indicated that visual inspection alone may provide

equivalent environmental protection in some cases, if certain conditions are met and if the

inspections are conducted at appropriate time intervals (see Section 7.3.4 of this document) in

accordance with good engineering practice. Therefore, if the Plan calls for visual inspection alone

in accordance with an industry standard, then the Plan must discuss the reason for the

nonconformance with §112.8(c)(6) or §112.12(c)(6) and comply with the environmental equivalence

provision in §112.7(a)(2). 

Some facilities may not have performed integrity testing of their tanks. In this case,

developing an appropriate integrity testing program will require assessing baseline conditions for

these tanks. This “baseline” will provide information on the condition of the tank shell, and the rate

of change in condition due to corrosion or other factors, in order to establish a regular inspection

schedule. Section 112.7 requires that if any facilities, procedures, methods, or equipment are not

yet fully operational, the SPCC Plan must explain the details of installation and operational start-up;

this applies to the inspection and testing programs required by the rule. For all types of facilities,

the PE is responsible for making the final determination on the scope and frequency of testing when

certifying that an SPCC Plan is consistent with good engineering practice and is appropriate for the

facility.

This section provides guidance on integrity testing for the following circumstances the

inspector may encounter at an SPCC-regulated facility: 

• Aboveground bulk storage containers for which the baseline condition is known;

• Aboveground bulk storage containers for which the baseline condition is not known;

• Deviation from integrity testing requirements based on environmental equivalence;

and 

• Environmental equivalence scenarios for shop-built containers.

This is not a comprehensive list of circumstances. For these and other cases, the PE may

recommend alternative approaches. 

7.3.1 Aboveground Bulk Storage Container for Which the Baseline Condition Is Known

In the case of tanks for which the baseline condition is known (e.g., the shell thickness and

corrosion rates are known), the inspection and testing schedule should typically occur at a scope

and frequency based on industry standards (or the equivalent developed by a PE for the
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site-specific SPCC Plan) per §112.8(c)(6) or §112.12(c)(6). There is an advantage to knowing the

baseline condition of a tank, particularly if the remaining wall thickness and the corrosion rate are 

known. Only when the baseline is known can an inspection and testing program be established on

a regular schedule. The inspection interval should be identified consistent with specific intervals

per industry standards or should be based on the corrosion rate and expected remaining life of the

container. This inspection interval must be documented in the Plan in accordance with §§112.3(d),

112.7(e), 112.8(c)(6), and 112.12(c)(6). API 653 is an example of an industry standard that directs

the owner/operator to consider the remaining wall thickness and the established corrosion rate to

determine an inspection interval for external and internal inspections and testing.

Inspection and testing standards may require visual inspection of both the exterior and

interior of the container, and the use of another method of non-destructive evaluation depending on

the type and configuration of the container. Inspectors should note that the scope and frequency of

inspections and tests for shop-built tanks and field-erected tanks at an SPCC-regulated facility may

vary due to the age of the tank, the configuration, and the applicable industry standard used as the

reference. For example, the PE may choose to develop an inspection and testing program for the

facility’s shop-built tanks in accordance with STI SP-001, and may elect to develop the program for

the facility’s field-erected tanks in accordance with API 653. As an alternative example, the PE may

elect to develop a program in accordance with STI SP-001 for the facility’s shop-built tanks and for

its field-erected tanks of a certain capacity and size. For containers at facilities storing animal fats

and vegetable oils, the PE may elect to develop a hybrid testing program building upon elements of

both API 653 and STI SP-001 or only one of the standards.

7.3.2 Aboveground Bulk Storage Container for Which the Baseline Condition Is Not Known

For a facility to comply with the requirement for integrity testing of containers on a regular

schedule (§§112.8(c)(6) and 112.12(c)(6)), a baseline condition for each container is necessary to

establish inspection intervals. The PE must attest that procedures for required inspections and

testing have been established (§112.3(d)(1)(iv)). However, for shop-built and field-erected

containers for which construction history and wall and/or bottom plate thickness baselines are not

known, a regular integrity testing program cannot be established. Instead, the PE must describe in

the SPCC Plan an interim schedule (in accordance with the introductory paragraph of §112.7) that

allows the facility to gather the baseline data to establish a regular schedule of integrity testing in

accordance with §§112.8(c)(6) and 112.12(c)(6). It should be noted that the introductory paragraph

of §112.7 of the SPCC rule allows for the Plan to describe procedures, methods, or equipment that

are not yet operational, and include a discussion of the details. 

When a container has no prior inspection history or baseline information, the implementation

of the baseline inspection program is important in order to assess the container’s “suitability for

continued service.” Both API 653 and STI SP-001 include details on how to assess a container’s

suitability for continued service. In some cases, where baseline information is not known, the

testing program may include two data collection periods to establish a baseline of shell thickness

and corrosion rate in order to develop the next inspection interval (or “regular” schedule), or an
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Scenario:

Facility has three aboveground atmospheric, mild-carbon steel tanks of different ages and conditions. Some have prior

inspection histories; others have never been inspected. Although there is limited history available for tank construction, 

the tanks are presumed to be field-erected tanks and to each have 100,000 gallons in storage capacity. What is an 

appropriate inspection schedule for these tanks? API 653 is the referenced inspection standard.

Additional information:

API 653 recommends a formal visual inspection every 5 years or 1⁄4 of corrosion rate, whichever is less, and a

non-destructive shell test (UT) within 15 years or 1⁄2 of corrosion rate, whichever is less. If corrosion rates are not known, the

maximum interval is 5 years. An internal inspection of the bottom of the tank is to be done based on corrosion rates. If the

corrosion rate is known, the interval cannot exceed 20 years. If the corrosion rate is unknown, the interval cannot exceed 10

years.

Determination of inspection schedule:

Construction Date Last Inspection Next Inspection (External) Next Inspection (Internal)

Tank 1 unknown none formal visual and shell test

(external) within first five-year

Plan review cycle 

formal (internal) bottom

inspection within first five-year

Plan review cycle

Tank 2 2001 none 2006 for both visual inspection

and non-destructive shell test 

2011 (i.e., not to exceed 10

years when corrosion rate of

tank bottom is not known)

Tank 3 1984 1994 1999 & 2004 formal visual

2009 non-destructive shell test 

both intervals may be

decreased based on calculated

corrosion rates from the 1994

inspection.

2014 or less based on

calculated corrosion rates

from the 1994 inspection

Note: Actual inspection schedule is ultimately an engineering determination made by the PE, based on industry standards,

and is certified in the Plan.

Figure 7-1. Example baselining plan to determine the integrity testing and inspection schedule.

alternative inspection schedule established by the PE in accordance with good engineering

practice.

 When no baseline information is available for a container, the PE may schedule visual

inspection and another testing technique within the first five-year review cycle of the SPCC Plan in

order to establish a regular integrity testing schedule based on current container conditions. In this

example, the review cycle would begin on the revised rule implementation deadline of August 18,

2006, so the first (baseline) container inspection and integrity test would be completed by August

18, 2011. In the case of a tank that is newly built, construction data (e.g., as-built drawings and/or

manufacturers cut-sheets) may typically be used as an initial datum point to establish wall

thicknesses and would be included in the established procedures for inspection and testing. 

The implementation, particularly in establishing inspection priorities, of the testing program

should be in accordance with good engineering practice and include consideration of industry

standards (§112.3(d)), as discussed in this document. For instance, special consideration may be

discussed in the Plan for containers for which the age and existing condition is not known (no

baseline information exists). For example, older tanks or tanks in more demanding service may be

identified as high-priority tanks for inspection, versus tanks for which the baseline information is
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known.

An example baselining plan is presented in Figure 7-1. The example presents a simple

scenario and is only provided as an illustration of some of the factors that may be considered when

determining a schedule to initiate inspections of bulk storage containers.

7.3.3 Deviation from Integrity Testing Requirements Based on Environmental Equivalence

Chapter 3 of this document describes the flexibility provided in the SPCC rule through the

use of environmental equivalent measures, per §112.7(a)(2). The discussion below describes

examples of measures that facility owners and operators can use to deviate from inspection and

testing requirements, while providing equivalent environmental protection.

The SPCC rule provides flexibility regarding integrity testing requirements of bulk storage

containers, as long as the alternatives provide equivalent environmental protection per

§112.7(a)(2). Measures that may be considered environmentally equivalent to integrity testing for

shop-built containers are those that effectively minimize the risk of container failure and that allow

detection of leaks before they become significant. Alternative measures to integrity testing requiring

the combination of internal, external, and non-destructive evaluation may, for example, prevent

container failure by minimizing the container’s exposure to conditions that promote corrosion (e.g.,

direct contact with soil), or they may enable facility personnel to detect leaks and other container

integrity problems early so they can be addressed before more severe integrity failure occurs. The

ability to use an environmentally equivalent alternative to integrity testing will often hinge on the

degree of protection provided by the tank configuration and secondary containment. EPA believes

that larger tanks (including larger shop-built tanks) may require inspection by a professional

inspector, in addition to the visual inspection by the tank owner/operator during the tank’s life. EPA

defers to applicable industry standards and to the certifying PE as to the type and scope of

inspections required in each case. However, the inspector should look for a clear rationale for the

development of the inspection and testing program, paying close attention to the referenced

industry standard.

EPA believes that environmental equivalence may be appropriate in other situations. For

example, facilities that store edible oils as part of a food manufacturing process may adhere to very

strict housekeeping and maintenance procedures that involve ongoing visual inspection and routine

cleaning of the exterior and interior of the containers (which are elevated so all sides are visible or

sit on a barrier that allows for rapid detect of a leak) by facility personnel. As part of these routine

inspections, small leaks can be detected before they can cause a discharge as defined in

§112.1(b). The PE certifying the facility’s SPCC Plan may determine, upon considering applicable

food-related regulations, industry standards, and site-specific conditions, that such inspections and

housekeeping procedures provide environmental protection equivalent to performing an integrity

test on these containers.

As with other requirements eligible for environmental equivalence provision, the measures

implemented as alternatives to integrity testing required under §112.8(c)(6) or §112.12(c)(6) may
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Figure 7-2. Drums elevated

on a storage rack. Drums

are also subject to secondary

containment requirements for

bulk storage in §112.8(c)(2).

not be measures already required to meet another part of the SPCC rule. A facility may not rely

solely on measures that are required by other sections of the rule (e.g., secondary containment) to

provide “equivalent environmental protection.” Otherwise, the deviation provision would allow for

approaches that provide a lesser degree of protection overall. However, for certain tank sizes and

configurations of secondary containment, continuous release detection and frequent visual

inspection by the owner/operator may be the sole inspection requirement, provided that the

rationale is discussed in the Plan (STI SP-001). This rationale should include a discussion of good

engineering practice referencing appropriate industry standards.

7.3.4 Environmental Equivalence Scenarios for Shop-Built Containers

Scenario 1: Elevated Drums. As EPA has indicated in the 2002

preamble to the revised SPCC rule, certain smaller shop-built containers

(e.g., 55-gallon drums) for which internal corrosion poses minimal risk of

failure, which are inspected at least monthly, and for which all sides are

visible (i.e., the container has no contact with the ground), visual

inspection alone might be considered to provide equivalent environmental

protection, subject to good engineering practice (67 FR 47120). In fact,

certain industry standards also reference these conditions as good

engineering practice. For example, elevating storage drums on an

appropriately designed storage rack (as shown in Figure 7-2) such that all

sides are visible allows the effective visual inspection of containers for

early signs of deterioration and leakage, and is therefore considered

environmentally equivalent to the requirement for integrity testing beyond

visual inspection for these smaller bulk storage containers. Note that the

drums, even if elevated, remain subject to the bulk storage secondary containment requirements in

§112.8(c)(2) or §112.12(c)(2). Determination of environmental equivalence is subject to good

engineering practice, including consideration of industry standards, as certified by the PE in

accordance with §112.3(d).

Scenario 2: Single-Use Bulk Storage Containers. For containers that are single-use and

for dispensing only (i.e., the container is not refilled), EPA recognizes that industry standards

typically require only visual examination by the owner/operator. Since these containers are

single-use, internal or comparative integrity testing for corrosion is generally not appropriate

because the containers are not maintained on site for a long enough period of time that degradation

and deterioration of the container’s integrity might occur. Single-use containers (e.g., 55-gallon

drums) typically are returned to the vendor, recycled, or disposed of in accordance with applicable

regulations. Good engineering practices for single-use containers should be identified in the Plan,

and these practices should ensure that the conditions of storage or use of a container do not

subject it to potential corrosion or other conditions that may compromise its integrity in its single-use

lifetime. Typically, good engineering practice recommends that these containers be elevated

(usually on pallets or other support structures) to minimize bottom corrosion and to facilitate a visual

inspection of all sides of the container to detect any leaks during the regular owner/operator

inspections outlined in the Plan. Determination of environmental equivalence is subject to good
Chapter 7: Inspection, Evaluation, and Testing

7

 For more information, refer to EPA’s letter to the Petroleum Marketers Association of America, available on EPA’s

Web site at http://www.epa.gov/oilspill/pdfs/PMAA_letter.pdf.

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Figure 7-3. Shop-built containers elevated

on saddles.

engineering practice, including consideration of industry standards, as certified by the PE in

accordance with §112.3(d).

When the container is fully emptied and meets the definition of a permanently closed

container (§112.2) (including labeling), it is not subject to the SPCC requirements, including the

integrity testing requirements. In this case, the capacity of the container does not count toward the

facility threshold capacity. If the container is refilled on site, however, it is not considered a

single-use container, and is therefore subject to the integrity testing requirements of the rule.

Scenario 3: Elevated shop-built containers. For

certain shop-built containers with a shell capacity of 30,000

gallons or under, EPA considers that visual inspection

provides equivalent environmental protection when

accompanied by certain additional actions to ensure that the

containers are not in contact with the soil. These actions

include elevating the container in a manner that decreases

corrosion potential and makes all sides of the container,

including the bottom, visible during inspection. Examples of

adequate measures include elevating shop-built containers

on properly designed tank saddles as illustrated in Figure 7-3

and described in EPA’s letter to PMAA.7

 Determination of environmental equivalence is subject to

good engineering practice, including consideration of industry standards, as certified by the PE in

accordance with §112.3(d).

Scenario 4: Shop-built containers placed on a liner. For certain shop-built containers

with a shell capacity of 30,000 gallons or under, visual inspection, plus certain additional actions to

ensure the containment and detection of leaks, is also considered by EPA to provide equivalent

environmental protection. Actions may include placing the containers onto a barrier between the

container and the ground, designed and operated in a way that ensures that any leaks are

immediately detected. For example, placing a shop-built container on an adequately designed,

maintained, and inspected synthetic liner would generally provide equivalent environmental

protection. Determination of environmental equivalence is subject to good engineering practice,

including consideration of industry standards, as certified by the PE in accordance with §112.3(d).

Other Situations. Although the scenarios discussed above primarily address shop-built

tanks, environmental equivalence may be used for other types of bulk storage containers, subject to

good engineering practice. In any case where the owner or operator of a facility uses an alternative

means of meeting the integrity testing requirement of §112.8(c)(6) or §112.12(c)(6), the SPCC Plan

must provide the reason for the deviation, describe the alternative approach, and explain how it

achieves equivalent environmental protection (§112.7(a)(2)), while considering good engineering

practice and industry standards. The description of the alternative approach should address how
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the approach complies or deviates from industry inspection standards and how it will be

implemented in the field. For example, if the alternative approach involves the visual inspection of

the containers, the SPCC Plan should describe the key elements of this inspection, including the

inspection frequency and scope, the training and/or qualifications of individuals conducting the

inspections, and the records used to document the inspection. If the alternative measure relies on

engineered systems to mitigate corrosion (e.g., coatings, cathodic protection) or to facilitate early

detection of small leaks, the SPCC Plan should describe how such systems are maintained and

monitored to ensure their effectiveness. For instance, where the alternative measure relies on the

presence of a liner, the Plan should discuss how the liner is adequately designed, maintained, and

inspected. This discussion may consider such factors as life expectancy stated by the

manufacturer (from cut-sheets), as-built specifications, and inspection and maintenance

procedures.

As discussed above, the environmental equivalence provision applies to the inspection and

appropriate integrity testing of bulk storage containers at §§112.8(c)(6), 112.9(c)(3), and

112.12(c)(6). PEs have the flexibility to offer environmental equivalent integrity testing options for

all classes of tanks, including shop-built tanks above 30,000 gallon capacity and field-erected tanks,

if the rationale is provided referencing appropriate industry standards. 

7.4 Documentation Requirements and Role of the EPA Inspector

The facility SPCC Plan must describe the scope and schedule of examinations to be

performed on bulk storage containers (as required in §§112.3(d)(1)(iv), 112.7(e), 112.8(c)(6),

112.9(c)(3), and 112.12(c)(6)), and should reference an applicable industry inspection standard or

describe an equivalent program developed by the PE, in accordance with good engineering

practice. If a PE specifies a hybrid inspection and testing program, then the EPA inspector should

verify that the testing program covers minimum elements for the inspections, the frequency of

inspections, and their scope (e.g., wall thickness, footings, tank supports). See Section 7.5 for a list

of suggested minimum standards.

A hybrid testing program may be appropriate for a facility where an industry inspection

standard does not yet contain enough specificity for a particular facility’s universe of tanks and/or

configuration, or while modifications to an industry inspection standard are under consideration. For

example, a tank user may have made a request to the industry standard-setting organizations

recommending a change or modification to a standard. Both API and STI have mechanisms to

allow tank users (and the regulatory community) to request changes to their respective inspection

standards. In this case, the modification to a standard may be proposed, but not yet accepted by

the standard-setting organization. In the meantime, the facility is still subject to the SPCC

requirements to develop an inspection and testing program. In this scenario, a hybrid inspection

and testing program may be appropriate. When reviewing the scope and schedule of a hybrid

program, the inspector should review whether an industry inspection standard and appropriate good

engineering practices were used in the development of the hybrid program. 
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The facility must maintain records of all visual inspections and integrity testing, as required

by the SPCC rule in §§112.7(e), 112.8(c)(6), 112.9(c)(3), and 112.12(c)(6). Records do not need to

be specifically created for this purpose, and may follow the format of records kept under usual and

customary business practices. These records should include the frequent inspections performed by

facility personnel. Also, industry standards generally provide example guidelines for formal tank

inspections, as well as sample checklists. The EPA inspector should review the inspection

checklists used by the facility to verify that they cover at least the minimum elements and are in

accordance with the PE-certified inspection and testing program. The tank inspection checklist

from Appendix F of 40 CFR part 112, reproduced as Table 7-6 at the end of this chapter, provides

an example of the type of information that may be included on an owner/operator-performed

inspection checklist.

The EPA inspector should review records of frequent visual inspections by facility personnel

as well as regular integrity testing of the container. Comparison records maintained at the facility

will aid in determining a container’s suitability for continued service. Both API 653 and STI SP-001

contain details on determining a container’s suitability for continued service. Though §112.7(e)

requires retention of all records for a period of three years, industry standards usually recommend 

retention of certified inspection and non-destructive examination reports for the life of the container.

In cases where the SPCC Plan has not identified a regularly scheduled inspection and

testing program, the inspector should request information on the anticipated schedule (e.g., when a

baseline has not been established). If the facility has not performed any integrity testing of bulk

storage containers so far, the EPA inspector should verify that the SPCC Plan describes: (1) the

strategy for implementing an inspection and testing program and collecting baseline conditions

within ten years of the installation date of the tank, or during the first five-year Plan cycle (or another

schedule as identified and certified by a PE); and (2) the ongoing testing program that will be

established once the baseline information has been collected. When the inspection program

establishes inspection priorities for multiple containers, the inspector should consider the rationale

for these priorities as described in the SPCC Plan and verify implementation. 

The EPA inspector should review records of regular and periodic inspections and tests of

buried and aboveground piping, valves, and appurtenances. Such inspections may be visual or

conducted by other means. 

The inspector reviewing a maintenance program, such as the flowline maintenance program

required under §112.9(d)(3) for oil production facilities, should verify that the Plan describes how

the flowlines are configured, monitored, and maintained to prevent discharges. The inspector

should also verify that the program is implemented in the field; for example, by verifying that facility

personnel responsible for the maintenance of the equipment are aware of the flowline locations and

are familiar with maintenance procedures, including replacement of damaged and/or leaking

flowlines.
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If an impracticability determination is made for secondary containment of flowlines, the EPA

inspector should extensively review the adequacy of the flowline maintenance program along with

the contingency plan (67 FR 47078).

In summary, the EPA inspector should verify that the owner or operator has inspection

reports that document the implementation of the testing, evaluation, or inspection criteria set forth in

the Plan. He/she may also verify whether the recommended actions that affect the potential for a

discharge have been taken to ensure the integrity of the container/piping until the next scheduled

inspection or replacement of the container/piping. When an inspection procedure is outlined in the

Plan that does not meet the requirement of §§112.8(c)(6) and 112.12(c)(6) (e.g., a combination of

visual inspection and another testing technique), the inspector should verify that the Plan includes a

discussion of an environmentally equivalent measure in accordance with §112.7(a)(2). 

Implementation of the SPCC Plan as certified by the PE is the responsibility of the facility

owner/operator (§112.3(d)(2)).

By certifying an SPCC Plan, the PE attests that the Plan has been prepared in accordance

with good engineering practice, that it meets the requirements of 40 CFR part 112, and that it is

adequate for the facility. Thus, if testing, evaluation, or inspection procedures have been reviewed

by the certifying PE and are properly documented, they should generally be considered acceptable

by the EPA inspector. However, if testing, evaluation, or inspection procedures do not meet the

standards of common sense, appear to be at odds with recognized industry standards, do not meet

the overall objective of oil spill response/prevention, or appear to be inadequate for the facility,

appropriate follow-up action may be warranted. In this case, the EPA inspector should clearly

document any concerns to assist review and follow-up by the Regional Administrator. The EPA

inspector may also request additional information from the facility owner or operator regarding the

testing, evaluation, or inspection procedures provided in the Plan.

7.5 Summary of Industry Standards and Regulations

This section provides an overview and description of the scope and key elements of

pertinent industry inspection standards, including references to relevant sections of the standards. 

Additionally, the section discusses the minimum elements for a so-called “hybrid” inspection

program for unique circumstances for which industry inspections standards do not contain enough

specificity for a given facility’s tank universe and configuration, or for which the PE chooses to

deviate from the industry standards based on professional judgement. When words such as “must,”

“required,” and “necessary,” or other such terms are used in this section, they are used in

describing what the various standards state and are not considered requirements imposed by EPA,

unless otherwise stated in the regulations. 

Industry standards are technical guidelines created by experts in a particular industry for use

throughout that industry. These guidelines assist in establishing common levels of safety and

common practices for manufacture, maintenance, and repair. Created by standard-setting

organizations using a consensus process, the standards establish the minimum accepted industry

practice. The SPCC rule (§112.3(d)(1)(iii)) requires that the Plan be prepared in accordance with
Chapter 7: Inspection, Evaluation, and Testing

8

 API Standard 653, “Tank Inspection, Repair, Alteration, and Reconstruction,” Third Edition, Addendum 1, American

Petroleum Institute, September 2003.

9

 See Section 1.1.3 of API Standard 653.

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good engineering practices, including the consideration of applicable industry standards. Use of a

particular standard is voluntary. If a standard (or parts of a standard) is incorporated into a facility’s

SPCC Plan, then adherence to that standard is mandatory for implementation of the Plan.

Although these guidelines are often grouped together under the term “standards,” several

other terms are used to differentiate among the types of guidelines:

• Standard (or code)—set of instructions or guidelines. Use of a particular standard

is voluntary. Some groups draw a distinction between a standard and a code. The

American Society of Mechanical Engineers (ASME), for example, stipulates that a

code is a standard that “has been adopted by one or more governmental bodies and

has the force of law...”

• Recommended practice—advisory document often useful for a particular situation.

• Specification—may be one element of a code or standard or may be used

interchangeably with these terms.

7.5.1 API Standard 653 – Tank Inspection, Repair, Alteration, and Reconstruction

API Standard 653 – Tank Inspection, Repair, Alteration, and Reconstruction (API 653)8

provides the minimum requirements for maintaining the integrity of carbon and alloy steel tanks built

to API Standard 650 (Welded Steel Tanks for Oil Storage) and its predecessor, API 12C (Welded

Oil Storage Tanks). API 653 may also be used for any steel tank constructed to a tank

specification.9

API 653 covers the maintenance, inspection, repair, alteration, relocation, and

reconstruction of welded or riveted, non-refrigerated, atmospheric pressure, aboveground,

field-fabricated, vertical storage tanks after they have been placed in service. The standard limits

its scope to the tank foundation, bottom, shell, structure, roof, attached appurtenances, and nozzles

to the face of the first flange, first threaded joint, or first welding-end connection. The standard is

intended for use by those facilities that utilize engineering and inspection personnel technically

trained and experienced in tank design, fabrication, repair, construction, and inspection. Section 1

of the standard introduces the standard and details its scope. Sections 2 and 3 of the standard list

the works cited and definitions used in the standard, respectively.

The standard requires that a tank evaluation be conducted when tank inspection results

reveal a change in a tank from its original physical condition. Sections 4 and 5 of the standard

describe procedures for evaluating an existing tank’s suitability for continued operation or a change

of service; for making decisions about repairs or alterations; or when considering dismantling,

relocating, or reconstructing an existing tank. Section 4 of the standard details the procedures to
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10 See Section 1.1.3 of API 653.

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follow in evaluating the roof, shell, bottom, and foundation of the tank. Section 5 of the standard

provides a decision tree to evaluate a tank’s risk of brittle fracture.

Section 6 focuses on factors to consider when establishing inspection intervals and covers

detailed procedures for performing external and internal tank integrity inspections. Inspection

intervals are largely dependent upon a tank’s service history. The standard establishes time

intervals for when routine in-service inspections of the tank exterior are to be conducted by the

owner/operator and when external visual inspections are to be conducted by an authorized

inspector. External ultrasonic thickness (UT) inspections may also be conducted periodically to

measure the thickness of the shell and are used to determine the rate of corrosion. Time intervals

for external UT inspections are also provided and are based on whether or not the corrosion rate is

known. 

Internal inspections (Section 6.4 of the standard) primarily focus on measuring the thickness

of the tank bottom and assessing its integrity. Measured or anticipated corrosion rates of the tank

bottom can be used to establish internal inspection intervals; however, the inspection interval

cannot exceed 20 years using these criteria. Alternatively, risk-based inspection (RBI) procedures,

which focus attention specifically on the equipment and associated deterioration mechanisms

presenting the most risk to the facility (Section 6.4.3 of the standard), can be used to establish

internal inspection intervals; an RBI may increase or decrease the 20-year inspection interval. API

653 states that an RBI assessment shall be reviewed and approved by an authorized tank inspector

and a tank design/corrosion engineer. If a facility chooses to use RBI in the development of a tank

integrity testing program, the EPA inspector should verify that these parties conducted the initial

RBI assessment.

An external inspection (Section 6.5 of the standard) can be used in place of an internal

inspection to determine the bottom plate thickness in cases where the external tank bottom is

accessible due to construction, size, or other aspects. If chosen, this option should be documented

and included as part of the tank’s permanent record. Owners/operators should maintain records

that detail construction, inspection history, and repair/alteration history for the tank (Section 6.8 of

the standard). Section 6.9 of the standard stipulates that detailed reports should be filed for every

inspection performed. 

Sections 7 through 11 of API 653 do not address integrity testing, but instead focus on the

repair, alteration, and reconstruction of tanks. Section 12 provides specific criteria for examining

and testing repairs made to tanks. Section 13 addresses the specific requirements for recording

any evaluations, repairs, alterations, or reconstructions that have been performed on a tank in

accordance with this standard. Appendix A to API 653 provides background information on

previously published editions of API welded steel storage tank standards. Appendix B details the

approaches that are used to monitor and evaluate the settlement of a tank bottom.10 Appendix C

provides sample checklists that the owner/operator can use when developing inspection intervals

and specific procedures for internal and external inspections of both in-service and out-of-service
Chapter 7: Inspection, Evaluation, and Testing

11 STI Standard SP-001, “Standard for the Inspection of Aboveground Storage Tanks,” 3rd Edition, Steel Tank

Institute, July 2005.

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tanks. The requirements for authorized inspector certification are the focus of Appendix D. 

Certification of authorized tank inspectors, which is valid for three years from the date of issue,

requires the successful completion of an examination, as well as a combination of education and

experience. Technical inquiries related to the standard are the focus of Appendix E. Appendix F

summarizes the non-destructive examination (NDE) requirements for reconstructed and repaired

tanks. Technical inquiries regarding the use of the standard can be made through API’s Web site

(www.api.org). Selected responses to technical inquiries are provided in the Technical Inquiry

appendices of the standard.

7.5.2 STI Standard SP-001 – Standard for the Inspection of Aboveground Storage Tanks

STI Standard SP-001 – Standard for the Inspection of Aboveground Storage Tanks

(SP-001)11 provides the minimum inspection requirements and evaluation criteria required to

determine the suitability for continued service of aboveground storage tanks until the next

scheduled inspection. Only aboveground tanks included in the scope of this standard are

applicable for inspection per this standard. Other standards, recommended practices, and other

equivalent engineering and best practices exist that provide alternative inspection requirements for

tanks defined within the scope of this standard and for tanks outside the scope of this standard. 

For example, API Standard 653, “Tank Inspection, Repair, Alteration, and Reconstruction,” provides

additional information pertaining to tanks built to API 650 and API 12C. API 12R1, “Recommended

Practice for Setting, Maintenance, Inspection, Operation, and Repair of Tanks in Production

Service,” pertains to tanks employed in production service or other similar service.

SP-001 applies to the inspection of aboveground storage tanks, including shop-fabricated

tanks, field-erected tanks, and portable containers, as defined in this standard, as well as the

containment systems. The inspection and testing requirements for field-erected tanks are covered

separately in Appendix B of the standard. Specifically, the standard applies to ASTs storing stable,

flammable, and combustible liquids at atmospheric pressure with a specific gravity less than

approximately 1.0 and those storing liquids with operating temperatures between ambient

temperature and 200 degrees Fahrenheit (93.3/C). At a minimum, the following tank components

shall be inspected (as applicable): tank, supports, anchors, foundation, gauges and alarms,

insulation, appurtenances, vents, release prevention barriers, and spill control systems.

Section 3 addresses safety considerations, and Section 4 addresses AST inspector

qualifications. 

Section 5 of the standard addresses the criteria, including AST type, size, type of

installation, corrosion rate, and previous inspection history, if any, that should be used to develop a

schedule of inspections for each AST. Table 5.5 (Table of Inspection Schedules) places tanks into

one of three categories and establishes different requirements regarding the type and frequency of

periodic inspection by tank owner/operators as well as formal external and internal inspections by a
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certified inspector. The factors used for categorizing tanks include tank size, whether or not the

tank is in contact with the ground, the presence or absence of secondary containment (or spill

control), and the presence or absence of a continuous release detection method (CRDM).

Section 6 provides guidelines for the periodic inspections conducted by the owner or his/her

designee. The owner’s inspector is to complete an AST Record for each AST or tank site, as well

as a Monthly Inspection Checklist and an Annual Inspection Checklist. Monthly inspections should

monitor water accumulation to prevent Microbial Influenced Corrosion (MIC), and action should be

taken if MIC is found. Additional requirements for field-erected tanks are in Appendix B of SP-001.

Section 7 of SP-001 contains the minimum inspection requirements for formal external

inspections, which are to be performed by a certified inspector. Inspections should cover the AST

foundations, supports, secondary containment, drain valves, ancillary equipment, piping, vents,

gauges, grounding system (if any), stairways, and coatings on the AST. Original shell thickness

should be determined using one of several suggested methods. Ultrasonic Thickness Testing

(UTT) readings are to be taken at different locations of the AST depending upon whether the AST is

horizontal, vertical, rectangular, and/or insulated. The final report should include field data,

measurements, pictures, drawings, tables, and an inspection summary, and should specify the next

scheduled inspection.

Section 8 of the standard details the minimum inspection requirements for formal internal

inspections, which are to be performed by a certified inspector. A formal internal inspection

includes the requirements of an external inspection with some additional requirements for specific

situations that are outlined in the standard. Double-wall tanks and secondary containment tanks

may be inspected by checking the interstice for liquid or by other equivalent methods. For elevated

ASTs where all external surfaces are accessible, the internal inspection may be conducted by

examining the tank exterior using such methods as Ultrasonic Thickness Scans (UTS). For all

other situations, entry into the interior of the AST is necessary. Internal inspection guidelines are

detailed separately for horizontal ASTs and for vertical and rectangular ASTs in Sections 8.2 and

8.3, respectively. Additional requirements for field-erected tanks are in Appendix B. The final

report should contain elements similar to reports prepared for external inspections.

Section 9 addresses leak testing methods. For shop-fabricated ASTs, the standard

references the Steel Tank Institute Recommended Practice R912, “Installation Instructions for Shop

Fabricated Stationary Aboveground Storage Tanks for Flammable, Combustible Liquids.” The

standard also references DOT regulations for portable containers:

• 49 CFR part 173.28, Reuse, reconditioning, and remanufacturing of packagings,

mainly for drums;

• 49 CFR part 178.803, Testing and certification of intermediate bulk containers

(IBCs); and 

• 49 CFR part 180.605, or equivalent, for portable container testing and recertification.
Chapter 7: Inspection, Evaluation, and Testing

12 API RP 575, “Inspection of Atmospheric and Low-Pressure Storage Tanks,” 1st ed., American Petroleum Institute,

November 1995.

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Section 10 addresses the suitability for continued service based on the results of formal

internal and/or external inspections. For ASTs that show signs of damage caused by MIC, the

criteria for assessing their suitability for continued service differ based on the category they fall into

(as per Section 5 of SP-001). Categories refer to the level of reduction of the shell thickness. For

other tank damage, an engineer experienced in AST design or a tank manufacturer should

determine if an inspection is required for any AST that was exposed to fire, natural disaster,

excessive settlement, overpressure, or damage from cracking. 

Section 11 of the standard details recordkeeping requirements. Appendix A presents

supplemental technical information including terms commonly associated with ASTs, and Appendix

B presents information for the inspection of field-erected ASTs. 

For more information on SP-001, please visit the Steel Tank Institute Web site,

http://www.steeltank.com.

7.5.3 API Recommended Practice 575 – Inspection of Atmospheric and Low-Pressure

Storage Tanks

API Recommended Practice 575 – Inspection of Atmospheric and Low-Pressure Storage

Tanks12 (API RP 575), which supplements API 653, covers the inspection of atmospheric tanks

(e.g., cone roof and floating roof tanks) and low-pressure storage tanks (i.e., those that have

cylindrical shells and cone or dome roofs) that have been designed to operate at pressures from

atmospheric to 15 pounds per square inch gauge (psig). (API RP 572 covers tanks operating

above 15 psig.) In addition to describing the types of storage tanks and standards for their

construction and maintenance, API RP 575 also covers the reasons for inspection, causes of

deterioration, frequency and methods of inspection, methods of repair, and the preparation of

records and reports. API RP 575 applies only to the inspection of atmospheric and low-pressure

storage tanks that have been in service. Section 1 of API RP 575 introduces the recommended

practice and details its scope. Section 2 lists the references that are cited in the recommended

practice.

Section 3 of API RP 575 describes selected methods for non-destructive examination of

tanks, including ultrasonic thickness measurement, ultrasonic corrosion testing, ultrasonic shear

wave testing, and magnetic flux testing. Section 4 describes the construction materials and design

standards, use, and specific types of atmospheric and low-pressure storage tanks. Section 5

covers the reasons for inspection and causes of deterioration of both steel and non-steel storage

tanks. Section 5 also covers the deterioration and failure of auxiliary equipment.

Section 6 of API RP 575 addresses inspection frequency; it mainly defers to the inspection

frequency requirements described in API 653. Section 7 covers the methods of inspection and

inspection scheduling. It addresses the external inspection of both in-service and out-of-service
SPCC Guidance for Regional Inspectors

13 API Recommended Practice 12R1, “Recommended Practice for Setting, Maintenance, Inspection, Operation, and

Repair of Tanks in Production Service,” 5th edition. American Petroleum Institute. August 1997. 

14 API Specifications 12B, D, F, and P correspond to bolted tanks for storage of production liquids, field welded tanks

for storage of production liquids, shop welded tanks for storage of production liquids, and specification for fiberglass

reinforced plastic tanks, respectively.

15 Section 7 of API RP 12R1 states that “..the spill prevention and examination/inspection provisions of this

recommended practice should be a companion to the spill prevention control and countermeasures (SPCC) to

prevent environmental damage.”

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tanks and the internal inspection of out-of-service tanks. Section 7 provides some information

about scheduling tank inspections, but it mostly defers to API 653. Section 8 addresses the

methods for repairing tanks. Recordkeeping and inspection reports are the focus of Section 9,

which stresses the importance of keeping complete records. Appendix A of the recommended

practice provides a typical field record form and history card. Appendix B contains a typical tank

report form. Appendix C provides sample checklists for internal and external tank inspections.

7.5.4 API Recommended Practice 12R1 – Recommended Practice for Setting, Maintenance,

Inspection, Operation, and Repair of Tanks in Production Service

API Recommended Practice 12R1 – Recommended Practice for Setting, Maintenance,

Inspection, Operation, and Repair of Tanks in Production Service (API RP 12R1)13 provides

guidance on new tank installations and maintenance of existing production tanks. These tanks are

often referred to as “upstream” or “extraction and production (E&P) tanks.” The recommended

practices are primarily intended for tanks fabricated to API Specifications 12B, D, F, and P that are

employed in on-land production service.14 This said, the basic principles in the recommended

practices can also be applied to other atmospheric tanks that are employed in similar oil and gas

production, treating, and processing services; however, they are not applicable to refineries,

marketing bulk stations, petrochemical plants, or pipeline storage facilities operated by carriers. 

According to the recommended practice, tanks that are fabricated to API Standards 12C or 650

should be maintained in accordance with API 653, summarized above.

Sections 1, 2, and 3 of API RP 12R1 describe the scope of the standard, the 19 standards it

references, and the relevant definitions, respectively. The remaining four main sections describe

the recommended practices. Section 4 provides recommended practices for setting of new or

relocated tanks and connecting tanks. Section 5 recommends practices for safe operation and spill

prevention for tanks.15 Section 6 details the recommended practices for routine operational and

external and internal condition examinations, internal and external inspections, maintenance of

tanks, and recordkeeping. Table 1 of this recommended practice details the type of observations,

frequency, and associated personnel requirements for internal and external tank inspections. 

Records from these inspections should be retained with permanent equipment records. Finally,

Section 7 provides guidance for the alteration or repair of various tank components. API RP 12R1

also contains nine appendices detailing the recommended requirements of qualified inspectors,

sample calculations for venting requirements, observations regarding shell corrosion and brittle

fracture, checklists for internal and external condition examinations and inspections, details

regarding the minimum thickness of tank elements, and various figures and diagrams.
Chapter 7: Inspection, Evaluation, and Testing

16 API 570, “Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of In-service Piping Systems,” 2nd

ed., American Petroleum Institute, October 1998.

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7.5.5 API 570 – Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of

In-service Piping Systems

API 570 – Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of In-service

Piping Systems (API 570)16 covers inspection, repair, alteration, and rerating procedures for metallic

piping systems that have been in service. API 570 was developed for the petroleum refining and

chemical process industries. In-service piping systems covered by API 570 include those used for

process fluids, hydrocarbons, and similar flammable or toxic fluids. API states that this standard is

not a substitute for the original construction requirements governing a piping system before it is

placed in service. API 570 is intended for use by organizations that maintain or have access to an

authorized inspection agency; a repair organization; and technically qualified piping engineers,

inspectors, and examiners. The owner/operator is responsible for implementing a piping system

inspection program, controlling the inspection frequencies, and ensuring the maintenance of piping

systems in accordance with this standard.

Section 5, the first substantive section of the standard, addresses the specific inspection

and testing practices for in-service piping systems. Section 6 addresses the frequency and extent

of inspection of piping. Inspection intervals for piping are based largely on the likelihood and

consequence of failure (i.e., they are risk-based), which takes into account the corrosion rate and

remaining life calculations; piping service classification; applicable jurisdictional requirements; and

the judgement of the inspector, the piping engineer, the piping engineer supervisor, or a corrosion

specialist. Table 6-1 of API 570 provides maximum inspection intervals for piping based on piping

service classification (Class 1 poses the highest risk of an emergency if a leak were to occur; Class

2, which includes the majority of unit process piping, poses an intermediate risk; Class 3 poses the

lowest risk) and the corrosion measurement technique (i.e., thickness measurements or visual

external inspection) that is used. In general, the maximum inspection interval for in-service piping

should be between five years for Class 1 piping to ten years for Class 3 piping.

Section 7 of the standard addresses data evaluation, analysis, and recording. The

owner/operator should maintain permanent records for all piping systems covered by API 570. 

Section 8 provides guidelines for repairing, altering, and rerating piping systems. Inspecting buried

process piping is different from inspecting other process piping because the inspection is hindered

by the inaccessibility of the affected areas of the piping; therefore, API 570 addresses the

inspection of buried piping separately in Section 9. Appendices A, B, C, and D of API 570 address

inspector certification, technical inquiries, examples of repairs, and the external inspection checklist

for process piping, respectively.
SPCC Guidance for Regional Inspectors

17 API RP 574, “Inspection Practices for Piping System Components,” 2nd ed., American Petroleum Institute, June

1998.

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7.5.6 API Recommended Practice 574 – Inspection Practices for Piping System

Components

API Recommended Practice 574 – Inspection Practices for Piping System Components (API

RP 574)17 covers inspection practices for piping, tubing, valves (other than control valves), and

fittings used in petroleum refineries and chemical plants. API RP 574 is not specifically intended to

cover specialty items, such as control valves, level gauges, and instrument controls columns, but

many of the inspection methods are applicable to these items. API RP 574 provides more detailed

information about piping system components and inspection procedures than API 570. Section 1

introduces the recommended practice and details its scope. Sections 2 and 3, respectively, list the

references and definitions used throughout the recommended practice.

Section 4, which begins the substantive portion of the recommended practice, details the

types, material specifications, sizes, and other characteristics of the components of the piping

system, which include the piping, tubing, valves, and fittings. This section of the recommended

practice also addresses the common joining methods used to assemble piping components. 

Section 5 of API RP 574 presents the rationale for inspecting the piping system: to maintain safety,

attain reliable and efficient operation, and meet regulatory requirements. The procedures for

monitoring the piping system components for corrosion and inspecting for deterioration are the

focus of Section 6. Section 7 provides guidelines for establishing the frequency and time (i.e., while

equipment is operating or while equipment is shut down) of inspection. Similar to API 570, this

recommended practice uses the following conditions to determine the frequency of inspection: the

consequences of a failure (piping classification, see summary of API 570 for a description), the

degree of risk, the amount of corrosion allowance remaining, the historical data available, and the

regulatory requirements.

Section 8 of API RP 574 outlines the safety precautions that should be taken and

preparatory work that should be performed prior to inspecting the piping system components. The

inspection tools commonly used to inspect piping are tabulated in Section 9 of this recommended

practice. Section 10 details the specific procedures that should be followed when inspecting the

components of the piping system. This section also covers the inspection of underground piping

(Section 10.3) and new construction (Section 10.4). Section 11 describes the procedures a piping

engineer should follow to determine the thickness at which piping and valves and flanged fittings

should be retired. Recordkeeping is the focus of Section 12. Appendix A of the recommended

practice provides an external inspection checklist for process piping. 
Chapter 7: Inspection, Evaluation, and Testing

18 API Recommended Practice 1110, “Pressure Testing of Liquid Petroleum Pipelines,” 4th edition, American

Petroleum Institute, March 1997. 

19 This does not include low-pressure pneumatic testing.

20 ASME B31.4, “Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and

Alcohols.”

21 U.S. Department of Transportation. Research and Special Programs Administration (49 CFR part 195).

22 API Recommended Practice 579, “Fitness for Service,” 1stEdition, American Petroleum Institute, January 2000.

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7.5.7 API Recommended Practice 1110 – Pressure Testing of Liquid Petroleum Pipelines

API Recommended Practice 1110 – Pressure Testing of Liquid Petroleum Pipelines (API RP

1110)18 provides guidance regarding the procedures, equipment, and factors to consider when

pressure testing new and existing liquid petroleum pipelines. Pressure testing uses a liquid test

medium (typically water) to apply internal pressure to a segment of pipe above its normal or

maximum operating pressure for a fixed period of time under no-flow conditions to verify that the

“test segments have the requisite structural integrity to withstand normal and maximum operating

pressures19 and to verify that they are capable of liquid containment.” This testing should be

performed by “test personnel” in accordance with ASME B31.4 20 and 49 CFR part 195.21

Sections 1 and 2 of API RP 1110 describe the scope of the standard and publications it

references, respectively. Section 3 explains how the pressure testing, performed one segment of

pipe at a time, should be executed. Generally this is done by filling a section of pipe with the testing

medium and increasing the pressure from its static pressure level at a controlled rate. Pipe

connections are tested for leaks during the pressurization and after the test pressure has been

reached.

Complete records of the testing should be kept, including information on any failures, the

places they occurred, and the methods of repair they require in order to comply with ASME B31.4,

49 CFR part 195, and any other applicable regulations. The final part of API RP 1110 is Appendix

A, which provides samples of various test record forms.

7.5.8 API Recommended Practice 579, Fitness-for-Service, Section 3

This recommended practice22 addresses “Assessment of Existing Equipment for Brittle

Fracture” and provides guidelines for evaluating the resistance to brittle fracture of existing carbon

and low alloy steel pressure vessels, piping, and storage tanks. If the results of the

fitness-for-service assessment indicate that the AST is suitable for the current operating conditions,

then the equipment can continue to be operated under the same conditions provided that suitable

monitoring/inspection programs are established. API RP 579 is intended to supplement and

augment the requirements in API 653. That is, when API 653 does not provide specific evaluation

procedures or acceptance criteria for a specific type of degradation, or when API 653 explicitly

allows the use of fitness-for-service criteria, API RP 579 may be used to evaluate the various types

of degradation or test requirements addressed in API 653.
SPCC Guidance for Regional Inspectors

23 API Recommended Practice 2610, “Design, Construction, Operation, Maintenance, and Inspection of Terminal and

Tank Facilities,” 2nd edition, American Petroleum Institute, May 2005.

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A brittle fracture assessment may be warranted based on operating conditions and/or the

condition of the AST. API RP 579 provides separate brittle fracture assessment procedures for

continued service based on three levels. All three apply to pressure vessels, piping, and tankage,

although a separate assessment procedure is provided for tankage.

• Level 1 assessments are used for equipment that meets toughness requirements in

a recognized code or standard (e.g., API 650).

• Level 2 assessments exempt equipment from further assessment and qualify it for

continued service based on one of three methods. These methods are based on

operating pressure and temperature; performance of a hydrotest; or the materials of

construction, operating conditions, service environment, and past operating

experience.

• Level 3 assessments, which normally utilize a fracture mechanics methodology, are

used for tanks that do not meet the acceptance criteria for Levels 1 and 2.

A decision tree in API RP 579 (Figure 3.2, Brittle Fracture Assessment for Storage Tanks)

outlines this assessment procedure. The Level 1 and Level 2 brittle fracture assessment

procedures are nearly identical to those found in API 653, Section 5, with a few notable exceptions:

API 653 does not use the Level 1 and Level 2 designations; API 653 applies only to tanks that meet

API 650 (7th edition or later) construction standards, whereas API 579 applies to tanks that meet

toughness requirements in the “current construction code”; and the two standards set a different

limit on the maximum membrane stress (the stress forces that form within the shell as a result of the

pressure of the liquid inside the vessel). There is, however, one major difference between API 653

and API 579: API 653, Section 5, does not allow for an exemption of the hydrostatic test

requirement as API 579 does. API 579 allows for a probabilistic evaluation of the potential for brittle

fracture using engineering calculations (i.e., a Level 3 assessment) in lieu of the hydrostatic test.

7.5.9 API Standard 2610 - Design, Construction, Operation, Maintenance, and Inspection of

Terminal & Tank Facilities

The standard23 has short sections on petroleum terminals, pipeline tankage facilities,

refinery facilities, bulk plants, lube blending and packaging facilities, asphalt plants, and aviation

service facilities; these sections mainly serve to define what is meant by each type of facility. The

standard does not apply to installations covered by API Standard 2510 and API RP 12R1, as well

as a list of specific types of facilities and equipment indicated in the standard. The standard lists

governmental requirements and reviews that should be conducted to ensure that facilities meet

applicable federal, state, or local requirements (Section 1.3); and has an extensive list of standards,

codes, and specifications to use (Section 2.1).

Section 4 of the standard covers the site selection and spacing requirements for the design

and construction of new terminal facilities. Section 5 addresses the methods of pollution prevention
Chapter 7: Inspection, Evaluation, and Testing

24 ASME B31.3, “Process Piping: The Complete Guide to ASME B31.3,” Charles Becht IV, The American Society of

Mechanical Engineers, 2nd edition, 2004.

25 ASME B31.3 does not have specific requirements for an examiner, but SNT-TC-1A, “Recommended Practice for

Nondestructive Testing Personnel Qualification and Certification,” acts as an acceptable guide.

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and waste management practices in the design, maintenance, and operation of petroleum terminal

and tank facilities. Section 6 covers the safe operation of terminals and tanks such as hazard

identification, operating procedures, safe work practices, emergency response and control

procedures, training, and other provisions. Section 7 covers fire prevention and protection,

including tank overfill protection and inspection and maintenance programs. This section also

covers considerations for special products. Section 8 covers aboveground petroleum storage tanks

and appurtenances such as release prevention, leak detection, and air emissions. This section

covers operations, inspections, maintenance, and repair for aboveground and underground tanks. 

Section 9 addresses dikes and berms. Section 10 covers pipe, valves, pumps, and piping systems. 

Section 11 covers loading, unloading, and product transfer facilities and activities including spill

prevention and containment. Section 12 addresses the procedures and practices for achieving

effective corrosion control. Section 13 addresses structures, utilities, and yards. Section 14 covers

removal or decommissioning of facilities. All of these sections extensively reference the regulatory

requirements and applicable industry standards.

7.5.10 ASME B31.3 – Process Piping 

ASME B31.3 – Process Piping24 is the generally accepted standard of minimum safety

requirements for the oil, petrochemical, and chemical industries’ process piping design and

construction (for process piping already in service, other standards should be used, such as API

570, “Piping Inspection Code”). ASME B31.3 is written to be very broad in scope to cover a range

of fluids, temperatures, and pressures. This broad coverage leaves a great deal of responsibility

with the owner to use good engineering practices. The safety requirements for the design,

examination, and testing of process piping vary in stringency based on three different categories of

fluid service. Categories include “Category D” for a low hazard of fluid service, “Category M” for a

high hazard of fluid service, with all remaining fluid services that are not in Category D or Category

M being “Normal.” It is the owner’s responsibility to select the appropriate fluid service category,

which determines the appropriate examination requirements.

The examination of process piping is to be completed by an examiner who demonstrates

sufficient qualifications to perform the specified examination and who has training and experience

records kept by his/her employer that can support these qualifications.25 Different types of

examinations performed include visual examinations, radiographic examinations, ultrasonic

examinations, in-process examinations, liquid-penetrant examinations, magnetic-particle

examinations, and hardness testing. 

While these examinations are a part of the quality assurance procedures for new piping,

leak testing should also be performed to test the overall system. According to ASME B31.3, leak

testing is required for all new piping systems other than those classified as Category D, which can
SPCC Guidance for Regional Inspectors

26 ASME Code for Pressure Piping, B31.4-2002, “Pipeline Transportation Systems for Liquid Hydrocarbons and Other

Liquids,” The American Society of Mechanical Engineers, revision of ASME B31.4-1998, 2002.

27 49 CFR part 180.605, “Requirements for Periodic Testing, Inspection, and Repair of Portable Tanks,” Department

of Transportation, 64 FR 28052, May 24, 1999, as amended at 67 FR 15744, April 3, 2002.

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be examined for leaks after being put into service. Options for leak testing include hydrostatic tests,

pneumatic tests, hydropneumatic tests, and alternative leak tests.

The standard requires that records detailing the examination personnel’s qualifications and

examination procedures be kept for at least five years. Test records or the inspector’s certification

that the piping has passed pressure testing are also required to be retained.

7.5.11 ASME Code for Pressure Piping B31.4-2002 – Pipeline Transportation Systems for

Liquid Hydrocarbons and Other Liquids

ASME Code for Pressure Piping B31.4-2002 – Pipeline Transportation Systems for 

Liquid Hydrocarbons and Other Liquids26 describes “engineering requirements deemed necessary

for safe design and construction of pressure piping.” These requirements are for the “design,

materials, construction, assembly, inspection, and testing of piping transporting liquids” such as

crude oil and liquid petroleum products between various facilities. Piping includes bolting, valves,

pipes, gaskets, flanges, fittings, relief devices, pressure-containing parts of other piping

components, hangers and supports, and any other equipment used to prevent the overstressing of

pressure-containing pipes. This code’s primary purpose is to “establish requirements for safe

design, construction, inspection, testing, operation, and maintenance of liquid pipeline systems for

protection of the general public and operating company personnel.”

The personnel inspecting the piping are deemed qualified based on their level of training

and experience and should be capable of performing various inspection services such as right-ofway and grading, welding, coating, pressure testing, and pipe surface inspections. Inspections of

piping material and inspections during piping construction should include the visual evaluation of all

piping components. Once construction is complete, these piping components and the entire system

should be tested. Testing methods include hydrostatic testing of internal pressure piping; leak

testing; and qualification tests based on a visual examination, bending properties, determination of

wall thickness, determination of weld joint factor, weldability, determination of yield strength, and the

minimum yield strength value.

Records detailing the design, construction, and testing of the piping should be kept in the

files of the operating company for the life of the facility. 

7.5.12 DOT 49 CFR 180.605 – Requirements for Periodic Testing, Inspection, and Repair of

Portable Tanks and Other Portable Containers

Section 180.60527 applies to any portable tank constructed to a DOT (e.g., 51, 56, 57, 60, or

intermodal [IM]) or United Nations (UN) specification. According to these requirements, a portable
Chapter 7: Inspection, Evaluation, and Testing

28 FAA Advisory Circular 150/5230-4A, “Aircraft Fuel Storage, Handling, and Dispensing on Airports,” Federal Aviation

Administration, U.S. Department of Transportation, June 18, 2004.

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tank must be inspected prior to further use if it shows evidence of a condition that might render it

unsafe for use, has been damaged in an accident, has been out of service for more than a year,

has been modified, or is in an unsafe operating condition. All tanks must receive an initial

inspection prior to being placed into service and a periodic inspection or intermediate periodic

inspection every two to five years. The timeframe between inspections depends upon the tank’s

specification. 

Intermediate periodic inspections must include an internal and external examination of the

tank and fittings, a leak test, and a test of the service equipment. The periodic inspection and test

must include an external and internal inspection and a sustained air pressure leak test, unless

exempted. For tanks that show evidence of damage or corrosion, an exceptional inspection and

test is mandated. The extent of the inspection is dictated by the amount of damage or deterioration

of the portable tank. Specification-60 tanks are further tested by filling them with water. 

Specification-IM or Specification-UN portable tanks must also be hydrostatically tested. Any tank

that fails a test may not return to service until it is repaired and retested. An approval agency must

witness the retest and certify the tank for return to service. The date of the last pressure test and

visual inspection must be clearly marked on each IM or UN portable tank. A written record of the

dates and results of the tests, including the name and address of the person performing the test, is

to be retained by the tank owner or authorized agent.

Requirements for retest and inspection of Intermediate Bulk Containers (IBCs) are specified

in 49 CFR 180.352. Requirements depend on the IBC shell material. For metal, rigid plastic, and

composite IBCs, they include a leakproof test and external visual inspection every 2.5 years from

the date of manufacture or repair. They also require an internal inspection every 5 years to ensure

that the IBC is free from damage and capable of withstanding the applicable conditions. Flexible,

fiberboard, or wooden IBCs must be visually inspected prior to first use and permitted reuse.

Records of each test must be kept until the next test, or for at least 2.5 years from the date of the

last test.

Design standards and specifications for initial qualification and reuse performance testing for

portable tanks, drums, and IBCs are contained in 49 CFR part 178, Specifications for Packaging. 

See www.access.gpo.gov/cfr. 

7.5.13 FAA Advisory Circular 150/5230-4A – Aircraft Fuel Storage, Handling, and Dispensing

on Airports

FAA Advisory Circular 150/5230-4A – Aircraft Fuel Storage, Handling, and Dispensing on

Airports28 identifies standards and procedures for storage, handling, and dispensing of aviation fuel

on airports. The Federal Aviation Administration (FAA) recommends the standards and procedures

referenced in the Advisory Circular (AC) for all airports. The FAA accepts these standards as one

means of complying with 14 CFR Part 139, Certification of Airports, as it pertains to fire safety in the
SPCC Guidance for Regional Inspectors

29 FAA Advisory Circular 150/5210-20, “Ground Vehicle Operations on Airports,” Federal Aviation Administration, U.S.

Department of Transportation, June 21, 2002. 

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safe storage, handling, and dispensing of fuels used in aircraft on airports but not in terms of quality

control. Although airports that are not certificated under 14 CFR part 139 are not required to

develop fuel safety standards, the FAA recommends that they do so.

This AC is not intended to replace airport procedures developed to meet requirements

imposed because of the use of special equipment, nor to replace local regulations. For specific

provisions, the other standards that are referenced in this AC are:

• For fuel storage, handling and dispensing, the National Fire Prevention Association’s

“Standard for Aircraft Fuel Servicing”

• For refueling and quality control procedures, the National Air Transportation

Association’s “Refueling and Quality Control Procedures for Airport Service and

Support Operations.” This provides information about fuel safety, types of aviation

fuels, fueling vehicle safety, facility inspection procedures, fueling procedures, and

methods for handling fuel spills. API also publishes documents pertaining to

refueling and facility specifications.

The AC also requires fuel safety training for airports certificated under 14 CFR part 139.

(See http://www.faa.gov/arp/publications/acs/5230-4A.pdf.)

7.5.14 FAA Advisory Circular 150/5210-20 – Ground Vehicle Operations on Airports

FAA Advisory Circular 150/5210-20 – Ground Vehicle Operations on Airports29 provides

“guidance to airport operators in developing training programs for safe ground vehicle operations

and pedestrian control on the airside of an airport.” Specifically, this advisory circular provides

recommended operating procedures accompanied by two appendices containing samples of the

training curriculum and training manual. With regard to the transportation and storage of oil, the

vehicle operator requirements on the airside of an airport require that “no fuel truck shall be brought

into, stored, or parked within 50 feet of a building. Fuel trucks must not be parked within 10 feet

from other vehicles.” (See http://www.faa.gov/arp/ACs/5210-20.pdf.)

7.5.15 Suggested Minimum Requirements for a PE-Developed Site-Specific Integrity Testing

Program (Hybrid Testing Program)

Although EPA refers to certain industry standards for inspection and testing, it does not

require that inspections and tests be performed according to a specific standard. The PE may use

industry standards along with other good engineering principles to develop a customized inspection

and testing program for the facility (a “hybrid inspection program”), considering the equipment type

and condition, characteristics of products stored and handled at the facility, and other site-specific

factors. 
Chapter 7: Inspection, Evaluation, and Testing

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For example, a hybrid testing program may be developed in cases where no specific

industry inspection standard exists to date, as is the case for tanks that contain certain products

such as animal fats and vegetable oils, asphalt, or oils that have a specific gravity greater than 1.0. 

Although there are no industry standards specific to integrity testing of bulk storage containers

containing vegetable oils at this time, some facilities with large animal fat and vegetable oil tanks

follow API 653. Additionally, the U.S. Food and Drug Administration (FDA) sets requirements for

food-grade oils, which would need to be followed in addition to EPA’s integrity testing requirements.

The following provide recommendations of the minimum elements for a hybrid inspection

program.

For shop-built tanks:

• Visually inspect exterior of tank;

• Evaluate external pitting;

• Evaluate “hoop stress and longitudinal stress risks” where corrosion of the shell is

present;

• Evaluate condition and operation of appurtenances;

• Evaluate welds;

• Establish corrosion rates and determine the inspection interval and suitability for

continued service;

• Evaluate tank bottom where it is in contact with ground and no cathodic protection is

provided;

• Evaluate the structural integrity of the foundation;

• Evaluate anchor bolts in areas where required; and

• Evaluate the tank to determine it is hydraulically sound and not leaking.

For field-erected tanks:

• Evaluate foundation;

• Evaluate settlement;

• Determine safe product fill height;

• Determine shell corrosion rate and remaining life;

• Determine bottom corrosion rate and remaining life;

• Determine the inspection interval and suitability for continued service;

• Evaluate all welds;

• Evaluate coatings and linings;

• Evaluate repairs for risk of brittle fracture; and

• Evaluate the tank to determine it is hydraulically sound and not leaking.

EPA suggests that an appropriately trained and qualified inspector conduct a hybrid

inspection and provide a detailed report of the findings. The qualifications of the tank inspector will

depend on the condition and circumstances of the tank (e.g., size, field-erected or shop-built), and

an inspector should only certify an inspection to the extent he/she is qualified to do so. A registered
SPCC Guidance for Regional Inspectors

U.S. Environmental Protection Agency 7-40 Version 1.1, 2/3/06

PE may be able to perform the hybrid inspection, but could also have a certified inspector (e.g., STI

or API) complete the inspection. Either way, the hybrid inspection should be reviewed and certified

by a PE in accordance with §112.3(d). Note that industry inspection standards require the

inspector’s certification number on these reports.

EPA also recommends that the hybrid inspection program include frequent (e.g., monthly),

visual examinations of the tank by the tank owner. Such an examination may include the following

elements:

• Foundation: Structurally sound and there is adequate drainage away from tank

(yes/no)

• Tank bottom: Shows visible signs of leakage (yes/no)

• Tank shell: Shows distortions, visible leaks, seepage at seam, external corrosion

(yes/no)

• Condition of coatings and insulation (satisfactory/unsatisfactory)

• Roof: Hatches securely closed, roof distortions, visible signs of holes, external

corrosion, adequate drainage (yes/no)

• Condition of coatings and insulation (satisfactory/unsatisfactory)

• Appurtenances: Thief hatch seals properly; thief hatch operational; vent valve

operational; drain and sample valves do not leak; piping properly supported off tank;

stairways, ladders, and walkways sound (yes/no)

• Miscellaneous: Cathodic protection and automatic tank gauging is operational, tank

area is clean of trash and vegetation (yes/no)

The inspector may review checklists used by facility personnel to conduct the frequent (e.g.,

monthly) inspections.
Chapter 7: Inspection, Evaluation, and Testing

U.S. Environmental Protection Agency 7-41 Version 1.1, 2/3/06

Table 7-5 summarizes the facility components covered by select industry standards and

recommended practices for tanks, valves, pipes, and appurtenances. Additional standards and/or

manufacturers’ standards may also apply. The recommended standards for facility personnel to

use for inspecting and testing at a particular facility would be specified in the SPCC Plan by the PE

preparing the Plan. All actions (e.g., visual inspection or testing) performed by facility personnel

must be appropriately documented and maintained in permanent facility records as per §112.7(e).

Table 7-5. Checklist summary of industry standards for inspection, evaluation, and testing. 

Facility Component(s) Covered in Standard or

Recommended Practice

Potentially Relevant Standards and

Recommended Practices

API 653

STISP001

API 570

API RP* 575API RP* 574

API 12R1

API 1110

ASME B31.3ASME B31.4

New equipment UUUU

Equipment that has been in service U U U UUUU U

Shop-built AST UU U U

Field-erected AST U UU

Plastic tanks U

Container supports or foundation UU U U

Buried metallic storage tank

Tank car or tank truck

Diked area U

Aboveground valves, piping, and appurtenances U U UU UU U

Underground piping U U

Offshore valves, piping, and appurtenances U

Steam return and exhaust lines

Field drainage systems, oil traps, sumps, and/or

skimmers

* Recommended practice.
SPCC Guidance for Regional Inspectors

U.S. Environmental Protection Agency 7-42 Version 1.1, 2/3/06

Table 7-6, tank inspection checklist, provides an example of the type of information that may be

included on an owner/operator-performed inspection checklist.

Table 7-6. Tank inspection checklist (from Appendix F of 40 CFR part 112).

I. Check tanks for leaks, specifically looking for:

A. Drip marks;

B. Discoloration of tanks;

C. Puddles containing spilled or leaked material;

D. Corrosion;

E. Cracks; and

F. Localized dead vegetation.

II. Check foundation for:

A. Cracks;

B. Discoloration;

C. Puddles containing spilled or leaked material;

D. Settling;

E. Gaps between tank and foundation; and

F. Damage caused by vegetation roots.

III. Check piping for:

A. Droplets of stored material;

B. Discoloration;

C. Corrosion;

D. Bowing of pipe between supports;

E. Evidence of stored material seepage from valves or seals; and

F. Localized dead vegetation.
Appendix A 

APPENDIX A: TEXT OF CWA 311(j)(1)(c)
 


U.S. Environmental Protection Agency Version 1.0, 11/28/2005 
CWA §§ 311(j)(1)(c)
 
 

Summary: 

The President is authorized to issue regulations establishing procedures, methods, 

equipment, and other requirements to prevent discharges of oil from vessels and facilities. 

Rule Text: 

(j) National Response System 

(1) In ge neral 

Consistent with the National Contingency Plan required by subsection 

(c)(2) of this section, as soon as practicable after October 18, 1972, and 

from time to time thereafter, the President shall issue regulations 

consistent with maritime safety and with marine and navigation laws 

(c) 

establishing procedures, methods, and equipment and other 

requirements for equipment to prevent discharges of oil and 

hazardous substances from vessels and from onshore facilities and 

off shore facilities, and to contain such discharges... 
Appendix B 

APPENDIX B: SELECT REGULATIONS 

40 CFR part 109

40 CFR part 110

40 CFR part 112

U.S. Environmental Protection Agency Version 1.0, 11/28/2005 

Environmental Protection Agency 

Law Judge, on his own motion, or at 

the request of any party, shall have the 

power to hold prehearing conferences, 

to issue subpoenas for the attendance 

and testimony of witnesses and the 

production of relevant papers, books, 

and documents, and he may administer 

oaths. The Regional Administrator, 

and any party submitting a request 

pursuant to § 108.3 or § 108.4, or counsel 

or other representative of such party 

or the Regional Administrator, may 

appear and offer evidence at the hearing. 

§ 108.6 Recommendations. 

At the conclusion of any hearing 

under this part, the Administrative 

Law Judge shall, based on the record, 

issue tentative findings of fact and recommendations concerning the alleged 

discrimination, and shall submit such 

tentative findings and recommendations to the Administrator. The Administrator shall adopt or modify the 

findings and recommendations of the 

Administrative Law Judge, and shall 

make copies of such findings and recommendations available to the complaining employee, the employer, and 

the public. 

§ 108.7 Hearing before Administrator. 

At his option, the Administrator may 

exercise any powers of an Administrative Law Judge with respect to hearings under this part. 

PART 109—CRITERIA FOR STATE, 

LOCAL AND REGIONAL OIL REMOVAL CONTINGENCY PLANS 

Sec. 
 

109.1 Applicability. 
 

109.2 Definitions. 
 

109.3 Purpose and scope. 
 

109.4 Relationship to Federal response 


actions. 

109.5 Development and implementation criteria for State, local and regional oil removal contingency plans. 

109.6 Coordination. 

AUTHORITY: Sec. 11(j)(1)(B), 84 Stat. 96, 33 

U.S.C. 1161(j)(1)(B). 

SOURCE: 36 FR 22485, Nov. 25, 1971, unless 

otherwise noted. 

§ 109.2 

§ 109.1 Applicability. 

The criteria in this part are provided 

to assist State, local and regional 

agencies in the development of oil removal contingency plans for the inland 

navigable waters of the United States 

and all areas other than the high seas, 

coastal and contiguous zone waters, 

coastal and Great Lakes ports and harbors and such other areas as may be 

agreed upon between the Environmental Protection Agency and the Department of Transportation in accordance with section 11(j)(1)(B) of the Federal Act, Executive Order No. 11548 

dated July 20, 1970 (35 FR 11677) and 

§ 306.2 of the National Oil and Hazardous Materials Pollution Contingency Plan (35 FR 8511). 

§ 109.2 Definitions. 

As used in these guidelines, the following terms shall have the meaning 

indicated below: 

(a) Oil means oil of any kind or in 

any form, including, but not limited to, 

petroleum, fuel oil, sludge, oil refuse, 

and oil mixed with wastes other than 

dredged spoil. 

(b) Discharge includes, but is not limited to, any spilling, leaking, pumping, 

pouring, emitting, emptying, or dumping. 

(c) Remove or removal refers to the removal of the oil from the water and 

shorelines or the taking of such other 

actions as may be necessary to minimize or mitigate damage to the public 

health or welfare, including, but not 

limited to, fish, shellfish, wildlife, and 

public and private property, shorelines, 

and beaches. 

(d) Major disaster means any hurricane, tornado, storm, flood, high water, 

wind-driven water, tidal wave, earthquake, drought, fire, or other catastrophe in any part of the United States 

which, in the determination of the 

President, is or threatens to become of 

sufficient severity and magnitude to 

warrant disaster assistance by the Federal Government to supplement the efforts and available resources of States 

and local governments and relief organizations in alleviating the damage, 

loss, hardship, or suffering caused 

thereby. 

15 
 

§ 109.3 

(e) United States means the States, 

the District of Columbia, the Commonwealth of Puerto Rico, the Canal Zone, 

Guam, American Samoa, the Virgin Islands, and the Trust Territory of the 

Pacific Islands. 

(f) Federal Act means the Federal 

Water Pollution Control Act, as 

amended, 33 U.S.C. 1151 et seq. 

§ 109.3 Purpose and scope. 

The guidelines in this part establish 

minimum criteria for the development 

and implementation of State, local, 

and regional contingency plans by 

State and local governments in consultation with private interests to insure timely, efficient, coordinated and 

effective action to minimize damage 

resulting from oil discharges. Such 

plans will be directed toward the protection of the public health or welfare 

of the United States, including, but not 

limited to, fish, shellfish, wildlife, and 

public and private property, shorelines, 

and beaches. The development and implementation of such plans shall be 

consistent with the National Oil and 

Hazardous Materials Pollution Contingency Plan. State, local and regional 

oil removal contingency plans shall 

provide for the coordination of the 

total response to an oil discharge so 

that contingency organizations established thereunder can function independently, in conjunction with each 

other, or in conjunction with the National and Regional Response Teams 

established by the National Oil and 

Hazardous Materials Pollution Contingency Plan. 

§ 109.4 Relationship to Federal response actions. 

The National Oil and Hazardous Materials Pollution Contingency Plan 

provides that the Federal on-scene 

commander shall investigate all reported spills. If such investigation 

shows that appropriate action is being 

taken by either the discharger or nonFederal entities, the Federal on-scene 

commander shall monitor and provide 

advice or assistance, as required. If appropriate containment or cleanup action is not being taken by the discharger or non-Federal entities, the 

Federal on-scene commander will take 

control of the response activity in ac40 CFR Ch. I (7–1–05 Edition) 

cordance with section 11(c)(1) of the 

Federal Act. 

§ 109.5 Development and implementation criteria for State, local and 

regional oil removal contingency

plans. 

Criteria for the development and implementation of State, local and regional oil removal contingency plans 

are: 

(a) Definition of the authorities, responsibilities and duties of all persons, 

organizations or agencies which are to 

be involved or could be involved in 

planning or directing oil removal operations, with particular care to clearly 

define the authorities, responsibilities 

and duties of State and local governmental agencies to avoid unnecessary 

duplication of contingency planning 

activities and to minimize the potential for conflict and confusion that 

could be generated in an emergency 

situation as a result of such duplications. 

(b) Establishment of notification procedures for the purpose of early detection and timely notification of an oil 

discharge including: 

(1) The identification of critical 

water use areas to facilitate the reporting of and response to oil discharges. 

(2) A current list of names, telephone 

numbers and addresses of the responsible persons and alternates on call to 

receive notification of an oil discharge 

as well as the names, telephone numbers and addresses of the organizations 

and agencies to be notified when an oil 

discharge is discovered. 

(3) Provisions for access to a reliable 

communications system for timely notification of an oil discharge and incorporation in the communications system of the capability for interconnection with the communications systems 

established under related oil removal 

contingency plans, particularly State 

and National plans. 

(4) An established, prearranged procedure for requesting assistance during a 

major disaster or when the situation 

exceeds the response capability of the 

State, local or regional authority. 

(c) Provisions to assure that full resource capability is known and can be 

committed during an oil discharge situation including: 

16 
 

Environmental Protection Agency 

(1) The identification and inventory 

of applicable equipment, materials and 

supplies which are available locally 

and regionally. 

(2) An estimate of the equipment, 

materials and supplies which would be 

required to remove the maximum oil 

discharge to be anticipated. 

(3) Development of agreements and 

arrangements in advance of an oil discharge for the acquisition of equipment, materials and supplies to be used 

in responding to such a discharge. 

(d) Provisions for well defined and 

specific actions to be taken after discovery and notification of an oil discharge including: 

(1) Specification of an oil discharge 

response operating team consisting of 

trained, prepared and available operating personnel. 

(2) Predesignation of a properly 

qualified oil discharge response coordinator who is charged with the responsibility and delegated commensurate authority for directing and coordinating 

response operations and who knows 

how to request assistance from Federal 

authorities operating under existing 

national and regional contingency 

plans. 

(3) A preplanned location for an oil 

discharge response operations center 

and a reliable communications system 

for directing the coordinated overall 

response operations. 

(4) Provisions for varying degrees of 

response effort depending on the severity of the oil discharge. 

(5) Specification of the order of priority in which the various water uses 

are to be protected where more than 

one water use may be adversely affected as a result of an oil discharge 

and where response operations may not 

be adequate to protect all uses. 

(e) Specific and well defined procedures to facilitate recovery of damages 

and enforcement measures as provided 

for by State and local statutes and ordinances. 

§ 109.6 Coordination. 

For the purposes of coordination, the 

contingency plans of State and local 

governments should be developed and 

implemented in consultation with private interests. A copy of any oil removal contingency plan developed by 

§ 110.1 

State and local governments should be 

forwarded to the Council on Environmental Quality upon request to facilitate the coordination of these contingency plans with the National Oil and 

Hazardous Materials Pollution Contingency Plan. 

PART 110—DISCHARGE OF OIL 

Sec. 
 

110.1 Definitions. 
 

110.2 Applicability. 
 

110.3 Discharge of oil in such quantities as 
 

‘‘may be harmful’’ pursuant to section 

311(b)(4) of the Act. 

110.4 Dispersants. 

110.5 Discharges of oil not determined ‘‘as 

may be harmful’’ pursuant to section 

311(b)(3) of the Act. 


110.6 Notice. 


AUTHORITY: 33 U.S.C. 1321(b)(3) and (b)(4) 

and 1361(a); E.O. 11735, 38 FR 21243, 3 CFR 

Parts 1971–1975 Comp., p. 793. 

SOURCE: 52 FR 10719, Apr. 2, 1987, unless 

otherwise noted. 

§ 110.1 Definitions. 

Terms not defined in this section 

have the same meaning given by the 

Section 311 of the Act. As used in this 

part, the following terms shall have 

the meaning indicated below: 

Act means the Federal Water Pollution Control Act, as amended, 33 U.S.C. 

1251 et seq., also known as the Clean 

Water Act; 

Administrator means the Administrator of the Environmental Protection 

Agency (EPA); 

Applicable water quality standards 

means State water quality standards 

adopted by the State pursuant to section 303 of the Act or promulgated by 

EPA pursuant to that section; 

MARPOL 73/78 means the International Convention for the Prevention 

of Pollution from Ships, 1973, as modified by the Protocol of 1978 relating 

thereto, Annex I, which regulates pollution from oil and which entered into 

force on October 2, 1983; 

Navigable waters means the waters of 

the United States, including the territorial seas. The term includes: 

(a) All waters that are currently 

used, were used in the past, or may be 

susceptible to use in interstate or foreign commerce, including all waters 

17 
 

§ 110.2 

that are subject to the ebb and flow of 

the tide; 

(b) Interstate waters, including interstate wetlands; 

(c) All other waters such as intrastate lakes, rivers, streams (including 

intermittent streams), mudflats, 

sandflats, and wetlands, the use, degradation, or destruction of which would 

affect or could affect interstate or foreign commerce including any such waters: 

(1) That are or could be used by interstate or foreign travelers for recreational or other purposes; 

(2) From which fish or shellfish are or 

could be taken and sold in interstate or 

foreign commerce; 

(3) That are used or could be used for 

industrial purposes by industries in 

interstate commerce; 

(d) All impoundments of waters otherwise defined as navigable waters 

under this section; 

(e) Tributaries of waters identified in 

paragraphs (a) through (d) of this section, including adjacent wetlands; and 

(f) Wetlands adjacent to waters identified in paragraphs (a) through (e) of 

this section: Provided, That waste 

treatment systems (other than cooling 

ponds meeting the criteria of this paragraph) are not waters of the United 

States; 

Navigable waters do not include prior 

converted cropland. Notwithstanding 

the determination of an area’s status 

as prior converted cropland by any 

other federal agency, for the purposes 

of the Clean Water Act, the final authority regarding Clean Water Act jurisdiction remains with EPA. 

NPDES means National Pollutant 

Discharge Elimination System; 

Sheen means an iridescent appearance on the surface of water; 

Sludge means an aggregate of oil or 

oil and other matter of any kind in any 

form other than dredged spoil having a 

combined specific gravity equivalent to 

or greater than water; 

United States means the States, the 

District of Columbia, the Commonwealth of Puerto Rico, Guam, American Samoa, the Virgin Islands, and the 

Trust Territory of the Pacific Islands; 

Wetlands means those areas that are 

inundated or saturated by surface or 

ground water at a frequency or dura40 CFR Ch. I (7–1–05 Edition) 

tion sufficient to support, and that 

under normal circumstances do support, a prevalence of vegetation typically adapted for life in saturated soil 

conditions. Wetlands generally include 

playa lakes, swamps, marshes, bogs 

and similar areas such as sloughs, prairie potholes, wet meadows, prairie 

river overflows, mudflats, and natural 

ponds. 

[52 FR 10719, Apr. 2, 1987, as amended at 58 

FR 45039, Aug. 25, 1993; 61 FR 7421, Feb. 28, 

1996] 

§ 110.2 Applicability. 

The regulations of this part apply to 

the discharge of oil prohibited by section 311(b)(3) of the Act. 

[61 FR 7421, Feb. 28, 1996] 

§ 110.3 Discharge of oil in such quantities as ‘‘may be harmful’’ pursuant 

to section 311(b)(4) of the Act. 

For purposes of section 311(b)(4) of 

the Act, discharges of oil in such quantities that the Administrator has determined may be harmful to the public 

health or welfare or the environment of 

the United States include discharges of 

oil that: 

(a) Violate applicable water quality 

standards; or 

(b) Cause a film or sheen upon or discoloration of the surface of the water 

or adjoining shorelines or cause a 

sludge or emulsion to be deposited beneath the surface of the water or upon 

adjoining shorelines. 

[61 FR 7421, Feb. 28, 1996] 

§110.4 Dispersants. 

Addition of dispersants or emulsifiers 

to oil to be discharged that would circumvent the provisions of this part is 

prohibited. 

[52 FR 10719, Apr. 2, 1987. Redesignated at 61 

FR 7421, Feb. 28, 1996] 

§ 110.5 Discharges of oil not determined ‘‘as may be harmful’’ pursuant to Section 311(b)(3) of the Act. 

Notwithstanding any other provisions of this part, the Administrator 

has not determined the following discharges of oil ‘‘as may be harmful’’ for 

purposes of section 311(b) of the Act: 

(a) Discharges of oil from a properly 

functioning vessel engine (including an 

18 
 

Environmental Protection Agency 

engine on a public vessel) and any discharges of such oil accumulated in the 

bilges of a vessel discharged in compliance with MARPOL 73/78, Annex I, as 

provided in 33 CFR part 151, subpart A; 

(b) Other discharges of oil permitted 

under MARPOL 73/78, Annex I, as provided in 33 CFR part 151, subpart A; and 

(c) Any discharge of oil explicitly 

permitted by the Administrator in connection with research, demonstration 

projects, or studies relating to the prevention, control, or abatement of oil 

pollution. 

[61 FR 7421, Feb. 28, 1996] 

§ 110.6 Notice. 

Any person in charge of a vessel or of 

an onshore or offshore facility shall, as 

soon as he or she has knowledge of any 

discharge of oil from such vessel or facility in violation of section 311(b)(3) of 

the Act, immediately notify the National Response Center (NRC) (800–424– 

8802; in the Washington, DC metropolitan area, 202–426–2675). If direct reporting to the NRC is not practicable, reports may be made to the Coast Guard 

or EPA predesignated On-Scene Coordinator (OSC) for the geographic area 

where the discharge occurs. All such 

reports shall be promptly relayed to 

the NRC. If it is not possible to notify 

the NRC or the predesignated OCS immediately, reports may be made immediately to the nearest Coast Guard 

unit, provided that the person in 

charge of the vessel or onshore or offshore facility notifies the NRC as soon 

as possible. The reports shall be made 

in accordance with such procedures as 

the Secretary of Transportation may 

prescribe. The procedures for such notice are set forth in U.S. Coast Guard 

regulations, 33 CFR part 153, subpart B 

and in the National Oil and Hazardous 

Substances Pollution Contingency 

Plan, 40 CFR part 300, subpart E. 

(Approved by the Office of Management and 

Budget under control number 2050–0046) 

[52 FR 10719, Apr. 2, 1987. Redesignated and 

amended at 61 FR 7421, Feb. 28, 1996; 61 FR 

14032, Mar. 29, 1996] 

Pt. 112 

PART 112—OIL POLLUTION 

PREVENTION 

Sec. 

Subpart A—Applicability, Definitions, and 

General Requirements For All Facilities 

and All Types of Oils 

112.1 General applicability. 

112.2 Definitions. 

112.3 Requirement to prepare and implement a Spill Prevention, Control, and 

Countermeasure Plan. 

112.4 Amendment of Spill Prevention, Control, and Countermeasure Plan by Regional Administrator. 

112.5 Amendment of Spill Prevention, Control, and Countermeasure Plan by owners 

or operators. 

112.6 [Reserved] 

112.7 General requirements for Spill Prevention, Control, and Countermeasure 

Plans. 

Subpart B—Requirements for Petroleum 

Oils and Non-Petroleum Oils, Except 

Animal Fats and Oils and Greases, 

and Fish and Marine Mammal Oils; 

and Vegetable Oils (Including Oils 

from Seeds, Nuts, Fruits, and Kernels) 

112.8 Spill Prevention, Control, and Countermeasure Plan requirements for onshore facilities (excluding production facilities). 

112.9 Spill Prevention, Control, and Countermeasure Plan requirements for onshore oil production facilities. 

112.10 Spill Prevention, Control, and Countermeasure Plan requirements for onshore oil drilling and workover facilities. 

112.11 Spill Prevention, Control, and Countermeasure Plan requirements for offshore oil drilling, production, or 

workover facilities. 

Subpart C—Requirements for Animal Fats 

and Oils and Greases, and Fish and 

Marine Mammal Oils; and for Vegetable Oils, Including Oils from Seeds, 

Nuts, Fruits and Kernels 

112.12 Spill Prevention, Control, and Countermeasure Plan requirements for onshore facilities (excluding production facilities). 

112.13 Spill Prevention, Control, and Countermeasure Plan requirements for onshore oil production facilities. 

112.14 Spill Prevention, Control, and Countermeasure Plan requirements for onshore oil drilling and workover facilities. 

19 
 
SPCC Guidance for Regional Inspectors 

This page intentionally left blank. 

U.S. Environmental Protection Agency Version 1.0, 11/28/2005 

Environmental Protection Agency 

engine on a public vessel) and any discharges of such oil accumulated in the 

bilges of a vessel discharged in compliance with MARPOL 73/78, Annex I, as 

provided in 33 CFR part 151, subpart A; 

(b) Other discharges of oil permitted 

under MARPOL 73/78, Annex I, as provided in 33 CFR part 151, subpart A; and 

(c) Any discharge of oil explicitly 

permitted by the Administrator in connection with research, demonstration 

projects, or studies relating to the prevention, control, or abatement of oil 

pollution. 

[61 FR 7421, Feb. 28, 1996] 

§ 110.6 Notice. 

Any person in charge of a vessel or of 

an onshore or offshore facility shall, as 

soon as he or she has knowledge of any 

discharge of oil from such vessel or facility in violation of section 311(b)(3) of 

the Act, immediately notify the National Response Center (NRC) (800–424– 

8802; in the Washington, DC metropolitan area, 202–426–2675). If direct reporting to the NRC is not practicable, reports may be made to the Coast Guard 

or EPA predesignated On-Scene Coordinator (OSC) for the geographic area 

where the discharge occurs. All such 

reports shall be promptly relayed to 

the NRC. If it is not possible to notify 

the NRC or the predesignated OCS immediately, reports may be made immediately to the nearest Coast Guard 

unit, provided that the person in 

charge of the vessel or onshore or offshore facility notifies the NRC as soon 

as possible. The reports shall be made 

in accordance with such procedures as 

the Secretary of Transportation may 

prescribe. The procedures for such notice are set forth in U.S. Coast Guard 

regulations, 33 CFR part 153, subpart B 

and in the National Oil and Hazardous 

Substances Pollution Contingency 

Plan, 40 CFR part 300, subpart E. 

(Approved by the Office of Management and 

Budget under control number 2050–0046) 

[52 FR 10719, Apr. 2, 1987. Redesignated and 

amended at 61 FR 7421, Feb. 28, 1996; 61 FR 

14032, Mar. 29, 1996] 

Pt. 112 

PART 112—OIL POLLUTION 

PREVENTION 

Sec. 

Subpart A—Applicability, Definitions, and 

General Requirements For All Facilities 

and All Types of Oils 

112.1 General applicability. 

112.2 Definitions. 

112.3 Requirement to prepare and implement a Spill Prevention, Control, and 

Countermeasure Plan. 

112.4 Amendment of Spill Prevention, Control, and Countermeasure Plan by Regional Administrator. 

112.5 Amendment of Spill Prevention, Control, and Countermeasure Plan by owners 

or operators. 

112.6 [Reserved] 

112.7 General requirements for Spill Prevention, Control, and Countermeasure 

Plans. 

Subpart B—Requirements for Petroleum 

Oils and Non-Petroleum Oils, Except 

Animal Fats and Oils and Greases, 

and Fish and Marine Mammal Oils; 

and Vegetable Oils (Including Oils 

from Seeds, Nuts, Fruits, and Kernels) 

112.8 Spill Prevention, Control, and Countermeasure Plan requirements for onshore facilities (excluding production facilities). 

112.9 Spill Prevention, Control, and Countermeasure Plan requirements for onshore oil production facilities. 

112.10 Spill Prevention, Control, and Countermeasure Plan requirements for onshore oil drilling and workover facilities. 

112.11 Spill Prevention, Control, and Countermeasure Plan requirements for offshore oil drilling, production, or 

workover facilities. 

Subpart C—Requirements for Animal Fats 

and Oils and Greases, and Fish and 

Marine Mammal Oils; and for Vegetable Oils, Including Oils from Seeds, 

Nuts, Fruits and Kernels 

112.12 Spill Prevention, Control, and Countermeasure Plan requirements for onshore facilities (excluding production facilities). 

112.13 Spill Prevention, Control, and Countermeasure Plan requirements for onshore oil production facilities. 

112.14 Spill Prevention, Control, and Countermeasure Plan requirements for onshore oil drilling and workover facilities. 

19 
 

§ 112.1 

112.15 Spill Prevention, Control, and Countermeasure Plan requirements for offshore oil drilling, production, or 

workover facilities. 

Subpart D—Response Requirements 

112.20 Facility response plans. 

112.21 Facility response training and drills/ 

exercises. 

APPENDIX A TO PART 112—MEMORANDUM OF 

UNDERSTANDING BETWEEN THE SECRETARY 

OF TRANSPORTATION AND THE ADMINISTRATOR OF THE ENVIRONMENTAL PROTECTION AGENCY 

APPENDIX B TO PART 112—MEMORANDUM OF 

UNDERSTANDING AMONG THE SECRETARY 

OF THE INTERIOR, SECRETARY OF TRANSPORTATION, AND ADMINISTRATOR OF THE 

ENVIRONMENTAL PROTECTION AGENCY 

APPENDIX C TO PART 112—SUBSTANTIAL HARM 

CRITERIA 

APPENDIX D TO PART 112—DETERMINATION OF 

A WORST CASE DISCHARGE PLANNING VOLUME 

APPENDIX E TO PART 112—DETERMINATION 

AND EVALUATION OF REQUIRED RESPONSE 

RESOURCES FOR FACILITY RESPONSE 

PLANS 

APPENDIX F TO PART 112—FACILITY-SPECIFIC 

RESPONSE PLAN 

AUTHORITY: 33 U.S.C. 1251 et seq.; 33 U.S.C. 

2720; E.O. 12777 (October 18, 1991), 3 CFR, 1991 

Comp., p. 351. 

SOURCE: 38 FR 34165, Dec. 11, 1973, unless 

otherwise noted. 

EDITORIAL NOTE: Nomenclature changes to 

part 112 appear at 65 FR 40798, June 30, 2000. 

Subpart A—Applicability, Definitions, and General Requirements for All Facilities and All 

Types of Oils 

SOURCE: 67 FR 47140, July 17, 2002, unless 

otherwise noted. 

§ 112.1 General applicability. 

(a)(1) This part establishes procedures, methods, equipment, and other 

requirements to prevent the discharge 

of oil from non-transportation-related 

onshore and offshore facilities into or 

upon the navigable waters of the 

United States or adjoining shorelines, 

or into or upon the waters of the contiguous zone, or in connection with activities under the Outer Continental 

Shelf Lands Act or the Deepwater Port 

Act of 1974, or that may affect natural 

resources belonging to, appertaining 

40 CFR Ch. I (7–1–05 Edition) 

to, or under the exclusive management 

authority of the United States (including resources under the Magnuson 

Fishery Conservation and Management 

Act). 

(2) As used in this part, words in the 

singular also include the plural and 

words in the masculine gender also include the feminine and vice versa, as 

the case may require. 

(b) Except as provided in paragraph 

(d) of this section, this part applies to 

any owner or operator of a non-transportation-related onshore or offshore 

facility engaged in drilling, producing, 

gathering, storing, processing, refining, 

transferring, distributing, using, or 

consuming oil and oil products, which 

due to its location, could reasonably be 

expected to discharge oil in quantities 

that may be harmful, as described in 

part 110 of this chapter, into or upon 

the navigable waters of the United 

States or adjoining shorelines, or into 

or upon the waters of the contiguous 

zone, or in connection with activities 

under the Outer Continental Shelf 

Lands Act or the Deepwater Port Act 

of 1974, or that may affect natural resources belonging to, appertaining to, 

or under the exclusive management authority of the United States (including 

resources under the Magnuson Fishery 

Conservation and Management Act) 

that has oil in: 

(1) Any aboveground container; 

(2) Any completely buried tank as defined in § 112.2; 

(3) Any container that is used for 

standby storage, for seasonal storage, 

or for temporary storage, or not otherwise ‘‘permanently closed’’ as defined 

in § 112.2; 

(4) Any ‘‘bunkered tank’’ or ‘‘partially buried tank’’ as defined in § 112.2, 

or any container in a vault, each of 

which is considered an aboveground 

storage container for purposes of this 

part. 

(c) As provided in section 313 of the 

Clean Water Act (CWA), departments, 

agencies, and instrumentalities of the 

Federal government are subject to this 

part to the same extent as any person. 

(d) Except as provided in paragraph 

(f) of this section, this part does not 

apply to: 

(1) The owner or operator of any facility, equipment, or operation that is 

20 
 

Environmental Protection Agency 

not subject to the jurisdiction of the 

Environmental Protection Agency 

(EPA) under section 311(j)(1)(C) of the 

CWA, as follows: 

(i) Any onshore or offshore facility, 

that due to its location, could not reasonably be expected to have a discharge as described in paragraph (b) of 

this section. This determination must 

be based solely upon consideration of 

the geographical and location aspects 

of the facility (such as proximity to 

navigable waters or adjoining shorelines, land contour, drainage, etc.) and 

must exclude consideration of manmade features such as dikes, equipment 

or other structures, which may serve 

to restrain, hinder, contain, or otherwise prevent a discharge as described 

in paragraph (b) of this section. 

(ii) Any equipment, or operation of a 

vessel or transportation-related onshore or offshore facility which is subject to the authority and control of the 

U.S. Department of Transportation, as 

defined in the Memorandum of Understanding between the Secretary of 

Transportation and the Administrator 

of EPA, dated November 24, 1971 (Appendix A of this part). 

(iii) Any equipment, or operation of a 

vessel or onshore or offshore facility 

which is subject to the authority and 

control of the U.S. Department of 

Transportation or the U.S. Department 

of the Interior, as defined in the Memorandum of Understanding between the 

Secretary of Transportation, the Secretary of the Interior, and the Administrator of EPA, dated November 8, 1993 

(Appendix B of this part). 

(2) Any facility which, although otherwise subject to the jurisdiction of 

EPA, meets both of the following requirements: 

(i) The completely buried storage capacity of the facility is 42,000 gallons or 

less of oil. For purposes of this exemption, the completely buried storage capacity of a facility excludes the capacity of a completely buried tank, as defined in § 112.2, and connected underground piping, underground ancillary 

equipment, and containment systems, 

that is currently subject to all of the 

technical requirements of part 280 of 

this chapter or all of the technical requirements of a State program approved under part 281 of this chapter. 

§ 112.1 

The completely buried storage capacity of a facility also excludes the capacity of a container that is ‘‘permanently closed,’’ as defined in § 112.2. 

(ii) The aggregate aboveground storage capacity of the facility is 1,320 gallons or less of oil. For purposes of this 

exemption, only containers of oil with 

a capacity of 55 gallons or greater are 

counted. The aggregate aboveground 

storage capacity of a facility excludes 

the capacity of a container that is 

‘‘permanently closed,’’ as defined in 

§ 112.2. 

(3) Any offshore oil drilling, production, or workover facility that is subject to the notices and regulations of 

the Minerals Management Service, as 

specified in the Memorandum of Understanding between the Secretary of 

Transportation, the Secretary of the 

Interior, and the Administrator of 

EPA, dated November 8, 1993 (Appendix 

B of this part). 

(4) Any completely buried storage 

tank, as defined in § 112.2, and connected underground piping, underground ancillary equipment, and containment systems, at any facility, that 

is subject to all of the technical requirements of part 280 of this chapter 

or a State program approved under 

part 281 of this chapter, except that 

such a tank must be marked on the facility diagram as provided in 

§ 112.7(a)(3), if the facility is otherwise 

subject to this part. 

(5) Any container with a storage capacity of less than 55 gallons of oil. 

(6) Any facility or part thereof used 

exclusively for wastewater treatment 

and not used to satisfy any requirement of this part. The production, recovery, or recycling of oil is not wastewater treatment for purposes of this 

paragraph. 

(e) This part establishes requirements for the preparation and implementation of Spill Prevention, Control, 

and Countermeasure (SPCC) Plans. 

SPCC Plans are designed to complement existing laws, regulations, 

rules, standards, policies, and procedures pertaining to safety standards, 

fire prevention, and pollution prevention rules. The purpose of an SPCC 

Plan is to form a comprehensive Federal/State spill prevention program 

21 
 

§ 112.2 

that minimizes the potential for discharges. The SPCC Plan must address 

all relevant spill prevention, control, 

and countermeasures necessary at the 

specific facility. Compliance with this 

part does not in any way relieve the 

owner or operator of an onshore or an 

offshore facility from compliance with 

other Federal, State, or local laws. 

(f) Notwithstanding paragraph (d) of 

this section, the Regional Administrator may require that the owner or 

operator of any facility subject to the 

jurisdiction of EPA under section 311(j) 

of the CWA prepare and implement an 

SPCC Plan, or any applicable part, to 

carry out the purposes of the CWA. 

(1) Following a preliminary determination, the Regional Administrator 

must provide a written notice to the 

owner or operator stating the reasons 

why he must prepare an SPCC Plan, or 

applicable part. The Regional Administrator must send such notice to the 

owner or operator by certified mail or 

by personal delivery. If the owner or 

operator is a corporation, the Regional 

Administrator must also mail a copy of 

such notice to the registered agent, if 

any and if known, of the corporation in 

the State where the facility is located. 

(2) Within 30 days of receipt of such 

written notice, the owner or operator 

may provide information and data and 

may consult with the Agency about the 

need to prepare an SPCC Plan, or applicable part. 

(3) Within 30 days following the time 

under paragraph (b)(2) of this section 

within which the owner or operator 

may provide information and data and 

consult with the Agency about the 

need to prepare an SPCC Plan, or applicable part, the Regional Administrator 

must make a final determination regarding whether the owner or operator 

is required to prepare and implement 

an SPCC Plan, or applicable part. The 

Regional Administrator must send the 

final determination to the owner or operator by certified mail or by personal 

delivery. If the owner or operator is a 

corporation, the Regional Administrator must also mail a copy of the 

final determination to the registered 

agent, if any and if known, of the corporation in the State where the facility 

is located. 

40 CFR Ch. I (7–1–05 Edition) 

(4) If the Regional Administrator 

makes a final determination that an 

SPCC Plan, or applicable part, is necessary, the owner or operator must prepare the Plan, or applicable part, within six months of that final determination and implement the Plan, or applicable part, as soon as possible, but not 

later than one year after the Regional 

Administrator has made a final determination. 

(5) The owner or operator may appeal 

a final determination made by the Regional Administrator requiring preparation and implementation of an SPCC 

Plan, or applicable part, under this 

paragraph. The owner or operator must 

make the appeal to the Administrator 

of EPA within 30 days of receipt of the 

final determination under paragraph 

(b)(3) of this section from the Regional 

Administrator requiring preparation 

and/or implementation of an SPCC 

Plan, or applicable part. The owner or 

operator must send a complete copy of 

the appeal to the Regional Administrator at the time he makes the appeal 

to the Administrator. The appeal must 

contain a clear and concise statement 

of the issues and points of fact in the 

case. In the appeal, the owner or operator may also provide additional information. The additional information 

may be from any person. The Administrator may request additional information from the owner or operator. The 

Administrator must render a decision 

within 60 days of receiving the appeal 

or additional information submitted by 

the owner or operator and must serve 

the owner or operator with the decision 

made in the appeal in the manner described in paragraph (f)(1) of this section. 

§ 112.2 Definitions. 

For the purposes of this part: 

Adverse weather means weather conditions that make it difficult for response equipment and personnel to 

clean up or remove spilled oil, and that 

must be considered when identifying 

response systems and equipment in a 

response plan for the applicable operating environment. Factors to consider 

include significant wave height as 

specified in Appendix E to this part (as 

appropriate), ice conditions, temperatures, weather-related visibility, and 

22 
 

Environmental Protection Agency 

currents within the area in which the 

systems or equipment is intended to 

function. 

Alteration means any work on a container involving cutting, burning, 

welding, or heating operations that 

changes the physical dimensions or 

configuration of the container. 

Animal fat means a non-petroleum 

oil, fat, or grease of animal, fish, or 

marine mammal origin. 

Breakout tank means a container used 

to relieve surges in an oil pipeline system or to receive and store oil transported by a pipeline for reinjection and 

continued transportation by pipeline. 

Bulk storage container means any container used to store oil. These containers are used for purposes including, 

but not limited to, the storage of oil 

prior to use, while being used, or prior 

to further distribution in commerce. 

Oil-filled electrical, operating, or manufacturing equipment is not a bulk 

storage container. 

Bunkered tank means a container 

constructed or placed in the ground by 

cutting the earth and re-covering the 

container in a manner that breaks the 

surrounding natural grade, or that lies 

above grade, and is covered with earth, 

sand, gravel, asphalt, or other material. A bunkered tank is considered an 

aboveground storage container for purposes of this part. 

Completely buried tank means any 

container completely below grade and 

covered with earth, sand, gravel, asphalt, or other material. Containers in 

vaults, bunkered tanks, or partially 

buried tanks are considered aboveground storage containers for purposes 

of this part. 

Complex means a facility possessing a 

combination of transportation-related 

and non-transportation-related components that is subject to the jurisdiction 

of more than one Federal agency under 

section 311(j) of the CWA. 

Contiguous zone means the zone established by the United States under 

Article 24 of the Convention of the Territorial Sea and Contiguous Zone, that 

is contiguous to the territorial sea and 

that extends nine miles seaward from 

the outer limit of the territorial area. 

Contract or other approved means 

means: 

§ 112.2 

(1) A written contractual agreement 

with an oil spill removal organization 

that identifies and ensures the availability of the necessary personnel and 

equipment within appropriate response 

times; and/or 

(2) A written certification by the 

owner or operator that the necessary 

personnel and equipment resources, 

owned or operated by the facility 

owner or operator, are available to respond to a discharge within appropriate response times; and/or 

(3) Active membership in a local or 

regional oil spill removal organization 

that has identified and ensures adequate access through such membership 

to necessary personnel and equipment 

to respond to a discharge within appropriate response times in the specified 

geographic area; and/or 

(4) Any other specific arrangement 

approved by the Regional Administrator upon request of the owner or operator. 

Discharge includes, but is not limited 

to, any spilling, leaking, pumping, 

pouring, emitting, emptying, or dumping of oil, but excludes discharges in 

compliance with a permit under section 402 of the CWA; discharges resulting from circumstances identified, reviewed, and made a part of the public 

record with respect to a permit issued 

or modified under section 402 of the 

CWA, and subject to a condition in 

such permit; or continuous or anticipated intermittent discharges from a 

point source, identified in a permit or 

permit application under section 402 of 

the CWA, that are caused by events occurring within the scope of relevant operating or treatment systems. For purposes of this part, the term discharge 

shall not include any discharge of oil 

that is authorized by a permit issued 

under section 13 of the River and Harbor Act of 1899 (33 U.S.C. 407). 

Facility means any mobile or fixed, 

onshore or offshore building, structure, 

installation, equipment, pipe, or pipeline (other than a vessel or a public 

vessel) used in oil well drilling operations, oil production, oil refining, oil 

storage, oil gathering, oil processing, 

oil transfer, oil distribution, and waste 

treatment, or in which oil is used, as 

described in Appendix A to this part. 

The boundaries of a facility depend on 

23 
 

§ 112.2 

several site-specific factors, including, 

but not limited to, the ownership or 

operation of buildings, structures, and 

equipment on the same site and the 

types of activity at the site. 

Fish and wildlife and sensitive environments means areas that may be identified by their legal designation or by 

evaluations of Area Committees (for 

planning) or members of the Federal 

On-Scene Coordinator’s spill response 

structure (during responses). These 

areas may include wetlands, National 

and State parks, critical habitats for 

endangered or threatened species, wilderness and natural resource areas, 

marine sanctuaries and estuarine reserves, conservation areas, preserves, 

wildlife areas, wildlife refuges, wild 

and scenic rivers, recreational areas, 

national forests, Federal and State 

lands that are research national areas, 

heritage program areas, land trust 

areas, and historical and archaeological sites and parks. These areas 

may also include unique habitats such 

as aquaculture sites and agricultural 

surface water intakes, bird nesting 

areas, critical biological resource 

areas, designated migratory routes, 

and designated seasonal habitats. 

Injury means a measurable adverse 

change, either long- or short-term, in 

the chemical or physical quality or the 

viability of a natural resource resulting either directly or indirectly from 

exposure to a discharge, or exposure to 

a product of reactions resulting from a 

discharge. 

Maximum extent practicable means 

within the limitations used to determine oil spill planning resources and 

response times for on-water recovery, 

shoreline protection, and cleanup for 

worst case discharges from onshore 

non-transportation-related facilities in 

adverse weather. It includes the 

planned capability to respond to a 

worst case discharge in adverse weather, as contained in a response plan that 

meets the requirements in § 112.20 or in 

a specific plan approved by the Regional Administrator. 

Navigable waters means the waters of 

the United States, including the territorial seas. 

(1) The term includes: 

(i) All waters that are currently used, 

were used in the past, or may be sus40 CFR Ch. I (7–1–05 Edition) 

ceptible to use in interstate or foreign 

commerce, including all waters subject 

to the ebb and flow of the tide; 

(ii) All interstate waters, including 

interstate wetlands; 

(iii) All other waters such as intrastate lakes, rivers, streams (including 

intermittent streams), mudflats, 

sandflats, wetlands, sloughs, prairie 

potholes, wet meadows, playa lakes, or 

natural ponds, the use, degradation, or 

destruction of which could affect interstate or foreign commerce including 

any such waters: 

(A) That are or could be used by 

interstate or foreign travelers for recreational or other purposes; or 

(B) From which fish or shellfish are 

or could be taken and sold in interstate 

or foreign commerce; or, 

(C) That are or could be used for industrial purposes by industries in 

interstate commerce; 

(iv) All impoundments of waters otherwise defined as waters of the United 

States under this section; 

(v) Tributaries of waters identified in 

paragraphs (1)(i) through (iv) of this 

definition; 

(vi) The territorial sea; and 

(vii) Wetlands adjacent to waters 

(other than waters that are themselves 

wetlands) identified in paragraph (1) of 

this definition. 

(2) Waste treatment systems, including treatment ponds or lagoons designed to meet the requirements of the 

CWA (other than cooling ponds which 

also meet the criteria of this definition) are not waters of the United 

States. Navigable waters do not include prior converted cropland. Notwithstanding the determination of an 

area’s status as prior converted cropland by any other Federal agency, for 

the purposes of the CWA, the final authority regarding CWA jurisdiction remains with EPA. 

Non-petroleum oil means oil of any 

kind that is not petroleum-based, including but not limited to: Fats, oils, 

and greases of animal, fish, or marine 

mammal origin; and vegetable oils, including oils from seeds, nuts, fruits, 

and kernels. 

Offshore facility means any facility of 

any kind (other than a vessel or public 

vessel) located in, on, or under any of 

the navigable waters of the United 

24 
 

Environmental Protection Agency 

States, and any facility of any kind 

that is subject to the jurisdiction of 

the United States and is located in, on, 

or under any other waters. 

Oil means oil of any kind or in any 

form, including, but not limited to: 

fats, oils, or greases of animal, fish, or 

marine mammal origin; vegetable oils, 

including oils from seeds, nuts, fruits, 

or kernels; and, other oils and greases, 

including petroleum, fuel oil, sludge, 

synthetic oils, mineral oils, oil refuse, 

or oil mixed with wastes other than 

dredged spoil. 

Oil Spill Removal Organization means 

an entity that provides oil spill response resources, and includes any forprofit or not-for-profit contractor, cooperative, or in-house response resources that have been established in a 

geographic area to provide required response resources. 

Onshore facility means any facility of 

any kind located in, on, or under any 

land within the United States, other 

than submerged lands. 

Owner or operator means any person 

owning or operating an onshore facility 

or an offshore facility, and in the case 

of any abandoned offshore facility, the 

person who owned or operated or maintained the facility immediately prior 

to such abandonment. 

Partially buried tank means a storage 

container that is partially inserted or 

constructed in the ground, but not entirely below grade, and not completely 

covered with earth, sand, gravel, asphalt, or other material. A partially 

buried tank is considered an aboveground storage container for purposes 

of this part. 

Permanently closed means any container or facility for which: 

(1) All liquid and sludge has been removed from each container and connecting line; and 

(2) All connecting lines and piping 

have been disconnected from the container and blanked off, all valves (except for ventilation valves) have been 

closed and locked, and conspicuous 

signs have been posted on each container stating that it is a permanently 

closed container and noting the date of 

closure. 

Person includes an individual, firm, 

corporation, association, or partnership. 

§ 112.2 

Petroleum oil means petroleum in any 

form, including but not limited to 

crude oil, fuel oil, mineral oil, sludge, 

oil refuse, and refined products. 

Production facility means all structures (including but not limited to 

wells, platforms, or storage facilities), 

piping (including but not limited to 

flowlines or gathering lines), or equipment (including but not limited to 

workover equipment, separation equipment, or auxiliary non-transportationrelated equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of oil, 

or associated storage or measurement, 

and located in a single geographical oil 

or gas field operated by a single operator. 

Regional Administrator means the Regional Administrator of the Environmental Protection Agency, in and for 

the Region in which the facility is located. 

Repair means any work necessary to 

maintain or restore a container to a 

condition suitable for safe operation, 

other than that necessary for ordinary, 

day-to-day maintenance to maintain 

the functional integrity of the container and that does not weaken the 

container. 

Spill Prevention, Control, and Countermeasure Plan; SPCC Plan, or Plan means 

the document required by § 112.3 that 

details the equipment, workforce, procedures, and steps to prevent, control, 

and provide adequate countermeasures 

to a discharge. 

Storage capacity of a container means 

the shell capacity of the container. 

Transportation-related and non-transportation-related, as applied to an onshore or offshore facility, are defined 

in the Memorandum of Understanding 

between the Secretary of Transportation and the Administrator of the 

Environmental Protection Agency, 

dated November 24, 1971, (Appendix A 

of this part). 

United States means the States, the 

District of Columbia, the Commonwealth of Puerto Rico, the Commonwealth of the Northern Mariana Islands, Guam, American Samoa, the 

U.S. Virgin Islands, and the Pacific Island Governments. 

Vegetable oil means a non-petroleum 

oil or fat of vegetable origin, including 

25 
 

§ 112.3 

but not limited to oils and fats derived 

from plant seeds, nuts, fruits, and kernels. 

Vessel means every description of 

watercraft or other artificial contrivance used, or capable of being used, as 

a means of transportation on water, 

other than a public vessel. 

Wetlands means those areas that are 

inundated or saturated by surface or 

groundwater at a frequency or duration 

sufficient to support, and that under 

normal circumstances do support, a 

prevalence of vegetation typically 

adapted for life in saturated soil conditions. Wetlands generally include playa 

lakes, swamps, marshes, bogs, and 

similar areas such as sloughs, prairie 

potholes, wet meadows, prairie river 

overflows, mudflats, and natural ponds. 

Worst case discharge for an onshore 

non-transportation-related facility 

means the largest foreseeable discharge in adverse weather conditions 

as determined using the worksheets in 

Appendix D to this part. 

§ 112.3 Requirement to prepare and 

implement a Spill Prevention, Control, and Countermeasure Plan. 

The owner or operator of an onshore 

or offshore facility subject to this section must prepare a Spill Prevention, 

Control, and Countermeasure Plan 

(hereafter ‘‘SPCC Plan’’ or ‘‘Plan),’’ in 

writing, and in accordance with § 112.7, 

and any other applicable section of this 

part. 

(a) If your onshore or offshore facility was in operation on or before August 16, 2002, you must maintain your 

Plan, but must amend it, if necessary 

to ensure compliance with this part, on 

or before February 17, 2006, and must 

implement the amended Plan as soon 

as possible, but not later than August 

18, 2006. If your onshore or offshore facility becomes operational after August 16, 2002, through August 18, 2006, 

and could reasonably be expected to 

have a discharge as described in 

§ 112.1(b), you must prepare a Plan on 

or before August 18, 2006, and fully implement it as soon as possible, but not 

later than August 18, 2006. 

(b) If you are the owner or operator 

of an onshore or offshore facility that 

becomes operational after August 18, 

2006, and could reasonably be expected 

40 CFR Ch. I (7–1–05 Edition) 

to have a discharge as described in 

§ 112.1(b), you must prepare and implement a Plan before you begin operations. 

(c) If you are the owner or operator 

of an onshore or offshore mobile facility, such as an onshore drilling or 

workover rig, barge mounted offshore 

drilling or workover rig, or portable 

fueling facility, you must prepare, implement, and maintain a facility Plan 

as required by this section. You must 

maintain your Plan, but must amend 

and implement it, if necessary to ensure compliance with this part, on or 

before August 18, 2006. If your onshore 

or offshore mobile facility becomes 

operational after August 18, 2006, and 

could reasonably be expected to have a 

discharge as described in § 112.1(b), you 

must prepare and implement a Plan before you begin operations. This provision does not require that you prepare 

a new Plan each time you move the facility to a new site. The Plan may be a 

general Plan. When you move the mobile or portable facility, you must locate and install it using the discharge 

prevention practices outlined in the 

Plan for the facility. The Plan is applicable only while the facility is in a 

fixed (non-transportation) operating 

mode. 

(d) A licensed Professional Engineer 

must review and certify a Plan for it to 

be effective to satisfy the requirements 

of this part. 

(1) By means of this certification the 

Professional Engineer attests: 

(i) That he is familiar with the requirements of this part ; 

(ii) That he or his agent has visited 

and examined the facility; 

(iii) That the Plan has been prepared 

in accordance with good engineering 

practice, including consideration of applicable industry standards, and with 

the requirements of this part; 

(iv) That procedures for required inspections and testing have been established; and 

(v) That the Plan is adequate for the 

facility. 

(2) Such certification shall in no way 

relieve the owner or operator of a facility of his duty to prepare and fully implement such Plan in accordance with 

the requirements of this part. 

26 
 

Environmental Protection Agency 

(e) If you are the owner or operator 

of a facility for which a Plan is required under this section, you must: 

(1) Maintain a complete copy of the 

Plan at the facility if the facility is 

normally attended at least four hours 

per day, or at the nearest field office if 

the facility is not so attended, and 

(2) Have the Plan available to the Regional Administrator for on-site review 

during normal working hours. 

(f) Extension of time. (1) The Regional 

Administrator may authorize an extension of time for the preparation and 

full implementation of a Plan, or any 

amendment thereto, beyond the time 

permitted for the preparation, implementation, or amendment of a Plan 

under this part, when he finds that the 

owner or operator of a facility subject 

to this section, cannot fully comply 

with the requirements as a result of either nonavailability of qualified personnel, or delays in construction or 

equipment delivery beyond the control 

and without the fault of such owner or 

operator or his agents or employees. 

(2) If you are an owner or operator 

seeking an extension of time under 

paragraph (f)(1) of this section, you 

may submit a written extension request to the Regional Administrator. 

Your request must include: 

(i) A full explanation of the cause for 

any such delay and the specific aspects 

of the Plan affected by the delay; 

(ii) A full discussion of actions being 

taken or contemplated to minimize or 

mitigate such delay; and 

(iii) A proposed time schedule for the 

implementation of any corrective actions being taken or contemplated, including interim dates for completion of 

tests or studies, installation and operation of any necessary equipment, or 

other preventive measures. In addition 

you may present additional oral or 

written statements in support of your 

extension request. 

(3) The submission of a written extension request under paragraph (f)(2) 

of this section does not relieve you of 

your obligation to comply with the requirements of this part. The Regional 

Administrator may request a copy of 

your Plan to evaluate the extension request. When the Regional Administrator authorizes an extension of time 

for particular equipment or other spe-

§ 112.4 

cific aspects of the Plan, such extension does not affect your obligation to 

comply with the requirements related 

to other equipment or other specific aspects of the Plan for which the Regional Administrator has not expressly 

authorized an extension. 

[67 FR 47140, July 17, 2002, as amended at 68 

FR 1351, Jan. 9, 2003; 68 FR 18894, Apr. 17, 

2003; 69 FR 48798, Aug. 11, 2004] 

§ 112.4 Amendment of Spill Prevention, Control, and Countermeasure 

Plan by Regional Administrator. 

If you are the owner or operator of a 

facility subject to this part, you must: 

(a) Notwithstanding compliance with 

§ 112.3, whenever your facility has discharged more than 1,000 U.S. gallons of 

oil in a single discharge as described in 

§ 112.1(b), or discharged more than 42 

U.S. gallons of oil in each of two discharges as described in § 112.1(b), occurring within any twelve month period, 

submit the following information to 

the Regional Administrator within 60 

days from the time the facility becomes subject to this section: 

(1) Name of the facility; 

(2) Your name; 

(3) Location of the facility; 

(4) Maximum storage or handling capacity of the facility and normal daily 

throughput; 

(5) Corrective action and countermeasures you have taken, including a 

description of equipment repairs and 

replacements; 

(6) An adequate description of the facility, including maps, flow diagrams, 

and topographical maps, as necessary; 

(7) The cause of such discharge as described in § 112.1(b), including a failure 

analysis of the system or subsystem in 

which the failure occurred; 

(8) Additional preventive measures 

you have taken or contemplated to 

minimize the possibility of recurrence; 

and 

(9) Such other information as the Regional Administrator may reasonably 

require pertinent to the Plan or discharge. 

(b) Take no action under this section 

until it applies to your facility. This 

section does not apply until the expiration of the time permitted for the initial preparation and implementation of 

27 
 

§ 112.5 

the Plan under § 112.3, but not including 

any amendments to the Plan. 

(c) Send to the appropriate agency or 

agencies in charge of oil pollution control activities in the State in which the 

facility is located a complete copy of 

all information you provided to the Regional Administrator under paragraph 

(a) of this section. Upon receipt of the 

information such State agency or agencies may conduct a review and make 

recommendations to the Regional Administrator as to further procedures, 

methods, equipment, and other requirements necessary to prevent and to contain discharges from your facility. 

(d) Amend your Plan, if after review 

by the Regional Administrator of the 

information you submit under paragraph (a) of this section, or submission 

of information to EPA by the State 

agency under paragraph (c) of this section, or after on-site review of your 

Plan, the Regional Administrator requires that you do so. The Regional 

Administrator may require you to 

amend your Plan if he finds that it 

does not meet the requirements of this 

part or that amendment is necessary to 

prevent and contain discharges from 

your facility. 

(e) Act in accordance with this paragraph when the Regional Administrator proposes by certified mail or by 

personal delivery that you amend your 

SPCC Plan. If the owner or operator is 

a corporation, he must also notify by 

mail the registered agent of such corporation, if any and if known, in the 

State in which the facility is located. 

The Regional Administrator must 

specify the terms of such proposed 

amendment. Within 30 days from receipt of such notice, you may submit 

written information, views, and arguments on the proposed amendment. 

After considering all relevant material 

presented, the Regional Administrator 

must either notify you of any amendment required or rescind the notice. 

You must amend your Plan as required 

within 30 days after such notice, unless 

the Regional Administrator, for good 

cause, specifies another effective date. 

You must implement the amended Plan 

as soon as possible, but not later than 

six months after you amend your Plan, 

unless the Regional Administrator 

specifies another date. 

40 CFR Ch. I (7–1–05 Edition) 

(f) If you appeal a decision made by 

the Regional Administrator requiring 

an amendment to an SPCC Plan, send 

the appeal to the EPA Administrator 

in writing within 30 days of receipt of 

the notice from the Regional Administrator requiring the amendment under 

paragraph (e) of this section. You must 

send a complete copy of the appeal to 

the Regional Administrator at the 

time you make the appeal. The appeal 

must contain a clear and concise statement of the issues and points of fact in 

the case. It may also contain additional information from you, or from 

any other person. The EPA Administrator may request additional information from you, or from any other person. The EPA Administrator must 

render a decision within 60 days of receiving the appeal and must notify you 

of his decision. 

§ 112.5 Amendment of Spill Prevention, Control, and Countermeasure 

Plan by owners or operators. 

If you are the owner or operator of a 

facility subject to this part, you must: 

(a) Amend the SPCC Plan for your facility in accordance with the general 

requirements in § 112.7, and with any 

specific section of this part applicable 

to your facility, when there is a change 

in the facility design, construction, operation, or maintenance that materially affects its potential for a discharge as described in § 112.1(b). Examples of changes that may require 

amendment of the Plan include, but 

are not limited to: commissioning or 

decommissioning containers; replacement, reconstruction, or movement of 

containers; reconstruction, replacement, or installation of piping systems; 

construction or demolition that might 

alter secondary containment structures; changes of product or service; or 

revision of standard operation or maintenance procedures at a facility. An 

amendment made under this section 

must be prepared within six months, 

and implemented as soon as possible, 

but not later than six months following 

preparation of the amendment. 

(b) Notwithstanding compliance with 

paragraph (a) of this section, complete 

a review and evaluation of the SPCC 

Plan at least once every five years 

from the date your facility becomes 

28 
 

Environmental Protection Agency 

subject to this part; or, if your facility 

was in operation on or before August 

16, 2002, five years from the date your 

last review was required under this 

part. As a result of this review and 

evaluation, you must amend your 

SPCC Plan within six months of the review to include more effective prevention and control technology if the technology has been field-proven at the 

time of the review and will significantly reduce the likelihood of a discharge as described in § 112.1(b) from 

the facility. You must implement any 

amendment as soon as possible, but not 

later than six months following preparation of any amendment. You must 

document your completion of the review and evaluation, and must sign a 

statement as to whether you will 

amend the Plan, either at the beginning or end of the Plan or in a log or an 

appendix to the Plan. The following 

words will suffice, ‘‘I have completed 

review and evaluation of the SPCC 

Plan for (name of facility) on (date), 

and will (will not) amend the Plan as a 

result.’’ 

(c) Have a Professional Engineer certify any technical amendment to your 

Plan in accordance with § 112.3(d). 

§ 112.6 [Reserved] 

§ 112.7 General requirements for Spill

Prevention, Control, and Countermeasure Plans. 

If you are the owner or operator of a 

facility subject to this part you must 

prepare a Plan in accordance with good 

engineering practices. The Plan must 

have the full approval of management 

at a level of authority to commit the 

necessary resources to fully implement 

the Plan. You must prepare the Plan in 

writing. If you do not follow the sequence specified in this section for the 

Plan, you must prepare an equivalent 

Plan acceptable to the Regional Administrator that meets all of the applicable requirements listed in this part, 

and you must supplement it with a section cross-referencing the location of 

requirements listed in this part and the 

equivalent requirements in the other 

prevention plan. If the Plan calls for 

additional facilities or procedures, 

methods, or equipment not yet fully 

operational, you must discuss these 

items in separate paragraphs, and must 

§ 112.7 

explain separately the details of installation and operational start-up. As detailed elsewhere in this section, you 

must also: 

(a)(1) Include a discussion of your facility’s conformance with the requirements listed in this part. 

(2) Comply with all applicable requirements listed in this part. Your 

Plan may deviate from the requirements in paragraphs (g), (h)(2) and (3), 

and (i) of this section and the requirements in subparts B and C of this part, 

except the secondary containment requirements in paragraphs (c) and (h)(1) 

of this section, and 

§§ 112.8(c)(2),112.8(c)(11), 112.9(c)(2), 

112.10(c), 112.12(c)(2), 

112.12(c)(11),112.13(c)(2), and 112.14(c), 

where applicable to a specific facility, 

if you provide equivalent environmental protection by some other 

means of spill prevention, control, or 

countermeasure. Where your Plan does 

not conform to the applicable requirements in paragraphs (g), (h)(2) and (3), 

and (i) of this section, or the requirements of subparts B and C of this part, 

except the secondary containment requirements in paragraphs (c) and (h)(1) 

of this section, and §§ 112.8(c)(2), 

112.8(c)(11), 112.9(c)(2), 112.10(c), 

112.12(c)(2), 112.12(c)(11), 112.13(c)(2), and 

112.14(c), you must state the reasons for 

nonconformance in your Plan and describe in detail alternate methods and 

how you will achieve equivalent environmental protection. If the Regional 

Administrator determines that the 

measures described in your Plan do not 

provide equivalent environmental protection, he may require that you 

amend your Plan, following the procedures in § 112.4(d) and (e). 

(3) Describe in your Plan the physical 

layout of the facility and include a facility diagram, which must mark the 

location and contents of each container. The facility diagram must include completely buried tanks that are 

otherwise exempted from the requirements of this part under § 112.1(d)(4). 

The facility diagram must also include 

all transfer stations and connecting 

pipes. You must also address in your 

Plan: 

(i) The type of oil in each container 

and its storage capacity; 

29 
 

§ 112.7 

(ii) Discharge prevention measures 

including procedures for routine handling of products (loading, unloading, 

and facility transfers, etc.); 

(iii) Discharge or drainage controls 

such as secondary containment around 

containers and other structures, equipment, and procedures for the control of 

a discharge; 

(iv) Countermeasures for discharge 

discovery, response, and cleanup (both 

the facility’s capability and those that 

might be required of a contractor); 

(v) Methods of disposal of recovered 

materials in accordance with applicable legal requirements; and 

(vi) Contact list and phone numbers 

for the facility response coordinator, 

National Response Center, cleanup contractors with whom you have an agreement for response, and all appropriate 

Federal, State, and local agencies who 

must be contacted in case of a discharge as described in § 112.1(b). 

(4) Unless you have submitted a response plan under § 112.20, provide information and procedures in your Plan 

to enable a person reporting a discharge as described in § 112.1(b) to relate information on the exact address 

or location and phone number of the facility; the date and time of the discharge, the type of material discharged; estimates of the total quantity discharged; estimates of the quantity discharged as described in 

§ 112.1(b); the source of the discharge; a 

description of all affected media; the 

cause of the discharge; any damages or 

injuries caused by the discharge; actions being used to stop, remove, and 

mitigate the effects of the discharge; 

whether an evacuation may be needed; 

and, the names of individuals and/or organizations who have also been contacted. 

(5) Unless you have submitted a response plan under § 112.20, organize portions of the Plan describing procedures 

you will use when a discharge occurs in 

a way that will make them readily usable in an emergency, and include appropriate supporting material as appendices. 

(b) Where experience indicates a reasonable potential for equipment failure 

(such as loading or unloading equipment, tank overflow, rupture, or leakage, or any other equipment known to 

40 CFR Ch. I (7–1–05 Edition) 

be a source of a discharge), include in 

your Plan a prediction of the direction, 

rate of flow, and total quantity of oil 

which could be discharged from the facility as a result of each type of major 

equipment failure. 

(c) Provide appropriate containment 

and/or diversionary structures or 

equipment to prevent a discharge as 

described in § 112.1(b). The entire containment system, including walls and 

floor, must be capable of containing oil 

and must be constructed so that any 

discharge from a primary containment 

system, such as a tank or pipe, will not 

escape the containment system before 

cleanup occurs. At a minimum, you 

must use one of the following prevention systems or its equivalent: 

(1) For onshore facilities: 

(i) Dikes, berms, or retaining walls 

sufficiently impervious to contain oil; 

(ii) Curbing; 

(iii) Culverting, gutters, or other 

drainage systems; 

(iv) Weirs, booms, or other barriers; 

(v) Spill diversion ponds; 

(vi) Retention ponds; or 

(vii) Sorbent materials. 

(2) For offshore facilities: 

(i) Curbing or drip pans; or 

(ii) Sumps and collection systems. 

(d) If you determine that the installation of any of the structures or pieces 

of equipment listed in paragraphs (c) 

and (h)(1) of this section, and 

§§ 112.8(c)(2), 112.8(c)(11), 112.9(c)(2), 

112.10(c), 112.12(c)(2), 112.12(c)(11), 

112.13(c)(2), and 112.14(c) to prevent a 

discharge as described in § 112.1(b) from 

any onshore or offshore facility is not 

practicable, you must clearly explain 

in your Plan why such measures are 

not practicable; for bulk storage containers, conduct both periodic integrity testing of the containers and periodic integrity and leak testing of the 

valves and piping; and, unless you have 

submitted a response plan under 

§ 112.20, provide in your Plan the following: 

(1) An oil spill contingency plan following the provisions of part 109 of this 

chapter. 

(2) A written commitment of manpower, equipment, and materials required to expeditiously control and remove any quantity of oil discharged 

that may be harmful. 

30 
 

Environmental Protection Agency 

(e) Inspections, tests, and records. Conduct inspections and tests required by 

this part in accordance with written 

procedures that you or the certifying 

engineer develop for the facility. You 

must keep these written procedures 

and a record of the inspections and 

tests, signed by the appropriate supervisor or inspector, with the SPCC Plan 

for a period of three years. Records of 

inspections and tests kept under usual 

and customary business practices will 

suffice for purposes of this paragraph. 

(f) Personnel, training, and discharge 

prevention procedures. (1) At a minimum, train your oil-handling personnel in the operation and maintenance of equipment to prevent discharges; discharge procedure protocols; 

applicable pollution control laws, 

rules, and regulations; general facility 

operations; and, the contents of the facility SPCC Plan. 

(2) Designate a person at each applicable facility who is accountable for 

discharge prevention and who reports 

to facility management. 

(3) Schedule and conduct discharge 

prevention briefings for your oil-handling personnel at least once a year to 

assure adequate understanding of the 

SPCC Plan for that facility. Such briefings must highlight and describe 

known discharges as described in 

§ 112.1(b) or failures, malfunctioning 

components, and any recently developed precautionary measures. 

(g) Security (excluding oil production 

facilities). (1) Fully fence each facility 

handling, processing, or storing oil, 

and lock and/or guard entrance gates 

when the facility is not in production 

or is unattended. 

(2) Ensure that the master flow and 

drain valves and any other valves permitting direct outward flow of the container’s contents to the surface have 

adequate security measures so that 

they remain in the closed position 

when in non-operating or non-standby 

status. 

(3) Lock the starter control on each 

oil pump in the ‘‘off’’ position and locate it at a site accessible only to authorized personnel when the pump is in 

a non-operating or non-standby status. 

(4) Securely cap or blank-flange the 

loading/unloading connections of oil 

pipelines or facility piping when not in 

§ 112.7 

service or when in standby service for 

an extended time. This security practice also applies to piping that is 

emptied of liquid content either by 

draining or by inert gas pressure. 

(5) Provide facility lighting commensurate with the type and location of 

the facility that will assist in the: 

(i) Discovery of discharges occurring 

during hours of darkness, both by operating personnel, if present, and by nonoperating personnel (the general public, local police, etc.); and 

(ii) Prevention of discharges occurring through acts of vandalism. 

(h) Facility tank car and tank truck 

loading/unloading rack (excluding offshore facilities). (1) Where loading/unloading area drainage does not flow 

into a catchment basin or treatment 

facility designed to handle discharges, 

use a quick drainage system for tank 

car or tank truck loading and unloading areas. You must design any containment system to hold at least the 

maximum capacity of any single compartment of a tank car or tank truck 

loaded or unloaded at the facility. 

(2) Provide an interlocked warning 

light or physical barrier system, warning signs, wheel chocks, or vehicle 

break interlock system in loading/unloading areas to prevent vehicles from 

departing before complete disconnection of flexible or fixed oil transfer 

lines. 

(3) Prior to filling and departure of 

any tank car or tank truck, closely inspect for discharges the lowermost 

drain and all outlets of such vehicles, 

and if necessary, ensure that they are 

tightened, adjusted, or replaced to prevent liquid discharge while in transit. 

(i) If a field-constructed aboveground 

container undergoes a repair, alteration, reconstruction, or a change in 

service that might affect the risk of a 

discharge or failure due to brittle fracture or other catastrophe, or has discharged oil or failed due to brittle fracture failure or other catastrophe, 

evaluate the container for risk of discharge or failure due to brittle fracture 

or other catastrophe, and as necessary, 

take appropriate action. 

(j) In addition to the minimal prevention standards listed under this section, include in your Plan a complete 

31 
 

§ 112.8 

discussion of conformance with the applicable requirements and other effective discharge prevention and containment procedures listed in this part or 

any applicable more stringent State 

rules, regulations, and guidelines. 

Subpart B—Requirements for Petroleum Oils and Non-Petroleum Oils, Except Animal Fats

and Oils and Greases, and 

Fish and Marine Mammal Oils; 

and Vegetable Oils (Including

Oils from Seeds, Nuts, Fruits, 

and Kernels) 

SOURCE: 67 FR 47146, July 17, 2002, unless 

otherwise noted. 

§ 112.8 Spill Prevention, Control, and 

Countermeasure Plan requirements

for onshore facilities (excluding 

production facilities). 

If you are the owner or operator of an 

onshore facility (excluding a production facility), you must: 

(a) Meet the general requirements for 

the Plan listed under § 112.7, and the 

specific discharge prevention and containment procedures listed in this section. 

(b) Facility drainage. (1) Restrain 

drainage from diked storage areas by 

valves to prevent a discharge into the 

drainage system or facility effluent 

treatment system, except where facility systems are designed to control 

such discharge. You may empty diked 

areas by pumps or ejectors; however, 

you must manually activate these 

pumps or ejectors and must inspect the 

condition of the accumulation before 

starting, to ensure no oil will be discharged. 

(2) Use valves of manual, open-andclosed design, for the drainage of diked 

areas. You may not use flapper-type 

drain valves to drain diked areas. If 

your facility drainage drains directly 

into a watercourse and not into an onsite wastewater treatment plant, you 

must inspect and may drain 

uncontaminated retained stormwater, 

as provided in paragraphs (c)(3)(ii), 

(iii), and (iv) of this section. 

(3) Design facility drainage systems 

from undiked areas with a potential for 

a discharge (such as where piping is lo40 CFR Ch. I (7–1–05 Edition) 

cated outside containment walls or 

where tank truck discharges may occur 

outside the loading area) to flow into 

ponds, lagoons, or catchment basins designed to retain oil or return it to the 

facility. You must not locate 

catchment basins in areas subject to 

periodic flooding. 

(4) If facility drainage is not engineered as in paragraph (b)(3) of this 

section, equip the final discharge of all 

ditches inside the facility with a diversion system that would, in the event of 

an uncontrolled discharge, retain oil in 

the facility. 

(5) Where drainage waters are treated 

in more than one treatment unit and 

such treatment is continuous, and 

pump transfer is needed, provide two 

‘‘lift’’ pumps and permanently install 

at least one of the pumps. Whatever 

techniques you use, you must engineer 

facility drainage systems to prevent a 

discharge as described in § 112.1(b) in 

case there is an equipment failure or 

human error at the facility. 

(c) Bulk storage containers. (1) Not use 

a container for the storage of oil unless 

its material and construction are compatible with the material stored and 

conditions of storage such as pressure 

and temperature. 

(2) Construct all bulk storage container installations so that you provide 

a secondary means of containment for 

the entire capacity of the largest single 

container and sufficient freeboard to 

contain precipitation. You must ensure 

that diked areas are sufficiently impervious to contain discharged oil. Dikes, 

containment curbs, and pits are commonly employed for this purpose. You 

may also use an alternative system 

consisting of a drainage trench enclosure that must be arranged so that any 

discharge will terminate and be safely 

confined in a facility catchment basin 

or holding pond. 

(3) Not allow drainage of 

uncontaminated rainwater from the 

diked area into a storm drain or discharge of an effluent into an open watercourse, lake, or pond, bypassing the 

facility treatment system unless you: 

(i) Normally keep the bypass valve 

sealed closed. 

(ii) Inspect the retained rainwater to 

ensure that its presence will not cause 

a discharge as described in § 112.1(b). 

32 
 

Environmental Protection Agency 

(iii) Open the bypass valve and reseal 

it following drainage under responsible 

supervision; and 

(iv) Keep adequate records of such 

events, for example, any records required under permits issued in accordance with §§ 122.41(j)(2) and 122.41(m)(3) 

of this chapter. 

(4) Protect any completely buried 

metallic storage tank installed on or 

after January 10, 1974 from corrosion 

by coatings or cathodic protection 

compatible with local soil conditions. 

You must regularly leak test such 

completely buried metallic storage 

tanks. 

(5) Not use partially buried or 

bunkered metallic tanks for the storage of oil, unless you protect the buried section of the tank from corrosion. 

You must protect partially buried and 

bunkered tanks from corrosion by 

coatings or cathodic protection compatible with local soil conditions. 

(6) Test each aboveground container 

for integrity on a regular schedule, and 

whenever you make material repairs. 

The frequency of and type of testing 

must take into account container size 

and design (such as floating roof, skidmounted, elevated, or partially buried). 

You must combine visual inspection 

with another testing technique such as 

hydrostatic testing, radiographic testing, ultrasonic testing, acoustic emissions testing, or another system of 

non-destructive shell testing. You 

must keep comparison records and you 

must also inspect the container’s supports and foundations. In addition, you 

must frequently inspect the outside of 

the container for signs of deterioration, discharges, or accumulation of oil 

inside diked areas. Records of inspections and tests kept under usual and 

customary business practices will suffice for purposes of this paragraph. 

(7) Control leakage through defective 

internal heating coils by monitoring 

the steam return and exhaust lines for 

contamination from internal heating 

coils that discharge into an open watercourse, or pass the steam return or 

exhaust lines through a settling tank, 

skimmer, or other separation or retention system. 

(8) Engineer or update each container 

installation in accordance with good 

engineering practice to avoid dis-

§ 112.8 

charges. You must provide at least one 

of the following devices: 

(i) High liquid level alarms with an 

audible or visual signal at a constantly 

attended operation or surveillance station. In smaller facilities an audible air 

vent may suffice. 

(ii) High liquid level pump cutoff devices set to stop flow at a predetermined container content level. 

(iii) Direct audible or code signal 

communication between the container 

gauger and the pumping station. 

(iv) A fast response system for determining the liquid level of each bulk 

storage container such as digital computers, telepulse, or direct vision 

gauges. If you use this alternative, a 

person must be present to monitor 

gauges and the overall filling of bulk 

storage containers. 

(v) You must regularly test liquid 

level sensing devices to ensure proper 

operation. 

(9) Observe effluent treatment facilities frequently enough to detect possible system upsets that could cause a 

discharge as described in § 112.1(b). 

(10) Promptly correct visible discharges which result in a loss of oil 

from the container, including but not 

limited to seams, gaskets, piping, 

pumps, valves, rivets, and bolts. You 

must promptly remove any accumulations of oil in diked areas. 

(11) Position or locate mobile or portable oil storage containers to prevent a 

discharge as described in § 112.1(b). You 

must furnish a secondary means of containment, such as a dike or catchment 

basin, sufficient to contain the capacity of the largest single compartment 

or container with sufficient freeboard 

to contain precipitation. 

(d) Facility transfer operations, pumping, and facility process. (1) Provide buried piping that is installed or replaced 

on or after August 16, 2002, with a protective wrapping and coating. You 

must also cathodically protect such 

buried piping installations or otherwise 

satisfy the corrosion protection standards for piping in part 280 of this chapter or a State program approved under 

part 281 of this chapter. If a section of 

buried line is exposed for any reason, 

you must carefully inspect it for deterioration. If you find corrosion damage, 

33 
 

§ 112.9 

you must undertake additional examination and corrective action as indicated by the magnitude of the damage. 

(2) Cap or blank-flange the terminal 

connection at the transfer point and 

mark it as to origin when piping is not 

in service or is in standby service for 

an extended time. 

(3) Properly design pipe supports to 

minimize abrasion and corrosion and 

allow for expansion and contraction. 

(4) Regularly inspect all aboveground 

valves, piping, and appurtenances. During the inspection you must assess the 

general condition of items, such as 

flange joints, expansion joints, valve 

glands and bodies, catch pans, pipeline 

supports, locking of valves, and metal 

surfaces. You must also conduct integrity and leak testing of buried piping 

at the time of installation, modification, construction, relocation, or replacement. 

(5) Warn all vehicles entering the facility to be sure that no vehicle will 

endanger aboveground piping or other 

oil transfer operations. 

§ 112.9 Spill Prevention, Control, and

Countermeasure Plan requirements 

for onshore oil production facilities. 

If you are the owner or operator of an 

onshore production facility, you must: 

(a) Meet the general requirements for 

the Plan listed under § 112.7, and the 

specific discharge prevention and containment procedures listed under this 

section. 

(b) Oil production facility drainage. (1) 

At tank batteries and separation and 

treating areas where there is a reasonable possibility of a discharge as described in § 112.1(b), close and seal at all 

times drains of dikes or drains of 

equivalent measures required under 

§ 112.7(c)(1), except when draining 

uncontaminated rainwater. Prior to 

drainage, you must inspect the diked 

area and take action as provided in 

§ 112.8(c)(3)(ii), (iii), and (iv). You must 

remove accumulated oil on the rainwater and return it to storage or dispose of it in accordance with legally 

approved methods. 

(2) Inspect at regularly scheduled intervals field drainage systems (such as 

drainage ditches or road ditches), and 

oil traps, sumps, or skimmers, for an 

accumulation of oil that may have re40 CFR Ch. I (7–1–05 Edition) 

sulted from any small discharge. You 

must promptly remove any accumulations of oil. 

(c) Oil production facility bulk storage 

containers. (1) Not use a container for 

the storage of oil unless its material 

and construction are compatible with 

the material stored and the conditions 

of storage. 

(2) Provide all tank battery, separation, and treating facility installations 

with a secondary means of containment for the entire capacity of the 

largest single container and sufficient 

freeboard to contain precipitation. You 

must safely confine drainage from 

undiked areas in a catchment basin or 

holding pond. 

(3) Periodically and upon a regular 

schedule visually inspect each container of oil for deterioration and 

maintenance needs, including the foundation and support of each container 

that is on or above the surface of the 

ground. 

(4) Engineer or update new and old 

tank battery installations in accordance with good engineering practice to 

prevent discharges. You must provide 

at least one of the following: 

(i) Container capacity adequate to assure that a container will not overfill if 

a pumper/gauger is delayed in making 

regularly scheduled rounds. 

(ii) Overflow equalizing lines between 

containers so that a full container can 

overflow to an adjacent container. 

(iii) Vacuum protection adequate to 

prevent container collapse during a 

pipeline run or other transfer of oil 

from the container. 

(iv) High level sensors to generate 

and transmit an alarm signal to the 

computer where the facility is subject 

to a computer production control system. 

(d) Facility transfer operations, oil production facility. (1) Periodically and 

upon a regular schedule inspect all 

aboveground valves and piping associated with transfer operations for the 

general condition of flange joints, 

valve glands and bodies, drip pans, pipe 

supports, pumping well polish rod 

stuffing boxes, bleeder and gauge 

valves, and other such items. 

(2) Inspect saltwater (oil field brine) 

disposal facilities often, particularly 

34 
 

Environmental Protection Agency 

following a sudden change in atmospheric temperature, to detect possible 

system upsets capable of causing a discharge. 

(3) Have a program of flowline maintenance to prevent discharges from 

each flowline. 

§ 112.10 Spill Prevention, Control, and

Countermeasure Plan requirements

for onshore oil drilling and 

workover facilities. 

If you are the owner or operator of an 

onshore oil drilling and workover facility, you must: 

(a) Meet the general requirements 

listed under § 112.7, and also meet the 

specific discharge prevention and containment procedures listed under this 

section. 

(b) Position or locate mobile drilling 

or workover equipment so as to prevent a discharge as described in 

§ 112.1(b). 

(c) Provide catchment basins or diversion structures to intercept and 

contain discharges of fuel, crude oil, or 

oily drilling fluids. 

(d) Install a blowout prevention 

(BOP) assembly and well control system before drilling below any casing 

string or during workover operations. 

The BOP assembly and well control 

system must be capable of controlling 

any well-head pressure that may be encountered while that BOP assembly 

and well control system are on the 

well. 

§ 112.11 Spill Prevention, Control, and 

Countermeasure Plan requirements 

for offshore oil drilling, production,

or workover facilities. 

If you are the owner or operator of an 

offshore oil drilling, production, or 

workover facility, you must: 

(a) Meet the general requirements 

listed under § 112.7, and also meet the 

specific discharge prevention and containment procedures listed under this 

section. 

(b) Use oil drainage collection equipment to prevent and control small oil 

discharges around pumps, glands, 

valves, flanges, expansion joints, hoses, 

drain lines, separators, treaters, tanks, 

and associated equipment. You must 

control and direct facility drains toward a central collection sump to prevent the facility from having a dis-

§ 112.11 

charge as described in § 112.1(b). Where 

drains and sumps are not practicable, 

you must remove oil contained in collection equipment as often as necessary to prevent overflow. 

(c) For facilities employing a sump 

system, provide adequately sized sump 

and drains and make available a spare 

pump to remove liquid from the sump 

and assure that oil does not escape. 

You must employ a regularly scheduled 

preventive maintenance inspection and 

testing program to assure reliable operation of the liquid removal system 

and pump start-up device. Redundant 

automatic sump pumps and control devices may be required on some installations. 

(d) At facilities with areas where separators and treaters are equipped with 

dump valves which predominantly fail 

in the closed position and where pollution risk is high, specially equip the facility to prevent the discharge of oil. 

You must prevent the discharge of oil 

by: 

(1) Extending the flare line to a diked 

area if the separator is near shore; 

(2) Equipping the separator with a 

high liquid level sensor that will automatically shut in wells producing to 

the separator; or 

(3) Installing parallel redundant 

dump valves. 

(e) Equip atmospheric storage or 

surge containers with high liquid level 

sensing devices that activate an alarm 

or control the flow, or otherwise prevent discharges. 

(f) Equip pressure containers with 

high and low pressure sensing devices 

that activate an alarm or control the 

flow. 

(g) Equip containers with suitable 

corrosion protection. 

(h) Prepare and maintain at the facility a written procedure within the Plan 

for inspecting and testing pollution 

prevention equipment and systems. 

(i) Conduct testing and inspection of 

the pollution prevention equipment 

and systems at the facility on a scheduled periodic basis, commensurate with 

the complexity, conditions, and circumstances of the facility and any 

other appropriate regulations. You 

35 
 

§ 112.12 

must use simulated discharges for testing and inspecting human and equipment pollution control and countermeasure systems. 

(j) Describe in detailed records surface and subsurface well shut-in valves 

and devices in use at the facility for 

each well sufficiently to determine 

their method of activation or control, 

such as pressure differential, change in 

fluid or flow conditions, combination 

of pressure and flow, manual or remote 

control mechanisms. 

(k) Install a BOP assembly and well 

control system during workover operations and before drilling below any 

casing string. The BOP assembly and 

well control system must be capable of 

controlling any well-head pressure that 

may be encountered while the BOP assembly and well control system are on 

the well. 

(l) Equip all manifolds (headers) with 

check valves on individual flowlines. 

(m) Equip the flowline with a high 

pressure sensing device and shut-in 

valve at the wellhead if the shut-in 

well pressure is greater than the working pressure of the flowline and manifold valves up to and including the 

header valves. Alternatively you may 

provide a pressure relief system for 

flowlines. 

(n) Protect all piping appurtenant to 

the facility from corrosion, such as 

with protective coatings or cathodic 

protection. 

(o) Adequately protect sub-marine 

piping appurtenant to the facility 

against environmental stresses and 

other activities such as fishing operations. 

(p) Maintain sub-marine piping appurtenant to the facility in good operating condition at all times. You must 

periodically and according to a schedule inspect or test such piping for failures. You must document and keep a 

record of such inspections or tests at 

the facility. 

40 CFR Ch. I (7–1–05 Edition) 

Subpart C—Requirements for Animal Fats and Oils and 

Greases, and Fish and Marine 

Mammal Oils; and for Vegetable Oils, including Oils from

Seeds, Nuts, Fruits, and Kernels. 

SOURCE: 67 FR 57149, July 17, 2002, unless 

otherwise noted. 

§ 112.12 Spill Prevention, Control, and 

Countermeasure Plan requirements 

for onshore facilities (excluding 

production facilities) 

If you are the owner or operator of an 

onshore facility (excluding a production facility), you must: 

(a) Meet the general requirements for 

the Plan listed under § 112.7, and the 

specific discharge prevention and containment procedures listed in this section. 

(b) Facility drainage. (1) Restrain 

drainage from diked storage areas by 

valves to prevent a discharge into the 

drainage system or facility effluent 

treatment system, except where facility systems are designed to control 

such discharge. You may empty diked 

areas by pumps or ejectors; however, 

you must manually activate these 

pumps or ejectors and must inspect the 

condition of the accumulation before 

starting, to ensure no oil will be discharged. 

(2) Use valves of manual, open-andclosed design, for the drainage of diked 

areas. You may not use flapper-type 

drain valves to drain diked areas. If 

your facility drainage drains directly 

into a watercourse and not into an onsite wastewater treatment plant, you 

must inspect and may drain 

uncontaminated retained stormwater, 

subject to the requirements of paragraphs (c)(3)(ii), (iii), and (iv) of this 

section. 

(3) Design facility drainage systems 

from undiked areas with a potential for 

a discharge (such as where piping is located outside containment walls or 

where tank truck discharges may occur 

outside the loading area) to flow into 

ponds, lagoons, or catchment basins designed to retain oil or return it to the 

facility. You must not locate 

36 
 

Environmental Protection Agency 

catchment basins in areas subject to 

periodic flooding. 

(4) If facility drainage is not engineered as in paragraph (b)(3) of this 

section, equip the final discharge of all 

ditches inside the facility with a diversion system that would, in the event of 

an uncontrolled discharge, retain oil in 

the facility. 

(5) Where drainage waters are treated 

in more than one treatment unit and 

such treatment is continuous, and 

pump transfer is needed, provide two 

‘‘lift’’ pumps and permanently install 

at least one of the pumps. Whatever 

techniques you use, you must engineer 

facility drainage systems to prevent a 

discharge as described in § 112.1(b) in 

case there is an equipment failure or 

human error at the facility. 

(c) Bulk storage containers. (1) Not use 

a container for the storage of oil unless 

its material and construction are compatible with the material stored and 

conditions of storage such as pressure 

and temperature. 

(2) Construct all bulk storage container installations so that you provide 

a secondary means of containment for 

the entire capacity of the largest single 

container and sufficient freeboard to 

contain precipitation. You must ensure 

that diked areas are sufficiently impervious to contain discharged oil. Dikes, 

containment curbs, and pits are commonly employed for this purpose. You 

may also use an alternative system 

consisting of a drainage trench enclosure that must be arranged so that any 

discharge will terminate and be safely 

confined in a facility catchment basin 

or holding pond. 

(3) Not allow drainage of 

uncontaminated rainwater from the 

diked area into a storm drain or discharge of an effluent into an open watercourse, lake, or pond, bypassing the 

facility treatment system unless you: 

(i) Normally keep the bypass valve 

sealed closed. 

(ii) Inspect the retained rainwater to 

ensure that its presence will not cause 

a discharge as described in § 112.1(b). 

(iii) Open the bypass valve and reseal 

it following drainage under responsible 

supervision; and 

(iv) Keep adequate records of such 

events, for example, any records required under permits issued in accord-

§ 112.12 

ance with §§ 122.41(j)(2) and 122.41(m)(3) 

of this chapter. 

(4) Protect any completely buried 

metallic storage tank installed on or 

after January 10, 1974 from corrosion 

by coatings or cathodic protection 

compatible with local soil conditions. 

You must regularly leak test such 

completely buried metallic storage 

tanks. 

(5) Not use partially buried or 

bunkered metallic tanks for the storage of oil, unless you protect the buried section of the tank from corrosion. 

You must protect partially buried and 

bunkered tanks from corrosion by 

coatings or cathodic protection compatible with local soil conditions. 

(6) Test each aboveground container 

for integrity on a regular schedule, and 

whenever you make material repairs. 

The frequency of and type of testing 

must take into account container size 

and design (such as floating roof, skidmounted, elevated, or partially buried). 

You must combine visual inspection 

with another testing technique such as 

hydrostatic testing, radiographic testing, ultrasonic testing, acoustic emissions testing, or another system of 

non-destructive shell testing. You 

must keep comparison records and you 

must also inspect the container’s supports and foundations. In addition, you 

must frequently inspect the outside of 

the container for signs of deterioration, discharges, or accumulation of oil 

inside diked areas. Records of inspections and tests kept under usual and 

customary business practices will suffice for purposes of this paragraph. 

(7) Control leakage through defective 

internal heating coils by monitoring 

the steam return and exhaust lines for 

contamination from internal heating 

coils that discharge into an open watercourse, or pass the steam return or 

exhaust lines through a settling tank, 

skimmer, or other separation or retention system. 

(8) Engineer or update each container 

installation in accordance with good 

engineering practice to avoid discharges. You must provide at least one 

of the following devices: 

(i) High liquid level alarms with an 

audible or visual signal at a constantly 

37 
 

§ 112.13 

attended operation or surveillance station. In smaller facilities an audible air 

vent may suffice. 

(ii) High liquid level pump cutoff devices set to stop flow at a predetermined container content level. 

(iii) Direct audible or code signal 

communication between the container 

gauger and the pumping station. 

(iv) A fast response system for determining the liquid level of each bulk 

storage container such as digital computers, telepulse, or direct vision 

gauges. If you use this alternative, a 

person must be present to monitor 

gauges and the overall filling of bulk 

storage containers. 

(v) You must regularly test liquid 

level sensing devices to ensure proper 

operation. 

(9) Observe effluent treatment facilities frequently enough to detect possible system upsets that could cause a 

discharge as described in § 112.1(b). 

(10) Promptly correct visible discharges which result in a loss of oil 

from the container, including but not 

limited to seams, gaskets, piping, 

pumps, valves, rivets, and bolts. You 

must promptly remove any accumulations of oil in diked areas. 

(11) Position or locate mobile or portable oil storage containers to prevent a 

discharge as described in § 112.1(b). You 

must furnish a secondary means of containment, such as a dike or catchment 

basin, sufficient to contain the capacity of the largest single compartment 

or container with sufficient freeboard 

to contain precipitation. 

(d) Facility transfer operations, pumping, and facility process. (1) Provide buried piping that is installed or replaced 

on or after August 16, 2002, with a protective wrapping and coating. You 

must also cathodically protect such 

buried piping installations or otherwise 

satisfy the corrosion protection standards for piping in part 280 of this chapter or a State program approved under 

part 281 of this chapter. If a section of 

buried line is exposed for any reason, 

you must carefully inspect it for deterioration. If you find corrosion damage, 

you must undertake additional examination and corrective action as indicated by the magnitude of the damage. 

(2) Cap or blank-flange the terminal 

connection at the transfer point and 

40 CFR Ch. I (7–1–05 Edition) 

mark it as to origin when piping is not 

in service or is in standby service for 

an extended time. 

(3) Properly design pipe supports to 

minimize abrasion and corrosion and 

allow for expansion and contraction. 

(4) Regularly inspect all aboveground 

valves, piping, and appurtenances. During the inspection you must assess the 

general condition of items, such as 

flange joints, expansion joints, valve 

glands and bodies, catch pans, pipeline 

supports, locking of valves, and metal 

surfaces. You must also conduct integrity and leak testing of buried piping 

at the time of installation, modification, construction, relocation, or replacement. 

(5) Warn all vehicles entering the facility to be sure that no vehicle will 

endanger aboveground piping or other 

oil transfer operations. 

§ 112.13 Spill Prevention, Control, and

Countermeasure Plan requirements 

for onshore oil production facilities. 

If you are the owner or operator of an 

onshore production facility, you must: 

(a) Meet the general requirements for 

the Plan listed under § 112.7, and the 

specific discharge prevention and containment procedures listed under this 

section. 

(b) Oil production facility drainage. (1) 

At tank batteries and separation and 

treating areas where there is a reasonable possibility of a discharge as described in § 112.1(b), close and seal at all 

times drains of dikes or drains of 

equivalent measures required under 

§ 112.7(c)(1), except when draining 

uncontaminated rainwater. Prior to 

drainage, you must inspect the diked 

area and take action as provided in 

§ 112.12(c)(3)(ii), (iii), and (iv). You must 

remove accumulated oil on the rainwater and return it to storage or dispose of it in accordance with legally 

approved methods. 

(2) Inspect at regularly scheduled intervals field drainage systems (such as 

drainage ditches or road ditches), and 

oil traps, sumps, or skimmers, for an 

accumulation of oil that may have resulted from any small discharge. You 

must promptly remove any accumulations of oil. 

(c) Oil production facility bulk storage 

containers. (1) Not use a container for 

38 
 

Environmental Protection Agency 

the storage of oil unless its material 

and construction are compatible with 

the material stored and the conditions 

of storage. 

(2) Provide all tank battery, separation, and treating facility installations 

with a secondary means of containment for the entire capacity of the 

largest single container and sufficient 

freeboard to contain precipitation. You 

must safely confine drainage from 

undiked areas in a catchment basin or 

holding pond. 

(3) Periodically and upon a regular 

schedule visually inspect each container of oil for deterioration and 

maintenance needs, including the foundation and support of each container 

that is on or above the surface of the 

ground. 

(4) Engineer or update new and old 

tank battery installations in accordance with good engineering practice to 

prevent discharges. You must provide 

at least one of the following: 

(i) Container capacity adequate to assure that a container will not overfill if 

a pumper/gauger is delayed in making 

regularly scheduled rounds. 

(ii) Overflow equalizing lines between 

containers so that a full container can 

overflow to an adjacent container. 

(iii) Vacuum protection adequate to 

prevent container collapse during a 

pipeline run or other transfer of oil 

from the container. 

(iv) High level sensors to generate 

and transmit an alarm signal to the 

computer where the facility is subject 

to a computer production control system. 

(d) Facility transfer operations, oil production facility. (1) Periodically and 

upon a regular schedule inspect all 

aboveground valves and piping associated with transfer operations for the 

general condition of flange joints, 

valve glands and bodies, drip pans, pipe 

supports, pumping well polish rod 

stuffing boxes, bleeder and gauge 

valves, and other such items. 

(2) Inspect saltwater (oil field brine) 

disposal facilities often, particularly 

following a sudden change in atmospheric temperature, to detect possible 

system upsets capable of causing a discharge. 

§ 112.15 

(3) Have a program of flowline maintenance to prevent discharges from 

each flowline. 

§ 112.14 Spill Prevention, Control, and 

Countermeasure Plan requirements 

for onshore oil drilling and 

workover facilities. 

If you are the owner or operator of an 

onshore oil drilling and workover facility, you must: 

(a) Meet the general requirements 

listed under § 112.7, and also meet the 

specific discharge prevention and containment procedures listed under this 

section. 

(b) Position or locate mobile drilling 

or workover equipment so as to prevent a discharge as described in 

§ 112.1(b). 

(c) Provide catchment basins or diversion structures to intercept and 

contain discharges of fuel, crude oil, or 

oily drilling fluids. 

(d) Install a blowout prevention 

(BOP) assembly and well control system before drilling below any casing 

string or during workover operations. 

The BOP assembly and well control 

system must be capable of controlling 

any well-head pressure that may be encountered while that BOP assembly 

and well control system are on the 

well. 

§ 112.15 Spill Prevention, Control, and 

Countermeasure Plan requirements 

for offshore oil drilling, production, 

or workover facilities. 

If you are the owner or operator of an 

offshore oil drilling, production, or 

workover facility, you must: 

(a) Meet the general requirements 

listed under § 112.7, and also meet the 

specific discharge prevention and containment procedures listed under this 

section. 

(b) Use oil drainage collection equipment to prevent and control small oil 

discharges around pumps, glands, 

valves, flanges, expansion joints, hoses, 

drain lines, separators, treaters, tanks, 

and associated equipment. You must 

control and direct facility drains toward a central collection sump to prevent the facility from having a discharge as described in § 112.1(b). Where 

drains and sumps are not practicable, 

39 
 

§ 112.20 

you must remove oil contained in collection equipment as often as necessary to prevent overflow. 

(c) For facilities employing a sump 

system, provide adequately sized sump 

and drains and make available a spare 

pump to remove liquid from the sump 

and assure that oil does not escape. 

You must employ a regularly scheduled 

preventive maintenance inspection and 

testing program to assure reliable operation of the liquid removal system 

and pump start-up device. Redundant 

automatic sump pumps and control devices may be required on some installations. 

(d) At facilities with areas where separators and treaters are equipped with 

dump valves which predominantly fail 

in the closed position and where pollution risk is high, specially equip the facility to prevent the discharge of oil. 

You must prevent the discharge of oil 

by: 

(1) Extending the flare line to a diked 

area if the separator is near shore; 

(2) Equipping the separator with a 

high liquid level sensor that will automatically shut in wells producing to 

the separator; or 

(3) Installing parallel redundant 

dump valves. 

(e) Equip atmospheric storage or 

surge containers with high liquid level 

sensing devices that activate an alarm 

or control the flow, or otherwise prevent discharges. 

(f) Equip pressure containers with 

high and low pressure sensing devices 

that activate an alarm or control the 

flow. 

(g) Equip containers with suitable 

corrosion protection. 

(h) Prepare and maintain at the facility a written procedure within the Plan 

for inspecting and testing pollution 

prevention equipment and systems. 

(i) Conduct testing and inspection of 

the pollution prevention equipment 

and systems at the facility on a scheduled periodic basis, commensurate with 

the complexity, conditions, and circumstances of the facility and any 

other appropriate regulations. You 

must use simulated discharges for testing and inspecting human and equipment pollution control and countermeasure systems. 

40 CFR Ch. I (7–1–05 Edition) 

(j) Describe in detailed records surface and subsurface well shut-in valves 

and devices in use at the facility for 

each well sufficiently to determine 

their method of activation or control, 

such as pressure differential, change in 

fluid or flow conditions, combination 

of pressure and flow, manual or remote 

control mechanisms. 

(k) Install a BOP assembly and well 

control system during workover operations and before drilling below any 

casing string. The BOP assembly and 

well control system must be capable of 

controlling any well-head pressure that 

may be encountered while that BOP assembly and well control system are on 

the well. 

(l) Equip all manifolds (headers) with 

check valves on individual flowlines. 

(m) Equip the flowline with a high 

pressure sensing device and shut-in 

valve at the wellhead if the shut-in 

well pressure is greater than the working pressure of the flowline and manifold valves up to and including the 

header valves. Alternatively you may 

provide a pressure relief system for 

flowlines. 

(n) Protect all piping appurtenant to 

the facility from corrosion, such as 

with protective coatings or cathodic 

protection. 

(o) Adequately protect sub-marine 

piping appurtenant to the facility 

against environmental stresses and 

other activities such as fishing operations. 

(p) Maintain sub-marine piping appurtenant to the facility in good operating condition at all times. You must 

periodically and according to a schedule inspect or test such piping for failures. You must document and keep a 

record of such inspections or tests at 

the facility. 

Subpart D—Response

Requirements 

§ 112.20 Facility response plans. 

(a) The owner or operator of any nontransportation-related onshore facility 

that, because of its location, could reasonably be expected to cause substantial harm to the environment by discharging oil into or on the navigable 

waters or adjoining shorelines shall 

prepare and submit a facility response 

40 
 

Environmental Protection Agency 

plan to the Regional Administrator, 

according to the following provisions: 

(1) For the owner or operator of a facility in operation on or before February 18, 1993 who is required to prepare and submit a response plan under 

33 U.S.C. 1321(j)(5), the Oil Pollution 

Act of 1990 (Pub. L. 101–380, 33 U.S.C. 

2701 et seq.) requires the submission of 

a response plan that satisfies the requirements of 33 U.S.C. 1321(j)(5) no 

later than February 18, 1993. 

(i) The owner or operator of an existing facility that was in operation on or 

before February 18, 1993 who submitted 

a response plan by February 18, 1993 

shall revise the response plan to satisfy 

the requirements of this section and resubmit the response plan or updated 

portions of the response plan to the Regional Administrator by February 18, 

1995. 

(ii) The owner or operator of an existing facility in operation on or before 

February 18, 1993 who failed to submit 

a response plan by February 18, 1993 

shall prepare and submit a response 

plan that satisfies the requirements of 

this section to the Regional Administrator before August 30, 1994. 

(2) The owner or operator of a facility 

in operation on or after August 30, 1994 

that satisfies the criteria in paragraph 

(f)(1) of this section or that is notified 

by the Regional Administrator pursuant to paragraph (b) of this section 

shall prepare and submit a facility response plan that satisfies the requirements of this section to the Regional 

Administrator. 

(i) For a facility that commenced operations after February 18, 1993 but 

prior to August 30, 1994, and is required 

to prepare and submit a response plan 

based on the criteria in paragraph (f)(1) 

of this section, the owner or operator 

shall submit the response plan or updated portions of the response plan, 

along with a completed version of the 

response plan cover sheet contained in 

Appendix F to this part, to the Regional Administrator prior to August 

30, 1994. 

(ii) For a newly constructed facility 

that commences operation after August 30, 1994, and is required to prepare 

and submit a response plan based on 

the criteria in paragraph (f)(1) of this 

section, the owner or operator shall 

§ 112.20 

submit the response plan, along with a 

completed version of the response plan 

cover sheet contained in Appendix F to 

this part, to the Regional Administrator prior to the start of operations 

(adjustments to the response plan to 

reflect changes that occur at the facility during the start-up phase of operations must be submitted to the Regional Administrator after an operational trial period of 60 days). 

(iii) For a facility required to prepare 

and submit a response plan after August 30, 1994, as a result of a planned 

change in design, construction, operation, or maintenance that renders the 

facility subject to the criteria in paragraph (f)(1) of this section, the owner 

or operator shall submit the response 

plan, along with a completed version of 

the response plan cover sheet contained in Appendix F to this part, to 

the Regional Administrator before the 

portion of the facility undergoing 

change commences operations (adjustments to the response plan to reflect 

changes that occur at the facility during the start-up phase of operations 

must be submitted to the Regional Administrator after an operational trial 

period of 60 days). 

(iv) For a facility required to prepare 

and submit a response plan after August 30, 1994, as a result of an unplanned event or change in facility 

characteristics that renders the facility subject to the criteria in paragraph 

(f)(1) of this section, the owner or operator shall submit the response plan, 

along with a completed version of the 

response plan cover sheet contained in 

Appendix F to this part, to the Regional Administrator within six 

months of the unplanned event or 

change. 

(3) In the event the owner or operator 

of a facility that is required to prepare 

and submit a response plan uses an alternative formula that is comparable 

to one contained in Appendix C to this 

part to evaluate the criterion in paragraph (f)(1)(ii)(B) or (f)(1)(ii)(C) of this 

section, the owner or operator shall attach documentation to the response 

plan cover sheet contained in Appendix 

F to this part that demonstrates the 

reliability and analytical soundness of 

the alternative formula. 

41 
 

§ 112.20 

(4) Preparation and submission of response plans—Animal fat and vegetable 

oil facilities. The owner or operator of 

any non-transportation-related facility 

that handles, stores, or transports animal fats and vegetable oils must prepare and submit a facility response 

plan as follows: 

(i) Facilities with approved plans. The 

owner or operator of a facility with a 

facility response plan that has been approved under paragraph (c) of this section by July 31, 2000 need not prepare 

or submit a revised plan except as otherwise required by paragraphs (b), (c), 

or (d) of this section. 

(ii) Facilities with plans that have been 

submitted to the Regional Administrator. 

Except for facilities with approved 

plans as provided in paragraph (a)(4)(i) 

of this section, the owner or operator 

of a facility that has submitted a response plan to the Regional Administrator prior to July 31, 2000 must review the plan to determine if it meets 

or exceeds the applicable provisions of 

this part. An owner or operator need 

not prepare or submit a new plan if the 

existing plan meets or exceeds the applicable provisions of this part. If the 

plan does not meet or exceed the applicable provisions of this part, the owner 

or operator must prepare and submit a 

new plan by September 28, 2000. 

(iii) Newly regulated facilities. The 

owner or operator of a newly constructed facility that commences operation after July 31, 2000 must prepare 

and submit a plan to the Regional Administrator in accordance with paragraph (a)(2)(ii) of this section. The plan 

must meet or exceed the applicable 

provisions of this part. The owner or 

operator of an existing facility that 

must prepare and submit a plan after 

July 31, 2000 as a result of a planned or 

unplanned change in facility characteristics that causes the facility to become regulated under paragraph (f)(1) 

of this section, must prepare and submit a plan to the Regional Administrator in accordance with paragraph 

(a)(2)(iii) or (iv) of this section, as appropriate. The plan must meet or exceed the applicable provisions of this 

part. 

(iv) Facilities amending existing plans. 

The owner or operator of a facility submitting an amended plan in accordance 

40 CFR Ch. I (7–1–05 Edition) 

with paragraph (d) of this section after 

July 31, 2000, including plans that had 

been previously approved, must also review the plan to determine if it meets 

or exceeds the applicable provisions of 

this part. If the plan does not meet or 

exceed the applicable provisions of this 

part, the owner or operator must revise 

and resubmit revised portions of an 

amended plan to the Regional Administrator in accordance with paragraph (d) 

of this section, as appropriate. The 

plan must meet or exceed the applicable provisions of this part. 

(b)(1) The Regional Administrator 

may at any time require the owner or 

operator of any non-transportation-related onshore facility to prepare and 

submit a facility response plan under 

this section after considering the factors in paragraph (f)(2) of this section. 

If such a determination is made, the 

Regional Administrator shall notify 

the facility owner or operator in writing and shall provide a basis for the determination. If the Regional Administrator notifies the owner or operator in 

writing of the requirement to prepare 

and submit a response plan under this 

section, the owner or operator of the 

facility shall submit the response plan 

to the Regional Administrator within 

six months of receipt of such written 

notification. 

(2) The Regional Administrator shall 

review plans submitted by such facilities to determine whether the facility 

could, because of its location, reasonably be expected to cause significant 

and substantial harm to the environment by discharging oil into or on the 

navigable waters or adjoining shorelines. 

(c) The Regional Administrator shall 

determine whether a facility could, because of its location, reasonably be expected to cause significant and substantial harm to the environment by 

discharging oil into or on the navigable 

waters or adjoining shorelines, based 

on the factors in paragraph (f)(3) of this 

section. If such a determination is 

made, the Regional Administrator 

shall notify the owner or operator of 

the facility in writing and: 

(1) Promptly review the facility response plan; 

42 
 

Environmental Protection Agency 

(2) Require amendments to any response plan that does not meet the requirements of this section; 

(3) Approve any response plan that 

meets the requirements of this section; 

and 

(4) Review each response plan periodically thereafter on a schedule established by the Regional Administrator 

provided that the period between plan 

reviews does not exceed five years. 

(d)(1) The owner or operator of a facility for which a response plan is required under this part shall revise and 

resubmit revised portions of the response plan within 60 days of each facility change that materially may affect the response to a worst case discharge, including: 

(i) A change in the facility’s configuration that materially alters the information included in the response plan; 

(ii) A change in the type of oil handled, stored, or transferred that materially alters the required response resources; 

(iii) A material change in capabilities 

of the oil spill removal organization(s) 

that provide equipment and personnel 

to respond to discharges of oil described in paragraph (h)(5) of this section; 

(iv) A material change in the facility’s spill prevention and response 

equipment or emergency response procedures; and 

(v) Any other changes that materially affect the implementation of the 

response plan. 

(2) Except as provided in paragraph 

(d)(1) of this section, amendments to 

personnel and telephone number lists 

included in the response plan and a 

change in the oil spill removal organization(s) that does not result in a material change in support capabilities do 

not require approval by the Regional 

Administrator. Facility owners or operators shall provide a copy of such 

changes to the Regional Administrator 

as the revisions occur. 

(3) The owner or operator of a facility 

that submits changes to a response 

plan as provided in paragraph (d)(1) or 

(d)(2) of this section shall provide the 

EPA-issued facility identification number (where one has been assigned) with 

the changes. 

§ 112.20 

(4) The Regional Administrator shall 

review for approval changes to a response plan submitted pursuant to 

paragraph (d)(1) of this section for a facility determined pursuant to paragraph (f)(3) of this section to have the 

potential to cause significant and substantial harm to the environment. 

(e) If the owner or operator of a facility determines pursuant to paragraph 

(a)(2) of this section that the facility 

could not, because of its location, reasonably be expected to cause substantial harm to the environment by discharging oil into or on the navigable 

waters or adjoining shorelines, the 

owner or operator shall complete and 

maintain at the facility the certification form contained in Appendix C to 

this part and, in the event an alternative formula that is comparable to 

one contained in Appendix C to this 

part is used to evaluate the criterion in 

paragraph (f)(1)(ii)(B) or (f)(1)(ii)(C) of 

this section, the owner or operator 

shall attach documentation to the certification form that demonstrates the 

reliability and analytical soundness of 

the comparable formula and shall notify the Regional Administrator in 

writing that an alternative formula 

was used. 

(f)(1) A facility could, because of its 

location, reasonably be expected to 

cause substantial harm to the environment by discharging oil into or on the 

navigable waters or adjoining shorelines pursuant to paragraph (a)(2) of 

this section, if it meets any of the following criteria applied in accordance 

with the flowchart contained in Attachment C-I to Appendix C to this 

part: 

(i) The facility transfers oil over 

water to or from vessels and has a total 

oil storage capacity greater than or 

equal to 42,000 gallons; or 

(ii) The facility’s total oil storage capacity is greater than or equal to 1 million gallons, and one of the following is 

true: 

(A) The facility does not have secondary containment for each aboveground storage area sufficiently large 

to contain the capacity of the largest 

aboveground oil storage tank within 

each storage area plus sufficient 

freeboard to allow for precipitation; 

43 
 

§ 112.20 

(B) The facility is located at a distance (as calculated using the appropriate formula in Appendix C to this 

part or a comparable formula) such 

that a discharge from the facility could 

cause injury to fish and wildlife and 

sensitive environments. For further description of fish and wildlife and sensitive environments, see Appendices I, 

II, and III of the ‘‘Guidance for Facility 

and Vessel Response Plans: Fish and 

Wildlife and Sensitive Environments’’ 

(see Appendix E to this part, section 13, 

for availability) and the applicable 

Area Contingency Plan prepared pursuant to section 311(j)(4) of the Clean 

Water Act; 

(C) The facility is located at a distance (as calculated using the appropriate formula in Appendix C to this 

part or a comparable formula) such 

that a discharge from the facility 

would shut down a public drinking 

water intake; or 

(D) The facility has had a reportable 

oil discharge in an amount greater 

than or equal to 10,000 gallons within 

the last 5 years. 

(2)(i) To determine whether a facility 

could, because of its location, reasonably be expected to cause substantial 

harm to the environment by discharging oil into or on the navigable 

waters or adjoining shorelines pursuant to paragraph (b) of this section, the 

Regional Administrator shall consider 

the following: 

(A) Type of transfer operation; 

(B) Oil storage capacity; 

(C) Lack of secondary containment; 

(D) Proximity to fish and wildlife and 

sensitive environments and other areas 

determined by the Regional Administrator to possess ecological value; 

(E) Proximity to drinking water intakes; 

(F) Spill history; and 

(G) Other site-specific characteristics 

and environmental factors that the Regional Administrator determines to be 

relevant to protecting the environment 

from harm by discharges of oil into or 

on navigable waters or adjoining shorelines. 

(ii) Any person, including a member 

of the public or any representative 

from a Federal, State, or local agency 

who believes that a facility subject to 

this section could, because of its loca40 CFR Ch. I (7–1–05 Edition) 

tion, reasonably be expected to cause 

substantial harm to the environment 

by discharging oil into or on the navigable waters or adjoining shorelines 

may petition the Regional Administrator to determine whether the facility meets the criteria in paragraph 

(f)(2)(i) of this section. Such petition 

shall include a discussion of how the 

factors in paragraph (f)(2)(i) of this section apply to the facility in question. 

The RA shall consider such petitions 

and respond in an appropriate amount 

of time. 

(3) To determine whether a facility 

could, because of its location, reasonably be expected to cause significant 

and substantial harm to the environment by discharging oil into or on the 

navigable waters or adjoining shorelines, the Regional Administrator may 

consider the factors in paragraph (f)(2) 

of this section as well as the following: 

(i) Frequency of past discharges; 

(ii) Proximity to navigable waters; 

(iii) Age of oil storage tanks; and 

(iv) Other facility-specific and Region-specific information, including 

local impacts on public health. 

(g)(1) All facility response plans shall 

be consistent with the requirements of 

the National Oil and Hazardous Substance Pollution Contingency Plan (40 

CFR part 300) and applicable Area Contingency Plans prepared pursuant to 

section 311(j)(4) of the Clean Water Act. 

The facility response plan should be coordinated with the local emergency response plan developed by the local 

emergency planning committee under 

section 303 of Title III of the Superfund 

Amendments and Reauthorization Act 

of 1986 (42 U.S.C. 11001 et seq.). Upon request, the owner or operator should 

provide a copy of the facility response 

plan to the local emergency planning 

committee or State emergency response commission. 

(2) The owner or operator shall review relevant portions of the National 

Oil and Hazardous Substances Pollution Contingency Plan and applicable 

Area Contingency Plan annually and, if 

necessary, revise the facility response 

plan to ensure consistency with these 

plans. 

(3) The owner or operator shall review and update the facility response 

44 
 

Environmental Protection Agency 

plan periodically to reflect changes at 

the facility. 

(h) A response plan shall follow the 

format of the model facility-specific response plan included in Appendix F to 

this part, unless you have prepared an 

equivalent response plan acceptable to 

the Regional Administrator to meet 

State or other Federal requirements. A 

response plan that does not follow the 

specified format in Appendix F to this 

part shall have an emergency response 

action plan as specified in paragraphs 

(h)(1) of this section and be supplemented with a cross-reference section 

to identify the location of the elements 

listed in paragraphs (h)(2) through 

(h)(10) of this section. To meet the requirements of this part, a response 

plan shall address the following elements, as further described in Appendix F to this part: 

(1) Emergency response action plan. 

The response plan shall include an 

emergency response action plan in the 

format specified in paragraphs (h)(1)(i) 

through (viii) of this section that is 

maintained in the front of the response 

plan, or as a separate document accompanying the response plan, and that includes the following information: 

(i) The identity and telephone number of a qualified individual having full 

authority, including contracting authority, to implement removal actions; 

(ii) The identity of individuals or organizations to be contacted in the 

event of a discharge so that immediate 

communications between the qualified 

individual identified in paragraph (h)(1) 

of this section and the appropriate Federal officials and the persons providing 

response personnel and equipment can 

be ensured; 

(iii) A description of information to 

pass to response personnel in the event 

of a reportable discharge; 

(iv) A description of the facility’s response equipment and its location; 

(v) A description of response personnel capabilities, including the duties of persons at the facility during a 

response action and their response 

times and qualifications; 

(vi) Plans for evacuation of the facility and a reference to community evacuation plans, as appropriate; 

(vii) A description of immediate 

measures to secure the source of the 

§ 112.20 

discharge, and to provide adequate containment and drainage of discharged 

oil; and 

(viii) A diagram of the facility. 

(2) Facility information. The response 

plan shall identify and discuss the location and type of the facility, the identity and tenure of the present owner 

and operator, and the identity of the 

qualified individual identified in paragraph (h)(1) of this section. 

(3) Information about emergency response. The response plan shall include: 

(i) The identity of private personnel 

and equipment necessary to remove to 

the maximum extent practicable a 

worst case discharge and other discharges of oil described in paragraph 

(h)(5) of this section, and to mitigate or 

prevent a substantial threat of a worst 

case discharge (To identify response resources to meet the facility response 

plan requirements of this section, owners or operators shall follow Appendix 

E to this part or, where not appropriate, shall clearly demonstrate in the 

response plan why use of Appendix E of 

this part is not appropriate at the facility and make comparable arrangements for response resources); 

(ii) Evidence of contracts or other approved means for ensuring the availability of such personnel and equipment; 

(iii) The identity and the telephone 

number of individuals or organizations 

to be contacted in the event of a discharge so that immediate communications between the qualified individual 

identified in paragraph (h)(1) of this 

section and the appropriate Federal official and the persons providing response personnel and equipment can be 

ensured; 

(iv) A description of information to 

pass to response personnel in the event 

of a reportable discharge; 

(v) A description of response personnel capabilities, including the duties of persons at the facility during a 

response action and their response 

times and qualifications; 

(vi) A description of the facility’s response equipment, the location of the 

equipment, and equipment testing; 

(vii) Plans for evacuation of the facility and a reference to community evacuation plans, as appropriate; 

45 
 

§ 112.20 

(viii) A diagram of evacuation routes; 

and 

(ix) A description of the duties of the 

qualified individual identified in paragraph (h)(1) of this section, that include: 

(A) Activate internal alarms and hazard communication systems to notify 

all facility personnel; 

(B) Notify all response personnel, as 

needed; 

(C) Identify the character, exact 

source, amount, and extent of the release, as well as the other items needed 

for notification; 

(D) Notify and provide necessary information to the appropriate Federal, 

State, and local authorities with designated response roles, including the 

National Response Center, State Emergency Response Commission, and Local 

Emergency Planning Committee; 

(E) Assess the interaction of the discharged substance with water and/or 

other substances stored at the facility 

and notify response personnel at the 

scene of that assessment; 

(F) Assess the possible hazards to 

human health and the environment due 

to the release. This assessment must 

consider both the direct and indirect 

effects of the release (i.e., the effects of 

any toxic, irritating, or asphyxiating 

gases that may be generated, or the effects of any hazardous surface water 

runoffs from water or chemical agents 

used to control fire and heat-induced 

explosion); 

(G) Assess and implement prompt removal actions to contain and remove 

the substance released; 

(H) Coordinate rescue and response 

actions as previously arranged with all 

response personnel; 

(I) Use authority to immediately access company funding to initiate cleanup activities; and 

(J) Direct cleanup activities until 

properly relieved of this responsibility. 

(4) Hazard evaluation. The response 

plan shall discuss the facility’s known 

or reasonably identifiable history of 

discharges reportable under 40 CFR 

part 110 for the entire life of the facility and shall identify areas within the 

facility where discharges could occur 

and what the potential effects of the 

discharges would be on the affected environment. To assess the range of areas 

40 CFR Ch. I (7–1–05 Edition) 

potentially affected, owners or operators shall, where appropriate, consider 

the distance calculated in paragraph 

(f)(1)(ii) of this section to determine 

whether a facility could, because of its 

location, reasonably be expected to 

cause substantial harm to the environment by discharging oil into or on the 

navigable waters or adjoining shorelines. 

(5) Response planning levels. The response plan shall include discussion of 

specific planning scenarios for: 

(i) A worst case discharge, as calculated using the appropriate worksheet in Appendix D to this part. In 

cases where the Regional Administrator determines that the worst case 

discharge volume calculated by the facility is not appropriate, the Regional 

Administrator may specify the worst 

case discharge amount to be used for 

response planning at the facility. For 

complexes, the worst case planning 

quantity shall be the larger of the 

amounts calculated for each component of the facility; 

(ii) A discharge of 2,100 gallons or 

less, provided that this amount is less 

than the worst case discharge amount. 

For complexes, this planning quantity 

shall be the larger of the amounts calculated for each component of the facility; and 

(iii) A discharge greater than 2,100 

gallons and less than or equal to 36,000 

gallons or 10 percent of the capacity of 

the largest tank at the facility, whichever is less, provided that this amount 

is less than the worst case discharge 

amount. For complexes, this planning 

quantity shall be the larger of the 

amounts calculated for each component of the facility. 

(6) Discharge detection systems. The response plan shall describe the procedures and equipment used to detect discharges. 

(7) Plan implementation. The response 

plan shall describe: 

(i) Response actions to be carried out 

by facility personnel or contracted personnel under the response plan to ensure the safety of the facility and to 

mitigate or prevent discharges described in paragraph (h)(5) of this section or the substantial threat of such 

discharges; 

46 
 

Environmental Protection Agency 

(ii) A description of the equipment to 

be used for each scenario; 

(iii) Plans to dispose of contaminated 

cleanup materials; and 

(iv) Measures to provide adequate 

containment and drainage of discharged oil. 

(8) Self-inspection, drills/exercises, and 

response training. The response plan 

shall include: 

(i) A checklist and record of inspections for tanks, secondary containment, and response equipment; 

(ii) A description of the drill/exercise 

program to be carried out under the response plan as described in § 112.21; 

(iii) A description of the training program to be carried out under the response plan as described in § 112.21; and 

(iv) Logs of discharge prevention 

meetings, training sessions, and drills/ 

exercises. These logs may be maintained as an annex to the response 

plan. 

(9) Diagrams. The response plan shall 

include site plan and drainage plan diagrams. 

(10) Security systems. The response 

plan shall include a description of facility security systems. 

(11) Response plan cover sheet. The response plan shall include a completed 

response plan cover sheet provided in 

Section 2.0 of Appendix F to this part. 

(i)(1) In the event the owner or operator of a facility does not agree with 

the Regional Administrator’s determination that the facility could, because of its location, reasonably be expected to cause substantial harm or 

significant and substantial harm to the 

environment by discharging oil into or 

on the navigable waters or adjoining 

shorelines, or that amendments to the 

facility response plan are necessary 

prior to approval, such as changes to 

the worst case discharge planning volume, the owner or operator may submit a request for reconsideration to 

the Regional Administrator and provide additional information and data in 

writing to support the request. The request and accompanying information 

must be submitted to the Regional Administrator within 60 days of receipt of 

notice of the Regional Administrator’s 

original decision. The Regional Administrator shall consider the request and 

§ 112.21 

render a decision as rapidly as practicable. 

(2) In the event the owner or operator 

of a facility believes a change in the facility’s classification status is warranted because of an unplanned event 

or change in the facility’s characteristics (i.e., substantial harm or significant and substantial harm), the owner 

or operator may submit a request for 

reconsideration to the Regional Administrator and provide additional information and data in writing to support the request. The Regional Administrator shall consider the request and 

render a decision as rapidly as practicable. 

(3) After a request for reconsideration under paragraph (i)(1) or (i)(2) of 

this section has been denied by the Regional Administrator, an owner or operator may appeal a determination 

made by the Regional Administrator. 

The appeal shall be made to the EPA 

Administrator and shall be made in 

writing within 60 days of receipt of the 

decision from the Regional Administrator that the request for reconsideration was denied. A complete copy of 

the appeal must be sent to the Regional Administrator at the time the 

appeal is made. The appeal shall contain a clear and concise statement of 

the issues and points of fact in the 

case. It also may contain additional information from the owner or operator, 

or from any other person. The EPA Administrator may request additional information from the owner or operator, 

or from any other person. The EPA Administrator shall render a decision as 

rapidly as practicable and shall notify 

the owner or operator of the decision. 

[59 FR 34098, July 1, 1994, as amended at 65 

FR 40798, June 30, 2000; 66 FR 34560, June 29, 

2001; 67 FR 47151, July 17, 2002] 

§ 112.21 Facility response training and 

drills/exercises. 

(a) The owner or operator of any facility required to prepare a facility response plan under § 112.20 shall develop 

and implement a facility response 

training program and a drill/exercise 

program that satisfy the requirements 

of this section. The owner or operator 

shall describe the programs in the response plan as provided in § 112.20(h)(8). 

47 
 

Pt. 112, App. A 

(b) The facility owner or operator 

shall develop a facility response training program to train those personnel 

involved in oil spill response activities. 

It is recommended that the training 

program be based on the USCG’s Training Elements for Oil Spill Response, as 

applicable to facility operations. An alternative program can also be acceptable subject to approval by the Regional Administrator. 

(1) The owner or operator shall be responsible for the proper instruction of 

facility personnel in the procedures to 

respond to discharges of oil and in applicable oil spill response laws, rules, 

and regulations. 

(2) Training shall be functional in nature according to job tasks for both supervisory and non-supervisory operational personnel. 

(3) Trainers shall develop specific lesson plans on subject areas relevant to 

facility personnel involved in oil spill 

response and cleanup. 

(c) The facility owner or operator 

shall develop a program of facility response drills/exercises, including evaluation procedures. A program that follows the National Preparedness for Response Exercise Program (PREP) (see 

Appendix E to this part, section 13, for 

availability) will be deemed satisfactory for purposes of this section. An alternative program can also be acceptable subject to approval by the Regional Administrator. 

[59 FR 34101, July 1, 1994, as amended at 65 

FR 40798, June 30, 2000] 

APPENDIX A TO PART 112—MEMORANDUM 

OF UNDERSTANDING BETWEEN THE 

SECRETARY OF TRANSPORTATION AND 

THE ADMINISTRATOR OF THE ENVIRONMENTAL PROTECTION AGENCY 

SECTION II—DEFINITIONS 

The Environmental Protection Agency and 

the Department of Transportation agree that 

for the purposes of Executive Order 11548, the 

term: 

(1) Non-transportation-related onshore and 

offshore facilities means: 

(A) Fixed onshore and offshore oil well 

drilling facilities including all equipment 

and appurtenances related thereto used in 

drilling operations for exploratory or development wells, but excluding any terminal facility, unit or process integrally associated 

with the handling or transferring of oil in 

bulk to or from a vessel. 

40 CFR Ch. I (7–1–05 Edition) 

(B) Mobile onshore and offshore oil well 

drilling platforms, barges, trucks, or other 

mobile facilities including all equipment and 

appurtenances related thereto when such 

mobile facilities are fixed in position for the 

purpose of drilling operations for exploratory 

or development wells, but excluding any terminal facility, unit or process integrally associated with the handling or transferring of 

oil in bulk to or from a vessel. 

(C) Fixed onshore and offshore oil production structures, platforms, derricks, and rigs 

including all equipment and appurtenances 

related thereto, as well as completed wells 

and the wellhead separators, oil separators, 

and storage facilities used in the production 

of oil, but excluding any terminal facility, 

unit or process integrally associated with 

the handling or transferring of oil in bulk to 

or from a vessel. 

(D) Mobile onshore and offshore oil production facilities including all equipment and 

appurtenances related thereto as well as 

completed wells and wellhead equipment, 

piping from wellheads to oil separators, oil 

separators, and storage facilities used in the 

production of oil when such mobile facilities 

are fixed in position for the purpose of oil 

production operations, but excluding any 

terminal facility, unit or process integrally 

associated with the handling or transferring 

of oil in bulk to or from a vessel. 

(E) Oil refining facilities including all 

equipment and appurtenances related thereto as well as in-plant processing units, storage units, piping, drainage systems and 

waste treatment units used in the refining of 

oil, but excluding any terminal facility, unit 

or process integrally associated with the 

handling or transferring of oil in bulk to or 

from a vessel. 

(F) Oil storage facilities including all 

equipment and appurtenances related thereto as well as fixed bulk plant storage, terminal oil storage facilities, consumer storage, pumps and drainage systems used in the 

storage of oil, but excluding inline or breakout storage tanks needed for the continuous 

operation of a pipeline system and any terminal facility, unit or process integrally associated with the handling or transferring of 

oil in bulk to or from a vessel. 

(G) Industrial, commercial, agricultural or 

public facilities which use and store oil, but 

excluding any terminal facility, unit or process integrally associated with the handling 

or transferring of oil in bulk to or from a 

vessel. 

(H) Waste treatment facilities including 

in-plant pipelines, effluent discharge lines, 

and storage tanks, but excluding waste 

treatment facilities located on vessels and 

terminal storage tanks and appurtenances 

for the reception of oily ballast water or 

tank washings from vessels and associated 

systems used for off-loading vessels. 

48 
 

Environmental Protection Agency 

(I) Loading racks, transfer hoses, loading 

arms and other equipment which are appurtenant to a nontransportation-related facility or terminal facility and which are used 

to transfer oil in bulk to or from highway vehicles or railroad cars. 

(J) Highway vehicles and railroad cars 

which are used for the transport of oil exclusively within the confines of a nontransportation-related facility and which are not 

intended to transport oil in interstate or 

intrastate commerce. 

(K) Pipeline systems which are used for the 

transport of oil exclusively within the confines of a nontransportation-related facility 

or terminal facility and which are not intended to transport oil in interstate or intrastate commerce, but excluding pipeline systems used to transfer oil in bulk to or from 

a vessel. 

(2) Transportation-related onshore and offshore facilities means: 

(A) Onshore and offshore terminal facilities including transfer hoses, loading arms 

and other equipment and appurtenances used 

for the purpose of handling or transferring 

oil in bulk to or from a vessel as well as storage tanks and appurtenances for the reception of oily ballast water or tank washings 

from vessels, but excluding terminal waste 

treatment facilities and terminal oil storage 

facilities. 

(B) Transfer hoses, loading arms and other 

equipment appurtenant to a non-transportation-related facility which is used to transfer oil in bulk to or from a vessel. 

(C) Interstate and intrastate onshore and 

offshore pipeline systems including pumps 

and appurtenances related thereto as well as 

in-line or breakout storage tanks needed for 

the continuous operation of a pipeline system, and pipelines from onshore and offshore 

oil production facilities, but excluding onshore and offshore piping from wellheads to 

oil separators and pipelines which are used 

for the transport of oil exclusively within 

the confines of a nontransportation-related 

facility or terminal facility and which are 

not intended to transport oil in interstate or 

intrastate commerce or to transfer oil in 

bulk to or from a vessel. 

(D) Highway vehicles and railroad cars 

which are used for the transport of oil in 

interstate or intrastate commerce and the 

equipment and appurtenances related thereto, and equipment used for the fueling of locomotive units, as well as the rights-of-way 

on which they operate. Excluded are highway vehicles and railroad cars and motive 

power used exclusively within the confines of 

a nontransportation-related facility or terminal facility and which are not intended for 

use in interstate or intrastate commerce. 

Pt. 112, App. B 

APPENDIX B TO PART 112—MEMORANDUM 

OF UNDERSTANDING AMONG THE SECRETARY OF THE INTERIOR, SECRETARY OF TRANSPORTATION, AND 

ADMINISTRATOR OF THE ENVIRONMENTAL PROTECTION AGENCY 

PURPOSE 

This Memorandum of Understanding 

(MOU) establishes the jurisdictional responsibilities for offshore facilities, including 

pipelines, pursuant to section 311 (j)(1)(c), 

(j)(5), and (j)(6)(A) of the Clean Water Act 

(CWA), as amended by the Oil Pollution Act 

of 1990 (Public Law 101–380). The Secretary of 

the Department of the Interior (DOI), Secretary of the Department of Transportation 

(DOT), and Administrator of the Environmental Protection Agency (EPA) agree to 

the division of responsibilities set forth 

below for spill prevention and control, response planning, and equipment inspection 

activities pursuant to those provisions. 

BACKGROUND 

Executive Order (E.O.) 12777 (56 FR 54757) 

delegates to DOI, DOT, and EPA various responsibilities identified in section 311(j) of 

the CWA. Sections 2(b)(3), 2(d)(3), and 2(e)(3) 

of E.O. 12777 assigned to DOI spill prevention 

and control, contingency planning, and 

equipment inspection activities associated 

with offshore facilities. Section 311(a)(11) defines the term ‘‘offshore facility’’ to include 

facilities of any kind located in, on, or under 

navigable waters of the United States. By 

using this definition, the traditional DOI 

role of regulating facilities on the Outer 

Continental Shelf is expanded by E.O. 12777 

to include inland lakes, rivers, streams, and 

any other inland waters. 

RESPONSIBILITIES 

Pursuant to section 2(i) of E.O. 12777, DOI 

redelegates, and EPA and DOT agree to assume, the functions vested in DOI by sections 2(b)(3), 2(d)(3), and 2(e)(3) of E.O. 12777 

as set forth below. For purposes of this MOU, 

the term ‘‘coast line’’ shall be defined as in 

the Submerged Lands Act (43 U.S.C. 1301(c)) 

to mean ‘‘the line of ordinary low water 

along that portion of the coast which is in 

direct contact with the open sea and the line 

marking the seaward limit of inland waters.’’ 

1. To EPA, DOI redelegates responsibility 

for non-transportation-related offshore facilities located landward of the coast line. 

2. To DOT, DOI redelegates responsibility 

for transportation-related facilities, including pipelines, located landward of the coast 

line. The DOT retains jurisdiction for deepwater ports and their associated seaward 

pipelines, as delegated by E.O. 12777. 

49 
 

Pt. 112, App. C 

3. The DOI retains jurisdiction over facilities, including pipelines, located seaward of 

the coast line, except for deepwater ports 

and associated seaward pipelines delegated 

by E.O. 12777 to DOT. 

EFFECTIVE DATE 

This MOU is effective on the date of the 

final execution by the indicated signatories. 

LIMITATIONS 

1. The DOI, DOT, and EPA may agree in 

writing to exceptions to this MOU on a facility-specific basis. Affected parties will receive notification of the exceptions. 

2. Nothing in this MOU is intended to replace, supersede, or modify any existing 

agreements between or among DOI, DOT, or 

EPA. 

MODIFICATION AND TERMINATION 

Any party to this agreement may propose 

modifications by submitting them in writing 

to the heads of the other agency/department. 

No modification may be adopted except with 

the consent of all parties. All parties shall 

indicate their consent to or disagreement 

with any proposed modification within 60 

days of receipt. Upon the request of any 

party, representatives of all parties shall 

meet for the purpose of considering exceptions or modifications to this agreement. 

This MOU may be terminated only with the 

mutual consent of all parties. 

Dated: November 8, 1993. 

Bruce Babbitt, 

Secretary of the Interior. 

Dated: December 14, 1993. 

Federico Pen ̃ a, 

Secretary of Transportation. 

Dated: February 3, 1994. 

Carol M. Browner, 

Administrator, Environmental Protection 

Agency. 

[59 FR 34102, July 1, 1994] 

APPENDIX C TO PART 112—SUBSTANTIAL 

HARM CRITERIA 

1.0 INTRODUCTION 

The flowchart provided in Attachment C–I 

to this appendix shows the decision tree with 

the criteria to identify whether a facility 

‘‘could reasonably be expected to cause substantial harm to the environment by discharging into or on the navigable waters or 

adjoining shorelines.’’ In addition, the Regional Administrator has the discretion to 

identify facilities that must prepare and submit facility-specific response plans to EPA. 

1.1 Definitions 

1.1.1 Great Lakes means Lakes Superior, 

Michigan, Huron, Erie, and Ontario, their 

connecting and tributary waters, the Saint 

40 CFR Ch. I (7–1–05 Edition) 

Lawrence River as far as Saint Regis, and 

adjacent port areas. 

1.1.2 Higher Volume Port Areas include 

(1) Boston, MA; 

(2) New York, NY; 

(3) Delaware Bay and River to Philadelphia, PA; 

(4) St. Croix, VI; 

(5) Pascagoula, MS; 

(6) Mississippi River from Southwest Pass, 

LA to Baton Rouge, LA; 

(7) Louisiana Offshore Oil Port (LOOP), 

LA; 

(8) Lake Charles, LA; 

(9) Sabine-Neches River, TX; 

(10) Galveston Bay and Houston Ship Channel, TX; 

(11) Corpus Christi, TX; 

(12) Los Angeles/Long Beach Harbor, CA; 

(13) San Francisco Bay, San Pablo Bay, 

Carquinez Strait, and Suisun Bay to Antioch, CA; 

(14) Straits of Juan de Fuca from Port Angeles, WA to and including Puget Sound, 

WA; 

(15) Prince William Sound, AK; and 

(16) Others as specified by the Regional Administrator for any EPA Region. 

1.1.3 Inland Area means the area shoreward of the boundary lines defined in 46 CFR 

part 7, except in the Gulf of Mexico. In the 

Gulf of Mexico, it means the area shoreward 

of the lines of demarcation (COLREG lines as 

defined in 33 CFR 80.740—80.850). The inland 

area does not include the Great Lakes. 

1.1.4 Rivers and Canals means a body of 

water confined within the inland area, including the Intracoastal Waterways and 

other waterways artificially created for 

navigating that have project depths of 12 feet 

or less. 

2.0	 DESCRIPTION OF SCREENING CRITERIA FOR 

THE SUBSTANTIAL HARM FLOWCHART 

A facility that has the potential to cause 

substantial harm to the environment in the 

event of a discharge must prepare and submit a facility-specific response plan to EPA 

in accordance with Appendix F to this part. 

A description of the screening criteria for 

the substantial harm flowchart is provided 

below: 

2.1 Non-Transportation-Related Facilities 

With a Total Oil Storage Capacity Greater Than 

or Equal to 42,000 Gallons Where Operations Include Over-Water Transfers of Oil. A nontransportation-related facility with a total 

oil storage capacity greater than or equal to 

42,000 gallons that transfers oil over water to 

or from vessels must submit a response plan 

to EPA. Daily oil transfer operations at 

these types of facilities occur between barges 

and vessels and onshore bulk storage tanks 

over open water. These facilities are located 

adjacent to navigable water. 

50 
 

Environmental Protection Agency 

2.2 Lack of Adequate Secondary Containment at Facilities With a Total Oil Storage Capacity Greater Than or Equal to 1 Million Gallons. Any facility with a total oil storage capacity greater than or equal to 1 million gallons without secondary containment sufficiently large to contain the capacity of the 

largest aboveground oil storage tank within 

each area plus sufficient freeboard to allow 

for precipitation must submit a response 

plan to EPA. Secondary containment structures that meet the standard of good engineering practice for the purposes of this part 

include berms, dikes, retaining walls, curbing, culverts, gutters, or other drainage systems. 

2.3 Proximity to Fish and Wildlife and Sensitive Environments at Facilities With a Total 

Oil Storage Capacity Greater Than or Equal to 

1 Million Gallons. A facility with a total oil 

storage capacity greater than or equal to 1 

million gallons must submit its response 

plan if it is located at a distance such that 

a discharge from the facility could cause injury (as defined at 40 CFR 112.2) to fish and 

wildlife and sensitive environments. For further description of fish and wildlife and sensitive environments, see Appendices I, II, and 

III to DOC/NOAA’s ‘‘Guidance for Facility 

and Vessel Response Plans: Fish and Wildlife 

and Sensitive Environments’’ (see Appendix 

E to this part, section 13, for availability) 

and the applicable Area Contingency Plan. 

Facility owners or operators must determine 

the distance at which an oil discharge could 

cause injury to fish and wildlife and sensitive environments using the appropriate 

formula presented in Attachment C–III to 

this appendix or a comparable formula. 

2.4 Proximity to Public Drinking Water Intakes at Facilities with a Total Oil Storage Capacity Greater than or Equal to 1 Million Gallons A facility with a total oil storage capacity greater than or equal to 1 million gallons 

must submit its response plan if it is located 

at a distance such that a discharge from the 

facility would shut down a public drinking 

water intake, which is analogous to a public 

Pt. 112, App. C 

water system as described at 40 CFR 143.2(c). 

The distance at which an oil discharge from 

an SPCC-regulated facility would shut down 

a public drinking water intake shall be calculated using the appropriate formula presented in Attachment C–III to this appendix 

or a comparable formula. 

2.5 Facilities That Have Experienced Reportable Oil Discharges in an Amount Greater Than 

or Equal to 10,000 Gallons Within the Past 5 

Years and That Have a Total Oil Storage Capacity Greater Than or Equal to 1 Million Gallons. A facility’s oil spill history within the 

past 5 years shall be considered in the evaluation for substantial harm. Any facility 

with a total oil storage capacity greater 

than or equal to 1 million gallons that has 

experienced a reportable oil discharge in an 

amount greater than or equal to 10,000 gallons within the past 5 years must submit a 

response plan to EPA. 

3.0	 CERTIFICATION FOR FACILITIES THAT DO 

NOT POSE SUBSTANTIAL HARM 

If the facility does not meet the substantial harm criteria listed in Attachment C–I 

to this appendix, the owner or operator shall 

complete and maintain at the facility the 

certification form contained in Attachment 

C–II to this appendix. In the event an alternative formula that is comparable to the one 

in this appendix is used to evaluate the substantial harm criteria, the owner or operator 

shall attach documentation to the certification form that demonstrates the reliability and analytical soundness of the comparable formula and shall notify the Regional Administrator in writing that an alternative formula was used. 

4.0 REFERENCES 

Chow, V.T. 1959. Open Channel Hydraulics. 

McGraw Hill. 

USCG IFR (58 FR 7353, February 5, 1993). 

This document is available through EPA’s 

rulemaking docket as noted in Appendix E to 

this part, section 13. 

51 
 
 

ER30JN00.061</GPH>

Pt. 112, App. C 40 CFR Ch. I (7–1–05 Edition) 

ATTACHMENTS TO APPENDIX C 

52 
 
 

Environmental Protection Agency 

ATTACHMENT C-II—CERTIFICATION OF THE APPLICABILITY OF THE SUBSTANTIAL HARM CRITERIA 

Facility Name: lllllllllllllll 

Facility Address: llllllllllllll 

1. Does the facility transfer oil over water 

to or from vessels and does the facility have 

a total oil storage capacity greater than or 

equal to 42,000 gallons? 

Yes lll No lll 

2. Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and does the facility lack secondary 

containment that is sufficiently large to 

contain the capacity of the largest aboveground oil storage tank plus sufficient 

freeboard to allow for precipitation within 

any aboveground oil storage tank area? 

Yes lll No lll 

3. Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and is the facility located at a distance (as calculated using the appropriate 

formula in Attachment C–III to this appendix or a comparable formula 1) such that a 

discharge from the facility could cause injury to fish and wildlife and sensitive environments? For further description of fish and 

wildlife and sensitive environments, see Appendices I, II, and III to DOC/NOAA’s ‘‘Guidance for Facility and Vessel Response Plans: 

Fish and Wildlife and Sensitive Environments’’ (see Appendix E to this part, section 

13, for availability) and the applicable Area 

Contingency Plan. 

Yes lll No lll 

4. Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and is the facility located at a distance (as calculated using the appropriate 

formula in Attachment C-III to this appendix 

or a comparable formula 1) such that a discharge from the facility would shut down a 

public drinking water intake 2 ? 

Yes lll No lll 

5. Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and has the facility experienced a reportable oil discharge in an amount greater 

than or equal to 10,000 gallons within the last 

5 years? 

Yes lll No lll 

Certification 

I certify under penalty of law that I have 

personally examined and am familiar with 

the information submitted in this document, 

1 If a comparable formula is used, documentation of the reliability and analytical 

soundness of the comparable formula must 

be attached to this form. 2 For the purposes of 40 CFR part 112, public drinking water intakes are analogous to 

public water systems as described at 40 CFR 

143.2(c). 

Pt. 112, App. C 

and that based on my inquiry of those individuals responsible for obtaining this information, I believe that the submitted information is true, accurate, and complete. 

llllllllllllllllllllllll 

Signature 

llllllllllllllllllllllll 

Name (please type or print) 

llllllllllllllllllllllll 

Title 

llllllllllllllllllllllll 

Date 

ATTACHMENT C-III—CALCULATION OF THE 

PLANNING DISTANCE 

1.0 Introduction 

1.1 The facility owner or operator must 

evaluate whether the facility is located at a 

distance such that a discharge from the facility could cause injury to fish and wildlife 

and sensitive environments or disrupt operations at a public drinking water intake. To 

quantify that distance, EPA considered oil 

transport mechanisms over land and on still, 

tidal influence, and moving navigable waters. EPA has determined that the primary 

concern for calculation of a planning distance is the transport of oil in navigable waters during adverse weather conditions. 

Therefore, two formulas have been developed 

to determine distances for planning purposes 

from the point of discharge at the facility to 

the potential site of impact on moving and 

still waters, respectively. The formula for oil 

transport on moving navigable water is 

based on the velocity of the water body and 

the time interval for arrival of response resources. The still water formula accounts for 

the spread of discharged oil over the surface 

of the water. The method to determine oil 

transport on tidal influence areas is based on 

the type of oil discharged and the distance 

down current during ebb tide and up current 

during flood tide to the point of maximum 

tidal influence. 

1.2 EPA’s formulas were designed to be 

simple to use. However, facility owners or 

operators may calculate planning distances 

using more sophisticated formulas, which 

take into account broader scientific or engineering principles, or local conditions. Such 

comparable formulas may result in different 

planning distances than EPA’s formulas. In 

the event that an alternative formula that is 

comparable to one contained in this appendix is used to evaluate the criterion in 40 

CFR 112.20(f)(1)(ii)(B) or (f)(1)(ii)(C), the 

owner or operator shall attach documentation to the response plan cover sheet contained in Appendix F to this part that demonstrates the reliability and analytical 

soundness of the alternative formula and 

shall notify the Regional Administrator in 

53 
 
 

Pt. 112, App. C 

writing that an alternative formula was 

used.1 

1.3 A regulated facility may meet the criteria for the potential to cause substantial 

harm to the environment without having to 

perform a planning distance calculation. For 

facilities that meet the substantial harm criteria because of inadequate secondary containment or oil spill history, as listed in the 

flowchart in Attachment C–I to this appendix, calculation of the planning distance is 

unnecessary. For facilities that do not meet 

the substantial harm criteria for secondary 

containment or oil spill history as listed in 

the flowchart, calculation of a planning distance for proximity to fish and wildlife and 

sensitive environments and public drinking 

water intakes is required, unless it is clear 

without performing the calculation (e.g., the 

facility is located in a wetland) that these 

areas would be impacted. 

1.4 A facility owner or operator who must 

perform a planning distance calculation on 

navigable water is only required to do so for 

the type of navigable water conditions (i.e., 

moving water, still water, or tidal- influenced water) applicable to the facility. If a 

facility owner or operator determines that 

more than one type of navigable water condition applies, then the facility owner or operator is required to perform a planning distance calculation for each navigable water 

type to determine the greatest single distance that oil may be transported. As a result, the final planning distance for oil 

transport on water shall be the greatest individual distance rather than a summation of 

each calculated planning distance. 

1.5 The planning distance formula for 

transport on moving waterways contains 

three variables: the velocity of the navigable 

water (v), the response time interval (t), and 

a conversion factor (c). The velocity, v, is determined by using the Chezy-Manning equation, which, in this case, models the flood 

flow rate of water in open channels. The 

Chezy-Manning equation contains three variables which must be determined by facility 

owners or operators. Manning’s Roughness 

1 For persistent oils or non-persistent oils, 

a worst case trajectory model (i.e., an alternative formula) may be substituted for the 

distance formulas described in still, moving, 

and tidal waters, subject to Regional Administrator’s review of the model. An example of 

an alternative formula that is comparable to 

the one contained in this appendix would be 

a worst case trajectory calculation based on 

credible adverse winds, currents, and/or river 

stages, over a range of seasons, weather conditions, and river stages. Based on historical 

information or a spill trajectory model, the 

Agency may require that additional fish and 

wildlife and sensitive environments or public 

drinking water intakes also be protected. 

40 CFR Ch. I (7–1–05 Edition) 

Coefficient (for flood flow rates), n, can be 

determined from Table 1 of this attachment. 

The hydraulic radius, r, can be estimated 

using the average mid-channel depth from 

charts provided by the sources listed in 

Table 2 of this attachment. The average 

slope of the river, s, can be determined using 

topographic maps that can be ordered from 

the U.S. Geological Survey, as listed in 

Table 2 of this attachment. 

1.6 Table 3 of this attachment contains 

specified time intervals for estimating the 

arrival of response resources at the scene of 

a discharge. Assuming no prior planning, response resources should be able to arrive at 

the discharge site within 12 hours of the discovery of any oil discharge in Higher Volume 

Port Areas and within 24 hours in Great 

Lakes and all other river, canal, inland, and 

nearshore areas. The specified time intervals 

in Table 3 of Appendix C are to be used only 

to aid in the identification of whether a facility could cause substantial harm to the 

environment. Once it is determined that a 

plan must be developed for the facility, the 

owner or operator shall reference Appendix E 

to this part to determine appropriate resource levels and response times. The specified time intervals of this appendix include a 

3-hour time period for deployment of boom 

and other response equipment. The Regional 

Administrator may identify additional areas 

as appropriate. 

2.0 Oil Transport on Moving Navigable Waters 

2.1 The facility owner or operator must 

use the following formula or a comparable 

formula as described in § 112.20(a)(3) to calculate the planning distance for oil transport 

on moving navigable water: 

d=v×t×c; where 

d: the distance downstream from a facility 

within which fish and wildlife and sensitive 

environments could be injured or a public 

drinking water intake would be shut down 

in the event of an oil discharge (in miles); 

v: the velocity of the river/navigable water of 

concern (in ft/sec) as determined by ChezyManning’s equation (see below and Tables 1 

and 2 of this attachment); 

t: the time interval specified in Table 3 based 

upon the type of water body and location 

(in hours); and 

c: constant conversion factor 0.68 secw mile/ 

hrw ft (3600 sec/hr ÷ 5280 ft/mile). 

2.2 Chezy-Manning’s equation is used to determine velocity: 

v=1.5/n×r2⁄3×s1⁄2; where 

v=the velocity of the river of concern (in ft/ 

sec); 

n=Manning’s Roughness Coefficient from 

Table 1 of this attachment; 

r=the hydraulic radius; the hydraulic radius 

can be approximated for parabolic channels by multiplying the average mid-channel depth of the river (in feet) by 0.667 

54 
 

Environmental Protection Agency 

(sources for obtaining the mid-channel 

depth are listed in Table 2 of this attachment); and 

s=the average slope of the river (unitless) obtained from U.S. Geological Survey topographic maps at the address listed in Table 

2 of this attachment. 

TABLE 1—MANNING’S ROUGHNESS COEFFICIENT 

FOR NATURAL STREAMS 

[NOTE: Coefficients are presented for high flow rates at or 

near flood stage.] 

Stream description 

Minor Streams (Top Width <100 ft.) 

Clean: 

Straight ............................................................. 

Winding ............................................................. 

Sluggish (Weedy, deep pools): 

No trees or brush ............................................. 

Trees and/or brush ........................................... 

Major Streams (Top Width >100 ft.) 

Regular section: 

(No boulders/brush) .......................................... 

Irregular section: 

(Brush) .............................................................. 

TABLE 2—SOURCES OF R AND S FOR THE CHEZYMANNING EQUATION 

All of the charts and related publications for 

navigational waters may be ordered from: 

Distribution Branch 

(N/CG33) 

National Ocean Service 

Riverdale, Maryland 20737–1199 

Phone: (301) 436–6990 

There will be a charge for materials ordered 

and a VISA or Mastercard will be accepted. 

The mid-channel depth to be used in the calculation of the hydraulic radius (r) can be 

obtained directly from the following sources: 

Charts of Canadian Coastal and Great Lakes 

Waters: 

Canadian Hydrographic Service 

Department of Fisheries and Oceans Institute 

P.O. Box 8080 

1675 Russell Road 

Ottawa, Ontario KIG 3H6 

Canada 

Phone: (613) 998–4931 

Charts and Maps of Lower Mississippi River 

(Gulf of Mexico to Ohio River and St. 

Francis, White, Big Sunflower, 

Atchafalaya, and other rivers): 

U.S. Army Corps of Engineers 

Vicksburg District 

P.O. Box 60 

Vicksburg, Mississippi 39180 

Phone: (601) 634–5000 

Charts of Upper Mississippi River and Illinois Waterway to Lake Michigan: 

U.S. Army Corps of Engineers 

Rock Island District 

P.O. Box 2004 

Roughness coefficient (n) 

0.03 

0.04 

0.06 

0.10 

0.035 

0.05 

Pt. 112, App. C 

Rock Island, Illinois 61204 
 


Phone: (309) 794–5552 
 


Charts of Missouri River: 
 


U.S. Army Corps of Engineers 
 

Omaha District 
 


6014 U.S. Post Office and Courthouse 
 


Omaha, Nebraska 68102 
 


Phone: (402) 221–3900 
 


Charts of Ohio River: 
 


U.S. Army Corps of Engineers 
 

Ohio River Division 
 


P.O. Box 1159 

Cincinnati, Ohio 45201 

Phone: (513) 684–3002 

Charts of Tennessee Valley Authority Reservoirs, Tennessee River and Tributaries: 

Tennessee Valley Authority 

Maps and Engineering Section 

416 Union Avenue 

Knoxville, Tennessee 37902 

Phone: (615) 632–2921 

Charts of Black Warrior River, Alabama 

River, Tombigbee River, Apalachicola 

River and Pearl River: 

U.S. Army Corps of Engineers 
 

Mobile District 
 


P.O. Box 2288 

Mobile, Alabama 36628–0001 

Phone: (205) 690–2511 

The average slope of the river (s) may be obtained from topographic maps: 

U.S. Geological Survey 

Map Distribution 

Federal Center 

Bldg. 41 

Box 25286 

Denver, Colorado 80225 

Additional information can be obtained from 

the following sources: 

1. The State’s Department of Natural Resources (DNR) or the State’s Aids to Navigation office; 

2. A knowledgeable local marina operator; or 

3.	 A knowledgeable local water authority 

(e.g., State water commission) 

2.3 The average slope of the river (s) can 

be determined from the topographic maps 

using the following steps: 

(1) Locate the facility on the map. 

(2) Find the Normal Pool Elevation at the 

point of discharge from the facility into the 

water (A). 

(3) Find the Normal Pool Elevation of the 

public drinking water intake or fish and 

wildlife and sensitive environment located 

downstream (B) (Note: The owner or operator should use a minimum of 20 miles downstream as a cutoff to obtain the average 

slope if the location of a specific public 

drinking water intake or fish and wildlife 

and sensitive environment is unknown). 

(4) If the Normal Pool Elevation is not 

available, the elevation contours can be used 

to find the slope. Determine elevation of the 

water at the point of discharge from the facility (A). Determine the elevation of the 

55 
 

Pt. 112, App. C 

water at the appropriate distance downstream (B). The formula presented below can 

be used to calculate the slope. 

(5) Determine the distance (in miles) between the facility and the public drinking 

water intake or fish and wildlife and sensitive environments (C). 

(6) Use the following formula to find the 

slope, which will be a unitless value: Average 

Slope=[(A¥B) (ft)/C (miles)] × [1 mile/5280 

feet] 

2.4 If it is not feasible to determine the 

slope and mid-channel depth by the ChezyManning equation, then the river velocity 

can be approximated on- site. A specific 

length, such as 100 feet, can be marked off 

along the shoreline. A float can be dropped 

into the stream above the mark, and the 

time required for the float to travel the distance can be used to determine the velocity 

in feet per second. However, this method will 

not yield an average velocity for the length 

of the stream, but a velocity only for the 

specific location of measurement. In addition, the flow rate will vary depending on 

weather conditions such as wind and rainfall. 

It is recommended that facility owners or 

operators repeat the measurement under a 

variety of conditions to obtain the most accurate estimate of the surface water velocity 

under adverse weather conditions. 

2.5 The planning distance calculations for 

moving and still navigable waters are based 

on worst case discharges of persistent oils. 

Persistent oils are of concern because they 

can remain in the water for significant periods of time and can potentially exist in large 

quantities downstream. Owners or operators 

of facilities that store persistent as well as 

non-persistent oils may use a comparable 

formula. The volume of oil discharged is not 

included as part of the planning distance calculation for moving navigable waters. Facilities that will meet this substantial harm criterion are those with facility capacities 

greater than or equal to 1 million gallons. It 

is assumed that these facilities are capable 

of having an oil discharge of sufficient quantity to cause injury to fish and wildlife and 

sensitive environments or shut down a public 

drinking water intake. While owners or operators of transfer facilities that store greater 

than or equal to 42,000 gallons are not required to use a planning distance formula for 

purposes of the substantial harm criteria, 

they should use a planning distance calculation in the development of facility-specific 

response plans. 

TABLE 3—SPECIFIED TIME INTERVALS 

Operating 

areas Substantial harm planning time (hrs) 

All other rivers 24 hour arrival+3 hour deployment=27 

and canals, hours. 

inland, and 

nearshore 

areas. 

40 CFR Ch. I (7–1–05 Edition) 

TABLE 3—SPECIFIED TIME INTERVALS— 

Continued 

2.6 Example of the Planning Distance Calculation for Oil Transport on Moving Navigable 

Waters. The following example provides a 

sample calculation using the planning distance formula for a facility discharging oil 

into the Monongahela River: 

(1) Solve for v by evaluating n, r, and s for 

the Chezy-Manning equation: 

Find the roughness coefficient, n, on Table 

1 of this attachment for a regular section of 

a major stream with a top width greater 

than 100 feet. The top width of the river can 

be found from the topographic map. 

n=0.035. 
 
 

Find slope, s, where A=727 feet, B=710 feet, 
 
 

and C=25 miles. 

Solving: 

s=[(727 ft¥1710 ft)/25 miles]×[1 mile/5280 

feet]=1.3×10¥4 

The average mid-channel depth is found by 

averaging the mid-channel depth for each 

mile along the length of the river between 

the facility and the public drinking water intake or the fish or wildlife or sensitive environment (or 20 miles downstream if applicable). This value is multiplied by 0.667 to obtain the hydraulic radius. The mid-channel 

depth is found by obtaining values for r and 

s from the sources shown in Table 2 for the 

Monongahela River. 

Solving: 
 
 

r=0.667×20 feet=13.33 feet 
 
 

Solve for v using: 
 
 

v=1.5/n×r2/3×s1/2: 
 
 

v=[1.5/0.035]×(13.33)2/3×(1.3×10¥4)1/2
 
 

v=2.73 feet/second 
 
 

(2) Find t from Table 3 of this attachment. 

The Monongahela River’s resource response 

time is 27 hours. 

(3) Solve for planning distance, d: 

d=v×t×c 

d=(2.73 ft/sec)×(27 hours)×(0.68 secw mile/hrw 

ft) 

d=50 miles 

Therefore, 50 miles downstream is the appropriate planning distance for this facility. 

3.0 Oil Transport on Still Water 

Operating 

areas Substantial harm planning time (hrs) 3.1 For bodies of water including lakes or 

ponds that do not have a measurable velocHigher volume 

port area. 

Great Lakes ... 

12 hour 

hours. 

24 hour 

arrival+3 

arrival+3 

hour 

hour 

deployment=15 

deployment=27 

ity, the spreading of the oil over the surface 

must be considered. Owners or operators of 

facilities located next to still water bodies 

hours. may use a comparable means of calculating 

56 

Environmental Protection Agency 

the planning distance. If a comparable formula is used, documentation of the reliability and analytical soundness of the comparable calculation must be attached to the 

response plan cover sheet. 

3.2 Example of the Planning Distance Calculation for Oil Transport on Still Water. To assist those facilities which could potentially 

discharge into a still body of water, the following analysis was performed to provide an 

example of the type of formula that may be 

used to calculate the planning distance. For 

this example, a worst case discharge of 

2,000,000 gallons is used. 

(1) The surface area in square feet covered 

by an oil discharge on still water, A1, can be 

determined by the following formula,2 where 

V is the volume of the discharge in gallons 

and C is a constant conversion factor: 

A1=105×V3⁄4×C 

C=0.1643 

A1=105×(2,000,000 gallons)3⁄4×(0.1643) 

A1=8.74×108 ft2 

(2) The spreading formula is based on the 

theoretical condition that the oil will spread 

uniformly in all directions forming a circle. 

In reality, the outfall of the discharge will 

direct the oil to the surface of the water 

where it intersects the shoreline. Although 

the oil will not spread uniformly in all directions, it is assumed that the discharge will 

spread from the shoreline into a semi-circle 

(this assumption does not account for winds 

or wave action). 

(3) The area of a circle=† r2 

(4) To account for the assumption that oil 

will spread in a semi-circular shape, the area 

of a circle is divided by 2 and is designated as 

A2. 

A2=(† r2)/2 

Solving for the radius, r, using the relationship A1=A2: 8.74×108 ft2=(†2)/2 

Therefore, r=23,586 ft 

r=23,586 ft÷5,280 ft/mile=4.5 miles 

Assuming a 20 knot wind under storm conditions: 

1 knot=1.15 miles/hour 

20 knots×1.15 miles/hour/knot=23 miles/hr 

Assuming that the oil slick moves at 3 percent of the wind’s speed:3 

23 miles/hour×0.03=0.69 miles/hour 

(5) To estimate the distance that the oil 

will travel, use the times required for response resources to arrive at different geographic locations as shown in Table 3 of this 

attachment. 

For example: 

2 Huang, J.C. and Monastero, F.C., 1982. Review of the State-of-the-Art of Oil Pollution 

Models. Final report submitted to the American Petroleum Institute by Raytheon Ocean 

Systems, Co., East Providence, Rhode Island. 3 Oil Spill Prevention & Control. National 

Spill Control School, Corpus Christi State 

University, Thirteenth Edition, May 1990. 

Pt. 112, App. C 

For Higher Volume Port Areas: 15 hrs×0.69 

miles/hr=10.4 miles 

For Great Lakes and all other areas: 27 

hrs×0.69 miles/hr=18.6 miles 

(6) The total distance that the oil will 

travel from the point of discharge, including 

the distance due to spreading, is calculated 

as follows: 

Higher Volume Port Areas: d=10.4+4.5 miles 

or approximately 15 miles 

Great Lakes and all other areas: d=18.6+4.5 

miles or approximately 23 miles 

4.0 Oil Transport on Tidal-Influence Areas 

4.1 The planning distance method for 

tidal influence navigable water is based on 

worst case discharges of persistent and nonpersistent oils. Persistent oils are of primary 

concern because they can potentially cause 

harm over a greater distance. For persistent 

oils discharged into tidal waters, the planning distance is 15 miles from the facility 

down current during ebb tide and to the 

point of maximum tidal influence or 15 

miles, whichever is less, during flood tide. 

4.2 For non-persistent oils discharged into 

tidal waters, the planning distance is 5 miles 

from the facility down current during ebb 

tide and to the point of maximum tidal influence or 5 miles, whichever is less, during 

flood tide. 

4.3 Example of Determining the Planning 

Distance for Two Types of Navigable Water 

Conditions. Below is an example of how to determine the proper planning distance when a 

facility could impact two types of navigable 

water conditions: moving water and tidal 

water. 

(1) Facility X stores persistent oil and is 

located downstream from locks along a slow 

moving river which is affected by tides. The 

river velocity, v, is determined to be 0.5 feet/ 

second from the Chezy-Manning equation 

used to calculate oil transport on moving 

navigable waters. The specified time interval, t, obtained from Table 3 of this attachment for river areas is 27 hours. Therefore, 

solving for the planning distance, d: 

d=v×t×c 
 
 

d=(0.5 ft/sec)×(27 hours)×(0.68 secmile/hrft) 
 
 

d=9.18 miles. 
 
 

(2) However, the planning distance for 

maximum tidal influence down current during ebb tide is 15 miles, which is greater than 

the calculated 9.18 miles. Therefore, 15 miles 

downstream is the appropriate planning distance for this facility. 

5.0 Oil Transport Over Land 

5.1 Facility owners or operators must 

evaluate the potential for oil to be transported over land to navigable waters of the 

United States. The owner or operator must 

evaluate the likelihood that portions of a 

worst case discharge would reach navigable 

57 
 

Pt. 112, App. C 

waters via open channel flow or from sheet 

flow across the land, or be prevented from 

reaching navigable waters when trapped in 

natural or man-made depressions excluding 

secondary containment structures. 

5.2 As discharged oil travels over land, it 

may enter a storm drain or open concrete 

channel intended for drainage. It is assumed 

that once oil reaches such an inlet, it will 

flow into the receiving navigable water. During a storm event, it is highly probable that 

the oil will either flow into the drainage 

structures or follow the natural contours of 

the land and flow into the navigable water. 

Expected minimum and maximum velocities 

are provided as examples of open concrete 

channel and pipe flow. The ranges listed 

below reflect minimum and maximum velocities used as design criteria.4 The calculation below demonstrates that the time required for oil to travel through a storm drain 

or open concrete channel to navigable water 

is negligible and can be considered instantaneous. The velocities are: 

For open concrete channels: 

maximum velocity=25 feet per second 

minimum velocity=3 feet per second 

For storm drains: 

maximum velocity=25 feet per second 

minimum velocity=2 feet per second 

5.3 Assuming a length of 0.5 mile from the 

point of discharge through an open concrete 

channel or concrete storm drain to a navigable water, the travel times (distance/velocity) are: 

1.8 minutes at a velocity of 25 feet per second 

14.7 minutes at a velocity of 3 feet per second 

22.0 minutes for at a velocity of 2 feet per 

second 

5.4 The distances that shall be considered 

to determine the planning distance are illustrated in Figure C-I of this attachment. The 

relevant distances can be described as follows: 

D1=Distance from the nearest opportunity 

for discharge, X 1, to a storm drain or an 

open concrete channel leading to navigable 

water. 

D2=Distance through the storm drain or 

open concrete channel to navigable water. 

D3=Distance downstream from the outfall 

within which fish and wildlife and sensitive 

4 The design velocities were obtained from 

Howard County, Maryland Department of 

Public Works’ Storm Drainage Design Manual. 

40 CFR Ch. I (7–1–05 Edition) 

environments could be injured or a public 

drinking water intake would be shut down 

as determined by the planning distance 

formula. 

D4=Distance from the nearest opportunity 

for discharge, X2, to fish and wildlife and 

sensitive environments not bordering navigable water. 

5.5 A facility owner or operator whose 

nearest opportunity for discharge is located 

within 0.5 mile of a navigable water must 

complete the planning distance calculation 

(D3) for the type of navigable water near the 

facility or use a comparable formula. 

5.6 A facility that is located at a distance 

greater than 0.5 mile from a navigable water 

must also calculate a planning distance (D3) 

if it is in close proximity (i.e., D1 is less than 

0.5 mile and other factors are conducive to 

oil travel over land) to storm drains that 

flow to navigable waters. Factors to be considered in assessing oil transport over land 

to storm drains shall include the topography 

of the surrounding area, drainage patterns, 

man-made barriers (excluding secondary 

containment structures), and soil distribution and porosity. Storm drains or concrete 

drainage channels that are located in close 

proximity to the facility can provide a direct 

pathway to navigable waters, regardless of 

the length of the drainage pipe. If D1 is less 

than or equal to 0.5 mile, a discharge from 

the facility could pose substantial harm because the time to travel the distance from 

the storm drain to the navigable water (D2) 

is virtually instantaneous. 

5.7 A facility’s proximity to fish and wildlife and sensitive environments not bordering a navigable water, as depicted as D4 

in Figure C–I of this attachment, must also 

be considered, regardless of the distance 

from the facility to navigable waters. Factors to be considered in assessing oil transport over land to fish and wildlife and sensitive environments should include the topography of the surrounding area, drainage 

patterns, man-made barriers (excluding secondary containment structures), and soil distribution and porosity. 

5.8 If a facility is not found to pose substantial harm to fish and wildlife and sensitive environments not bordering navigable 

waters via oil transport on land, then supporting documentation should be maintained 

at the facility. However, such documentation 

should be submitted with the response plan 

if a facility is found to pose substantial 

harm. 

58 
 
 

EC01MR92.010</GPH>

Environmental Protection Agency Pt. 112, App. C 

[59 FR 34102, July 1, 1994, as amended at 65 FR 40798, June 30, 2000; 67 FR 47152, July 17, 2002] 

59 
 
 

Pt. 112, App. D 

APPENDIX D TO PART 112—DETERMINATION OF A WORST CASE DISCHARGE 

PLANNING VOLUME 

1.0 Instructions 

1.1 An owner or operator is required to 

complete this worksheet if the facility meets 

the criteria, as presented in Appendix C to 

this part, or it is determined by the RA that 

the facility could cause substantial harm to 

the environment. The calculation of a worst 

case discharge planning volume is used for 

emergency planning purposes, and is required in 40 CFR 112.20 for facility owners or 

operators who must prepare a response plan. 

When planning for the amount of resources 

and equipment necessary to respond to the 

worst case discharge planning volume, adverse weather conditions must be taken into 

consideration. An owner or operator is required to determine the facility’s worst case 

discharge planning volume from either part 

A of this appendix for an onshore storage facility, or part B of this appendix for an onshore production facility. The worksheet 

considers the provision of adequate secondary containment at a facility. 

1.2 For onshore storage facilities and production facilities, permanently manifolded 

oil storage tanks are defined as tanks that 

are designed, installed, and/or operated in 

such a manner that the multiple tanks function as one storage unit (i.e., multiple tank 

volumes are equalized). In a worst case discharge scenario, a single failure could cause 

the discharge of the contents of more than 

one tank. The owner or operator must provide evidence in the response plan that tanks 

with common piping or piping systems are 

not operated as one unit. If such evidence is 

provided and is acceptable to the RA, the 

worst case discharge planning volume would 

be based on the capacity of the largest oil 

storage tank within a common secondary 

containment area or the largest oil storage 

tank within a single secondary containment 

area, whichever is greater. For permanently 

manifolded tanks that function as one oil 

storage unit, the worst case discharge planning volume would be based on the combined 

oil storage capacity of all manifolded tanks 

or the capacity of the largest single oil storage tank within a secondary containment 

area, whichever is greater. For purposes of 

this rule, permanently manifolded tanks 

that are separated by internal divisions for 

each tank are considered to be single tanks 

and individual manifolded tank volumes are 

not combined. 

1.3 For production facilities, the presence 

of exploratory wells, production wells, and 

oil storage tanks must be considered in the 

calculation. Part B of this appendix takes 

these additional factors into consideration 

and provides steps for their inclusion in the 

total worst case discharge planning volume. 

40 CFR Ch. I (7–1–05 Edition) 

Onshore oil production facilities may include 

all wells, flowlines, separation equipment, 

storage facilities, gathering lines, and auxiliary non-transportation-related equipment 

and facilities in a single geographical oil or 

gas field operated by a single operator. Although a potential worst case discharge 

planning volume is calculated within each 

section of the worksheet, the final worst 

case amount depends on the risk parameter 

that results in the greatest volume. 

1.4 Marine transportation-related transfer 

facilities that contain fixed aboveground onshore structures used for bulk oil storage are 

jointly regulated by EPA and the U.S. Coast 

Guard (USCG), and are termed ‘‘complexes.’’ 

Because the USCG also requires response 

plans from transportation-related facilities 

to address a worst case discharge of oil, a 

separate calculation for the worst case discharge planning volume for USCG-related facilities is included in the USCG IFR (see Appendix E to this part, section 13, for availability). All complexes that are jointly regulated by EPA and the USCG must compare 

both calculations for worst case discharge 

planning volume derived by using the EPA 

and USCG methodologies and plan for whichever volume is greater. 

PART A: WORST CASE DISCHARGE PLANNING VOLUME CALCULATION FOR ONSHORE STORAGE FACILITIES 1 

Part A of this worksheet is to be completed by the owner or operator of an SPCCregulated facility (excluding oil production 

facilities) if the facility meets the criteria as 

presented in Appendix C to this part, or if it 

is determined by the RA that the facility 

could cause substantial harm to the environment. If you are the owner or operator of a 

production facility, please proceed to part B 

of this worksheet. 

A.1 SINGLE-TANK FACILITIES 

For facilities containing only one aboveground oil storage tank, the worst case discharge planning volume equals the capacity 

of the oil storage tank. If adequate secondary containment (sufficiently large to 

contain the capacity of the aboveground oil 

storage tank plus sufficient freeboard to 

allow for precipitation) exists for the oil 

storage tank, multiply the capacity of the 

tank by 0.8. 

(1) FINAL WORST CASE VOLUME: 

llll GAL 

(2) Do not proceed further. 

1 ‘‘Storage facilities’’ represent all facilities subject to this part, excluding oil production facilities. 

60 
 

Environmental Protection Agency 

A.2 SECONDARY CONTAINMENT— 

MULTIPLE-TANK FACILITIES 

Are all aboveground oil storage tanks or 

groups of aboveground oil storage tanks at 

the facility without adequate secondary containment? 2 

llll (Y/N) 

A.2.1 If the answer is yes, the final worst 

case discharge planning volume equals the 

total aboveground oil storage capacity at the facility. 

(1) FINAL WORST CASE VOLUME: 

llll GAL 

(2) Do not proceed further. 

A.2.2 If the answer is no, calculate the 

total aboveground oil storage capacity of 

tanks without adequate secondary containment. If all aboveground oil storage tanks or 

groups of aboveground oil storage tanks at 

the facility have adequate secondary containment, ENTER ‘‘0’’ (zero). 

llll GAL 

A.2.3 Calculate the capacity of the largest 

single aboveground oil storage tank within 

an adequate secondary containment area or 

the combined capacity of a group of aboveground oil storage tanks permanently 

manifolded together, whichever is greater, 

PLUS THE VOLUME FROM QUESTION 

A.2.2. 

FINAL WORST CASE VOLUME: 3 lll 

GAL 

PART B: WORST CASE DISCHARGE PLANNING VOLUME CALCULATION FOR ONSHORE PRODUCTION FACILITIES 

Part B of this worksheet is to be completed 

by the owner or operator of an SPCC-regulated oil production facility if the facility 

meets the criteria presented in Appendix C 

to this part, or if it is determined by the RA 

that the facility could cause substantial 

harm. A production facility consists of all 

wells (producing and exploratory) and related equipment in a single geographical oil 

or gas field operated by a single operator. 

B.1 SINGLE-TANK FACILITIES 

B.1.1 For facilities containing only one 

aboveground oil storage tank, the worst case 

discharge planning volume equals the capacity of the aboveground oil storage tank plus 

the production volume of the well with the 

highest output at the facility. If adequate 

2 Secondary containment is described in 40 

CFR part 112, subparts A through C. Acceptable methods and structures for containment 

are also given in 40 CFR 112.7(c)(1). 3 All complexes that are jointly regulated 

by EPA and the USCG must also calculate 

the worst case discharge planning volume for 

the transportation-related portions of the facility and plan for whichever volume is 

greater. 

Pt. 112, App. D 

secondary containment (sufficiently large to 

contain the capacity of the aboveground oil 

storage tank plus sufficient freeboard to 

allow for precipitation) exists for the storage 

tank, multiply the capacity of the tank by 

0.8. 

B.1.2 For facilities with production wells 

producing by pumping, if the rate of the well 

with the highest output is known and the 

number of days the facility is unattended 

can be predicted, then the production volume 

is equal to the pumping rate of the well multiplied by the greatest number of days the 

facility is unattended. 

B.1.3 If the pumping rate of the well with 

the highest output is estimated or the maximum number of days the facility is unattended is estimated, then the production volume is determined from the pumping rate of 

the well multiplied by 1.5 times the greatest 

number of days that the facility has been or 

is expected to be unattended. 

B.1.4 Attachment D–1 to this appendix 

provides methods for calculating the production volume for exploratory wells and production wells producing under pressure. 

(1) FINAL WORST CASE VOLUME: 

llll GAL 

(2) Do not proceed further. 

B.2 SECONDARY CONTAINMENT— 

MULTIPLE-TANK FACILITIES 

Are all aboveground oil storage tanks or 

groups of aboveground oil storage tanks at 

the facility without adequate secondary containment? 

lll (Y/N) 

B.2.1 If the answer is yes, the final worst 

case volume equals the total aboveground oil 

storage capacity without adequate secondary 

containment plus the production volume of 

the well with the highest output at the facility. 

(1) For facilities with production wells producing by pumping, if the rate of the well 

with the highest output is known and the 

number of days the facility is unattended 

can be predicted, then the production volume 

is equal to the pumping rate of the well multiplied by the greatest number of days the 

facility is unattended. 

(2) If the pumping rate of the well with the 

highest output is estimated or the maximum 

number of days the facility is unattended is 

estimated, then the production volume is determined from the pumping rate of the well 

multiplied by 1.5 times the greatest number 

of days that the facility has been or is expected to be unattended. 

(3) Attachment D–1 to this appendix provides methods for calculating the production 

volumes for exploratory wells and production wells producing under pressure. 

(A) FINAL WORST CASE VOLUME: 

llll GAL 

(B) Do not proceed further. 

61 

Pt. 112, App. D 

B.2.2 If the answer is no, calculate the 

total aboveground oil storage capacity of 

tanks without adequate secondary containment. If all aboveground oil storage tanks or 

groups of aboveground oil storage tanks at 

the facility have adequate secondary containment, ENTER ‘‘0’’ (zero). 

llll GAL 

B.2.3 Calculate the capacity of the largest 

single aboveground oil storage tank within 

an adequate secondary containment area or 

the combined capacity of a group of aboveground oil storage tanks permanently 

manifolded together, whichever is greater, 

plus the production volume of the well with 

the highest output, PLUS THE VOLUME 

FROM QUESTION B.2.2. Attachment D–1 

provides methods for calculating the production volumes for exploratory wells and production wells producing under pressure. 

(1) FINAL WORST CASE VOLUME: 4 

llll GAL 

(2) Do not proceed further. 

ATTACHMENTS TO APPENDIX D 

ATTACHMENT D–I—METHODS TO CALCULATE 

PRODUCTION VOLUMES FOR PRODUCTION FACILITIES WITH EXPLORATORY WELLS OR PRODUCTION WELLS PRODUCING UNDER PRESSURE 

1.0 Introduction 

The owner or operator of a production facility with exploratory wells or production 

wells producing under pressure shall compare the well rate of the highest output well 

(rate of well), in barrels per day, to the ability of response equipment and personnel to 

recover the volume of oil that could be discharged (rate of recovery), in barrels per day. 

The result of this comparison will determine 

the method used to calculate the production 

volume for the production facility. This production volume is to be used to calculate the 

worst case discharge planning volume in part 

B of this appendix. 

2.0 Description of Methods 

2.1 Method A 

If the well rate would overwhelm the response efforts (i.e., rate of well/rate of recovery ≥1), then the production volume would be 

the 30-day forecasted well rate for a well 

10,000 feet deep or less, or the 45-day forecasted well rate for a well deeper than 10,000 

feet. 

(1) For wells 10,000 feet deep or less: 

Production volume=30 days × rate of well. 

4 All complexes that are jointly regulated 

by EPA and the USCG must also calculate 

the worst case discharge planning volume for 

the transportation-related portions of the facility and plan for whichever volume is 

greater. 

40 CFR Ch. I (7–1–05 Edition) 

(2) For wells deeper than 10,000 feet: 

Production volume=45 days × rate of well. 

2.2 Method B 

2.2.1 If the rate of recovery would be 

greater than the well rate (i.e., rate of well/ 

rate of recovery <1), then the production volume would equal the sum of two terms: 

Production volume=discharge volume1 + discharge volume2 

2.2.2 The first term represents the volume 

of the oil discharged from the well between 

the time of the blowout and the time the response resources are on scene and recovering 

oil (discharge volume1). 

Discharge volume1=(days unattended+days 

to respond) × (rate of well) 

2.2.3 The second term represents the volume of oil discharged from the well after the 

response resources begin operating until the 

discharge is stopped, adjusted for the recovery rate of the response resources (discharge 

volume 2). 

(1) For wells 10,000 feet deep or less: 
 

Discharge 	
volume2=[30 days¥(days unattended + days to respond)] × (rate of well) 

× (rate of well/rate of recovery) 

(2) For wells deeper than 10,000 feet: 
 

Discharge 	
volume2=[45 days¥(days unattended + days to respond)] × (rate of well) 

× (rate of well/rate of recovery) 

3.0 Example 

3.1 A facility consists of two production 

wells producing under pressure, which are 

both less than 10,000 feet deep. The well rate 

of well A is 5 barrels per day, and the well 

rate of well B is 10 barrels per day. The facility is unattended for a maximum of 7 days. 

The facility operator estimates that it will 

take 2 days to have response equipment and 

personnel on scene and responding to a blowout, and that the projected rate of recovery 

will be 20 barrels per day. 

(1) First, the facility operator determines 

that the highest output well is well B. The 

facility operator calculates the ratio of the 

rate of well to the rate of recovery: 

10 barrels per day/20 barrels per day=0.5 Because the ratio is less than one, the facility operator will use Method B to calculate 

the production volume. 

(2) The first term of the equation is: 

Discharge volume1=(7 days + 2 days) × (10 

barrels per day)=90 barrels 

(3) The second term of the equation is: 

Discharge volume 2=[30 days—(7 days + 2 

days)] × (10 barrels per day) × (0.5)=105 barrels 

(4) Therefore, the production volume is: 

Production volume=90 barrels + 105 

barrels=195 barrels 

62 
 

Environmental Protection Agency 

3.2 If the recovery rate was 5 barrels per 

day, the ratio of rate of well to rate of recovery would be 2, so the facility operator would 

use Method A. The production volume would 

have been: 

30 days × 10 barrels per day=300 barrels 

[59 FR 34110, July 1, 1994; 59 FR 49006, Sept. 

26, 1994, as amended at 65 FR 40800, June 30, 

2000; 67 FR 47152, July 17, 2002] 

APPENDIX E TO PART 112—DETERMINATION AND EVALUATION OF REQUIRED 

RESPONSE RESOURCES FOR FACILITY 

RESPONSE PLANS 

1.0 Purpose and Definitions 

1.1 The purpose of this appendix is to describe the procedures to identify response resources to meet the requirements of § 112.20. 

To identify response resources to meet the 

facility response plan requirements of 40 

CFR 112.20(h), owners or operators shall follow this appendix or, where not appropriate, 

shall clearly demonstrate in the response 

plan why use of this appendix is not appropriate at the facility and make comparable 

arrangements for response resources. 

1.2 Definitions. 

1.2.1 Animal fat means a non-petroleum 

oil, fat, or grease of animal, fish, or marine 

mammal origin. Animal fats are further 

classified based on specific gravity as follows: 

(1) Group A—specific gravity less than 0.8. 

(2) Group B—specific gravity equal to or 

greater than 0.8 and less than 1.0. 

(3) Group C—specific gravity equal to or 

greater than 1.0. 

1.2.2 Nearshore is an operating area defined as extending seaward 12 miles from the 

boundary lines defined in 46 CFR part 7, except in the Gulf of Mexico. In the Gulf of 

Mexico, it means the area extending 12 miles 

from the line of demarcation (COLREG lines) 

defined in 49 CFR 80.740 and 80.850. 

1.2.3 Non-persistent oils or Group 1 oils include: 

(1) A petroleum-based oil that, at the time 

of shipment, consists of hydrocarbon fractions: 

(A) At least 50 percent of which by volume, 

distill at a temperature of 340 degrees C (645 

degrees F); and 

(B) At least 95 percent of which by volume, 

distill at a temperature of 370 degrees C (700 

degrees F); and 

(2) A non-petroleum oil, other than an animal fat or vegetable oil, with a specific gravity less than 0.8. 

1.2.4 Non-petroleum oil means oil of any 

kind that is not petroleum-based, including 

but not limited to: fats, oils, and greases of 

animal, fish, or marine mammal origin; and 

vegetable oils, including oils from seeds, 

nuts, fruits, and kernels. 

Pt. 112, App. E 

1.2.5 Ocean means the nearshore area. 

1.2.6 Operating area means Rivers and Canals, Inland, Nearshore, and Great Lakes geographic location(s) in which a facility is 

handling, storing, or transporting oil. 

1.2.7 Operating environment means Rivers 

and Canals, Inland, Great Lakes, or Ocean. 

These terms are used to define the conditions in which response equipment is designed to function. 

1.2.8 Persistent oils include: 

(1) A petroleum-based oil that does not 

meet the distillation criteria for a non-persistent oil. Persistent oils are further classified based on specific gravity as follows: 

(A) Group 2—specific gravity less than 0.85; 

(B) Group 3—specific gravity equal to or 

greater than 0.85 and less than 0.95; 

(C) Group 4—specific gravity equal to or 

greater than 0.95 and less than 1.0; or 

(D) Group 5—specific gravity equal to or 

greater than 1.0. 

(2) A non-petroleum oil, other than an animal fat or vegetable oil, with a specific gravity of 0.8 or greater. These oils are further 

classified based on specific gravity as follows: 

(A) Group 2—specific gravity equal to or 

greater than 0.8 and less than 0.85; 

(B) Group 3—specific gravity equal to or 

greater than 0.85 and less than 0.95; 

(C) Group 4—specific gravity equal to or 

greater than 0.95 and less than 1.0; or 

(D) Group 5—specific gravity equal to or 

greater than 1.0. 

1.2.9 Vegetable oil means a non-petroleum 

oil or fat of vegetable origin, including but 

not limited to oils and fats derived from 

plant seeds, nuts, fruits, and kernels. Vegetable oils are further classified based on specific gravity as follows: 

(1) Group A—specific gravity less than 0.8. 

(2) Group B—specific gravity equal to or 

greater than 0.8 and less than 1.0. 

(3) Group C—specific gravity equal to or 

greater than 1.0. 

1.2.10 Other definitions are included in 

§ 112.2, section 1.1 of Appendix C, and section 

3.0 of Appendix F. 

2.0 Equipment Operability and Readiness 

2.1 All equipment identified in a response 

plan must be designed to operate in the conditions expected in the facility’s geographic 

area (i.e., operating environment). These 

conditions vary widely based on location and 

season. Therefore, it is difficult to identify a 

single stockpile of response equipment that 

will function effectively in each geographic 

location (i.e., operating area). 

2.2 Facilities handling, storing, or transporting oil in more than one operating environment as indicated in Table 1 of this appendix must identify equipment capable of 

successfully functioning in each operating 

environment. 

63 
 

Pt. 112, App. E 

2.3 When identifying equipment for the 

response plan (based on the use of this appendix), a facility owner or operator must 

consider the inherent limitations of the 

operability of equipment components and response systems. The criteria in Table 1 of 

this appendix shall be used to evaluate the 

operability in a given environment. These 

criteria reflect the general conditions in certain operating environments. 

2.3.1 The Regional Administrator may require documentation that the boom identified in a facility response plan meets the criteria in Table 1 of this appendix. Absent acceptable documentation, the Regional Administrator may require that the boom be 

tested to demonstrate that it meets the criteria in Table 1 of this appendix. Testing 

must be in accordance with ASTM F 715, 

ASTM F 989, or other tests approved by EPA 

as deemed appropriate (see Appendix E to 

this part, section 13, for general availability 

of documents). 

2.4 Table 1 of this appendix lists criteria 

for oil recovery devices and boom. All other 

equipment necessary to sustain or support 

response operations in an operating environment must be designed to function in the 

same conditions. For example, boats that deploy or support skimmers or boom must be 

capable of being safely operated in the significant wave heights listed for the applicable operating environment. 

2.5 A facility owner or operator shall refer 

to the applicable Area Contingency Plan 

(ACP), where available, to determine if ice, 

debris, and weather-related visibility are significant factors to evaluate the operability 

of equipment. The ACP may also identify the 

average temperature ranges expected in the 

facility’s operating area. All equipment identified in a response plan must be designed to 

operate within those conditions or ranges. 

2.6 This appendix provides information on 

response resource mobilization and response 

times. The distance of the facility from the 

storage location of the response resources 

must be used to determine whether the resources can arrive on-scene within the stated 

time. A facility owner or operator shall include the time for notification, mobilization, 

and travel of resources identified to meet the 

medium and Tier 1 worst case discharge requirements identified in sections 4.3 and 9.3 

of this appendix (for medium discharges) and 

section 5.3 of this appendix (for worst case 

discharges). The facility owner or operator 

must plan for notification and mobilization 

of Tier 2 and 3 response resources as necessary to meet the requirements for arrival 

on-scene in accordance with section 5.3 of 

this appendix. An on-water speed of 5 knots 

and a land speed of 35 miles per hour is assumed, unless the facility owner or operator 

can demonstrate otherwise. 

2.7 In identifying equipment, the facility 

owner or operator shall list the storage loca40 CFR Ch. I (7–1–05 Edition) 

tion, quantity, and manufacturer’s make and 

model. For oil recovery devices, the effective 

daily recovery capacity, as determined using 

section 6 of this appendix, must be included. 

For boom, the overall boom height (draft and 

freeboard) shall be included. A facility owner 

or operator is responsible for ensuring that 

the identified boom has compatible connectors. 

3.0	 Determining Response Resources Required 

for Small Discharges—Petroleum Oils and 

Non-Petroleum Oils Other Than Animal Fats 

and Vegetable Oils 

3.1 A facility owner or operator shall 

identify sufficient response resources available, by contract or other approved means as 

described in § 112.2, to respond to a small discharge. A small discharge is defined as any 

discharge volume less than or equal to 2,100 

gallons, but not to exceed the calculated 

worst case discharge. The equipment must be 

designed to function in the operating environment at the point of expected use. 

3.2 Complexes that are regulated by EPA 

and the United States Coast Guard (USCG) 

must also consider planning quantities for 

the transportation-related transfer portion 

of the facility. 

3.2.1 Petroleum oils. The USCG planning 

level that corresponds to EPA’s ‘‘small discharge’’ is termed ‘‘the average most probable discharge.’’ A USCG rule found at 33 

CFR 154.1020 defines ‘‘the average most probable discharge’’ as the lesser of 50 barrels 

(2,100 gallons) or 1 percent of the volume of 

the worst case discharge. Owners or operators of complexes that handle, store, or 

transport petroleum oils must compare oil 

discharge volumes for a small discharge and 

an average most probable discharge, and 

plan for whichever quantity is greater. 

3.2.2 Non-petroleum oils other than animal 

fats and vegetable oils. Owners or operators of 

complexes that handle, store, or transport 

non-petroleum oils other than animal fats 

and vegetable oils must plan for oil discharge volumes for a small discharge. There 

is no USCG planning level that directly corresponds to EPA’s ‘‘small discharge.’’ However, the USCG (at 33 CFR 154.545) has requirements to identify equipment to contain 

oil resulting from an operational discharge. 

3.3 The response resources shall, as appropriate, include: 

3.3.1 One thousand feet of containment 

boom (or, for complexes with marine transfer 

components, 1,000 feet of containment boom 

or two times the length of the largest vessel 

that regularly conducts oil transfers to or 

from the facility, whichever is greater), and 

a means of deploying it within 1 hour of the 

discovery of a discharge; 

3.3.2 Oil recovery devices with an effective daily recovery capacityequal to the 

amount of oil discharged in a small discharge or greater which is available at the 

64 
 

Environmental Protection Agency 

facility within 2 hours of the detection of an 

oil discharge; and 

3.3.3 Oil storage capacity for recovered 

oily material indicated in section 12.2 of this 

appendix. 

4.0	 Determining Response Resources Required 

for Medium Discharges—Petroleum Oils and 

Non-Petroleum Oils Other Than Animal Fats 

and Vegetable Oils 

4.1 A facility owner or operator shall 

identify sufficient response resources available, by contract or other approved means as 

described in § 112.2, to respond to a medium 

discharge of oil for that facility. This will require response resources capable of containing and collecting up to 36,000 gallons of 

oil or 10 percent of the worst case discharge, 

whichever is less. All equipment identified 

must be designed to operate in the applicable 

operating environment specified in Table 1 of 

this appendix. 

4.2 Complexes that are regulated by EPA 

and the USCG must also consider planning 

quantities for the transportation-related 

transfer portion of the facility. 

4.2.1 Petroleum oils. The USCG planning 

level that corresponds to EPA’s ‘‘medium 

discharge’’ is termed ‘‘the maximum most 

probable discharge.’’ The USCG rule found at 

33 CFR part 154 defines ‘‘the maximum most 

probable discharge’’ as a discharge of 1,200 

barrels (50,400 gallons) or 10 percent of the 

worst case discharge, whichever is less. Owners or operators of complexes that handle, 

store, or transport petroleum oils must compare calculated discharge volumes for a medium discharge and a maximum most probable discharge, and plan for whichever quantity is greater. 

4.2.2 Non-petroleum oils other than animal 

fats and vegetable oils. Owners or operators of 

complexes that handle, store, or transport 

non-petroleum oils other than animal fats 

and vegetable oils must plan for oil discharge volumes for a medium discharge. For 

non-petroleum oils, there is no USCG planning level that directly corresponds to EPA’s 

‘‘medium discharge.’’ 

4.3 Oil recovery devices identified to meet 

the applicable medium discharge volume 

planning criteria must be located such that 

they are capable of arriving on-scene within 

6 hours in higher volume port areas and the 

Great Lakes and within 12 hours in all other 

areas. Higher volume port areas and Great 

Lakes areas are defined in section 1.1 of Appendix C to this part. 

4.4 Because rapid control, containment, 

and removal of oil are critical to reduce discharge impact, the owner or operator must 

determine response resources using an effective daily recovery capacity for oil recovery 

devices equal to 50 percent of the planning 

volume applicable for the facility as determined in section 4.1 of this appendix. The effective daily recovery capacity for oil recovPt. 112, App. E 

ery devices identified in the plan must be determined using the criteria in section 6 of 

this appendix. 

4.5 In addition to oil recovery capacity, 

the plan shall, as appropriate, identify sufficient quantity of containment boom available, by contract or other approved means as 

described in § 112.2, to arrive within the required response times for oil collection and 

containment and for protection of fish and 

wildlife and sensitive environments. For further description of fish and wildlife and sensitive environments, see Appendices I, II, and 

III to DOC/NOAA’s ‘‘Guidance for Facility 

and Vessel Response Plans: Fish and Wildlife 

and Sensitive Environments’’ (see Appendix 

E to this part, section 13, for availability) 

and the applicable ACP. Although 40 CFR 

part 112 does not set required quantities of 

boom for oil collection and containment, the 

response plan shall identify and ensure, by 

contract or other approved means as described in § 112.2, the availability of the 

quantity of boom identified in the plan for 

this purpose. 

4.6 The plan must indicate the availability of temporary storage capacity to 

meet section 12.2 of this appendix. If available storage capacity is insufficient to meet 

this level, then the effective daily recovery 

capacity must be derated (downgraded) to 

the limits of the available storage capacity. 

4.7 The following is an example of a medium discharge volume planning calculation 

for equipment identification in a higher volume port area: The facility’s largest aboveground storage tank volume is 840,000 gallons. Ten percent of this capacity is 84,000 

gallons. Because 10 percent of the facility’s 

largest tank, or 84,000 gallons, is greater 

than 36,000 gallons, 36,000 gallons is used as 

the planning volume. The effective daily recovery capacity is 50 percent of the planning 

volume, or 18,000 gallons per day. The ability 

of oil recovery devices to meet this capacity 

must be calculated using the procedures in 

section 6 of this appendix. Temporary storage capacity available on-scene must equal 

twice the daily recovery capacity as indicated in section 12.2 of this appendix, or 

36,000 gallons per day. This is the information the facility owner or operator must use 

to identify and ensure the availability of the 

required response resources, by contract or 

other approved means as described in § 112.2. 

The facility owner shall also identify how 

much boom is available for use. 

5.0	 Determining Response Resources Required 

for the Worst Case Discharge to the Maximum 

Extent Practicable 

5.1 A facility owner or operator shall 

identify and ensure the availability of, by 

65 
 
 

Pt. 112, App. E 

contract or other approved means as described in § 112.2, sufficient response resources to respond to the worst case discharge of oil to the maximum extent practicable. Sections 7 and 10 of this appendix describe the method to determine the necessary response resources. Worksheets are 

provided as Attachments E–1 and E–2 at the 

end of this appendix to simplify the procedures involved in calculating the planning 

volume for response resources for the worst 

case discharge. 

5.1 A facility owner or operator shall 

identify and ensure the availability of, by 

contract or other approved means as described in § 112.2, sufficient response resources to respond to the worst case discharge of oil to the maximum extent practicable. Sections 7 and 10 of this appendix describe the method to determine the necessary response resources. Worksheets are 

provided as Attachments E–1 and E–2 at the 

end of this appendix to simplify the procedures involved in calculating the planning 

40 CFR Ch. I (7–1–05 Edition) 

volume for response resources for the worst 

case discharge. 

5.2 Complexes that are regulated by EPA 

and the USCG must also consider planning 

for the worst case discharge at the transportation-related portion of the facility. The 

USCG requires that transportation-related 

facility owners or operators use a different 

calculation for the worst case discharge in 

the revisions to 33 CFR part 154. Owners or 

operators of complex facilities that are regulated by EPA and the USCG must compare 

both calculations of worst case discharge derived by EPA and the USCG and plan for 

whichever volume is greater. 

5.3 Oil discharge response resources identified in the response plan and available, by 

contract or other approved means as described in § 112.2, to meet the applicable 

worst case discharge planning volume must 

be located such that they are capable of arriving at the scene of a discharge within the 

times specified for the applicable response 

tier listed as follows 

Tier 1 Tier 2 Tier 3 

(in hours) (in hours) (in hours) 

Higher volume port areas .............................................................................................. 6 30 54 

Great Lakes ................................................................................................................... 12 36 60 

All other river and canal, inland, and nearshore areas ................................................ 12 36 60 

The three levels of response tiers apply to 

the amount of time in which facility owners 

or operators must plan for response resources to arrive at the scene of a discharge 

to respond to the worst case discharge planning volume. For example, at a worst case 

discharge in an inland area, the first tier of 

response resources (i.e., that amount of onwater and shoreline cleanup capacity necessary to respond to the fraction of the worst 

case discharge as indicated through the series of steps described in sections 7.2 and 7.3 

or sections 10.2 and 10.3 of this appendix) 

would arrive at the scene of the discharge 

within 12 hours; the second tier of response 

resources would arrive within 36 hours; and 

the third tier of response resources would arrive within 60 hours. 

5.4 The effective daily recovery capacity 

for oil recovery devices identified in the response plan must be determined using the 

criteria in section 6 of this appendix. A facility owner or operator shall identify the storage locations of all response resources used 

for each tier. The owner or operator of a facility whose required daily recovery capacity 

exceeds the applicable contracting caps in 

Table 5 of this appendix shall, as appropriate, identify sources of additional equipment, their location, and the arrangements 

made to obtain this equipment during a response. The owner or operator of a facility 

whose calculated planning volume exceeds 

the applicable contracting caps in Table 5 of 

this appendix shall, as appropriate, identify 

sources of additional equipment equal to 

twice the cap listed in Tier 3 or the amount 

necessary to reach the calculated planning 

volume, whichever is lower. The resources 

identified above the cap shall be capable of 

arriving on-scene not later than the Tier 3 

response times in section 5.3 of this appendix. No contract is required. While general 

listings of available response equipment may 

be used to identify additional sources (i.e., 

‘‘public’’ resources vs. ‘‘private’’ resources), 

the response plan shall identify the specific 

sources, locations, and quantities of equipment that a facility owner or operator has 

considered in his or her planning. When listing USCG-classified oil spill removal organization(s) that have sufficient removal capacity to recover the volume above the response 

capacity cap for the specific facility, as specified in Table 5 of this appendix, it is not 

necessary to list specific quantities of equipment. 

5.5 A facility owner or operator shall 

identify the availability of temporary storage capacity to meet section 12.2 of this appendix. If available storage capacity is insufficient, then the effective daily recovery capacity must be derated (downgraded) to the 

limits of the available storage capacity. 

5.6 When selecting response resources necessary to meet the response plan requirements, the facility owner or operator shall, 

as appropriate, ensure that a portion of 

66 
 

Environmental Protection Agency 

those resources is capable of being used in 

close-to-shore response activities in shallow 

water. For any EPA-regulated facility that 

is required to plan for response in shallow 

water, at least 20 percent of the on-water response equipment identified for the applicable operating area shall, as appropriate, be 

capable of operating in water of 6 feet or less 

depth. 

5.7 In addition to oil spill recovery devices, a facility owner or operator shall identify sufficient quantities of boom that are 

available, by contract or other approved 

means as described in § 112.2, to arrive onscene within the specified response times for 

oil containment and collection. The specific 

quantity of boom required for collection and 

containment will depend on the facility-specific information and response strategies employed. A facility owner or operator shall, as 

appropriate, also identify sufficient quantities of oil containment boom to protect 

fish and wildlife and sensitive environments. 

For further description of fish and wildlife 

and sensitive environments, see Appendices 

I, II, and III to DOC/NOAA’s ‘‘Guidance for 

Facility and Vessel Response Plans: Fish and 

Wildlife and Sensitive Environments’’ (see 

Appendix E to this part, section 13, for availability), and the applicable ACP. Refer to 

this guidance document for the number of 

days and geographic areas (i.e., operating environments) specified in Table 2 and Table 6 

of this appendix. 

5.8 A facility owner or operator shall also 

identify, by contract or other approved 

means as described in § 112.2, the availability 

of an oil spill removal organization(s) (as described in § 112.2) capable of responding to a 

shoreline cleanup operation involving the 

calculated volume of oil and emulsified oil 

that might impact the affected shoreline. 

The volume of oil that shall, as appropriate, 

be planned for is calculated through the application of factors contained in Tables 2, 3, 

6, and 7 of this appendix. The volume calculated from these tables is intended to assist the facility owner or operator to identify 

an oil spill removal organization with sufficient resources and expertise. 

6.0 Determining Effective Daily Recovery 

Capacity for Oil Recovery Devices 

6.1 Oil recovery devices identified by a facility owner or operator must be identified 

by the manufacturer, model, and effective 

daily recovery capacity. These capacities 

must be used to determine whether there is 

sufficient capacity to meet the applicable 

planning criteria for a small discharge, a medium discharge, and a worst case discharge 

to the maximum extent practicable. 

6.2 To determine the effective daily recovery capacity of oil recovery devices, the formula listed in section 6.2.1 of this appendix 

shall be used. This formula considers potential limitations due to available daylight, 

Pt. 112, App. E 

weather, sea state, and percentage of 

emulsified oil in the recovered material. The 

RA may assign a lower efficiency factor to 

equipment listed in a response plan if it is 

determined that such a reduction is warranted. 

6.2.1 The following formula shall be used 

to calculate the effective daily recovery capacity: 

R = T × 24 hours × E 

where: 

R—Effective daily recovery capacity; 

T—Throughput rate in barrels per hour 

(nameplate capacity); and 

E—20 percent efficiency factor (or lower factor as determined by the Regional Administrator). 

6.2.2 For those devices in which the pump 

limits the throughput of liquid, throughput 

rate shall be calculated using the pump capacity. 

6.2.3 For belt or moptype devices, the 

throughput rate shall be calculated using the 

speed of the belt or mop through the device, 

assumed thickness of oil adhering to or collected by the device, and surface area of the 

belt or mop. For purposes of this calculation, 

the assumed thickness of oil will be 1⁄4 inch. 

6.2.4 Facility owners or operators that include oil recovery devices whose throughput 

is not measurable using a pump capacity or 

belt/mop speed may provide information to 

support an alternative method of calculation. This information must be submitted 

following the procedures in section 6.3.2 of 

this appendix. 

6.3 As an alternative to section 6.2 of this 

appendix, a facility owner or operator may 

submit adequate evidence that a different effective daily recovery capacity should be applied for a specific oil recovery device. Adequate evidence is actual verified performance data in discharge conditions or tests 

using American Society of Testing and Materials (ASTM) Standard F 631–99, F 808–83 

(1999), or an equivalent test approved by EPA 

as deemed appropriate (see Appendix E to 

this part, section 13, for general availability 

of documents). 

6.3.1 The following formula must be used 

to calculate the effective daily recovery capacity under this alternative: 

R = D × U 
 
 

where: 
 
 

R—Effective daily recovery capacity; 
 
 

D—Average Oil Recovery Rate in barrels per 
 
 

hour (Item 26 in F 808–83; Item 13.2.16 in F 

631–99; or actual performance data); and 

U—Hours per day that equipment can operate under discharge conditions. Ten hours 

per day must be used unless a facility 

owner or operator can demonstrate that 

the recovery operation can be sustained for 

longer periods. 

67 
 

Pt. 112, App. E 

6.3.2 A facility owner or operator submitting a response plan shall provide data that 

supports the effective daily recovery capacities for the oil recovery devices listed. The 

following is an example of these calculations: 

(1) A weir skimmer identified in a response 

plan has a manufacturer’s rated throughput 

at the pump of 267 gallons per minute (gpm). 

267 gpm=381 barrels per hour (bph) 

R=381 bph×24 hr/day×0.2=1,829 barrels per day 

(2) After testing using ASTM procedures, 

the skimmer’s oil recovery rate is determined to be 220 gpm. The facility owner or 

operator identifies sufficient resources available to support operations for 12 hours per 

day. 

220 gpm=314 bph 

R=314 bph×12 hr/day=3,768 barrels per day 

(3) The facility owner or operator will be 

able to use the higher capacity if sufficient 

temporary oil storage capacity is available. 

Determination of alternative efficiency factors under section 6.2 of this appendix or the 

acceptability of an alternative effective 

daily recovery capacity under section 6.3 of 

this appendix will be made by the Regional 

Administrator as deemed appropriate. 

7.0	 Calculating Planning Volumes for a Worst 

Case Discharge—Petroleum Oils and Non-Petroleum Oils Other Than Animal Fats and 

Vegetable Oils 

7.1 A facility owner or operator shall plan 

for a response to the facility’s worst case discharge. The planning for on-water oil recovery must take into account a loss of some oil 

to the environment due to evaporative and 

natural dissipation, potential increases in 

volume due to emulsification, and the potential for deposition of oil on the shoreline. 

The procedures for non-petroleum oils other 

than animal fats and vegetable oils are discussed in section 7.7 of this appendix. 

7.2 The following procedures must be used 

by a facility owner or operator in determining the required on-water oil recovery 

capacity: 

7.2.1 The following must be determined: 

the worst case discharge volume of oil in the 

facility; the appropriate group(s) for the 

types of oil handled, stored, or transported 

at the facility [persistent (Groups 2, 3, 4, 5) 

or non-persistent (Group 1)]; and the facility’s specific operating area. See sections 1.2.3 

and 1.2.8 of this appendix for the definitions 

of non-persistent and persistent oils, respectively. Facilities that handle, store, or transport oil from different oil groups must calculate each group separately, unless the oil 

group constitutes 10 percent or less by volume of the facility’s total oil storage capacity. This information is to be used with 

Table 2 of this appendix to determine the 

percentages of the total volume to be used 

40 CFR Ch. I (7–1–05 Edition) 

for removal capacity planning. Table 2 of 

this appendix divides the volume into three 

categories: oil lost to the environment; oil 

deposited on the shoreline; and oil available 

for on-water recovery. 

7.2.2 The on-water oil recovery volume 

shall, as appropriate, be adjusted using the 

appropriate emulsification factor found in 

Table 3 of this appendix. Facilities that handle, store, or transport oil from different petroleum groups must compare the on-water 

recovery volume for each oil group (unless 

the oil group constitutes 10 percent or less 

by volume of the facility’s total storage capacity) and use the calculation that results 

in the largest on-water oil recovery volume 

to plan for the amount of response resources 

for a worst case discharge. 

7.2.3 The adjusted volume is multiplied by 

the on-water oil recovery resource mobilization factor found in Table 4 of this appendix 

from the appropriate operating area and response tier to determine the total on-water 

oil recovery capacity in barrels per day that 

must be identified or contracted to arrive 

on-scene within the applicable time for each 

response tier. Three tiers are specified. For 

higher volume port areas, the contracted 

tiers of resources must be located such that 

they are capable of arriving on-scene within 

6 hours for Tier 1, 30 hours for Tier 2, and 54 

hours for Tier 3 of the discovery of an oil discharge. For all other rivers and canals, inland, nearshore areas, and the Great Lakes, 

these tiers are 12, 36, and 60 hours. 

7.2.4 The resulting on-water oil recovery 

capacity in barrels per day for each tier is 

used to identify response resources necessary 

to sustain operations in the applicable operating area. The equipment shall be capable 

of sustaining operations for the time period 

specified in Table 2 of this appendix. The facility owner or operator shall identify and 

ensure the availability, by contract or other 

approved means as described in § 112.2, of sufficient oil spill recovery devices to provide 

the effective daily oil recovery capacity required. If the required capacity exceeds the 

applicable cap specified in Table 5 of this appendix, then a facility owner or operator 

shall ensure, by contract or other approved 

means as described in § 112.2, only for the 

quantity of resources required to meet the 

cap, but shall identify sources of additional 

resources as indicated in section 5.4 of this 

appendix. The owner or operator of a facility 

whose planning volume exceeded the cap in 

1993 must make arrangements to identify 

and ensure the availability, by contract or 

other approved means as described in § 112.2, 

for additional capacity to be under contract 

by 1998 or 2003, as appropriate. For a facility 

that handles multiple groups of oil, the required effective daily recovery capacity for 

each oil group is calculated before applying 

the cap. The oil group calculation resulting 

in the largest on-water recovery volume 

68 
 

Environmental Protection Agency 

must be used to plan for the amount of response resources for a worst case discharge, 

unless the oil group comprises 10 percent or 

less by volume of the facility’s total oil storage capacity. 

7.3 The procedures discussed in sections 

7.3.1–7.3.3 of this appendix must be used to 

calculate the planning volume for identifying shoreline cleanup capacity (for Group 1 

through Group 4 oils). 

7.3.1 The following must be determined: 

the worst case discharge volume of oil for 

the facility; the appropriate group(s) for the 

types of oil handled, stored, or transported 

at the facility [persistent (Groups 2, 3, or 4) 

or non-persistent (Group 1)]; and the geographic area(s) in which the facility operates 

(i.e., operating areas). For a facility handling, storing, or transporting oil from different groups, each group must be calculated 

separately. Using this information, Table 2 

of this appendix must be used to determine 

the percentages of the total volume to be 

used for shoreline cleanup resource planning. 

7.3.2 The shoreline cleanup planning volume must be adjusted to reflect an emulsification factor using the same procedure as 

described in section 7.2.2 of this appendix. 

7.3.3 The resulting volume shall be used 

to identify an oil spill removal organization 

with the appropriate shoreline cleanup capability. 

7.4 A response plan must identify response resources with fire fighting capability. The owner or operator of a facility 

that handles, stores, or transports Group 1 

through Group 4 oils that does not have adequate fire fighting resources located at the 

facility or that cannot rely on sufficient 

local fire fighting resources must identify 

adequate fire fighting resources. The facility 

owner or operator shall ensure, by contract 

or other approved means as described in 

§ 112.2, the availability of these resources. 

The response plan must also identify an individual located at the facility to work with 

the fire department for Group 1 through 

Group 4 oil fires. This individual shall also 

verify that sufficient well-trained fire fighting resources are available within a reasonable response time to a worst case scenario. 

The individual may be the qualified individual identified in the response plan or another appropriate individual located at the 

facility. 

7.5 The following is an example of the procedure described above in sections 7.2 and 7.3 

of this appendix: A facility with a 270,000 barrel (11.3 million gallons) capacity for #6 oil 

(specific gravity 0.96) is located in a higher 

volume port area. The facility is on a peninsula and has docks on both the ocean and 

bay sides. The facility has four aboveground 

oil storage tanks with a combined total capacity of 80,000 barrels (3.36 million gallons) 

and no secondary containment. The remaining facility tanks are inside secondary conPt. 112, App. E 

tainment structures. The largest aboveground oil storage tank (90,000 barrels or 3.78 

million gallons) has its own secondary containment. Two 50,000 barrel (2.1 million gallon) tanks (that are not connected by a 

manifold) are within a common secondary 

containment tank area, which is capable of 

holding 100,000 barrels (4.2 million gallons) 

plus sufficient freeboard. 

7.5.1 The worst case discharge for the facility is calculated by adding the capacity of 

all aboveground oil storage tanks without 

secondary containment (80,000 barrels) plus 

the capacity of the largest aboveground oil 

storage tank inside secondary containment. 

The resulting worst case discharge volume is 

170,000 barrels or 7.14 million gallons. 

7.5.2 Because the requirements for Tiers 1, 

2, and 3 for inland and nearshore exceed the 

caps identified in Table 5 of this appendix, 

the facility owner will contract for a response to 10,000 barrels per day (bpd) for Tier 

1, 20,000 bpd for Tier 2, and 40,000 bpd for Tier 

3. Resources for the remaining 7,850 bpd for 

Tier 1, 9,750 bpd for Tier 2, and 7,600 bpd for 

Tier 3 shall be identified but need not be contracted for in advance. The facility owner or 

operator shall, as appropriate, also identify 

or contract for quantities of boom identified 

in their response plan for the protection of 

fish and wildlife and sensitive environments 

within the area potentially impacted by a 

worst case discharge from the facility. For 

further description of fish and wildlife and 

sensitive environments, see Appendices I, II, 

and III to DOC/NOAA’s ‘‘Guidance for Facility and Vessel Response Plans: Fish and 

Wildlife and Sensitive Environments,’’ (see 

Appendix E to this part, section 13, for availability) and the applicable ACP. Attachment 

C–III to Appendix C provides a method for 

calculating a planning distance to fish and 

wildlife and sensitive environments and public drinking water intakes that may be impacted in the event of a worst case discharge. 

7.6 The procedures discussed in sections 

7.6.1–7.6.3 of this appendix must be used to 

determine appropriate response resources for 

facilities with Group 5 oils. 

7.6.1 The owner or operator of a facility 

that handles, stores, or transports Group 5 

oils shall, as appropriate, identify the response resources available by contract or 

other approved means, as described in § 112.2. 

The equipment identified in a response plan 

shall, as appropriate, include: 

(1) Sonar, sampling equipment, or other 

methods for locating the oil on the bottom 

or suspended in the water column; 

(2) Containment boom, sorbent boom, silt 

curtains, or other methods for containing 

the oil that may remain floating on the surface or to reduce spreading on the bottom; 

(3) Dredges, pumps, or other equipment 

necessary to recover oil from the bottom and 

shoreline; 

69 
 

Pt. 112, App. E 

(4) Equipment necessary to assess the impact of such discharges; and 

(5) Other appropriate equipment necessary 

to respond to a discharge involving the type 

of oil handled, stored,, or transported. 

7.6.2 Response resources identified in a response plan for a facility that handles, 

stores, or transports Group 5 oils under section 7.6.1 of this appendix shall be capable of 

being deployed (on site) within 24 hours of 

discovery of a discharge to the area where 

the facility is operating. 

7.6.3 A response plan must identify response resources with fire fighting capability. The owner or operator of a facility 

that handles, stores, or transports Group 5 

oils that does not have adequate fire fighting 

resources located at the facility or that cannot rely on sufficient local fire fighting resources must identify adequate fire fighting 

resources. The facility owner or operator 

shall ensure, by contract or other approved 

means as described in § 112.2, the availability 

of these resources. The response plan shall 

also identify an individual located at the facility to work with the fire department for 

Group 5 oil fires. This individual shall also 

verify that sufficient well-trained fire fighting resources are available within a reasonable response time to respond to a worst case 

discharge. The individual may be the qualified individual identified in the response 

plan or another appropriate individual located at the facility. 

7.7 Non-petroleum oils other than animal 

fats and vegetable oils. The procedures described in sections 7.7.1 through 7.7.5 of this 

appendix must be used to determine appropriate response plan development and evaluation criteria for facilities that handle, 

store, or transport non-petroleum oils other 

than animal fats and vegetable oils. Refer to 

section 11 of this appendix for information 

on the limitations on the use of chemical 

agents for inland and nearshore areas. 

7.7.1 An owner or operator of a facility 

that handles, stores, or transports non-petroleum oils other than animal fats and vegetable oils must provide information in his or 

her plan that identifies: 

(1) Procedures and strategies for responding to a worst case discharge to the maximum extent practicable; and 

(2) Sources of the equipment and supplies 

necessary to locate, recover, and mitigate 

such a discharge. 

7.7.2 An owner or operator of a facility 

that handles, stores, or transports non-petroleum oils other than animal fats and vegetable oils must ensure that any equipment 

identified in a response plan is capable of operating in the conditions expected in the geographic area(s) (i.e., operating environments) in which the facility operates using 

the criteria in Table 1 of this appendix. When 

evaluating the operability of equipment, the 

facility owner or operator must consider lim40 CFR Ch. I (7–1–05 Edition) 

itations that are identified in the appropriate ACPs, including: 

(1) Ice conditions; 

(2) Debris; 

(3) Temperature ranges; and 

(4) Weather-related visibility. 

7.7.3 The owner or operator of a facility 

that handles, stores, or transports non-petroleum oils other than animal fats and vegetable oils must identify the response resources that are available by contract or 

other approved means, as described in § 112.2. 

The equipment described in the response 

plan shall, as appropriate, include: 

(1) Containment boom, sorbent boom, or 

other methods for containing oil floating on 

the surface or to protect shorelines from impact; 

(2) Oil recovery devices appropriate for the 

type of non-petroleum oil carried; and 

(3) Other appropriate equipment necessary 

to respond to a discharge involving the type 

of oil carried. 

7.7.4 Response resources identified in a response plan according to section 7.7.3 of this 

appendix must be capable of commencing an 

effective on-scene response within the applicable tier response times in section 5.3 of 

this appendix. 

7.7.5 A response plan must identify response resources with fire fighting capability. The owner or operator of a facility 

that handles, stores, or transports non-petroleum oils other than animal fats and vegetable oils that does not have adequate fire 

fighting resources located at the facility or 

that cannot rely on sufficient local fire 

fighting resources must identify adequate 

fire fighting resources. The owner or operator shall ensure, by contract or other approved means as described in § 112.2, the 

availability of these resources. The response 

plan must also identify an individual located 

at the facility to work with the fire department for fires of these oils. This individual 

shall also verify that sufficient well-trained 

fire fighting resources are available within a 

reasonable response time to a worst case scenario. The individual may be the qualified 

individual identified in the response plan or 

another appropriate individual located at 

the facility. 

8.0	 Determining Response Resources Required 

for Small Discharges—Animal Fats and Vegetable Oils 

8.1 A facility owner or operator shall 

identify sufficient response resources available, by contract or other approved means as 

described in § 112.2, to respond to a small discharge of animal fats or vegetable oils. A 

small discharge is defined as any discharge 

volume less than or equal to 2,100 gallons, 

but not to exceed the calculated worst case 

discharge. The equipment must be designed 

to function in the operating environment at 

the point of expected use. 

70 
 

Environmental Protection Agency 

8.2 Complexes that are regulated by EPA 

and the USCG must also consider planning 

quantities for the marine transportation-related portion of the facility. 

8.2.1 The USCG planning level that corresponds to EPA’s ‘‘small discharge’’ is 

termed ‘‘the average most probable discharge.’’ A USCG rule found at 33 CFR 

154.1020 defines ‘‘the average most probable 

discharge’’ as the lesser of 50 barrels (2,100 

gallons) or 1 percent of the volume of the 

worst case discharge. Owners or operators of 

complexes that handle, store, or transport 

animal fats and vegetable oils must compare 

oil discharge volumes for a small discharge 

and an average most probable discharge, and 

plan for whichever quantity is greater. 

8.3 The response resources shall, as appropriate, include: 

8.3.1 One thousand feet of containment 

boom (or, for complexes with marine transfer 

components, 1,000 feet of containment boom 

or two times the length of the largest vessel 

that regularly conducts oil transfers to or 

from the facility, whichever is greater), and 

a means of deploying it within 1 hour of the 

discovery of a discharge; 

8.3.2 Oil recovery devices with an effective daily recovery capacity equal to the 

amount of oil discharged in a small discharge or greater which is available at the 

facility within 2 hours of the detection of a 

discharge; and 

8.3.3 Oil storage capacity for recovered 

oily material indicated in section 12.2 of this 

appendix. 

9.0	 Determining Response Resources Required 

for Medium Discharges—Animal Fats and 

Vegetable Oils 

9.1 A facility owner or operator shall 

identify sufficient response resources available, by contract or other approved means as 

described in § 112.2, to respond to a medium 

discharge of animal fats or vegetable oils for 

that facility. This will require response resources capable of containing and collecting 

up to 36,000 gallons of oil or 10 percent of the 

worst case discharge, whichever is less. All 

equipment identified must be designed to operate in the applicable operating environment specified in Table 1 of this appendix. 

9.2 Complexes that are regulated by EPA 

and the USCG must also consider planning 

quantities for the transportation-related 

transfer portion of the facility. Owners or 

operators of complexes that handle, store, or 

transport animal fats or vegetable oils must 

plan for oil discharge volumes for a medium 

discharge. For non-petroleum oils, there is 

no USCG planning level that directly corresponds to EPA’s ‘‘medium discharge.’’ Although the USCG does not have planning requirements for medium discharges, they do 

have requirements (at 33 CFR 154.545) to 

identify equipment to contain oil resulting 

from an operational discharge. 

Pt. 112, App. E 

9.3 Oil recovery devices identified to meet 

the applicable medium discharge volume 

planning criteria must be located such that 

they are capable of arriving on-scene within 

6 hours in higher volume port areas and the 

Great Lakes and within 12 hours in all other 

areas. Higher volume port areas and Great 

Lakes areas are defined in section 1.1 of Appendix C to this part. 

9.4 Because rapid control, containment, 

and removal of oil are critical to reduce discharge impact, the owner or operator must 

determine response resources using an effective daily recovery capacity for oil recovery 

devices equal to 50 percent of the planning 

volume applicable for the facility as determined in section 9.1 of this appendix. The effective daily recovery capacity for oil recovery devices identified in the plan must be determined using the criteria in section 6 of 

this appendix. 

9.5 In addition to oil recovery capacity, 

the plan shall, as appropriate, identify sufficient quantity of containment boom available, by contract or other approved means as 

described in § 112.2, to arrive within the required response times for oil collection and 

containment and for protection of fish and 

wildlife and sensitive environments. For further description of fish and wildlife and sensitive environments, see Appendices I, II, and 

III to DOC/NOAA’s ‘‘Guidance for Facility 

and Vessel Response Plans: Fish and Wildlife 

and Sensitive Environments’’ (59 FR 14713–22, 

March 29, 1994) and the applicable ACP. Although 40 CFR part 112 does not set required 

quantities of boom for oil collection and containment, the response plan shall identify 

and ensure, by contract or other approved 

means as described in § 112.2, the availability 

of the quantity of boom identified in the 

plan for this purpose. 

9.6 The plan must indicate the availability of temporary storage capacity to 

meet section 12.2 of this appendix. If available storage capacity is insufficient to meet 

this level, then the effective daily recovery 

capacity must be derated (downgraded) to 

the limits of the available storage capacity. 

9.7 The following is an example of a medium discharge volume planning calculation 

for equipment identification in a higher volume port area: 

The facility’s largest aboveground storage 

tank volume is 840,000 gallons. Ten percent 

of this capacity is 84,000 gallons. Because 10 

percent of the facility’s largest tank, or 

84,000 gallons, is greater than 36,000 gallons, 

36,000 gallons is used as the planning volume. 

The effective daily recovery capacity is 50 

percent of the planning volume, or 18,000 gallons per day. The ability of oil recovery devices to meet this capacity must be calculated using the procedures in section 6 of 

this appendix. Temporary storage capacity 

available on-scene must equal twice the 

71 
 

Pt. 112, App. E 

daily recovery capacity as indicated in section 12.2 of this appendix, or 36,000 gallons 

per day. This is the information the facility 

owner or operator must use to identify and 

ensure the availability of the required response resources, by contract or other approved means as described in § 112.2. The facility owner shall also identify how much 

boom is available for use. 

10.0	 Calculating Planning Volumes for a Worst 

Case Discharge—Animal Fats and Vegetable 

Oils. 

10.1 A facility owner or operator shall 

plan for a response to the facility’s worst 

case discharge. The planning for on-water oil 

recovery must take into account a loss of 

some oil to the environment due to physical, 

chemical, and biological processes, potential 

increases in volume due to emulsification, 

and the potential for deposition of oil on the 

shoreline or on sediments. The response 

planning procedures for animal fats and vegetable oils are discussed in section 10.7 of 

this appendix. You may use alternate response planning procedures for animal fats 

and vegetable oils if those procedures result 

in environmental protection equivalent to 

that provided by the procedures in section 

10.7 of this appendix. 

10.2 The following procedures must be 

used by a facility owner or operator in determining the required on-water oil recovery 

capacity: 

10.2.1 The following must be determined: 

the worst case discharge volume of oil in the 

facility; the appropriate group(s) for the 

types of oil handled, stored, or transported 

at the facility (Groups A, B, C); and the facility’s specific operating area. See sections 

1.2.1 and 1.2.9 of this appendix for the definitions of animal fats and vegetable oils and 

groups thereof. Facilities that handle, store, 

or transport oil from different oil groups 

must calculate each group separately, unless 

the oil group constitutes 10 percent or less 

by volume of the facility’s total oil storage 

capacity. This information is to be used with 

Table 6 of this appendix to determine the 

percentages of the total volume to be used 

for removal capacity planning. Table 6 of 

this appendix divides the volume into three 

categories: oil lost to the environment; oil 

deposited on the shoreline; and oil available 

for on-water recovery. 

10.2.2 The on-water oil recovery volume 

shall, as appropriate, be adjusted using the 

appropriate emulsification factor found in 

Table 7 of this appendix. Facilities that handle, store, or transport oil from different 

groups must compare the on-water recovery 

volume for each oil group (unless the oil 

group constitutes 10 percent or less by volume of the facility’s total storage capacity) 

and use the calculation that results in the 

largest on-water oil recovery volume to plan 

40 CFR Ch. I (7–1–05 Edition) 

for the amount of response resources for a 

worst case discharge. 

10.2.3 The adjusted volume is multiplied 

by the on-water oil recovery resource mobilization factor found in Table 4 of this appendix from the appropriate operating area and 

response tier to determine the total on-water 

oil recovery capacity in barrels per day that 

must be identified or contracted to arrive 

on-scene within the applicable time for each 

response tier. Three tiers are specified. For 

higher volume port areas, the contracted 

tiers of resources must be located such that 

they are capable of arriving on-scene within 

6 hours for Tier 1, 30 hours for Tier 2, and 54 

hours for Tier 3 of the discovery of a discharge. For all other rivers and canals, inland, nearshore areas, and the Great Lakes, 

these tiers are 12, 36, and 60 hours. 

10.2.4 The resulting on-water oil recovery 

capacity in barrels per day for each tier is 

used to identify response resources necessary 

to sustain operations in the applicable operating area. The equipment shall be capable 

of sustaining operations for the time period 

specified in Table 6 of this appendix. The facility owner or operator shall identify and 

ensure, by contract or other approved means 

as described in § 112.2, the availability of sufficient oil spill recovery devices to provide 

the effective daily oil recovery capacity required. If the required capacity exceeds the 

applicable cap specified in Table 5 of this appendix, then a facility owner or operator 

shall ensure, by contract or other approved 

means as described in § 112.2, only for the 

quantity of resources required to meet the 

cap, but shall identify sources of additional 

resources as indicated in section 5.4 of this 

appendix. The owner or operator of a facility 

whose planning volume exceeded the cap in 

1998 must make arrangements to identify 

and ensure, by contract or other approved 

means as described in § 112.2, the availability 

of additional capacity to be under contract 

by 2003, as appropriate. For a facility that 

handles multiple groups of oil, the required 

effective daily recovery capacity for each oil 

group is calculated before applying the cap. 

The oil group calculation resulting in the 

largest on-water recovery volume must be 

used to plan for the amount of response resources for a worst case discharge, unless the 

oil group comprises 10 percent or less by volume of the facility’s oil storage capacity. 

10.3 The procedures discussed in sections 

10.3.1 through 10.3.3 of this appendix must be 

used to calculate the planning volume for 

identifying shoreline cleanup capacity (for 

Groups A and B oils). 

10.3.1 The following must be determined: 

the worst case discharge volume of oil for 

the facility; the appropriate group(s) for the 

types of oil handled, stored, or transported 

at the facility (Groups A or B); and the geographic area(s) in which the facility operates 

72 
 

Environmental Protection Agency 

(i.e., operating areas). For a facility handling, storing, or transporting oil from different groups, each group must be calculated 

separately. Using this information, Table 6 

of this appendix must be used to determine 

the percentages of the total volume to be 

used for shoreline cleanup resource planning. 

10.3.2 The shoreline cleanup planning volume must be adjusted to reflect an emulsification factor using the same procedure as 

described in section 10.2.2 of this appendix. 

10.3.3 The resulting volume shall be used 

to identify an oil spill removal organization 

with the appropriate shoreline cleanup capability. 

10.4 A response plan must identify response resources with fire fighting capability 

appropriate for the risk of fire and explosion 

at the facility from the discharge or threat 

of discharge of oil. The owner or operator of 

a facility that handles, stores, or transports 

Group A or B oils that does not have adequate fire fighting resources located at the 

facility or that cannot rely on sufficient 

local fire fighting resources must identify 

adequate fire fighting resources. The facility 

owner or operator shall ensure, by contract 

or other approved means as described in 

§ 112.2, the availability of these resources. 

The response plan must also identify an individual to work with the fire department for 

Group A or B oil fires. This individual shall 

also verify that sufficient well-trained fire 

fighting resources are available within a reasonable response time to a worst case scenario. The individual may be the qualified 

individual identified in the response plan or 

another appropriate individual located at 

the facility. 

10.5 The following is an example of the 

procedure described in sections 10.2 and 10.3 

of this appendix. A facility with a 37.04 million gallon (881,904 barrel) capacity of several 

types of vegetable oils is located in the InPt. 112, App. E 

land Operating Area. The vegetable oil with 

the highest specific gravity stored at the facility is soybean oil (specific gravity 0.922, 

Group B vegetable oil). The facility has ten 

aboveground oil storage tanks with a combined total capacity of 18 million gallons 

(428,571 barrels) and without secondary containment. The remaining facility tanks are 

inside secondary containment structures. 

The largest aboveground oil storage tank (3 

million gallons or 71,428 barrels) has its own 

secondary containment. Two 2.1 million gallon (50,000 barrel) tanks (that are not connected by a manifold) are within a common 

secondary containment tank area, which is 

capable of holding 4.2 million gallons (100,000 

barrels) plus sufficient freeboard. 

10.5.1 The worst case discharge for the facility is calculated by adding the capacity of 

all aboveground vegetable oil storage tanks 

without secondary containment (18.0 million 

gallons) plus the capacity of the largest 

aboveground storage tank inside secondary 

containment (3.0 million gallons). The resulting worst case discharge is 21 million 

gallons or 500,000 barrels. 

10.5.2 With a specific worst case discharge 

identified, the planning volume for on-water 

recovery can be identified as follows: 

Worst case discharge: 21 million gallons 

(500,000 barrels) of Group B vegetable oil 

Operating Area: Inland 

Planned percent recovered floating vegetable 

oil (from Table 6, column Nearshore/Inland/ 

Great Lakes): Inland, Group B is 20% 

Emulsion factor (from Table 7): 2.0 

Planning volumes for on-water recovery: 

21,000,000 gallons × 0.2 × 2.0 = 8,400,000 gallons or 200,000 barrels. 

Determine required resources for on-water 

recovery for each of the three tiers using 

mobilization factors (from Table 4, column 

Inland/Nearshore/Great Lakes) 

Inland Operating Area Tier 1 Tier 2 Tier 3 

Mobilization factor by which you multiply planning volume ............................................................ .15 .25 .40 

Estimated Daily Recovery Capacity (bbls) ...................................................................................... 30,000 50,000 80,000 

10.5.3 Because the requirements for OnWater Recovery Resources for Tiers 1, 2, and 

3 for Inland Operating Area exceed the caps 

identified in Table 5 of this appendix, the facility owner will contract for a response of 

12,500 barrels per day (bpd) for Tier 1, 25,000 

bpd for Tier 2, and 50,000 bpd for Tier 3. Resources for the remaining 17,500 bpd for Tier 

1, 25,000 bpd for Tier 2, and 30,000 bpd for Tier 

3 shall be identified but need not be contracted for in advance. 

10.5.4 With the specific worst case discharge identified, the planning volume of onshore recovery can be identified as follows: 

Worst case discharge: 21 million gallons 

(500,000 barrels) of Group B vegetable oil 

Operating Area: Inland 

Planned percent recovered floating vegetable 

oil from onshore (from Table 6, column 

Nearshore/Inland/Great Lakes): Inland, 

Group B is 65% 

Emulsion factor (from Table 7): 2.0 
 

Planning volumes for shoreline recovery: 
 

21,000,000 gallons × 0.65 × 2.0 = 27,300,000 gal-


lons or 650,000 barrels 

10.5.5 The facility owner or operator shall, 

as appropriate, also identify or contract for 

quantities of boom identified in the response 

plan for the protection of fish and wildlife 

73 
 

Pt. 112, App. E 

and sensitive environments within the area 

potentially impacted by a worst case discharge from the facility. For further description of fish and wildlife and sensitive environments, see Appendices I, II, and III to 

DOC/NOAA’s ‘‘Guidance for Facility and Vessel Response Plans: Fish and Wildlife and 

Sensitive Environments,’’ (see Appendix E to 

this part, section 13, for availability) and the 

applicable ACP. Attachment C–III to Appendix C provides a method for calculating a 

planning distance to fish and wildlife and 

sensitive environments and public drinking 

water intakes that may be adversely affected 

in the event of a worst case discharge. 

10.6 The procedures discussed in sections 

10.6.1 through 10.6.3 of this appendix must be 

used to determine appropriate response resources for facilities with Group C oils. 

10.6.1 The owner or operator of a facility 

that handles, stores, or transports Group C 

oils shall, as appropriate, identify the response resources available by contract or 

other approved means, as described in § 112.2. 

The equipment identified in a response plan 

shall, as appropriate, include: 

(1) Sonar, sampling equipment, or other 

methods for locating the oil on the bottom 

or suspended in the water column; 

(2) Containment boom, sorbent boom, silt 

curtains, or other methods for containing 

the oil that may remain floating on the surface or to reduce spreading on the bottom; 

(3) Dredges, pumps, or other equipment 

necessary to recover oil from the bottom and 

shoreline; 

(4) Equipment necessary to assess the impact of such discharges; and 

(5) Other appropriate equipment necessary 

to respond to a discharge involving the type 

of oil handled, stored, or transported. 

10.6.2 Response resources identified in a 

response plan for a facility that handles, 

stores, or transports Group C oils under section 10.6.1 of this appendix shall be capable of 

being deployed on scene within 24 hours of 

discovery of a discharge. 

10.6.3 A response plan must identify response resources with fire fighting capability. The owner or operator of a facility 

that handles, stores, or transports Group C 

oils that does not have adequate fire fighting 

resources located at the facility or that cannot rely on sufficient local fire fighting resources must identify adequate fire fighting 

resources. The owner or operator shall ensure, by contract or other approved means as 

described in § 112.2, the availability of these 

resources. The response plan shall also identify an individual located at the facility to 

work with the fire department for Group C 

oil fires. This individual shall also verify 

that sufficient well-trained fire fighting resources are available within a reasonable response time to respond to a worst case discharge. The individual may be the qualified 

individual identified in the response plan or 

40 CFR Ch. I (7–1–05 Edition) 

another appropriate individual located at 

the facility. 

10.7 The procedures described in sections 

10.7.1 through 10.7.5 of this appendix must be 

used to determine appropriate response plan 

development and evaluation criteria for facilities that handle, store, or transport animal fats and vegetable oils. Refer to section 

11 of this appendix for information on the 

limitations on the use of chemical agents for 

inland and nearshore areas. 

10.7.1 An owner or operator of a facility 

that handles, stores, or transports animal 

fats and vegetable oils must provide information in the response plan that identifies: 

(1) Procedures and strategies for responding to a worst case discharge of animal fats 

and vegetable oils to the maximum extent 

practicable; and 

(2) Sources of the equipment and supplies 

necessary to locate, recover, and mitigate 

such a discharge. 

10.7.2 An owner or operator of a facility 

that handles, stores, or transports animal 

fats and vegetable oils must ensure that any 

equipment identified in a response plan is capable of operating in the geographic area(s) 

(i.e., operating environments) in which the 

facility operates using the criteria in Table 1 

of this appendix. When evaluating the operability of equipment, the facility owner or 

operator must consider limitations that are 

identified in the appropriate ACPs, including: 

(1) Ice conditions; 

(2) Debris; 

(3) Temperature ranges; and 

(4) Weather-related visibility. 

10.7.3. The owner or operator of a facility 

that handles, stores, or transports animal 

fats and vegetable oils must identify the response resources that are available by contract or other approved means, as described 

in § 112.2. The equipment described in the response plan shall, as appropriate, include: 

(1) Containment boom, sorbent boom, or 

other methods for containing oil floating on 

the surface or to protect shorelines from impact; 

(2) Oil recovery devices appropriate for the 

type of animal fat or vegetable oil carried; 

and 

(3) Other appropriate equipment necessary 

to respond to a discharge involving the type 

of oil carried. 

10.7.4 Response resources identified in a 

response plan according to section 10.7.3 of 

this appendix must be capable of commencing an effective on-scene response within the applicable tier response times in section 5.3 of this appendix. 

10.7.5 A response plan must identify response resources with fire fighting capability. The owner or operator of a facility 

that handles, stores, or transports animal 

fats and vegetable oils that does not have 

adequate fire fighting resources located at 

74 
 

Environmental Protection Agency 

the facility or that cannot rely on sufficient 

local fire fighting resources must identify 

adequate fire fighting resources. The owner 

or operator shall ensure, by contract or 

other approved means as described in § 112.2, 

the availability of these resources. The response plan shall also identify an individual 

located at the facility to work with the fire 

department for animal fat and vegetable oil 

fires. This individual shall also verify that 

sufficient well-trained fire fighting resources 

are available within a reasonable response 

time to respond to a worst case discharge. 

The individual may be the qualified individual identified in the response plan or another appropriate individual located at the 

facility. 

11.0 Determining the Availability of 

Alternative Response Methods 

11.1 For chemical agents to be identified 

in a response plan, they must be on the NCP 

Product Schedule that is maintained by 

EPA. (Some States have a list of approved 

dispersants for use within State waters. Not 

all of these State-approved dispersants are 

listed on the NCP Product Schedule.) 

11.2 Identification of chemical agents in 

the plan does not imply that their use will be 

authorized. Actual authorization will be governed by the provisions of the NCP and the 

applicable ACP. 

12.0 Additional Equipment Necessary to 

Sustain Response Operations 

12.1 A facility owner or operator shall 

identify sufficient response resources available, by contract or other approved means as 

described in § 112.2, to respond to a medium 

discharge of animal fats or vegetables oils 

for that facility. This will require response 

resources capable of containing and collecting up to 36,000 gallons of oil or 10 percent of the worst case discharge, whichever 

is less. All equipment identified must be designed to operate in the applicable operating 

environment specified in Table 1 of this appendix. 

12.2 A facility owner or operator shall 

evaluate the availability of adequate temporary storage capacity to sustain the effective daily recovery capacities from equipment identified in the plan. Because of the 

inefficiencies of oil spill recovery devices, response plans must identify daily storage capacity equivalent to twice the effective daily 

recovery capacity required on-scene. This 

temporary storage capacity may be reduced 

if a facility owner or operator can demonstrate by waste stream analysis that the 

efficiencies of the oil recovery devices, ability to decant waste, or the availability of alternative temporary storage or disposal locaPt. 112, App. E 

tions will reduce the overall volume of oily 

material storage. 

12.3 A facility owner or operator shall ensure that response planning includes the capability to arrange for disposal of recovered 

oil products. Specific disposal procedures 

will be addressed in the applicable ACP. 

13.0 References and Availability 

13.1 All materials listed in this section 

are part of EPA’s rulemaking docket and are 

located in the Superfund Docket, 1235 Jefferson Davis Highway, Crystal Gateway 1, Arlington, Virginia 22202, Suite 105 (Docket 

Numbers SPCC–2P, SPCC–3P, and SPCC–9P). 

The docket is available for inspection between 9 a.m. and 4 p.m., Monday through 

Friday, excluding Federal holidays. 

Appointments to review the docket can be 

made by calling 703–603–9232. Docket hours 

are subject to change. As provided in 40 CFR 

part 2, a reasonable fee may be charged for 

copying services. 

13.2 The docket will mail copies of materials to requestors who are outside the Washington, DC metropolitan area. Materials may 

be available from other sources, as noted in 

this section. As provided in 40 CFR part 2, a 

reasonable fee may be charged for copying 

services. The RCRA/Superfund Hotline at 

800–424–9346 may also provide additional information on where to obtain documents. To 

contact the RCRA/Superfund Hotline in the 

Washington, DC metropolitan area, dial 703– 

412–9810. The Telecommunications Device for 

the Deaf (TDD) Hotline number is 800–553– 

7672, or, in the Washington, DC metropolitan 

area, 703–412–3323. 

13.3 Documents 

(1) National Preparedness for Response Exercise Program (PREP). The PREP draft 

guidelines are available from United States 

Coast Guard Headquarters (G-MEP-4), 2100 

Second Street, SW., Washington, DC 20593. 

(See 58 FR 53990–91, October 19, 1993, Notice 

of Availability of PREP Guidelines). 

(2) ‘‘Guidance for Facility and Vessel Response Plans: Fish and Wildlife and Sensitive 

Environments (published in the Federal Register by DOC/NOAA at 59 FR 14713–22, March 

29, 1994.). The guidance is available in the 

Superfund Docket (see sections 13.1 and 13.2 

of this appendix). 

(3) ASTM Standards. ASTM F 715, ASTM F 

989, ASTM F 631–99, ASTM F 808–83 (1999). 

The ASTM standards are available from the 

American Society for Testing and Materials, 

100 Barr Harbor Drive, West Conshohocken, 

PA 19428–2959. 

(4) Response Plans for Marine Transportation-Related Facilities, Interim Final 

Rule. Published by USCG, DOT at 58 FR 7330– 

76, February 5, 1993. 

75 
 

Pt. 112, App. E 40 CFR Ch. I (7–1–05 Edition) 

TABLE 1 TO APPENDIX E—RESPONSE RESOURCE OPERATING CRITERIA 

Oil Recovery Devices 

Operating environment Significant wave 

height 1 Sea state 

Rivers and Canals ................................................................................................................. ≤ 1 foot ...................... 1 

Inland ..................................................................................................................................... ≤ 3 feet ...................... 2 

Great Lakes ........................................................................................................................... ≤ 4 feet ...................... 2–3 

Ocean .................................................................................................................................... ≤ 6 feet ...................... 3–4 

Boom 

Boom property 

Use 

Rivers and 

canals Inland Great Lakes Ocean 

Significant Wave Height 1 ............................................................... ≤ 1 ............... ≤ 3 ............... ≤ 4 ............... ≤ 6 

Sea State ........................................................................................ 1 .................. 2 .................. 2–3 .............. 3–4 

Boom height—inches (draft plus freeboard) ................................... 6–18 ............ 18–42 .......... 18–42 .......... ≥42 

Reserve Buoyancy to Weight Ratio ................................................ 2:1 ............... 2:1 ............... 2:1 ............... 3:1 to 4:1 

Total Tensile Strength—pounds ..................................................... 4,500 ........... 15,000– 15,000– ≥20,000 

20,000. 20,000. 

Skirt Fabric Tensile Strength—pounds ........................................... 200 .............. 300 .............. 300 .............. 500 

Skirt Fabric Tear Strength—pounds ............................................... 100 .............. 100 .............. 100 .............. 125 

1 Oil recovery devices and boom shall be at least capable of operating in wave heights up to and including the values listed in 

Table 1 for each operating environment. 

TABLE 2 TO APPENDIX E—REMOVAL CAPACITY PLANNING TABLE FOR PETROLEUM OILS 

Spill location Rivers and canals Nearshore/Inland/Great Lakes 

Sustainability of on-water oil recovery 3 days 4 days 

Oil group 1 

Percent natural dissipation Percent recovered 

floating oil 

Percent oil 

onshore 

Percent natural dissipation Percent recovered 

floating oil 

Percent oil 

onshore 

1—Non-persistent oils ........................... 80 10 10 80 20 10 

2—Light crudes ..................................... 40 15 45 50 50 30 

3—Medium crudes and fuels ................ 20 15 65 30 50 50 

4—Heavy crudes and fuels .................. 5 20 75 10 50 70 

1 The response resource considerations for non-petroleum oils other than animal fats and vegetable oils are outlined in section 

7.7 of this appendix. 

NOTE: Group 5 oils are defined in section 1.2.8 of this appendix; the response resource considerations are outlined in section 

7.6 of this appendix. 

TABLE 3 TO APPENDIX E—EMULSIFICATION FACTORS FOR PETROLEUM OIL GROUPS 1 

Non-Persistent Oil: 

Group 1 .............................................................................................................................................................................. 1.0 

Persistent Oil: 

Group 2 .............................................................................................................................................................................. 1.8 

Group 3 .............................................................................................................................................................................. 2.0 

Group 4 .............................................................................................................................................................................. 1.4 

Group 5 oils are defined in section 1.2.7 of this appendix; the response resource considerations are outlined in section 

7.6 of this appendix. 

1 See sections 1.2.2 and 1.2.7 of this appendix for group designations for non-persistent and persistent oils, respectively. 

TABLE 4 TO APPENDIX E—ON-WATER OIL RECOVERY RESOURCE MOBILIZATION FACTORS 

Operating area Tier 1 Tier 2 Tier 3 

Rivers and Canals ............................................................................................. 0.30 0.40 0.60 

Inland/Nearshore Great Lakes .......................................................................... 0.15 0.25 0.40 

Note: These mobilization factors are for total resources mobilized, not incremental response resources. 

TABLE 5 TO APPENDIX E—RESPONSE CAPABILITY CAPS BY OPERATING AREA 

Tier 1 Tier 2 Tier 3 

February 18, 1993: 

All except Rivers & Canals, Great Lakes ........................................... 10K bbls/day 20K bbls/day 40K bbls/day. 

76 
 
 

Environmental Protection Agency Pt. 112, App. E 

TABLE 5 TO APPENDIX E—RESPONSE CAPABILITY CAPS BY OPERATING AREA—Continued 

Tier 1 Tier 2 Tier 3 

Great Lakes ........................................................................................ 5K bbls/day 10K bbls/day 20K bbls/day. 

Rivers & Canals .................................................................................. 1.5K bbls/day 3.0K bbls/day 6.0K bbls/day. 

February 18, 1998: 

All except Rivers & Canals, Great Lakes ........................................... 12.5K bbls/day 25K bbls/day 50K bbls/day. 

Great Lakes ........................................................................................ 6.35K bbls/day 12.3K bbls/day 25K bbls/day. 

Rivers & Canals .................................................................................. 1.875K bbls/ 3.75K bbls/day 7.5K bbls/day. 

day 

February 18, 2003: 

All except Rivers & Canals, Great Lakes ........................................... TBD TBD TBD. 

Great Lakes ........................................................................................ TBD TBD TBD. 

Rivers & Canals .................................................................................. TBD TBD TBD. 

Note: The caps show cumulative overall effective daily recovery capacity, not incremental increases. 

TBD=To Be Determined. 

TABLE 6 TO APPENDIX E—REMOVAL CAPACITY PLANNING TABLE FOR ANIMAL FATS AND VEGETABLE 

OILS 

Spill location Rivers and canals Nearshore/Inland/Great Lakes 

Sustainability of on-water oil recovery 3 days 4 days 

Oil group 1 Percent natural loss 

Percent recovered 

floating oil 

Percent recovered oil 

from onshore 

Percent natural loss 

Percent recovered 

floating oil 

Percent recovered oil 

from onshore 

Group A ................................................. 40 15 45 50 20 30 

Group B ................................................. 20 15 65 30 20 50 

1 Substances with a specific gravity greater than 1.0 generally sink below the surface of the water. Response resource considerations are outlined in section 10.6 of this appendix. The owner or operator of the facility is responsible for determining appropriate response resources for Group C oils including locating oil on the bottom or suspended in the water column; containment 

boom or other appropriate methods for containing oil that may remain floating on the surface; and dredges, pumps, or other 

equipment to recover animal fats or vegetable oils from the bottom and shoreline. 

NOTE: Group C oils are defined in sections 1.2.1 and 1.2.9 of this appendix; the response resource procedures are discussed 

in section 10.6 of this appendix. 

TABLE 7 TO APPENDIX E—EMULSIFICATION FACTORS FOR ANIMAL FATS AND VEGETABLE OILS 

Oil Group 1: 

Group A .......................................................................................................................................................................... 1.0 

Group B .......................................................................................................................................................................... 2.0 

1 Substances with a specific gravity greater than 1.0 generally sink below the surface of the water. Response resource considerations are outlined in section 10.6 of this appendix. The owner or operator of the facility is responsible for determining appro­ priate response resources for Group C oils including locating oil on the bottom or suspended in the water column; containment 

boom or other appropriate methods for containing oil that may remain floating on the surface; and dredges, pumps, or other 

equipment to recover animal fats or vegetable oils from the bottom and shoreline. 

NOTE: Group C oils are defined in sections 1.2.1 and 1.2.9 of this appendix; the response resource procedures are discussed 

in section 10.6 of this appendix. 

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Environmental Protection Agency 	 Pt. 112, App. F 

[59 FR 34111, July 1, 1994; 59 FR 49006, Sept. 26, 1994, as amended at 65 FR 40806, 40807, June 

30, 2000; 65 FR 47325, Aug. 2, 2000; 66 FR 47325, Aug. 2, 2000; 66 FR 35460, 35461, June 29, 2001] 

APPENDIX F TO PART 112—FACILITYSPECIFIC RESPONSE PLAN 

Table of Contents 

1.0 Model Facility-Specific Response Plan 
 
 

1.1 Emergency Response Action Plan 
 
 

1.2 Facility Information 
 
 

1.3 Emergency Response Information 
 
 

1.3.1 Notification 
 
 

1.3.2 Response Equipment List 
 
 

1.3.3	 Response Equipment Testing/Deploy-
 
 

ment 
 
 

1.3.4 Personnel 
 
 

1.3.5 Evacuation Plans 
 
 

1.3.6 Qualified Individual’s Duties 
 
 

1.4 Hazard Evaluation 
 
 

1.4.1 Hazard Identification 
 
 

1.4.2 Vulnerability Analysis 
 
 

1.4.3	 Analysis of the Potential for an Oil 
 
 

Spill 
 
 

1.4.4 Facility Reportable Oil Spill History 
 
 

1.5 Discharge Scenarios 
 
 

1.5.1 Small and Medium Discharges 
 
 

1.5.2 Worst Case Discharge 
 
 

1.6 Discharge Detection Systems 
 
 

1.6.1 Discharge Detection By Personnel 
 
 

1.6.2 Automated Discharge Detection 
 
 

85 

Pt. 112, App. F 

1.7 Plan Implementation 

1.7.1	 Response Resources for Small, Medium, and Worst Case Spills 

1.7.2 Disposal Plans 

1.7.3 Containment and Drainage Planning 

1.8 Self-Inspection, Drills/Exercises, and Response Training 

1.8.1 Facility Self-Inspection 

1.8.1.1 Tank Inspection 

1.8.1.2 Response Equipment Inspection 

1.8.1.3 Secondary Containment Inspection 

1.8.2 Facility Drills/Exercises 

1.8.2.1	 Qualified Individual Notification 

Drill Logs 

1.8.2.2	 Spill Management Team Tabletop 

Exercise Logs 

1.8.3 Response Training 

1.8.3.1 Personnel Response Training Logs 

1.8.3.2 Discharge Prevention Meeting Logs 

1.9 Diagrams 

1.10 Security 

2.0 Response Plan Cover Sheet 

3.0 Acronyms 

4.0 References 

1.0 Model Facility-Specific Response Plan 

(A) Owners or operators of facilities regulated under this part which pose a threat of 

substantial harm to the environment by discharging oil into or on navigable waters or 

adjoining shorelines are required to prepare 

and submit facility-specific response plans to 

EPA in accordance with the provisions in 

40 CFR Ch. I (7–1–05 Edition) 

this appendix. This appendix further describes the required elements in § 112.20(h). 

(B) Response plans must be sent to the appropriate EPA Regional office. Figure F–1 of 

this Appendix lists each EPA Regional office 

and the address where owners or operators 

must submit their response plans. Those facilities deemed by the Regional Administrator (RA) to pose a threat of significant 

and substantial harm to the environment 

will have their plans reviewed and approved 

by EPA. In certain cases, information required in the model response plan is similar 

to information currently maintained in the 

facility’s Spill Prevention, Control, and 

Countermeasures (SPCC) Plan as required by 

40 CFR 112.3. In these cases, owners or operators may reproduce the information and include a photocopy in the response plan. 

(C) A complex may develop a single response plan with a set of core elements for 

all regulating agencies and separate sections 

for the non-transportation-related and transportation-related components, as described 

in § 112.20(h). Owners or operators of large facilities that handle, store, or transport oil at 

more than one geographically distinct location (e.g., oil storage areas at opposite ends 

of a single, continuous parcel of property) 

shall, as appropriate, develop separate sections of the response plan for each storage 

area. 

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1.1 Emergency Response Action Plan 

Several sections of the response plan shall 

be co-located for easy access by response personnel during an actual emergency or oil discharge. This collection of sections shall be 

called the Emergency Response Action Plan. 

The Agency intends that the Action Plan 

contain only as much information as is necessary to combat the discharge and be arranged so response actions are not delayed. 

The Action Plan may be arranged in a number of ways. For example, the sections of the 

Emergency Response Action Plan may be 

photocopies or condensed versions of the 

87 
 
 

Pt. 112, App. F 

forms included in the associated sections of 

the response plan. Each Emergency Response 

Action Plan section may be tabbed for quick 

reference. The Action Plan shall be maintained in the front of the same binder that 

contains the complete response plan or it 

shall be contained in a separate binder. In 

the latter case, both binders shall be kept together so that the entire plan can be 

accessed by the qualified individual and appropriate spill response personnel. The 

Emergency Response Action Plan shall be 

made up of the following sections: 

1. Qualified Individual Information (Section 

1.2) partial 

2. Emergency Notification Phone List (Section 1.3.1) partial 

3. Spill Response Notification Form (Section 

1.3.1) partial 

4.	 Response Equipment List and Location 

(Section 1.3.2) complete 

5. Response Equipment Testing and Deployment (Section 1.3.3) complete 

6.	 Facility Response Team (Section 1.3.4) 

partial 

7. Evacuation Plan (Section 1.3.5) condensed 

8.	 Immediate Actions (Section 1.7.1) complete 

9. Facility Diagram (Section 1.9) complete 

1.2 Facility Information 

The facility information form is designed 

to provide an overview of the site and a description of past activities at the facility. 

Much of the information required by this 

section may be obtained from the facility’s 

existing SPCC Plan. 

1.2.1 Facility name and location: Enter facility name and street address. Enter the address of corporate headquarters only if corporate headquarters are physically located 

at the facility. Include city, county, state, 

zip code, and phone number. 

1.2.2 Latitude and Longitude: Enter the 

latitude and longitude of the facility. Include degrees, minutes, and seconds of the 

main entrance of the facility. 

1.2.3 Wellhead Protection Area: Indicate if 

the facility is located in or drains into a 

wellhead protection area as defined by the 

Safe Drinking Water Act of 1986 (SDWA).1 

The response plan requirements in the Wellhead Protection Program are outlined by the 

1 A wellhead protection area is defined as 

the surface and subsurface area surrounding 

a water well or wellfield, supplying a public 

water system, through which contaminants 

are reasonably likely to move toward and 

reach such water well or wellfield. For further information regarding State and territory protection programs, facility owners or 

operators may contact the SDWA Hotline at 

1–800–426–4791. 

40 CFR Ch. I (7–1–05 Edition) 

State or Territory in which the facility resides. 

1.2.4 Owner/operator: Write the name of 

the company or person operating the facility 

and the name of the person or company that 

owns the facility, if the two are different. 

List the address of the owner, if the two are 

different. 

1.2.5 Qualified Individual: Write the name 

of the qualified individual for the entire facility. If more than one person is listed, each 

individual indicated in this section shall 

have full authority to implement the facility 

response plan. For each individual, list: 

name, position, home and work addresses 

(street addresses, not P.O. boxes), emergency 

phone number, and specific response training 

experience. 

1.2.6 Date of Oil Storage Start-up: Enter the 

year which the present facility first started 

storing oil. 

1.2.7 Current Operation: Briefly describe 

the facility’s operations and include the 

North American Industrial Classification 

System (NAICS) code. 

1.2.8 Dates and Type of Substantial Expansion: Include information on expansions that 

have occurred at the facility. Examples of 

such expansions include, but are not limited 

to: Throughput expansion, addition of a 

product line, change of a product line, and 

installation of additional oil storage capacity. The data provided shall include all facility historical information and detail the expansion of the facility. An example of substantial expansion is any material alteration 

of the facility which causes the owner or operator of the facility to re-evaluate and increase the response equipment necessary to 

adequately respond to a worst case discharge 

from the facility. 

Date of Last Update: lll 

FACILITY INFORMATION FORM 

Facility Name: lllllllllllllll 

Location (Street Address): llllllll 

City: lll State: lll Zip: lll 

County: lll Phone Number: ( ) lll 

Latitude: lll Degrees lll Minutes 

lll Seconds 

Longitude: lll Degrees lll Minutes 

lll Seconds 

Wellhead Protection Area: lllllllll 

Owner: lllllllllllllllllll 

Owner Location (Street Address): llll 

(if different from Facility Address) 

City: lll State:lll Zip: lll 

County: lll Phone Number: ( ) lll 

Operator (if not Owner): llllllllll 

Qualified Individual(s): (attach additional 

sheets if more than one) 

Name: lllllllllllllllllll 

Position: lllllllllllllllll 

Work Address: lllllllllllllll 

Home Address: llllllllllllll 

Emergency Phone Number: ( ) llll 

88 
 

Environmental Protection Agency 

Date of Oil Storage Start-up: llllllll 

Current Operations: lllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Date(s) and Type(s) of Substantial Expansion(s): llllllllllllllllll 

llllllllllllllllllllllll 

(Attach additional sheets if necessary) 

1.3 Emergency Response Information 

(A) The information provided in this section shall describe what will be needed in an 

actual emergency involving the discharge of 

oil or a combination of hazardous substances 

and oil discharge. The Emergency Response 

Information section of the plan must include 

the following components: 

(1) The information provided in the Emergency Notification Phone List in section 

1.3.1 identifies and prioritizes the names and 

phone numbers of the organizations and personnel that need to be notified immediately 

in the event of an emergency. This section 

shall include all the appropriate phone numbers for the facility. These numbers must be 

verified each time the plan is updated. The 

contact list must be accessible to all facility 

employees to ensure that, in case of a discharge, any employee on site could immediately notify the appropriate parties. 

(2) The Spill Response Notification Form 

in section 1.3.1 creates a checklist of information that shall be provided to the National Response Center (NRC) and other response personnel. All information on this 

checklist must be known at the time of notification, or be in the process of being collected. This notification form is based on a 

similar form used by the NRC. Note: Do not 

delay spill notification to collect the information on the list. 

(3) Section 1.3.2 provides a description of 

the facility’s list of emergency response 

equipment and location of the response 

equipment. When appropriate, the amount of 

oil that emergency response equipment can 

handle and any limitations (e.g., launching 

sites) must be described. 

(4) Section 1.3.3 provides information regarding response equipment tests and deployment drills. Response equipment deployment exercises shall be conducted to ensure 

that response equipment is operational and 

the personnel who would operate the equipment in a spill response are capable of deploying and operating it. Only a representative sample of each type of response equipment needs to be deployed and operated, as 

long as the remainder is properly maintained. If appropriate, testing of response 

equipment may be conducted while it is 

being deployed. Facilities without facilityowned response equipment must ensure that 

the oil spill removal organization that is 

Pt. 112, App. F 

to the National Preparedness for Response 

Exercise Program (PREP) Guidelines (see 

Appendix E to this part, section 13, for availability), which satisfy Oil Pollution Act 

(OPA) response exercise requirements. 

(5) Section 1.3.4 lists the facility response 

personnel, including those employed by the 

facility and those under contract to the facility for response activities, the amount of 

time needed for personnel to respond, their 

responsibility in the case of an emergency, 

and their level of response training. Three 

different forms are included in this section. 

The Emergency Response Personnel List 

shall be composed of all personnel employed 

by the facility whose duties involve responding to emergencies, including oil discharges, 

even when they are not physically present at 

the site. An example of this type of person 

would be the Building Engineer-in-Charge or 

Plant Fire Chief. The second form is a list of 

the Emergency Response Contractors (both 

primary and secondary) retained by the facility. Any changes in contractor status 

must be reflected in updates to the response 

plan. Evidence of contracts with response 

contractors shall be included in this section 

so that the availability of resources can be 

verified. The last form is the Facility Response Team List, which shall be composed 

of both emergency response personnel (referenced by job title/position) and emergency 

response contractors, included in one of the 

two lists described above, that will respond 

immediately upon discovery of an oil discharge or other emergency (i.e., the first 

people to respond). These are to be persons 

normally on the facility premises or primary 

response contractors. Examples of these personnel would be the Facility Hazardous Materials (HAZMAT) Spill Team 1, Facility 

Fire Engine Company 1, Production Supervisor, or Transfer Supervisor. Company personnel must be able to respond immediately 

and adequately if contractor support is not 

available. 

(6) Section 1.3.5 lists factors that must, as 

appropriate, be considered when preparing an 

evacuation plan. 

(7) Section 1.3.6 references the responsibilities of the qualified individual for the facility in the event of an emergency. 

(B) The information provided in the emergency response section will aid in the assessment of the facility’s ability to respond to a 

worst case discharge and will identify additional assistance that may be needed. In addition, the facility owner or operator may 

want to produce a wallet-size card containing a checklist of the immediate response and notification steps to be taken in 

the event of an oil discharge. 

identified in the response plan to provide 1.3.1 Notification this response equipment certifies that the 

deployment exercises have been met. Refer Date of Last Update: llllllllllll 

89 
 
 

Pt. 112, App. F 

EMERGENCY NOTIFICATION PHONE LIST WHOM 
 

TO NOTIFY 
 

Reporter’s Name: llllllllllllll 

Date: llllllllllllllllllll 

Facility Name: lllllllllllllll 

Owner Name: llllllllllllllll 

Facility Identification Number: llllll 

Date and Time of Each NRC Notification: l 

Organization Phone No. 

1. National Response Center (NRC): 1–800–424–8802 

2. Qualified Individual: 

Evening Phone: 

3. Company Response Team: 

Evening Phone: 

4. Federal On-Scene Coordinator (OSC) 

and/or Regional Response Center 

(RRC): 

Evening Phone(s): 

Pager Number(s): 

5. Local Response Team (Fire Dept./Cooperatives): 

6. Fire Marshall: 

Evening Phone: 

7. State Emergency Response Commission (SERC): 

Evening Phone: 

8. State Police: 

9. Local Emergency Planning Committee 

(LEPC): 

10. Local Water Supply System: 

Evening Phone: 

11. Weather Report: 

12. Local Television/Radio Station for 

Evacuation Notification: 

13. Hospitals: 

40 CFR Ch. I (7–1–05 Edition) 

SPILL RESPONSE NOTIFICATION FORM 

Reporter’s Last Name: lllllllllll 

First: llllllllllllllllllll 

M.I.: lllllllllllllllllllll 

Position: llllllllllllllllll 

Phone Numbers: 

Day ( ) – 

Evening ( ) – 

Company: llllllllllllllllll 

Organization Type: lllllllllllll 

Address: lllllllllllllllllll 

llllllllllllllllllllllll 

City: lllllllllllllllllllll 

State: llllllllllllllllllll 

Zip: lllllllllllllllllllll 

Were Materials Discharged? lll (Y/N) Confidential? lll (Y/N) 

Meeting Federal Obligations to Report? 

lll (Y/N) Date Called: lll 

Calling for Responsible Party? lll (Y/N) 

Time Called: lll 

Incident Description 

Source and/or Cause of Incident: llllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Date of Incident: llllllllllllll 

Time of Incident: lll AM/PM 

Incident Address/Location: lllllllll 

llllllllllllllllllllllll 

Nearest City:llllllll State: llll 

County: llll Zip: llll 

Distance from City: lll Units of Measure: 

lll Direction from City: lll 

Section: llll Township: llll Range: 

llll Borough: llll 

Container Type: lll Tank Oil Storage Capacity: llll Units of Measure: lll 

Facility Oil Storage Capacity: llll Units 

of Measure: lll 

Facility Latitude: lll Degrees lll Minutes lll Seconds 

Facility Longitude: lll Degrees llll 

Minutes lll Seconds 

Material 

Material Dis- CHRIS Code Discharged quan- Unit of measure charged in water Quantity Unit of measure tity 

90 
 
 

Environmental Protection Agency 	 	 Pt. 112, App. F 

Material Dis- CHRIS Code Discharged quan- Unit of measure charged in water Quantity Unit of measure tity 

Response Action 

Actions Taken to Correct, Control or Mitigate Incident: 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Impact 

Number of Injuries: lll Number of Deaths: 

lll 

Were there Evacuations? lll (Y/N) Number Evacuated: lll 

Was there any Damage? lll (Y/N) 

Damage in Dollars (approximate): lllll 

Medium Affected: llllllllllllll 

Description: lllllllllllllllll 

More Information about Medium: lllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Additional Information 

Any information about the incident not recorded elsewhere in the report: 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Caller Notifications 

EPA? lll (Y/N) USCG? lll (Y/N) State? 

lll (Y/N) 

Other? lll (Y/N) Describe: llllll 

1.3.2 Response Equipment List 

Date of Last Update:lll 

FACILITY RESPONSE EQUIPMENT LIST 

1. Skimmers/Pumps—Operational Status: l 

Type, Model, and Year: 	 llllllllll 

llllllllllllllllllllll 

Type Model Year 

Number: llllllllllllllllll 

Capacity: llll gal./min. 

Daily Effective Recovery Rate: llllll 

Storage Location(s): lllllllllll 

Date Fuel Last Changed: lllllllll 

2. Boom—Operational Status: 	llllllll 

Type, Model, and Year: llllllllll 

Type Model Year 

Number: llllllllllllllllll 

Size (length): llll ft. 

Containment Area: llll sq. ft. 

Storage Location: lllllllllllll 

3. Chemicals Stored (Dispersants listed on 

EPA’s NCP Product Schedule) 

Type Amount Date purchased 

Treatment 

capacity 

Storage 

location 

Were appropriate procedures used to receive approval for use of dispersants in accordance with the NCP (40 CFR 300.910) and 

the Area Contingency Plan (ACP), where applicable?lll (Y/N). 

Name and State of On-Scene Coordinator 

(OSC) authorizing use: lll . 

Date Authorized: lll . 

4. Dispersant Dispensing Equipment—Operational Status: lll . 

Type and year Capacity Storage 

location 

Response 

time 

(minutes) 

91 
 
 

Pt. 112, App. F 	 	 40 CFR Ch. I (7–1–05 Edition) 

5. Sorbents—Operational Status: 	 llllll 

Type and Year Purchased: llllllll 

Amount: llllllllllllllllll 

Absorption Capacity (gal.): llllllll 

Storage Location(s): lllllllllll 

6. Hand Tools—Operational Status: lllll 

Type and year Quantity Storage 

location 

Type and year Quantity Storage 

location 

9. Other (e.g., Heavy Equipment, Boats and 

Motors)—Operational Status: lll 

7. Communication Equipment (include operating frequency and channel and/or cellular phone numbers)—Operational Status: 

Type and year Quantity Storage 

location 

lll 	 	 1.3.3 Response Equipment Testing/Deployment 

Type and year Quantity Storage location/ 

number 

Date of Last Update:llll 

Response Equipment Testing and 

Deployment Drill Log 

Last Inspection or Response Equipment Test 

Date: lllllllllllllllllll 8. Fire Fighting and Personnel Protective Inspection Frequency: lllllllllll Equipment—Operational Status: lll Last Deployment Drill Date: llllllll 

Type and year Quantity Storage 

location 

Deployment Frequency: llllllllll 

Oil Spill Removal Organization Certification 

(if applicable): lllllllllllllll 

1.3.4 Personnel 

Date of Last Update:llll 

EMERGENCY RESPONSE PERSONNEL 

Company Personnel 

Name Phone 1 Response time Responsibility during response action Response training type/date 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

11. 

12. 

1 Phone number to be used when person is not on-site. 

92 

Environmental Protection Agency Pt. 112, App. F 

EMERGENCY RESPONSE CONTRACTORS 

Date of Last Update: llll 

Contractor Phone Response time Contract responsibility 1 

1. 

2. 

3. 

4. 

1 Include evidence of contracts/agreements with response contractors to ensure the availability of personnel and response 

equipment. 

FACILITY RESPONSE TEAM 

Date of Last Update:llll 

Team member Response time (minutes) Phone or pager number (day/evening) 

Qualified Individual: 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

/ 

NOTE: If the facility uses contracted help in an emergency response situation, the owner or operator must provide the contractors’ names and review the contractors’ capacities to provide adequate personnel and response equipment. 

93 

Pt. 112, App. F 

1.3.5 Evacuation Plans 

1.3.5.1 Based on the analysis of the facility, as discussed elsewhere in the plan, a facility-wide evacuation plan shall be developed. In addition, plans to evacuate parts of 

the facility that are at a high risk of exposure in the event of a discharge or other release must be developed. Evacuation routes 

must be shown on a diagram of the facility 

(see section 1.9 of this appendix). When developing evacuation plans, consideration 

must be given to the following factors, as appropriate: 

(1) Location of stored materials; 

(2) Hazard imposed by discharged material; 

(3) Discharge flow direction; 

(4) Prevailing wind direction and speed; 

(5) Water currents, tides, or wave conditions (if applicable); 

(6) Arrival route of emergency response 

personnel and response equipment; 

(7) Evacuation routes; 

(8) Alternative routes of evacuation; 

(9) Transportation of injured personnel to 

nearest emergency medical facility; 

(10) Location of alarm/notification systems; 

(11) The need for a centralized check-in 

area for evacuation validation (roll call); 

(12) Selection of a mitigation command 

center; and 

(13) Location of shelter at the facility as 

an alternative to evacuation. 

1.3.5.2 One resource that may be helpful 

to owners or operators in preparing this section of the response plan is The Handbook of 

Chemical Hazard Analysis Procedures by the 

Federal Emergency Management Agency 

(FEMA), Department of Transportation 

(DOT), and EPA. The Handbook of Chemical 

Hazard Analysis Procedures is available from: 

FEMA , Publication Office, 500 C. Street, 

S.W., Washington, DC 20472, (202) 646–3484. 

1.3.5.3 As specified in § 112.20(h)(1)(vi), the 

facility owner or operator must reference existing community evacuation plans, as appropriate. 

1.3.6 Qualified Individual’s Duties 

The duties of the designated qualified individual are specified in § 112.20(h)(3)(ix). The 

qualified individual’s duties must be described and be consistent with the minimum 

requirements in § 112.20(h)(3)(ix). In addition, 

the qualified individual must be identified 

with the Facility Information in section 1.2 

of the response plan. 

1.4 Hazard Evaluation 

This section requires the facility owner or 

operator to examine the facility’s operations 

closely and to predict where discharges could 

occur. Hazard evaluation is a widely used industry practice that allows facility owners 

or operators to develop a complete understanding of potential hazards and the re40 CFR Ch. I (7–1–05 Edition) 

sponse actions necessary to address these 

hazards. The Handbook of Chemical Hazard 

Analysis Procedures, prepared by the EPA, 

DOT, and the FEMA and the Hazardous Materials Emergency Planning Guide (NRT–1), prepared by the National Response Team are 

good references for conducting a hazard analysis. Hazard identification and evaluation 

will assist facility owners or operators in 

planning for potential discharges, thereby 

reducing the severity of discharge impacts 

that may occur in the future. The evaluation 

also may help the operator identify and correct potential sources of discharges. In addition, special hazards to workers and emergency response personnel’s health and safety 

shall be evaluated, as well as the facility’s 

oil spill history. 

1.4.1 Hazard Identification 

The Tank and Surface Impoundment (SI) 

forms, or their equivalent, that are part of 

this section must be completed according to 

the directions below. (‘‘Surface Impoundment’’ means a facility or part of a facility 

which is a natural topographic depression, 

man-made excavation, or diked area formed 

primarily of earthen materials (although it 

may be lined with man-made materials), 

which is designed to hold an accumulation of 

liquid wastes or wastes containing free liquids, and which is not an injection well or a 

seepage facility.) Similar worksheets, or 

their equivalent, must be developed for any 

other type of storage containers. 

(1) List each tank at the facility with a 

separate and distinct identifier. Begin aboveground tank identifiers with an ‘‘A’’ and belowground tank identifiers with a ‘‘B’’, or 

submit multiple sheets with the aboveground 

tanks and belowground tanks on separate 

sheets. 

(2) Use gallons for the maximum capacity 

of a tank; and use square feet for the area. 

(3) Using the appropriate identifiers and 

the following instructions, fill in the appropriate forms: 

(a) Tank or SI number—Using the aforementioned identifiers (A or B) or multiple 

reporting sheets, identify each tank or SI at 

the facility that stores oil or hazardous materials. 

(b) Substance Stored—For each tank or SI 

identified, record the material that is stored 

therein. If the tank or SI is used to store 

more than one material, list all of the stored 

materials. 

(c) Quantity Stored—For each material 

stored in each tank or SI, report the average 

volume of material stored on any given day. 

(d) Tank Type or Surface Area/Year—For 

each tank, report the type of tank (e.g., 

floating top), and the year the tank was 

originally installed. If the tank has been refabricated, the year that the latest refabrication was completed must be recorded in parentheses next to the year installed. For 

94 
 

Environmental Protection Agency 

each SI, record the surface area of the impoundment and the year it went into service. 

(e) Maximum Capacity—Record the operational maximum capacity for each tank and 

SI. If the maximum capacity varies with the 

season, record the upper and lower limits. 

(f) Failure/Cause—Record the cause and 

date of any tank or SI failure which has resulted in a loss of tank or SI contents. 

(4) Using the numbers from the tank and 

SI forms, label a schematic drawing of the 

facility. This drawing shall be identical to 

any schematic drawings included in the 

SPCC Plan. 

(5) Using knowledge of the facility and its 

operations, describe the following in writing: 

(a) The loading and unloading of transportation vehicles that risk the discharge of oil 

or release of hazardous substances during 

transport processes. These operations may 

include loading and unloading of trucks, 

railroad cars, or vessels. Estimate the volume of material involved in transfer operPt. 112, App. F 

ations, if the exact volume cannot be determined. 

(b) Day-to-day operations that may 

present a risk of discharging oil or releasing 

a hazardous substance. These activities include scheduled venting, piping repair or replacement, valve maintenance, transfer of 

tank contents from one tank to another, etc. 

(not including transportation-related activities). Estimate the volume of material involved in these operations, if the exact volume cannot be determined. 

(c) The secondary containment volume associated with each tank and/or transfer point 

at the facility. The numbering scheme developed on the tables, or an equivalent system, 

must be used to identify each containment 

area. Capacities must be listed for each individual unit (tanks, slumps, drainage traps, 

and ponds), as well as the facility total. 

(d) Normal daily throughput for the facility and any effect on potential discharge volumes that a negative or positive change in 

that throughput may cause. 

HAZARD IDENTIFICATION TANKS 1 

Date of Last Update: llll 

Tank No. 

Substance Stored 

(Oil and Hazardous 

Substance) 

Quantity Stored 

(gallons) Tank Type/Year Maximum Capacity (gallons) Failure/Cause 

1 Tank = any container that stores oil. 

Attach as many sheets as necessary. 

HAZARD IDENTIFICATION SURFACE IMPOUNDMENTS (SIS) 

Date of Last Update: llll 

SI No. Substance Stored Quantity Stored 

(gallons) Surface Area/Year Maximum Capacity (gallons) Failure/Cause 

95 
 
 

Pt. 112, App. F 40 CFR Ch. I (7–1–05 Edition) 

HAZARD IDENTIFICATION SURFACE IMPOUNDMENTS (SIS)—Continued 

Date of Last Update: llll 

SI No. Substance Stored Quantity Stored 

(gallons) Surface Area/Year Maximum Capacity (gallons) Failure/Cause 

Attach as many sheets as necessary. 

1.4.2 Vulnerability Analysis 

The vulnerability analysis shall address 

the potential effects (i.e., to human health, 

property, or the environment) of an oil discharge. Attachment C–III to Appendix C to 

this part provides a method that owners or 

operators shall use to determine appropriate 

distances from the facility to fish and wildlife and sensitive environments. Owners or 

operators can use a comparable formula that 

is considered acceptable by the RA. If a comparable formula is used, documentation of 

the reliability and analytical soundness of 

the formula must be attached to the response plan cover sheet. This analysis must 

be prepared for each facility and, as appropriate, must discuss the vulnerability of: 

(1) Water intakes (drinking, cooling, or 

other); 

(2) Schools; 

(3) Medical facilities; 

(4) Residential areas; 

(5) Businesses; 

(6) Wetlands or other sensitive environments; 2 

(7) Fish and wildlife; 

(8) Lakes and streams; 

(9) Endangered flora and fauna; 

(10) Recreational areas; 

(11) Transportation routes (air, land, and 

water); 

(12) Utilities; and 

(13) Other areas of economic importance 

(e.g., beaches, marinas) including terrestrially sensitive environments, aquatic environments, and unique habitats. 

1.4.3 Analysis of the Potential for an Oil 

Discharge 

Each owner or operator shall analyze the 

probability of a discharge occurring at the 

2 Refer to the DOC/NOAA ‘‘Guidance for 

Facility and Vessel Response Plans: Fish and 

Wildlife and Sensitive Environments’’ (See 

appendix E to this part, section 13, for availability). 

facility. This analysis shall incorporate factors such as oil discharge history, horizontal 

range of a potential discharge, and vulnerability to natural disaster, and shall, as appropriate, incorporate other factors such as 

tank age. This analysis will provide information for developing discharge scenarios for a 

worst case discharge and small and medium 

discharges and aid in the development of 

techniques to reduce the size and frequency 

of discharges. The owner or operator may 

need to research the age of the tanks the oil 

discharge history at the facility. 

1.4.4 Facility Reportable Oil Spill History 

Briefly describe the facility’s reportable 

oil spill 3 history for the entire life of the facility to the extent that such information is 

reasonably identifiable, including: 

(1) Date of discharge(s); 

(2) List of discharge causes; 

(3) Material(s) discharged; 

(4) Amount discharged in gallons; 

(5) Amount of discharge that reached navigable waters, if applicable; 

(6) Effectiveness and capacity of secondary 

containment; 

(7) Clean-up actions taken; 

(8) Steps taken to reduce possibility of recurrence; 

(9) Total oil storage capacity of the tank(s) 

or impoundment(s) from which the material 

discharged; 

(10) Enforcement actions; 

(11) Effectiveness of monitoring equipment; and 

(12) Description(s) of how each oil discharge was detected. 

3 As described in 40 CFR part 110, reportable oil spills are those that: (a) violate applicable water quality standards, or (b) cause 

a film or sheen upon or discoloration of the 

surface of the water or adjoining shorelines 

or cause a sludge or emulsion to be deposited 

beneath the surface of the water or upon adjoining shorelines. 

96 
 

Environmental Protection Agency 

The information solicited in this section 

may be similar to requirements in 40 CFR 

112.4(a). Any duplicate information required 

by § 112.4(a) may be photocopied and inserted. 

1.5 Discharge Scenarios 

In this section, the owner or operator is required to provide a description of the facility’s worst case discharge, as well as a small 

and medium discharge, as appropriate. A 

multi-level planning approach has been chosen because the response actions to a discharge (i.e., necessary response equipment, 

products, and personnel) are dependent on 

the magnitude of the discharge. Planning for 

lesser discharges is necessary because the 

nature of the response may be qualitatively 

different depending on the quantity of the 

discharge. The facility owner or operator 

shall discuss the potential direction of the 

discharge pathway. 

1.5.1 Small and Medium Discharges 

1.5.1.1 To address multi-level planning requirements, the owner or operator must consider types of facility-specific discharge scenarios that may contribute to a small or medium discharge. The scenarios shall account 

for all the operations that take place at the 

facility, including but not limited to: 

(1) Loading and unloading of surface transportation; 

(2) Facility maintenance; 

(3) Facility piping; 

(4) Pumping stations and sumps; 

(5) Oil storage tanks; 

(6) Vehicle refueling; and 

(7) Age and condition of facility and components. 

1.5.1.2 The scenarios shall also consider 

factors that affect the response efforts required by the facility. These include but are 

not limited to: 

(1) Size of the discharge; 

(2) Proximity to downgradient wells, waterways, and drinking water intakes; 

(3) Proximity to fish and wildlife and sensitive environments; 

(4) Likelihood that the discharge will travel offsite (i.e., topography, drainage); 

(5) Location of the material discharged 

(i.e., on a concrete pad or directly on the 

soil); 

(6) Material discharged; 

(7) Weather or aquatic conditions (i.e., 

river flow); 

(8) Available remediation equipment; 

(9) Probability of a chain reaction of failures; and 

(10) Direction of discharge pathway. 

1.5.2 Worst Case Discharge 

1.5.2.1 In this section, the owner or operator must identify the worst case discharge 

volume at the facility. Worksheets for production and non-production facility owners 

Pt. 112, App. F 

or operators to use when calculating worst 

case discharge are presented in Appendix D 

to this part. When planning for the worst 

case discharge response, all of the aforementioned factors listed in the small and medium discharge section of the response plan 

shall be addressed. 

1.5.2.2 For onshore storage facilities and 

production facilities, permanently 

manifolded oil storage tanks are defined as 

tanks that are designed, installed, and/or operated in such a manner that the multiple 

tanks function as one storage unit (i.e., multiple tank volumes are equalized). In this 

section of the response plan, owners or operators must provide evidence that oil storage 

tanks with common piping or piping systems 

are not operated as one unit. If such evidence 

is provided and is acceptable to the RA, the 

worst case discharge volume shall be based 

on the combined oil storage capacity of all 

manifold tanks or the oil storage capacity of 

the largest single oil storage tank within the 

secondary containment area, whichever is 

greater. For permanently manifolded oil 

storage tanks that function as one storage 

unit, the worst case discharge shall be based 

on the combined oil storage capacity of all 

manifolded tanks or the oil storage capacity 

of the largest single tank within a secondary 

containment area, whichever is greater. For 

purposes of the worst case discharge calculation, permanently manifolded oil storage 

tanks that are separated by internal divisions for each tank are considered to be single tanks and individual manifolded tank 

volumes are not combined. 

1.6 Discharge Detection Systems 

In this section, the facility owner or operator shall provide a detailed description of 

the procedures and equipment used to detect 

discharges. A section on discharge detection 

by personnel and a discussion of automated 

discharge detection, if applicable, shall be 

included for both regular operations and 

after hours operations. In addition, the facility owner or operator shall discuss how the 

reliability of any automated system will be 

checked and how frequently the system will 

be inspected. 

1.6.1 Discharge Detection by Personnel 

In this section, facility owners or operators shall describe the procedures and personnel that will detect any discharge of oil 

or release of a hazardous substance. A thorough discussion of facility inspections must 

be included. In addition, a description of initial response actions shall be addressed. This 

section shall reference section 1.3.1 of the response plan for emergency response information. 

97 
 

Pt. 112, App. F 

1.6.2 Automated Discharge Detection 

In this section, facility owners or operators must describe any automated discharge 

detection equipment that the facility has in 

place. This section shall include a discussion 

of overfill alarms, secondary containment 

sensors, etc. A discussion of the plans to 

verify an automated alarm and the actions 

to be taken once verified must also be included. 

1.7 Plan Implementation 

In this section, facility owners or operators must explain in detail how to implement the facility’s emergency response plan 

by describing response actions to be carried 

out under the plan to ensure the safety of 

the facility and to mitigate or prevent discharges described in section 1.5 of the response plan. This section shall include the 

identification of response resources for 

small, medium, and worst case discharges; 

disposal plans; and containment and drainage planning. A list of those personnel who 

would be involved in the cleanup shall be 

identified. Procedures that the facility will 

use, where appropriate or necessary, to update their plan after an oil discharge event 

and the time frame to update the plan must 

be described. 

1.7.1	 Response Resources for Small, Medium, 

and Worst Case Discharages 

1.7.1.1 Once the discharge scenarios have 

been identified in section 1.5 of the response 

plan, the facility owner or operator shall 

identify and describe implementation of the 

response actions. The facility owner or operator shall demonstrate accessibility to the 

proper response personnel and equipment to 

effectively respond to all of the identified 

discharge scenarios. The determination and 

demonstration of adequate response capability are presented in Appendix E to this 

part. In addition, steps to expedite the cleanup of oil discharges must be discussed. At a 

minimum, the following items must be addressed: 

(1) Emergency plans for spill response; 

(2) Additional response training; 

(3) Additional contracted help; 

(4) Access to additional response equipment/experts; and 

(5) Ability to implement the plan including 

response training and practice drills. 

1.7.1.2A recommended form detailing immediate actions follows. 

OIL SPILL RESPONSE—IMMEDIATE ACTIONS 

1. Stop the product flow Act quickly to secure 

pumps, close valves, 

etc. 

40 CFR Ch. I (7–1–05 Edition) 

OIL SPILL RESPONSE—IMMEDIATE ACTIONS— 

Continued 

2. Warn personnel ..........
 
 Enforce safety and security measures. 

3. Shut off ignition Motors, electrical circuits, 

sources. open flames, etc. 

4. Initiate containment .... Around the tank and/or in 

the water with oil 

boom. 

5. Notify NRC .................
 
 1–800–424–8802 


6. Notify OSC 

7. Notify, as appropriate 

Source: FOSS, Oil Spill Response—Emergency Procedures, Revised December 3, 1992. 

1.7.2 Disposal Plans 

1.7.2.1 Facility owners or operators must 

describe how and where the facility intends 

to recover, reuse, decontaminate, or dispose 

of materials after a discharge has taken 

place. The appropriate permits required to 

transport or dispose of recovered materials 

according to local, State, and Federal requirements must be addressed. Materials 

that must be accounted for in the disposal 

plan, as appropriate, include: 

(1) Recovered product; 

(2) Contaminated soil; 

(3) Contaminated equipment and materials, including drums, tank parts, valves, 

and shovels; 

(4) Personnel protective equipment; 

(5) Decontamination solutions; 

(6) Adsorbents; and 

(7) Spent chemicals. 

1.7.2.2 These plans must be prepared in accordance with Federal (e.g., the Resource 

Conservation and Recovery Act [RCRA]), 

State, and local regulations, where applicable. A copy of the disposal plans from the facility’s SPCC Plan may be inserted with this 

section, including any diagrams in those 

plans. 

Material Disposal facility Location RCRA permit/manifest 

1. 

2. 

3. 

4. 

1.7.3 Containment and Drainage Planning 

A proper plan to contain and control a discharge through drainage may limit the 

threat of harm to human health and the environment. This section shall describe how 

to contain and control a discharge through 

drainage, including: 

98 
 

Environmental Protection Agency 

(1) The available volume of containment 

(use the information presented in section 

1.4.1 of the response plan); 

(2) The route of drainage from oil storage 

and transfer areas; 

(3) The construction materials used in 

drainage troughs; 

(4) The type and number of valves and separators used in the drainage system; 

(5) Sump pump capacities; 

(6) The containment capacity of weirs and 

booms that might be used and their location 

(see section 1.3.2 of this appendix); and 

(7) Other cleanup materials. 

In addition, a facility owner or operator 

must meet the inspection and monitoring requirements for drainage contained in 40 CFR 

part 112, subparts A through C. A copy of the 

containment and drainage plans that are required in 40 CFR part 112, subparts A 

through C may be inserted in this section, 

including any diagrams in those plans. 

NOTE: The general permit for stormwater 

drainage may contain additional requirements. 

1.8 Self-Inspection, Drills/Exercises, and 

Response Training 

The owner or operator must develop programs for facility response training and for 

drills/exercises according to the requirements of 40 CFR 112.21. Logs must be kept for 

facility drills/exercises, personnel response 

training, and spill prevention meetings. 

Much of the recordkeeping information required by this section is also contained in 

the SPCC Plan required by 40 CFR 112.3. 

These logs may be included in the facility response plan or kept as an annex to the facility response plan. 

1.8.1 Facility Self-Inspection 

Under 40 CFR 112.7(e), you must include 

the written procedures and records of inspections for each facility in the SPCC Plan. You 

must include the inspection records for each 

container, secondary containment, and item 

of response equipment at the facility. You 

must cross-reference the records of inspecPt. 112, App. F 

tions of each container and secondary containment required by 40 CFR 112.7(e) in the 

facility response plan. The inspection record 

of response equipment is a new requirement 

in this plan. Facility self-inspection requires 

two-steps: (1) a checklist of things to inspect; and (2) a method of recording the actual inspection and its findings. You must 

note the date of each inspection. You must 

keep facility response plan records for five 

years. You must keep SPCC records for three 

years. 

1.8.1.1. Tank Inspection 

The tank inspection checklist presented 

below has been included as guidance during 

inspections and monitoring. Similar requirements exist in 40 CFR part 112, subparts A 

through C. Duplicate information from the 

SPCC Plan may be photocopied and inserted 

in this section. The inspection checklist consists of the following items: 

TANK INSPECTION CHECKLIST 

1. Check tanks for leaks, specifically looking 

for: 

A. drip marks; 

B. discoloration of tanks; 

C. puddles containing spilled or leaked material; 

D. corrosion; 

E. cracks; and 

F. localized dead vegetation. 

2. Check foundation for: 

A. cracks; 

B. discoloration; 

C. puddles containing spilled or leaked material; 

D. settling; 

E. gaps between tank and foundation; and 

F. damage caused by vegetation roots. 

3. Check piping for: 

A. droplets of stored material; 

B. discoloration; 

C. corrosion; 

D. bowing of pipe between supports; 

E.	 evidence of stored material seepage 

from valves or seals; and 

F. localized dead vegetation. 

TANK/SURFACE IMPOUNDMENT INSPECTION LOG 

Inspector Tank or SI# Date Comments 

99 

Pt. 112, App. F 40 CFR Ch. I (7–1–05 Edition) 

TANK/SURFACE IMPOUNDMENT INSPECTION LOG—Continued 

Inspector Tank or SI# Date Comments 

1.8.1.2 Response Equipment Inspection 3. Accessibility (time to access and reUsing the Emergency Response Equipment spond); 

List provided in section 1.3.2 of the response 4. Operational status/condition; 

plan, describe each type of response equip- 5. Actual use/testing (last test date and frement, checking for the following: quency of testing); and 

6. Shelf life (present age, expected replaceResponse Equipment Checklist ment date). 

1. Inventory (item and quantity); Please note any discrepancies between this 

2. Storage location; list and the available response equipment. 

RESPONSE EQUIPMENT INSPECTION LOG 

[Use section 1.3.2 of the response plan as a checklist] 

Inspector Date Comments 

100 
 
 

Environmental Protection Agency 	 Pt. 112, App. F 

RESPONSE EQUIPMENT INSPECTION LOG—Continued 

[Use section 1.3.2 of the response plan as a checklist] 

Inspector Date Comments 

1.8.1.3 Secondary Containment Inspection 

Inspect the secondary containment (as described in sections 1.4.1 and 1.7.2 of the response plan), checking the following: 

Secondary Containment Checklist 

1. Dike or berm system. 

A. Level of precipitation in dike/available 

capacity; 

B. Operational status of drainage valves; 

C. Dike or berm permeability; 

D. Debris; 

E. Erosion; 

F.	 Permeability of the earthen floor of 

diked area; and 

G. Location/status of pipes, inlets, drainage beneath tanks, etc. 

2. Secondary containment 

A. Cracks; 

B. Discoloration; 

C. Presence of spilled or leaked material 

(standing liquid); 

D. Corrosion; and 

E. Valve conditions. 

3. Retention and drainage ponds 

A. Erosion; 

B. Available capacity; 

C. Presence of spilled or leaked material; 

D. Debris; and 

E. Stressed vegetation. 

The tank inspection checklist presented 

below has been included as guidance during 

inspections and monitoring. Similar requirements exist in 40 CFR part 112, subparts A 

through C. Similar requirements exist in 40 

CFR 112.7(e). Duplicate information from the 

SPCC Plan may be photocopied and inserted 

in this section. 

1.8.2 Facility Drills/Exercises 

(A) CWA section 311(j)(5), as amended by 

OPA, requires the response plan to contain a 

description of facility drills/exercises. According to 40 CFR 112.21(c), the facility 

owner or operator shall develop a program of 

facility response drills/exercises, including 

evaluation procedures. Following the PREP 

guidelines (see Appendix E to this part, section 13, for availability) would satisfy a facility’s requirements for drills/exercises 

under this part. Alternately, under § 112.21(c), 

a facility owner or operator may develop a 

program that is not based on the PREP 

guidelines. Such a program is subject to approval by the Regional Administrator based 

on the description of the program provided 

in the response plan. 

(B) The PREP Guidelines specify that the 

facility conduct internal and external drills/ 

exercises. The internal exercises include: 

qualified individual notification drills, spill 

management team tabletop exercises, equipment deployment exercises, and unannounced exercises. External exercises include Area Exercises. Credit for an Area or 

Facility-specific Exercise will be given to 

the facility for an actual response to a discharge in the area if the plan was utilized for 

response to the discharge and the objectives 

of the Exercise were met and were properly 

evaluated, documented, and self-certified. 

(C) Section 112.20(h)(8)(ii) requires the facility owner or operator to provide a description of the drill/exercise program to be carried out under the response plan. Qualified 

Individual Notification Drill and Spill Management Team Tabletop Drill logs shall be 

provided in sections 1.8.2.1 and 1.8.2.2, respectively. These logs may be included in the facility response plan or kept as an annex to 

the facility response plan. See section 1.3.3 of 

this appendix for Equipment Deployment 

Drill Logs. 

101 
 
 

Pt. 112, App. F 

1.8.2.1 Qualified Individual Notification Drill 

Logs 

Qualified Individual Notification Drill Log 

Date: llllllllllllllllllll 

Company: llllllllllllllllll 

Qualified Individual(s): lllllllllll 

Emergency Scenario: llllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Evaluation: lllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Changes to be Implemented: llllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Time Table for Implementation: llllll 

llllllllllllllllllllllll 

1.8.2.2 Spill Management Team Tabletop 

Exercise Logs 

Spill Management Team Tabletop Exercise 

Log 

Date: llllllllllllllllllll 

Company: llllllllllllllllll 

Qualified Individual(s): lllllllllll 

Emergency Scenario: llllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Evaluation: lllllllllllllllll 

40 CFR Ch. I (7–1–05 Edition) 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Changes to be Implemented: llllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

Time Table for Implementation: llllll 

1.8.3 Response Training 

Section 112.21(a) requires facility owners or 

operators to develop programs for facility response training. Facility owners or operators 

are required by § 112.20(h)(8)(iii) to provide a 

description of the response training program 

to be carried out under the response plan. A 

facility’s training program can be based on 

the USCG’s Training Elements for Oil Spill 

Response, to the extent applicable to facility 

operations, or another response training program acceptable to the RA. The training elements are available from the USCG Office of 

Response (G-MOR) at (202) 267–0518 or fax 

(202) 267–4085. Personnel response training 

logs and discharge prevention meeting logs 

shall be included in sections 1.8.3.1 and 1.8.3.2 

of the response plan respectively. These logs 

may be included in the facility response plan 

or kept as an annex to the facility response 

plan. 

1.8.3.1 Personnel Response Training Logs 

PERSONNEL RESPONSE TRAINING LOG 

Name Response training/date and number of 

hours 

Prevention training/date and number of 

hours 

1.8.3.2 Discharge Prevention Meetings Logs 

DISCHARGE PREVENTION MEETING LOG 

Date: llllllllllllllllllll 

Attendees: llllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

102 

Environmental Protection Agency 	 Pt. 112, App. F 

Subject/issue identified Required action Implementation date 

1.9 Diagrams 

The facility-specific response plan shall include the following diagrams. Additional diagrams that would aid in the development of 

response plan sections may also be included. 

(1) The Site Plan Diagram shall, as appropriate, include and identify: 

(A) the entire facility to scale; 

(B) above and below ground bulk oil storage tanks; 

(C) the contents and capacities of bulk oil 

storage tanks; 

(D) the contents and capacity of drum oil 

storage areas; 

(E) the contents and capacities of surface 

impoundments; 

(F) process buildings; 

(G) transfer areas; 

(H) secondary containment systems (location and capacity); 

(I) structures where hazardous materials 

are stored or handled, including materials stored and capacity of storage; 

(J) location of communication and emergency response equipment; 

(K) location of electrical equipment which 

contains oil; and 

(L)	 for complexes only, the interface(s) 

(i.e., valve or component) between the 

portion of the facility regulated by EPA 

and the portion(s) regulated by other 

Agencies. In most cases, this interface is 

defined as the last valve inside secondary 

containment before piping leaves the secondary containment area to connect to 

the transportation-related portion of the 

facility (i.e., the structure used or intended to be used to transfer oil to or 

from a vessel or pipeline). In the absence 

of secondary containment, this interface 

is the valve manifold adjacent to the 

tank nearest the transfer structure as described above. The interface may be defined differently at a specific facility if 

agreed to by the RA and the appropriate 

Federal official. 

(2) The Site Drainage Plan Diagram shall, as 

appropriate, include: 

(A) major sanitary and storm sewers, manholes, and drains; 

(B) weirs and shut-off valves; 

(C) surface water receiving streams; 

(D) fire fighting water sources; 

(E) other utilities; 

(F) response personnel ingress and egress; 

(G) response equipment transportation 

routes; and 

(H) direction of discharge flow from dis-


charge points. 


(3) The Site Evacuation Plan Diagram shall, 

as appropriate, include: 

(A)	 site plan diagram with evacuation 

route(s); and 

(B) location of evacuation regrouping 

areas. 

1.10 Security 

According to 40 CFR 112.7(g) facilities are 

required to maintain a certain level of security, as appropriate. In this section, a description of the facility security shall be provided and include, as appropriate: 

(1) emergency cut-off locations (automatic 

or manual valves); 

(2) enclosures (e.g., fencing, etc.); 
 

(3) guards and their duties, day and night; 
 

(4) lighting; 
 

(5) valve and pump locks; and 
 

(6) pipeline connection caps. 
 

The SPCC Plan contains similar informa-


tion. Duplicate information may be 
 


photocopied and inserted in this section. 
 


2.0 Response Plan Cover Sheet 

A three-page form has been developed to be 

completed and submitted to the RA by owners or operators who are required to prepare 

and submit a facility-specific response plan. 

The cover sheet (Attachment F–1) must accompany the response plan to provide the 

Agency with basic information concerning 

the facility. This section will describe the 

Response Plan Cover Sheet and provide instructions for its completion. 

2.1 General Information 

Owner/Operator of Facility: Enter the name 

of the owner of the facility (if the owner is 

the operator). Enter the operator of the facility if otherwise. If the owner/operator of 

103 
 
 

Pt. 112, App. F 

the facility is a corporation, enter the name 

of the facility’s principal corporate executive. Enter as much of the name as will fit in 

each section. 

(1) Facility Name: Enter the proper name of 

the facility. 

(2) Facility Address: Enter the street address, city, State, and zip code. 

(3) Facility Phone Number: Enter the phone 

number of the facility. 

(4) Latitude and Longitude: Enter the facility latitude and longitude in degrees, minutes, and seconds. 

(5) Dun and Bradstreet Number: Enter the 

facility’s Dun and Bradstreet number if 

available (this information may be obtained 

from public library resources). 

(6) North American Industrial Classification System (NAICS) Code: Enter the facility’s NAICS code as determined by the Office 

of Management and Budget (this information 

may be obtained from public library resources.) 

(7) Largest Oil Storage Tank Capacity: Enter 

the capacity in GALLONS of the largest 

aboveground oil storage tank at the facility. 

(8) Maximum Oil Storage Capacity: Enter the 

total maximum capacity in GALLONS of all 

aboveground oil storage tanks at the facility. 

(9) Number of Oil Storage Tanks: Enter the 

number of all aboveground oil storage tanks 

at the facility. 

(10) Worst Case Discharge Amount: Using information from the worksheets in Appendix 

D, enter the amount of the worst case discharge in GALLONS. 

(11) Facility Distance to Navigable Waters: 

Mark the appropriate line for the nearest 

distance between an opportunity for discharge (i.e., oil storage tank, piping, or 

flowline) and a navigable water. 

2.2 Applicability of Substantial Harm Criteria 

Using the flowchart provided in Attachment C–I to Appendix C to this part, mark 

the appropriate answer to each question. Explanations of referenced terms can be found 

in Appendix C to this part. If a comparable 

formula to the ones described in Attachment 

C–III to Appendix C to this part is used to 

calculate the planning distance, documentation of the reliability and analytical soundness of the formula must be attached to the 

response plan cover sheet. 

2.3 Certification 

Complete this block after all other questions have been answered. 

3.0 Acronyms 

ACP: Area Contingency Plan 

ASTM: American Society of Testing Materials 

bbls: Barrels 

bpd: Barrels per Day 

40 CFR Ch. I (7–1–05 Edition) 

bph: Barrels per Hour 

CHRIS: Chemical Hazards Response Information System 

CWA: Clean Water Act 

DOI: Department of Interior 

DOC: Department of Commerce 

DOT: Department of Transportation 

EPA: Environmental Protection Agency 

FEMA: Federal Emergency Management 

Agency 

FR: Federal Register 

gal: Gallons 

gpm: Gallons per Minute 

HAZMAT: Hazardous Materials 

LEPC: Local Emergency Planning Committee 

MMS: Minerals Management Service (part of 

DOI) 

NAICS: North American Industrial Classification System 

NCP: National Oil and Hazardous Substances 

Pollution Contingency Plan 

NOAA: National Oceanic and Atmospheric 

Administration (part of DOC) 

NRC: National Response Center 

NRT: National Response Team 

OPA: Oil Pollution Act of 1990 

OSC: On-Scene Coordinator 

PREP: National Preparedness for Response 

Exercise Program 

RA: Regional Administrator 

RCRA: Resource Conservation and Recovery 

Act 

RRC: Regional Response Centers 

RRT: Regional Response Team 

RSPA: Research and Special Programs Administration 

SARA: Superfund Amendments and Reauthorization Act 

SERC: State Emergency Response Commission 

SDWA: Safe Drinking Water Act of 1986 

SI: Surface Impoundment 

SPCC: Spill Prevention, Control, and Countermeasures 

USCG: United States Coast Guard 

4.0 References 

CONCAWE. 1982. Methodologies for Hazard 

Analysis and Risk Assessment in the Petroleum Refining and Storage Industry. Prepared by CONCAWE’s Risk Assessment Adhoc Group. 

U.S. Department of Housing and Urban Development. 1987. Siting of HUD-Assisted 

Projects Near Hazardous Facilities: Acceptable Separation Distances from Explosive 

and Flammable Hazards. Prepared by the Office of Environment and Energy, Environmental Planning Division, Department of 

Housing and Urban Development. Washington, DC. 

U.S. DOT, FEMA and U.S. EPA. Handbook 

of Chemical Hazard Analysis Procedures. 

U.S. DOT, FEMA and U.S. EPA. Technical 

Guidance for Hazards Analysis: Emergency 

104 
 
 

Environmental Protection Agency 

Planning for Extremely Hazardous Substances. 

The National Response Team. 1987. Hazardous Materials Emergency Planning 

Guide. Washington, DC. 

The National Response Team. 1990. Oil 

Spill Contingency Planning, National Status: A Report to the President. Washington, 

DC. U.S. Government Printing Office. 

Offshore Inspection and Enforcement Division. 1988. Minerals Management Service, 

Offshore Inspection Program: National Potential Incident of Noncompliance (PINC) 

List. Reston, VA. 

ATTACHMENTS TO APPENDIX F 

Attachment F–1—Response Plan Cover Sheet 

This cover sheet will provide EPA with 

basic information concerning the facility. It 

must accompany a submitted facility response plan. Explanations and detailed instructions can be found in Appendix F. 

Please type or write legibly in blue or black 

ink. Public reporting burden for the collection of this information is estimated to vary 

from 1 hour to 270 hours per response in the 

first year, with an average of 5 hours per response. This estimate includes time for reviewing instructions, searching existing data 

sources, gathering the data needed, and completing and reviewing the collection of information. Send comments regarding the burden estimate of this information, including 

suggestions for reducing this burden to: 

Chief, Information Policy Branch, Mail Code: 

PM–2822, U.S. Environmental Protection 

Agency, Ariel Rios Building, 1200 Pennsylvania Avenue, NW., Washington, DC 20460; 

and to the Office of Information and Regulatory Affairs, Office of Management and 

Budget, Washington D.C. 20503. 

GENERAL INFORMATION 

Owner/Operator of Facility: 

llllllllllllllllllllllll 

Facility Name: lllllllllllllll 

Facility Address (street address or route): 

llllllllllllllllllllllll 

llllllllllllllllllllllll 

City, State, and U.S. Zip Code: 

llllllllllllllllllllllll 

Facility Phone No.: lllllllllllll 

Latitude (Degrees: North): 

llllllllllllllllllllllll 

degrees, minutes, seconds 

Dun & Bradstreet Number: 1 

llllllllllllllllllllllll 

Largest Aboveground Oil Storage Tank Capacity (Gallons): 

llllllllllllllllllllllll 

1 These numbers may be obtained from public library resources. 

Pt. 112, App. F 

Number of Aboveground Oil Storage Tanks: 

llllllllllllllllllllllll 

Longitude (Degrees: West): 

llllllllllllllllllllllll 

degrees, minutes, seconds llllllllll 

North American Industrial Classification 

System (NAICS) Code: 1 llllllllll 

llllllllllllllllllllllll 

Maximum Oil Storage Capacity (Gallons): l 

Worst Case Oil Discharge Amount (Gallons): 

Facility Distance to Navigable Water. Mark 

the appropriate line. lllllllllll 

0– 1⁄4 mile ll 1⁄4–1⁄2 mile ll 1⁄2–1 mile ll >1 

mile ll 

APPLICABILITY OF SUBSTANTIAL HARM 

CRITERIA 

Does the facility transfer oil over-water 2 

to or from vessels and does the facility have 

a total oil storage capacity greater than or 

equal to 42,000 gallons? 

Yes lllllllllllllllllllll 

No llllllllllllllllllllll 

Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and, within any storage area, does 

the facility lack secondary containment 2 

that is sufficiently large to contain the capacity of the largest aboveground oil storage 

tank plus sufficient freeboard to allow for 

precipitation? 

Yes lllllllllllllllllllll 

No llllllllllllllllllllll 

Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and is the facility located at a distance 2 (as calculated using the appropriate 

formula in Appendix C or a comparable formula) such that a discharge from the facility 

could cause injury to fish and wildlife and 

sensitive environments? 3 

Yes lllllllllllllllllllll 

No llllllllllllllllllllll 

Does the facility have a total oil storage capacity greater than or equal to 1 million 

2 Explanations of the above-referenced 

terms can be found in Appendix C to this 

part. If a comparable formula to the ones 

contained in Attachment C–III is used to establish the appropriate distance to fish and 

wildlife and sensitive environments or public 

drinking water intakes, documentation of 

the reliability and analytical soundness of 

the formula must be attached to this form. 3 For further description of fish and wildlife 

and sensitive environments, see Appendices 

I, II, and III to DOC/NOAA’s ‘‘Guidance for 

Facility and Vessel Response Plans: Fish and 

Wildlife and Sensitive Environments’’ (see 

Appendix E to this part, section 13, for availability) and the applicable ACP. 

105 
 
 

Pt. 113 

gallons and is the facility located at a distance 2 (as calculated using the appropriate 

formula in Appendix C or a comparable formula) such that a discharge from the facility would shut down a public drinking 

water intake? 2 llllllllllllll 

Yes lllllllllllllllllllll 

No llllllllllllllllllllll 

Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and has the facility experienced a reportable oil spill 2 in an amount greater than 

or equal to 10,000 gallons within the last 5 

years? 

Yes lllllllllllllllllllll 

No llllllllllllllllllllll 

CERTIFICATION 

I certify under penalty of law that I have 

personally examined and am familiar with 

the information submitted in this document, 

and that based on my inquiry of those individuals responsible for obtaining information, I believe that the submitted information is true, accurate, and complete. 

Signature: llllllllllllllllll 

Name (Please type or print): llllllll 

llllllllllllllllllllllll 

Title: llllllllllllllllllll 

Date: llllllllllllllllllll 

[59 FR 34122, July 1, 1994; 59 FR 49006, Sept. 

26, 1994, as amended at 65 FR 40816, June 30, 

2000; 65 FR 43840, July 14, 2000; 66 FR 34561, 

June 29, 2001; 67 FR 47152, July 17, 2002] 

PART 113—LIABILITY LIMITS FOR 

SMALL ONSHORE STORAGE 

FACILITIES 

Subpart A—Oil Storage Facilities 

Sec. 
 
 

113.1 Purpose. 
 
 

113.2 Applicability. 
 
 

113.3 Definitions. 
 
 

40 CFR Ch. I (7–1–05 Edition) 

for small onshore oil storage facilities 

with fixed capacity of 1,000 barrels or 

less. 

§ 113.2 Applicability. 

This subpart applies to all onshore 

oil storage facilities with fixed capacity of 1,000 barrels or less. When a discharge to the waters of the United 

States occurs from such facilities and 

when removal of said discharge is performed by the United States Government pursuant to the provisions of subsection 311(c)(1) of the Act, the liability 

of the owner or operator and the facility will be limited to the amounts specified in § 113.4. 

§ 113.3 Definitions. 

As used in this subpart, the following 

terms shall have the meanings indicated below: 

(a) Aboveground storage facility 

means a tank or other container, the 

bottom of which is on a plane not more 

than 6 inches below the surrounding 

surface. 

(b) Act means the Federal Water Pollution Control Act, as amended, 33 

U.S.C. 1151, et seq. 

(c) Barrel means 42 United States gallons at 60 degrees Fahrenheit. 

(d) Belowground storage facility 

means a tank or other container located other than as defined as ‘‘Aboveground’’. 

(e) Discharge includes, but is not limited to any spilling, leaking, pumping, 

pouring, emitting, emptying or dumping. 

(f) Onshore Oil Storage Facility means 

any facility (excluding motor vehicles 

and rolling stock) of any kind located 113.4 Size classes and associated liability 
 
in, on, or under, any land within the limits for fixed onshore oil storage facilities, 1,000 barrels or less capacity. 

113.5 Exclusions. 

113.6 Effect on other laws. 

AUTHORITY: Sec. 311(f)(2), 86 Stat. 867 (33 

U.S.C. 1251 (1972)). 

SOURCE: 38 FR 25440, Sept. 13, 1973, unless 

otherwise noted. 

Subpart A—Oil Storage Facilities 

§ 113.1 Purpose. 

This subpart establishes size classifications and associated liability limits 

United States, other than submerged 

land. 

(g) On-Scene Coordinator is the single 

Federal representative designated pursuant to the National Oil and Hazardous Substances Pollution Contingency Plan and identified in approved 

Regional Oil and Hazardous Substances 

Pollution Contingency Plans. 

(h) Oil means oil of any kind or in 

any form, including but not limited to, 

petroleum, fuel oil, sludge, oil refuse, 

and oil mixed with wastes other than 

dredged spoil. 

106 
 
 
SPCC Guidance for Regional Inspectors 

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U.S. Environmental Protection Agency Version 1.0, 11/28/2005 
Appendix C: Summary of Revised Rule Provisions 

APPENDIX UMMARY OF REVISED ULE PROVISIONS
 

Citation 

containers or 42,000 gallons in completely buried tanks must prepare a Plan. Note: 

§112.1(d)(2)(i) 

and (ii) 

Change from 1974 rule: The single container capacity of 660 gallons for the previous 

threshold requirement has been eliminated. 

Completely buried storage tanks subject to all of the technical requirements under 

40 CFR parts 280 or 281 and permanently closed USTs are not required to comply 

with SPCC provisions. 

§112.1(d)(2)(i) and 

(USTs) 

§112.1(d)(4). 

112.1(d)(4) Change from 1974 rule:

once the facility met any of the SPCC threshold requirements. 

A de minimis container capacity of 55 gallons or more has been established to 

ith a capacity of less than 

§112.1(d)(5) 

Size 

Change from 1974 rule:

to be subject to SPCC provisions. 

the rule. 

§112.1(d)(6) 

Change from 1974 rule: No direct counterpart in the 1974 rule. 

SPCC Plan The Regional Administrator (RA) has the authority to require a facility, regardless of

§112.1(f) 

Preparation 

case basis. 

Change from 1974 rule: No direct counterpart in the 1974 rule. 

Definitions for the terms “alteration,” “breakout tank,” “bulk storage container,” 

§112.2 “bunkered tank,” “completely buried tank,” “contiguous zone,” “facility,” “partially buried 

tank,” “permanently closed,” “production facility,” “repair,” “SPCC Plan,” “storage 

Change from 1974 rule:

described as a discharge as described in 112.1(b) 

described in 40 CFR part 110. 

C: S SPCC R

Revised Rule Provision 

New Threshold An owner or operator of a facility that stores more than 1,320 gallons in aboveground 

Requirement 

Completely buried USTs subject to all to the technical requirements of 40 CFR parts 

280 or 281 are exempt from the threshold calculation. 

Underground 

Storage Tanks 

Note: The facility diagram must include completely buried tanks 

that are exempt from 

 Previously, all USTs were subject to the SPCC provisions 

Minimum Container 

determine aboveground storage capacity. All containers w

55 gallons are exempt from the rule. 

 Previously all containers, regardless of size, were considered 

Wastewater A facility or part thereof, if used exclusively for wastewater treatment, is exempt from 

Treatment Note: The production, recovery, or recycling of oil is not considered 

wastewater treatment. 

exemptions, to prepare an SPCC Plan. This authority will be exercised on a case-byNew Definitions 

capacity,” and “wetlands” were added. 

 The definition for “spill event” was removed but is now 

Note: A “harmful discharge” is 

U.S. Environmental Protection Agency C-1 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

Citation 
 

Oil-Filled Equipment 
 Oil-filled electrical, operating, and manufacturing equipment does not need to meet the 

§112.2 

meet other provisions of the rule, including secondary containment as described in 

§112.7(c). 

Change from 1974 rule: Clarification on the application of the rule to this type of 

equipment. 

Professional 

) 

Certification 

§112.3(d) 

In order for a facility to comply with the provisions of §112.3(d), a licensed Professional 

Engineer (PE) must attest to the following: 

i. The PE is familiar with 40 CFR part 112; 

ii. 

iii. The Plan has been prepared in accordance with good engineering practice, 

including consideration of industry standards and the requirements of the rule; 

iv. Procedures for required inspections and testing have been established; and 

v. The Plan is adequate for the facility. 

Change from 1974 rule: The previous rule required a PE to attest that, through the 

i 

prepared in accordance with good engineering practice. 

Plan Location 

§112.3(e)(1) facility is normally attended at least four hours per day. 

Change from 1974 rule: The rule previously required a Plan to be located at the 

Discharge 

Notification to EPA 

Regional 

) 

Whenever a facility has a discharge as described in §112.1(b) that is greater than 

within any 12-month period, the facility must submit certain information regarding the 

spill to the RA. The SPCC Plan does not need to be submitted unless requested by the 

RA. 

for SPCC facilities 

§112.4 

Change from 1974 rule: 

reporting. 

reportable to the National Response Center) did not change. 

Documentation 

§112.5(b) and 

112.5(c) 

ill be amended. Note: The 

review and evaluation do not require a Professional Engineer (PE) certification. 

However, any technical changes to the Plan do require a PE certification. 

Change from 1974 rule: 

§112.7 

plan that includes all applicable SPCC requirements with a cross-reference. 

Change from 1974 rule: No direct counterpart for alternative plan formats in the 1974 

rule. 

requirements for bulk storage containers (§112.8) as this equipment is excluded from 

the definition of a “bulk storage container.” However, this equipment does need to 

Revised Rule Provision 

Engineer (PE 

The PE or his agent has visited and examined the facility; 

examination of the facility and familiarity w th the provisions of the rule, the Plan was 

The owner or operator must maintain a complete copy of the Plan at the facility if the 

facility if it was attended for at least eight hours per day. 

Reportable 

Administrator (RA 

1,000 gallons of oil or two discharges each of more than 42 gallons of oil occurring 

 Previously, the SPCC Plan was submitted to the RA as part 

of the reporting requirement, and there was a different threshold for SPCC spill 

Note: The basic oil discharge reporting requirements for 40 CFR 110 (spills 

Five-Year Review The period in which an owner or operator is required to review and evaluate the SPCC 

Plan is now five years. The review and evaluation must be documented, and a 

statement must be signed stating whether or not the Plan w

 The review period was previously three years. 

Alternative Formats The Plan must be in writing, and if the Plan does not follow the sequence specified in 

the rule, an equivalent plan and a cross-reference must be provided. For example, the 

owner/operator may use an Integrated Contingency Plan (ICP) or an equivalent state 

U.S. Environmental Protection Agency C-2 Version 1.0, 11/28/2005 
Appendix C: Summary of Revised Rule Provisions 

Citation Revised Rule Provision 

Spill history does not need to be reported. Note: Facility Response Plans (FRPs) are 

Previously 

Spill History 

still required to include a spill history. 

§112.7(a) Change from 1974 rule: The previous rule required a spill history for reportable 

discharges, including corrective actions and preventive measures for spills occurring 

before the effective date of the 1974 rule. This requirement has been eliminated in the 

2002 rule. 

Environmental Where a facility does not conform with SPCC provisions, the owner or operator must 

state the reason for nonconformance and describe, in detail, alternate methods to 

§112.7(a)(2) 

Equivalence 

achieve equivalent environmental protection. Note: This waiver does not apply to any 

secondary containment requirements. 

Change from 1974 rule: No direct counterpart in the 1974 rule. 

The facility is required to prepare a facility diagram that includes the location and 

§112.7(a)(3) 

Facility Diagram 

contents of containers, transfer stations, and connecting pipes. The facility diagram 

must also include exempt USTs. 

Change from 1974 rule: No direct counterpart in the 1974 rule. 

Information for Use The owner or operator must provide, in the Plan, information and procedures relating 

to basic spill prevention, reporting (contact list with phone numbers), and response. 

§112.7(a)(3) 

in a Discharge 

The specific information is listed in the rule text. Note: This subparagraph applies to all 

facilities. 

Change from 1974 rule: No direct counterpart in the 1974 rule. 

Information for Use Unless the facility has submitted a response plan under §112.20, the owner or operator 

must provide, in the Plan, information and procedures to enable a person reporting a 

§112.7(a)(4) and 

in a Discharge 

discharge to relate the necessary information. The plan must have an organization that 

112.7(a)(5) will make it readily usable in an emergency. The necessary information is listed in the 

rule text. 

Change from 1974 rule: No direct counterpart in the 1974 rule. 

Secondary The entire containment system must be able to contain oil and prevent a discharge

from a primary containment system from escaping the confines of the containment 

§112.7(c) 

Containment 

system before cleanup occurs. 

Change from 1974 rule: The new language clarifies the requirement in the previous 

rule that containment and/or diversionary structures must “prevent discharged oil from 

reaching a navigable water course.” 

Impracticability When it is not practicable to install secondary containment, the owner/operator must 

Claim/Integrity clearly explain why, and for bulk storage containers, conduct both periodic integrity 

testing of the containers and periodic integrity and leak testing of the valves and piping. 

§112.7(d) 

Testing 

Note: Facilities must still prepare an oil spill contingency plan following 40 CFR part 

109 and a have written comm tment of resources to respond to and clean up a i

discharge. 

Change from 1974 rule: The previous rule did not require integrity testing or leak 

testing if an impracticability claim was made for secondary containment for bulk 

storage containers. 

U.S. Environmental Protection Agency C-3 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

Citation Revised Rule Provision 

Business Records 

§§112.7(e) and 

112.8(c)(6) 

Employee Training 

§112.7(f) 

Brittle Fracture 

Evaluation 

§112.7(i) 

Secondary 

Containment 

Onshore facilities 

§112.8(c)(2) 

Onshore production 

facilities 

§112.9(c)(2) 

An owner or operator may use usual and customary business records to satisfy the 

recordkeeping requirements for inspections and tests. Written procedures and a 

record of inspections and tests must be maintained for three years. 

Change from 1974 rule: Previously, the rule required maintenance of a record of 

inspections and tests for three years but did not allow for the use of usual and 

customary business records. 

Training is required for oil-handling personnel, and the revised rule supplies additional 

topics for this training. Discharge prevention briefings must be conducted at least once 

a year. 

Change from 1974 rule: The revised rule requires training only for oil-handling 

personnel and not for all employees. It also clarifies that briefings must be conducted 

once a year, instead of intervals “frequent enough to assure adequate understanding 

of the SPCC Plan for that facility.” 

The rule requires evaluations for field-constructed aboveground storage containers 

undergoing repair, alteration, reconstruction, or a change in service. 

Change from 1974 rule: No direct counterpart in the 1974 rule. 

Onshore facilities (including production facilities) must ensure that secondary 

Whatever method used 

must be documented in the Plan. 

Change from 1974 rule: 

containment has sufficient freeboard to allow for precipitation. 

 Onshore facilities were required to provide sufficient 

freeboard to allow for precipitation, though the previous rule did not specify that an 

allowance for precipitation was required for production facilities. 

Integrity Testing per Facilities must test aboveground containers for integrity on a regular schedule, and 

Industry Standards whenever material repairs are made. Testing must combine visual inspection with

§112.8(c)(6) another non-destructive shell thickness testing technique. A list of organizations that 

may be helpful in the identification and explanation of industry standards is included in 

the rule preamble. 

Change from 1974 rule: Previously, the rule stated that integrity testing should occur 

periodically and did not require the combination of a visual inspection with another nondestructive shell thickness testing technique. 

Cathodic Protection All buried piping that is installed or replaced on or after August 16, 2002, must have 

§112.8(d)(1) protective wrapping and coating as well as cathodic protection, for all soil conditions. 

Note: A facility can also satisfy the corrosion protection provisions through 40 CFR part 

280 or a state program approved under 40 CFR part 281. 

Change from 1974 rule: The previous rule required cathodic protection for buried 

piping if soil conditions warranted such protection. It did not allow for satisfaction of the 

provision through 40 CFR part 280 or a state program approved under 40 CFR part 

281. 

Reorganization/ Included are new sections for different types of facilities and new subparts for different 

Plain Language types of oils in compliance with Edible Oil Regulatory Reform Act (EORRA.) The rule 

Format has been written in a plain language format to make it clearer and easier to use. 

Requirements for the SPCC Plan are included in §§112.1 through 112.15. 

U.S. Environmental Protection Agency C-4 Version 1.0, 11/28/2005 
Appendix D 

APPENDIX D: SAMPLE BULK STORAGE FACILITY SPCC PLAN
 


U.S. Environmental Protection Agency Version 1.0, 11/28/2005 
DISCLAIMER - APPENDIX D 

The sample Spill Prevention, Control and Countermeasure (SPCC) Plan in Appendix D 

is intended to provide examples and illustrations of how a bulk storage facility could address a 

variety of scenarios in its SPCC Plan. The “facility” is not an actual facility, nor does it represent 

any actual facility or company. Rather, EPA is providing illustrative examples of the type and 

amount of information that is appropriate SPCC Plan language for these hypothetical situations. 

Because the SPCC rule is designed to give each facility owner/operator the flexibility to 

tailor the facility’s SPCC Plan to the facility’s circumstances, this sample SPCC Plan is not a 

template to be adopted by a facility; doing so does not mean that the facility will be in 

compliance with the SPCC rule requirements. Nor is the sample plan a template that must be 

followed in order for the facility to be considered in compliance with the SPCC rule. 

Version 1.0, 11/28/2005 
SPILL PREVENTION, CONTROL, AND COUNTERMEASURE PLAN 

Unified Oil Company 

123 A Street
 
 

Stonefield, Massachusetts 02000
 
 

May 12, 2003
 
 

Prepared by
 
 

Poppins & Associates, Inc.
 
 

Clearwater Falls, Massachusetts, 02210
 
 

Version 1.0, 11/28/2005 
Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

TABLE OF CONTENTS 

Page
 
 

Introduction 1
 
 

Part 1: Plan Administration
 

1.1 Management Approval and Designated Person 3
 
 

1.2 Professional Engineer Certification 3
 
 

1.3 Location of SPCC Plan 4
 
 

1.4 Plan Review 4
 
 

1.5 Facilities, Procedures, Methods, or Equipment Not Yet Fully Operational 5
 
 

1.6 Cross-Reference with SPCC Provisions 5
 
 

Part 2: General Facility Information 

2.1 Facility Description 8
 
 

2.2 Evaluation of Discharge Potential 11
 
 

Part 3: Discharge Prevention – General SPCC Provisions 

3.1 Compliance with Applicable Requirements 12
 
 

3.2 Facility Layout Diagram 12
 
 

3.3 Spill Reporting 12
 
 

3.4 Potential Discharge Volumes and Direction of Flow 13
 
 

3.5 Containment and Diversionary Structures 14
 
 

3.6 Practicability of Secondary Containment 16
 
 

3.7 Inspections, Tests, and Records 16
 
 

3.8 Personnel, Training, and Discharge Prevention Procedures 18
 
 

3.9 Security 19
 
 

3.10 Tank Truck Loading/Unloading Rack Requirements 19
 
 

3.11 Brittle Fracture Evaluation 22
 
 

3.12 Conformance with State and Local Applicable Requirements 22
 
 

Part 4: Discharge Prevention – SPCC Provisions for Onshore Facilities 

(Excluding Production Facilities) 

4.1 Facility Drainage 23
 
 

4.2 Bulk Storage Containers 23
 
 

4.3 Transfer Operations, Pumping, and In-Plant Processes 29
 
 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

Part 5: Discharge Response 

5.1 Response to a Minor Discharge 30 

5.2 Response to a Major Discharge 31 

5.3 Waste Disposal 32 

5.4 Discharge Notification 32 

5.5 Cleanup Contractors and Equipment Suppliers 33 

List of Tables 

Table 1-1: Plan Review Log 6 

Table 1-2: SPCC Cross-Reference 7 

Table 2-1: Oil Containers 9 

Table 2-2: Oil Discharge History 10 

Table 3-1: Potential Discharge Volume and Direction of Flow 13 

Table 3-2: Inspection and Testing Program 16 

Table 3-3: Fuel Transfer Procedures 21 

Table 4-1: List of Oil Containers 24 

Table 4-2: Scope and Frequency of Bulk Storage Containers Inspections and Tests 27 

Appendices 

A: Site Plan and Facility Diagram 

B: Substantial Harm Determination 

C: Facility Inspection Checklists 

D: Record of Containment Dike Drainage 

E: Record of Discharge Prevention Briefings and Training 

F: Calculation of Secondary Containment Capacity 

G: Records of Tank Integrity and Pressure Tests 

H: Emergency Contacts 

I: Discharge Notification Form 

J: Discharge Response Equipment Inventory 

K: Agency Notification Standard Report 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

LIST OF ACRONYMS AND ABBREVIATIONS
 
 

AST Aboveground Storage Tank 

EPA U.S. Environmental Protection Agency 

MADEP Massachusetts Department of Environmental Protection 

NPDES National Pollutant Discharge Elimination System 

PE Professional Engineer 

POTW Publicly Owned Treatment Works 

SPCC Spill Prevention, Control, and Countermeasure 

STI Steel Tank Institute 

UST Underground Storage Tank 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

INTRODUCTION 

Purpose 

The purpose of this Spill Prevention, Control, and Countermeasure (SPCC) Plan is to 

describe measures implemented by Unified Oil to prevent oil discharges from occurring, and to 

prepare Unified Oil to respond in a safe, effective, and timely manner to mitigate the impacts of 

a discharge. 

This Plan has been prepared to meet the requirements of Title 40, Code of Federal 

Regulations, Part 112 (40 CFR part 112), and supercedes the earlier Plan developed to meet 

provisions in effect since 1974. 

In addition to fulfilling requirements of 40 CFR part 112, this SPCC Plan is used as a 

reference for oil storage information and testing records, as a tool to communicate practices on 

preventing and responding to discharges with employees, as a guide to facility inspections, and 

as a resource during emergency response. 

Unified Oil management has determined that this facility does not pose a risk of 

substantial harm under 40 CFR part 112, as recorded in the “Substantial Harm Determination” 

included in Appendix B of this Plan. 

This Plan provides guidance on key actions that Unified Oil must perform to comply with 

the SPCC rule: 

‘ Complete monthly and annual site inspections as outlined in the Inspection, 

Tests, and Records section of this Plan (Section 3.7) using the inspection 

checklists included in Appendix C. 

‘ Perform preventive maintenance of equipment, secondary containment systems, 

and discharge prevention systems described in this Plan as needed to keep them 

in proper operating conditions. 

‘ Conduct annual employee training as outlined in the Personnel, Training, and 

Spill Prevention Procedures section of this Plan (Section 3.8) and document 

them on the log included in Appendix E. 

‘ If either of the following occurs, submit the SPCC Plan to the EPA Region 1 

Regional Administrator (RA) and the Massachusetts Department of 

Environmental Protection (MADEP), along with other information as detailed in 

Section 5.4 of this Plan: 

‘ The facility discharges more than 1,000 gallons of oil into or upon the 

navigable waters of the U.S. or adjoining shorelines in a single spill event; 

or 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

‘	 	 The facility discharges oil in quantity greater than 42 gallons in each of 

two spill events within any 12-month period. 

‘	 	 Review the SPCC Plan at least once every five (5) years and amend it to include 

more effective prevention and control technology, if such technology will 

significantly reduce the likelihood of a spill event and has been proven effective 

in the field at the time of the review. Plan amendments, other than administrative 

changes discussed above, must be recertified by a Professional Engineer on the 

certification page in Section 1.2 of this Plan. 

‘	 	 Amend the SPCC Plan within six (6) months whenever where is a change in 

facility design, construction, operation, or maintenance that materially affects the 

facility’s spill potential. The revised Plan must be recertified by a Professional 

Engineer (PE). 

‘	 	 Review the Plan on an annual basis. Update the Plan to reflect any 

“administrative changes” that are applicable, such as personnel changes or 

revisions to contact information, such as phone numbers. Administrative changes 

must be documented in the Plan review log of Section 1.4 of this Plan, but do not 

have to be certified by a PE. 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

Part 1: Plan Administration 

1.1 Management Approval and Designated Person (40 CFR 112.7) 

Unified Oil Company (“Unified Oil’) is committed to preventing discharges of oil to navigable 

waters and the environment, and to maintaining the highest standards for spill prevention 

control and countermeasures through the implementation and regular review and amendment to 

the Plan. This SPCC Plan has the full approval of Unified Oil management. Unified Oil has 

committed the necessary resources to implement the measures described in this Plan. 

The Facility Manager is the Designated Person Accountable for Oil Spill Prevention at the 

facility and has the authority to commit the necessary resources to implement this Plan. 

Authorized Facility Representative (facility response coordinator): Susan Blake 

Signature: 

Title: Facility Manager 

Date: May 12, 2003 

1.2 Professional Engineer Certification (40 CFR 112.3(d)) 

The undersigned Registered Professional Engineer is familiar with the requirements of Part 112 

of Title 40 of the Code of Federal Regulations (40 CFR part 112) and has visited and examined 

the facility, or has supervised examination of the facility by appropriately qualified personnel. 

The undersigned Registered Professional Engineer attests that this Spill Prevention, Control, 

and Countermeasure Plan has been prepared in accordance with good engineering practice, 

including consideration of applicable industry standards and the requirements of 40 CFR part 

112; that procedures for required inspections and testing have been established; and that this 

Plan is adequate for the facility. [40 CFR 112.3(d)] 

This certification in no way relieves the owner or operator of the facility of his/her duty to prepare 

and fully implement this SPCC Plan in accordance with the requirements of 40 CFR part 112. 

This Plan is valid only to the extent that the facility owner or operator maintains, tests, and 

inspects equipment, containment, and other devices as prescribed in this Plan. 

Julie Andrews 90535055, Massachusetts 

Signature Professional Engineer Registration Number 

Julie Andrews Sr. Process Engineer 

Name Title 

Poppins and Associates May 12, 2003 PE Seal 

Company Date MA 

Julie Andrews 

#90535055 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

1.3 Location of SPCC Plan (40 CFR 112.3(e)) 

In accordance with 40 CFR 112.3(e), a complete copy of this SPCC Plan is maintained at the 

facility in the office building. The front office is attended whenever the facility is operating, i.e., 

7:00 AM to 5:00 PM, 6 days per week (closed on Sundays). 

1.4 Plan Review (40 CFR 112.3 and 112.5) 

1.4.1 Changes in Facility Configuration 

In accordance with 40 CFR 112.5(a), Unified Oil periodically reviews and evaluates this SPCC 

Plan for any change in the facility design, construction, operation, or maintenance that 

materially affects the facility’s potential for an oil discharge, including, but not limited to: 

< commissioning of containers; 
 


< reconstruction, replacement, or installation of piping systems; 
 


< construction or demolition that might alter secondary containment structures; or 
 


< changes of product or service, revisions to standard operation, modification of 
 


testing/inspection procedures, and use of new or modified industry standards or 

maintenance procedures. 

Amendments to the Plan made to address changes of this nature are referred to as technical 

amendments, and must be certified by a PE. Non-technical amendments can be done (and 

must be documented in this section) by the facility owner and/or operator. Non-technical 

amendments include the following: 

< change in the name or contact information (i.e., telephone numbers) of 

individuals responsible for the implementation of this Plan; or 

< change in the name or contact information of spill response or cleanup 

contractors. 

Unified Oil must make the needed revisions to the SPCC Plan as soon as possible, but no later 

than six months after the change occurs. The Plan must be implemented as soon as possible 

following any technical amendment, but no later than six months from the date of the 

amendment. The Facility Manager is responsible for initiating and coordinating revisions to the 

SPCC Plan. 

1.4.2 Scheduled Plan Reviews 

In accordance with 40 CFR 112.5(b), Unified Oil reviews this SPCC Plan at least once every 

five years (in the past, such reviews were required every three years). Revisions to the Plan, if 

needed, are made within six months of the five-year review. A registered Professional Engineer 

certifies any technical amendment to the Plan, as described above, in accordance with 40 CFR 

112.3(d). The last SPCC review occurred on May 13, 2001. This Plan is dated May 12, 2003. 

The next plan review is therefore scheduled to take place on or prior to May 12, 2008. 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

1.4.3	 	 Record of Plan Reviews 

Scheduled reviews and Plan amendments are recorded in the Plan Review Log (Table 1-1). 

This log must be completed even if no amendment is made to the Plan as a result of the review. 

Unless a technical or administrative change prompts an earlier review of the Plan, the next 

scheduled review of this Plan must occur by May 12, 2008. 

1.5	 	 Facilities, Procedures, Methods, or Equipment Not Yet Fully 

Operational (40 CFR 112.7) 

Bulk storage containers at this facility have never been tested for integrity since their installation 

in 1989. Section 4.2.6 of this Plan describes the inspection program to be implemented by the 

facility following a regular schedule, including the dates by which each of the bulk storage 

containers must be tested. 

1.6 	 	 Cross-Reference with SPCC Provisions (40 CFR 112.7) 

This SPCC Plan does not follow the exact order presented in 40 CFR part 112. Section 

headings identify, where appropriate, the relevant section(s) of the SPCC rule. Table 1-2 

presents a cross-reference of Plan sections relative to applicable parts of 40 CFR part 112. 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

PE
 

certification
 

By Date required? Comments
 

Mike Davies 5/20/1989 Prepare Plan Yes 

Start of 

Operations 

Mike Davies 5/18/1992 Scheduled No No change. 

review 

Mike Davies 2/18/1994 Plan Yes* Changes to inspection procedures, 

amendment addition of a new tank, full review not 

conducted. 

Susan Blake Scheduled No Change in responsible individual and 

review contact information. 

Susan Blake Scheduled No No change. 

review 

Susan Blake Scheduled No No change. 

review 

Susan Blake Periodic review Yes* Installation of oil/water separator 

due to physical 

change 

Table 1-1: Plan Review Log 

Activity 

Initial SPCC Plan. 

5/15/1995 

5/15/1998 

5/13/2001 

5/12/2003 

* Previous PE certifications of this Plan are summarized below. 

Date Scope PE Name 

Licensing State and 

Registration No. 

2/18/1994 Addition of new tank and changes in 

inspection procedures. 

Chris Ebert 

5/12/2003 Installation of oil/water separator Julie Andrews 

MA, 90117823 

MA, 905350055 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

Table 1-2: SPCC Cross-Reference 

112.3(d) Professional Engineer Certification 3 

112.3(e) Location of SPCC Plan 4 

112.5 4 

Table 1-1 

112.7 3 

112.7 ith SPCC Rule Table 1-2 

112.7(a)(3) 8 

Appendix A 

112.7(a)(4) 5.4 Discharge Notification 32 

Appendix I 

Appendix K 

112.7(a)(5) 32 

112.7(b) 3.4 Potential Discharge Volumes and Direction of Flow 13 

112.7(c) 14 

112.7(d) 16 

112.7(e) 3.7 Inspections, Tests, and Records 

Appendix B 

112.7(f) 18 

112.7(g) 3.9 Security 19 

112.7(h) 3.10 Tank Truck Loading/Unloading 19 

112.7(i) 3.11 Brittle Fracture Evaluation 

112.7(j) 3.12 Conformance wi 

112.8(b) 23 

112.8(c)(1) 4.2.1 Construction 23 

112.8(c)(2) 25 

112.8(c)(3) 4.2.3 Drainage of Diked Areas 26 

Appendix D 

112.8(c)(4) 4.2.4 Corrosion Protection 26 

112.8(c)(5) 26 

112.8(c)(6) 4.2.6 Inspection 26 

Appendix C 

112.8(c)(7) 4.2.7 Heating Coils 27 

112.8(c)(8) 27 

112.8(c)(9) 4.2.9 Effluent Treatment Facilities 28 

112.8(c)(10) 4.2.10 Visible Discharges 28 

112.8(c)(11) 4.2.11 Mobile and Portable Containers 28 

112.8(d) 

112.20(e) Certification of Substantial Harm Determination 

Provision Plan Section Page 

Plan Review 

Management Approval 

Cross-Reference w 

Part 2: General Facility Information 

Appendix A: Site Plan and Facility Diagram 

Part 5: Discharge Response 

3.5 Containment and Diversionary Structures 

3.6 Practicability of Secondary Containment 

16 

3.8 Personnel, Training and Discharge Prevention Procedures 

22 

th Applicable State and Local Requirements 22 

4.1 Facility Drainage 

4.2.2 Secondary Containment 

4.2.5 Partially Buried and Bunkered Storage Tanks 

Appendix B - Facility Inspection Checklists 

4.2.8 Overfill Prevention System 

4.3 Transfer Operations, Pumping and In-Plant Processes 29 

Appendix B 

* Only selected excerpts of relevant rule text are provided. For a complete list of SPCC requirements, refer 

to the full text of 40 CFR part 112. 

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Part 2: General Facility Information 

Name: 	 	 Unified Oil Company 

Address: 	 	 123 A Street 

Stonefield, MA 02000 

(781) 555-5556 

Type: 	 	 Bulk storage distribution facility 

Date of Initial Operations: 	 	 May 20, 1989 

Owner/Operator: 	 	 Blake and Daughters, Inc. 

20 Fairview Road 

Stonefield, MA 02000 

Primary contact: 	 	 Susan Blake, Facility Manager 

Work: (781) 555-5550 

Cell (24 hours): (781) 555-5559 

2.1 Facility Description (40 CFR 112.7(a)(3)) 

2.1.1 Location and Activities 

Unified Oil distributes a variety of petroleum products to primarily commercial customers. The 

facility handles, stores, uses, and distributes petroleum products in the form of gasoline, diesel, 

No. 2 fuel oil, No. 6 fuel oil, and motor oil. Unified Oil receives products by common carrier via 

tanker truck. The products are stored in several aboveground storage tanks (ASTs) and in one 

underground storage tank (UST). They are delivered to customers by Unified Oil trucks or by 

independent contractors. The facility refuels its own two delivery trucks from an underground 

diesel tank connected to a fueling pump. 

Hours of operation are between 7:00 AM and 5:00 PM, 6 days per week. Personnel at the 

facility include a facility manager, a plant operator, two truck drivers, an office administrator, and 

three operations and maintenance personnel. 

The Site Plan and Facility Diagram included in Appendix A of this Plan show the location and 

layout of the facility. The Facility Diagram (Figure A-2) shows the location of oil containers, 

buildings, loading/unloading and transfer areas, and critical spill control structures. 

Unified Oil is located in a primarily commercial area at 123 A Street in Stonefield, 

Massachusetts. The site is comprised of approximately 2 acres of land and is bordered to the 

east by A Street, to the west by Silver Creek, and to the north by ABC Plating Co. 

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The site includes an office building, a maintenance shop, a tanker truck loading rack and 

unloading area, and product storage and handling areas. Petroleum products are stored within 

the main bulk storage area, underground, and inside the maintenance building. 

2.1.2 

metallic USTs. In addition, the facility stores a varying stock of oil drums inside the maintenance 

building. 

The capacities of oil containers present at the site are listed below and are also indicated on the 

facility diagram in Figure A-2. All containers with capacity of 55 gallons or more are included. 

The capacity of the oil/water separator is not included in the total storage capacity for the facility 

since it is used to treat storm water and as a means of secondary containment for areas of the 

facility with potential for an oil discharge outside dikes or berms. 

One of the two trucks is periodically parked overnight while full; the capacity of this truck is 

therefore counted in the total storage capacity for this facility. 

Table 2-1: Oil Containers 

ID Storage capacity Content 

Fixed Storage 

1 20,000 gallons Diesel 

2 20,000 gallons Unleaded regular gasoline 

built-in saddles 

3 20,000 gallons Unleaded premium gasoline 

built-in saddles 

6 No. 2 fuel oil 

7 10,000 gallons No. 6 fuel oil 

1,100 gallons Motor oil 55-gallon storage drums (variable stock; up 

to 20 drums on site at any time) 

Portable storage 

4 500 gallons Gasoline 

Vehicles 

2,000 gallons Fuel oil 

Oil Storage 

Oil storage at the facility consists of seven tanks: four fixed ASTs, one portable tank, and two 

Unified Oil owns two 2,000-gallon transport trucks that are used to deliver product to customers. 

Description 

Aboveground vertical tank 

Aboveground horizontal tank elevated on 

Aboveground horizontal tank elevated on 

1,000 gallons Underground horizontal tank 

Field-constructed aboveground vertical tank 

Double-walled aboveground horizontal tank 

Delivery truck* 

* Note: Unified Oil owns two delivery trucks. Both trucks are used in transportationrelated activities outside the confines of the facility and generally return to the facility 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

empty for parking overnight. One of the two delivery trucks is periodically parked while 

full. This truck is therefore counted in the storage capacity for this facility. The other truck 

is dedicated to scheduled deliveries and returns to the facility empty (except for minor 

residual). If the tanker truck returns to the facility with more than residual product, this 

product will be returned to inventory via the unloading station. If the facility decides to 

use this tanker for overnight storage, then this Plan must be modified to include the 

capacity of the truck and ensure compliance with other rule requirements, including 

secondary containment. 

Total Oil Storage: 74,600 gallons 

Other containers: (1) 1,500-gallon oil/water separator 

Note: The oil/water separator is used treat facility drainage (i.e., 

wastewater) prior to discharge into Silver Creek under state and federal 

wastewater discharge permits. Discharge from the facility includes storm 

water collected from the paved areas outside the loading rack/unloading 

area containment berm and bulk storage containment dike. No external 

oil tanks are associated with the oil/water separator. This equipment is 

used to meet certain secondary containment requirements under 40 CFR 

part 112, as described later in this Plan. Thus, the capacity of the 

oil/water separator is not counted towards the facility total storage 

capacity. 

(1) 5,000-gallon underground horizontal tank (Diesel) – Tank #5 

Note: This underground storage tank is subject to, and meets, all the 

technical requirements of Massachusetts Underground Storage Tank 

Program at 527 CMR 9, as approved under 40 CFR part 281, and is 

therefore not counted in the storage capacity for this facility (exempted 

under 40 CFR 112.1(d)(4). Its location is indicated on the Facility Diagram 

in Appendix A. Note that the other underground storage tank (Tank #6) 

which contains No. 2 fuel oil for heating consumption on the premises of 

the facility is not subject to certain technical requirements under 40 CFR 

part 280 or a program approved under part 281, in particular corrosion 

protection, and is therefore included in the storage capacity for this facility 

(and is SPCC-regulated), as described above. 

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2.2 Evaluation of Discharge Potential 

2.2.1 Distance to Navigable Waters and Adjoining Shorelines and Flow Paths 

The facility is located on relatively level terrain. Drainage generally flows in the direction of Silver 

Creek, which runs immediately along the southwest side of the site. Silver Creek flows north to 

the Blackpool River approximately 1.5 miles from the facility. Spill trajectories are indicated on 

the facility diagram. Storm drains are located along A Street at the northeast end of the site. 

They discharge to Silver Creek. 

Approximately three-quarters of the facility’s ground surface area is paved with asphalt. The 

remainder consists of compacted gravel, grass, and low-lying vegetation. 

2.2.2 Discharge History 

Table 2-1 summarizes the facility’s discharge history. 

Table 2-2: Oil Discharge History 

Description of Discharge Recurrence 

On 3/23/2003, a leaking valve 

on a delivery truck discharged 

50 gallons of diesel oil onto the 

ground during a rain event, 

allowing approximately 10 

gallons to enter Silver Creek. 

A boom was placed into Silver 

Creek immediately upon 

discovery. Approximately 35 

gallons of oil were recovered 

from Silver creek and the facility 

ground. 

An oil/water separator was 

installed and the facility 

drainage was designed to flow 

into the separator. 

Corrective Actions Taken 

Plan for Preventing 

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PART 3: Discharge Prevention - General SPCC Provisions 

The following measures are implemented to prevent oil discharges during the handling, use, or 

transfer of oil products at the facility. Oil-handling employees have received training in the 

proper implementation of these measures. 

3.1 Compliance with Applicable Requirements (40 CFR 112.7(a)(2)) 

This facility uses an oil/water separator as part of its drainage system to contain oil discharged 

in certain areas of the facility (i.e., overfills, and the loading/unloading area associated with Tank 

#4). Because Tank #4 does not meet the specifications provided in EPA’s memorandum 

concerning its policy on double-walled tanks, general containment must be provided to address 

overfills. The separator provides environmental protection equivalent to the requirements under 

112.8(b)(3) to use ponds, lagoons, or catchment basins to retain oil at the facility in the event of 

an uncontrolled discharge. As described in Section 3.5 of this Plan, the operational and 

emergency oil storage capacity of the oil/water separator is sufficient to handle the quantity of 

oil expected to be discharged in undiked areas from tank overfills or transfer operations. 

Non-destructive integrity evaluation is not performed on Tank #4 (500-gallon portable storage 

tank) or the 55-gallon storage drums. Tank #4 has a double-wall construction and is elevated off 

the ground. The tank is inspected regularly and following a regular schedule in accordance with 

the Steel Tank Institute (STI) SP-001 tank inspection standard as described in this Plan. Any 

leakage from the primary container would be detected through monitoring of the interstitial 

space performed on a monthly basis. Any leakage from the secondary shell would be detected 

visually during scheduled visual inspections by facility personnel. Storage drums are elevated 

on spill pallets and have all sides visible, and any leak would be readily detected by facility 

personnel before they can cause a discharge to navigable waters or adjoining shorelines. 

Corrosion poses minimal risk of failure since drums are single-use and remain on site for a 

relatively short period of time (less than one year). The drum storage area is inspected monthly. 

This is in accordance with accepted industry practice for drum storage and provides an effective 

means of verifying container integrity, as noted by EPA in the preamble to the SPCC rule at 

67 FR 47120. 

3.2 Facility Layout Diagram (40 CFR 112.7(a)(3)) 

Figure A-1 in Appendix A shows the general location of the facility on a U.S. Geological Survey 

topographic map. Figure A-2 in Appendix A presents a layout of the facility and the location of 

storage tanks and drums. The diagram also shows the location of storm water drain inlets and 

the direction of surface water runoff. As required under 40 CFR 112.7(a)(3), the facility diagram 

indicates the location and content of ASTs, USTs, and transfer stations and connecting piping. 

3.3 Spill Reporting (40 CFR 112.7(a)(4)) 

The discharge notification form included in Appendix I will be completed upon immediate 

detection of a discharge and prior to reporting a spill to the proper notification contacts. 

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3.4 

Table 3-1 presents expected volume, discharge rate, general direction of flow in the event of 

equipment failure, and means of secondary containment for different parts of the facility where 

oil is stored, used, or handled. 

Table 3-1: Potential Discharge Volumes and Direction of Flow 

released 

) 

20,000 Gradual to 

instantaneous 

Concrete dike 

1 to 120 60 gal/min Concrete dike 

Pipe failure 20,000 240 gal/min Concrete dike 

Leaking pipe or valve packing 600 1 gal/min Concrete dike 

10,000 1 gal/min Concrete dike 

rollover berm 

1 to 2,000 Gradual to 

instantaneous 

SW to Silver Creek Rollover berm, 

separator 

rollover berm 

1 to 2,000 Gradual to 

instantaneous 

SW to Silver Creek Rollover berm, 

separator 

Hose leak during truck loading 1 to 300 60 gal/min Rollover berm 

connections leak 

1 to 150 30 gal/minute Land-based spill 

response 

separator 

Maintenance Building 

Leak or failure of drum 1 to 55 Gradual to 

instantaneous 

SW to Silver Creek. 

separator 

Complete failure of portable tank 500 Gradual to 

instantaneous 

separator 

1 to 100 3 gal/min 

separator 

Potential Discharge Volumes and Direction of Flow (40 CFR 112.7(b)) 

Potential Event 

Maximum 

volume 

(gallons 

Maximum 

discharge rate Direction of Flow 

Secondary 

Containment 

Bulk Storage Area (Aboveground Storage Tanks #1, 2, 3, or 7) 

Failure of aboveground tank (collapse 

or puncture below product level) 

SW to Silver Creek 

Tank overfill SW to Silver Creek 

SW to Silver Creek 

SW to Silver Creek 

Leaking heating coil (Tank #7) SW to Silver Creek 

Loading Rack/Unloading Area 

Tank truck leak or failure inside the 

on to oil/water 

Tank truck leak or failure outside the 

on to oil/water 

SW to Silver Creek 

Fuel Dispensing Areas 

Tank #4 and diesel dispenser hose/ SW to Silver Creek. 

capability (spill 

kit) and oil/water 

Spill pallets, 

oil/water 

Other Areas 

(Tank #4) 

SW to Silver Creek. Secondary shell, 

oil/water 

Leaking portable tank or overfills 

(Tank #4) 

SW to Silver Creek. Secondary shell, 

oil/water 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

released 

) 

Leak during transfer to heating fuel 1 to 120 60 gal/min 

separator 

1 gal/min 

Potential Event 

Maximum 

volume 

(gallons 

Maximum 

discharge rate Direction of Flow 

Secondary 

Containment 

UST (Tank # 6) 

SW to Silver Creek. Oil/water 

Oil/water separator malfunction 1 to 300 SW to Silver Creek. 

3.5	 	 Containment and Diversionary Structures (40 CFR 112.7(c)) 

Methods of secondary containment at this facility include a combination of structures (e.g., dike, 

berm, built-in secondary containment), drainage systems (e.g., oil/water separator), and landbased spill response (e.g., drain covers, sorbents) to prevent oil from reaching navigable waters 

and adjoining shorelines: 

<	 	 For bulk storage containers (refer to Section 4.2.2 of this Plan): 

<	 	 Dike. A concrete dike enclosure is provided around fixed aboveground 

storage tanks, as described in Section 4.2.2 of this Plan. 

<	 	 Double-wall tank construction. Tank #6 (UST), and the 500-gallon 

portable storage tank (Tank #4) both have double-wall design with a 

secondary shell designed to contain 110 percent of the inner shell 

capacity. The portable tank is generally located near the entrance to the 

maintenance building; however, it may be used elsewhere on site. It is 

used to refuel various small pieces of equipment (each less than 55-

gallon capacity) such as trucks and compressors, that may be deployed 

at different areas on the site. 

<	 	 Spill pallets. Each spill pallet has a capacity of 75 gallons, which can 

effectively contain the volume of any single 55-gallon drum. Drums are 

also stored inside the maintenance building and are not exposed to 

precipitation. The floor of the maintenance building and lower 24 inches of 

the outside walls are constructed of poured concrete that would restrict 

the flow of oil outside the building. The floor has two floor drains; the drain 

closest to the drum storage area is located 18 feet away. Floor drains flow 

into the oil/water separator, which is capable of containing any oil 

discharged from a 55-gallon drum. 

<	 	 At the loading rack and unloading area (refer to Section 3.10 of this Plan): 

<	 	 Rollover berm. The loading rack/unloading area is surrounded by a 4-

inch rollover berm that provides sufficient containment for the largest 

compartment of the tank truck loading or unloading at the facility (2,000 

gallons), and an additional 4 inches of freeboard for precipitation. 

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<	 	 In transfer areas and other parts of the facility where a discharge could occur: 

<	 	 Drip pans. Fill ports for all ASTs are equipped with drip pans to contain 

small leaks from the piping/hose connections. 

<	 	 Sorbent material. Spill cleanup kits that include absorbent material, 

booms, and other portable barriers are located inside the maintenance 

building near the drummed oil storage area and in an outside shed 

located near the loading rack/unloading area, as shown on the Facility 

Diagram in Appendix A. The spill kits are located within close proximity of 

the oil product storage and handling areas for rapid deployment should a 

spill occur. Sorbent material, booms, and other portable barriers are 

stored in the shed next to the loading rack/unloading area to allow for 

quick deployment in the event of a discharge during loading/unloading 

activities or any other accidental discharge outside the dike or loading 

rack/unloading area, such as from tank vehicles entering/leaving the 

facility or spills associated with the fuel dispenser. The response 

equipment inventory for the facility is listed in Appendix J of this Plan. The 

inventory is checked monthly to ensure that used material is replenished. 

<	 	 Drainage system. The facility surface drainage is engineered to direct oil 

that may be discharged outside of engineered containment structures 

such as dikes or berms into the oil/water separator. 

<	 	 Oil/water separator. The oil/water separator is designed to separate and 

retain oil at the facility. The oil/water separator has a total capacity for 

oil/water mixture of 1,500 gallons and a design flow rate of 150 gallons 

per minute. The separator outlet valve can be closed in the event of a 

large discharge (greater than 300 gallons) to provide additional 

emergency containment of up to 1,200 gallons. The maximum amount of 

oil potentially discharged outside the diked or bermed areas is estimated 

at roughly 2,000 gallons (from the complete failure of an on-site tanker 

truck). A spill of this volume outside the diked or bermed areas will be 

primarily contained by deploying sorbent material and other portable spill 

barriers upon discovery of the spill, and additional oil containment 

capacity will be provided by the oil/water separator. The operating oil 

storage capacity is 300 gallons. Best Management Practices are used to 

minimize the amount of solids and oil that flow into the oil/water 

separator. Facility personnel are instructed to avoid and address small 

spills using sorbents to minimize runoff of oil into the oil/water separator. 

The oil/water separator is inspected monthly as part of the scheduled 

inspection to check the level of water within the separator and measure 

the depth of bottom sludges and floating oils. Floating oil is removed by a 

licensed waste collector when it reaches a thickness of 2 inches. 

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3.6 

Unified Oil management has determined that secondary containment is practicable at this 

facility. 

3.7 

As required by the SPCC rule, Unified Oil performs the inspections, tests, and evaluations listed 

in the following table. Table 3-2 summarizes the various types of inspections and tests 

performed at the facility. The inspections and tests are described later in this section, and in the 

respective sections that describe different parts of the facility (e.g., Section 4.2.6 for bulk 

storage containers). 

Table 3-2: Inspection and Testing Program 

Facility 

Component Action Frequency/Circumstances 

Aboveground Test container integrity. Combine Following a regular schedule (monthly, 

container visual inspection with another testing annual, and during scheduled inspections) 

technique (non-destructive shell and whenever material repairs are made. 

testing). Inspect outside of container 

for signs of deterioration and 

discharges. 

Container supports Inspect container’s supports and Following a regular schedule (monthly, 

and foundation foundations. annual, and during scheduled inspections) 

and whenever material repairs are made. 

Liquid level sensing Test for proper operation. Monthly 

devices (overfill) 

Diked area Inspect for signs of deterioration, Monthly 

discharges, or accumulation of oil 

inside diked areas. 

Visually inspect content for presence Prior to draining 

of oil. 

Lowermost drain Prior to filling and departure 

and all outlets of 

tank truck 

Effluent treatment Detect possible system upsets that 

facilities could cause a discharge. 

All aboveground Assess general condition of items, Monthly 

valves, piping, and such as flange joints, expansion 

appurtenances joints, valve glands and bodies, catch 

pans, pipeline supports, locking of 

valves, and metal surfaces. 

Practicability of Secondary Containment (40 CFR 112.7(d)) 

Inspections, Tests, and Records (40 CFR 112.7(e)) 

Visually inspect. 

Daily, monthly 

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Facility 

Component Action Frequency/Circumstances 

Buried metallic Leak test. Annually 

storage tank 

Buried piping Inspect for deterioration. 	 Whenever a section of buried line is 

exposed for any reason. 

Integrity and leak testing. 	 At the time of installation, modification, 

construction, relocation, or replacement. 

3.7.1 Daily Inspection 

A Unified Oil employee performs a complete walk-through of the facility each day. This daily 

visual inspection involves: (1) looking for tank/piping damage or leakage, stained or discolored 

soils, or excessive accumulation of water in diked and bermed areas; (2) observing the effluent 

from the oil/water separator; and (3) verifying that the dike drain valve is securely closed. 

3.7.2 Monthly Inspection 

The checklist provided in Appendix C is used for monthly inspections by Unified Oil personnel. 

The monthly inspections cover the following key elements: 

‘ Observing the exterior of aboveground storage tanks, pipes, and other 

equipment for signs of deterioration, leaks, corrosion, and thinning. 

‘ Observing the exterior of portable containers for signs of deterioration or leaks. 

‘ Observing tank foundations and supports for signs of instability or excessive 

settlement. 

‘ Observing the tank fill and discharge pipes for signs of poor connection that 

could cause a discharge, and tank vent for obstructions and proper operation. 

‘ Verifying the proper functioning of overfill prevention systems. 

‘ Checking the inventory of discharge response equipment and restocking as 

needed. 

‘ Observing the effluent and measuring the quantity of accumulated oil within the 

oil/water separator. 

All problems regarding tanks, piping, containment, or response equipment must immediately be 

reported to the Facility Manager. Visible oil leaks from tank walls, piping, or other components 

must be repaired as soon as possible to prevent a larger spill or a discharge to navigable waters 

or adjoining shorelines. Pooled oil is removed immediately upon discovery. 

Written monthly inspection records are signed by the Facility Manager and maintained with this 

SPCC Plan for a period of three years. 

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3.7.3	 	 Annual Inspection 

Facility personnel perform a more thorough inspection of facility equipment on an annual basis. 

This annual inspection complements the monthly inspection described above and is performed 

in June of each year using the checklist provided in Appendix C of this Plan. 

The annual inspection is preferably performed after a large storm event in order to verify the 

imperviousness and/or proper functioning of drainage control systems such as the dike, rollover 

berm, control valves, and the oil/water separator. 

Written annual inspection records are signed by the Facility Manager and maintained with this 

SPCC Plan for a period of three years. 

3.7.4	 	 Periodic Integrity Testing 

In addition to the above monthly and annual inspections by facility personnel, Tanks #1, 2, 3, 4, 

and 7 are periodically evaluated by an outside certified tank inspector following the Steel Tank 

Institute (STI) Standard for the Inspection of Aboveground Storage Tanks, SP-001, 2005 

version, as described in Section 4.2.6 of this Plan. 

3.8	 	 Personnel, Training, and Discharge Prevention Procedures 

(40 CFR 112.7(f)) 

The Facility Manager is the facility designee and is responsible for oil discharge prevention, 

control, and response preparedness activities at this facility. 

Unified Oil management has instructed oil-handling facility personnel in the operation and 

maintenance of oil pollution prevention equipment, discharge procedure protocols, applicable 

pollution control laws, rules and regulations, general facility operations, and the content of this 

SPCC Plan. Any new facility personnel with oil-handling responsibilities are provided with this 

same training prior to being involved in any oil operation. 

Annual discharge prevention briefings are held by the Facility Manager for all facility personnel 

involved in oil operations. The briefings are aimed at ensuring continued understanding and 

adherence to the discharge prevention procedures presented in the SPCC Plan. The briefings 

also highlight and describe known discharge events or failures, malfunctioning components, and 

recently implemented precautionary measures and best practices. Facility operators and other 

personnel will have the opportunity during the briefings to share recommendations concerning 

health, safety, and environmental issues encountered during facility operations. 

A simulation of an on-site vehicular discharge has been conducted, and future training 

exercises will be periodically held to prepare for possible discharge responses. 

Records of the briefings and discharge prevention training are kept on the form shown in 

Appendix E and maintained with this SPCC Plan for a period of three years. 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

3.9 Security (40 CFR 112.7(g)) 

The facility is surrounded by 8-ft tall steel security fencing. The fence encircles the entire 

footprint of the facility. The single entrance gate is locked when the facility is unattended. 

All drain valves for containment areas are locked in the closed position to prevent unauthorized 

opening. Water draw valves on the 20,000-gallon storage tanks are maintained in the closed 

position to prevent unauthorized opening via locks. Keys for all locked valves are kept in the 

front office. 

Two area lights illuminate the loading/unloading and storage areas. Additional motion-activated 

lights are placed in other areas of the facility. The lights are placed to allow for the discovery of 

discharges and to deter acts of vandalism. 

The electrical starter controls for the oil pumps, including the fuel dispenser, are located in a 

closet inside the maintenance shop. The closet is locked when the pumps are not in use. The 

maintenance shop is locked when the facility is unattended. 

The facility securely caps or blank-flanges the loading/unloading connections of facility piping 

when not in service or when in standby service for an extended period of time, or when piping is 

emptied of liquid content either by draining or by inert gas pressure. 

3.10 Tank Truck Loading/Unloading Rack Requirements (40 CFR 112.7(h)) 

The potential for discharges during tank truck loading and unloading operations is of particular 

concern at this facility. Unified Oil management is committed to ensuring the safe transfer of 

material to and from storage tanks. The following measures are implemented to prevent oil 

discharges during tank truck loading and unloading operations. 

3.10.1 Secondary Containment (40 CFR 112.7(h)(1)) 

The facility has both a loading rack (for loading moderate capacity oil delivery tanker trucks) and 

an unloading area (where product is unloaded from large capacity tanker truck to the facility 

bulk storage tanks). 

The loading rack and unloading area are co-located and are used by outside suppliers making 

deliveries to the facility and to load Unified Oil delivery trucks. 

The tank truck loading rack/unloading area is surrounded with a 4-inch rollover asphalt berm 

that provides secondary containment in the event of a discharge during transfer operations. The 

secondary containment berm is designed to address the more stringent rack containment 

requirements of 40 CFR 112.7(h), which requires that the berm be sufficient to contain the 

capacity of the largest compartment, plus freeboard for precipitation. The curbed area provides 

a catchment capacity of 2,500 gallons, which is capable of containing the largest compartment 

of the petroleum suppliers truck making deliveries at this facility (maximum 2,000 gallons), and 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

is also capable of containing the capacity of Unified Oil’s delivery trucks, which each have a 

total capacity of 2,000 gallons. 

To minimize direct exposure to rain, and facilitate the cleanup of small spills that may occur 

during loading/unloading operations, the area is partially covered by a roof. 

The area is graded to direct the flow of oil or water away from the vehicle, and the low point of 

the curbed area is fitted with a gate valve that is normally kept closed and locked. The key for 

that lock is kept in the main office. The berm is drained by Unified personnel after verifying that 

the retained water is free of oil. The accumulated water is released to the oil/water separator. 

The drain valve is closed and locked following drainage. 

Although delivery trucks are usually empty while at the site for extended periods of time, Unified 

Oil periodically parks one of its two delivery trucks while full overnight. If a delivery truck is 

parked overnight or for an extended period of time while it still contains fuel, it is parked inside 

the loading rack/unloading area containment berm. As discussed above, the berm provides 

sufficient containment capacity for the truck volume, plus sufficient freeboard for 4 inches of 

precipitation. 

3.10.2 Loading/Unloading Procedures (40 CFR 112.7(h)(2) and (3)) 

All suppliers must meet the minimum requirements and regulations for tank truck 

loading/unloading established by the U.S. Department of Transportation. Unified Oil ensures 

that the vendor understands the site layout, knows the protocol for entering the facility and 

unloading product, and has the necessary equipment to respond to a discharge from the vehicle 

or fuel delivery hose. 

The Facility Manager or his/her designee supervises oil deliveries for all new suppliers, and 

periodically observes deliveries for existing, approved suppliers. 

All loading and unloading of tank vehicles takes place only in the designated loading 

rack/unloading area. 

Vehicle filling operations are performed by facility personnel trained in proper discharge 

prevention procedures. The truck driver or facility personnel remain with the vehicle at all times 

while fuel is being transferred. Transfer operations are performed according to the minimum 

procedures outlined in Table 3-3. This table is also posted next to the loading/unloading point. 

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Table 3-3: Fuel Transfer Procedures 

Stage 

Visually check all hoses for leaks and wet spots.
 

Verify that sufficient volume (ullage) is available in the storage tank or truck.
 

Lock in the closed position all drainage valves of the secondary containment
 

structure.
 

Secure the tank vehicle with wheel chocks and interlocks.
 

Ensure that the vehicle’s parking brakes are set.
 

Verify proper alignment of valves and proper functioning of the pumping
 


 

If filling a tank truck, inspect the lowermost drain and all outlets.
 

Establish adequate bonding/grounding prior to connecting to the fuel transfer
 

point.
 

Turn off cell phone.
 

Tasks 

system. 

Prior to ‘
 loading/ ‘
 

unloading ‘
 

‘
 

‘
 

‘
 

‘
 

‘
 

‘

During ‘
 
 

loading/
 
 

unloading ‘
 
 

‘

‘

‘
 

‘
 

‘
 

‘
 

After loading/ ‘ Make sure the transfer operation is completed.
 
 

unloading ‘ Close all tank and loading valves before disconnecting.
 
 

‘ Securely close all vehicle internal, external, and dome cover valves before
 
 

disconnecting.
 

‘ Secure all hatches.
 

‘ Disconnect grounding/bonding wires.
 

‘ Make sure the hoses are drained to remove the remaining oil before moving
 

them away from the connection. Use a drip pan.
 

‘ Cap the end of the hose and other connecting devices before moving them to
 

prevent uncontrolled leakage.
 

‘ Remove wheel chocks and interlocks.
 

‘ Inspect the lowermost drain and all outlets on tank truck prior to departure. If
 

necessary, tighten, adjust, or replace caps, valves, or other equipment to
 

prevent oil leaking while in transit.
 

Driver must stay with the vehicle at all times during loading/unloading
 
 

activities.
 
 

Periodically inspect all systems, hoses and connections.
 
 

When loading, keep internal and external valves on the receiving tank open 
 
 

along with the pressure relief valves.
 
 

When making a connection, shut off the vehicle engine. When transferring 
 
 

Class 3 materials, shut off the vehicle engine unless it is used to operate a
 
 

pump.
 
 

Maintain communication with the pumping and receiving stations.
 
 

Monitor the liquid level in the receiving tank to prevent overflow.
 
 

Monitor flow meters to determine rate of flow.
 
 

When topping off the tank, reduce flow rate to prevent overflow.
 
 

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3.11	 	Brittle Fracture Evaluation (40 CFR 112.7(i)) 

The only field-constructed tank at the facility is Tank #7. All other tanks were shop-built. 

The shell thickness of Tank #7 is less than one-half inch. As discussed in the American 

Petroleum Institute (API) Standard 653 Tank Inspection, Repair, Alteration, and Reconstruction 

(API-653), brittle fracture is not a concern for tanks that have a shell thickness of less than onehalf inch. This is the extent of the brittle fracture evaluation for this tank. 

Nonetheless, in the event that Tank #7 undergoes a repair, alteration, reconstruction, or change 

in service that might affect the risk of a discharge or failure, the container will be evaluated for 

risk of discharge or failure, following API-653 or an equivalent approach, and corrective action 

will be taken as necessary. 

3.12	 	Conformance with State and Local Applicable Requirements (40 CFR 

112.7(j)) 

All bulk storage tanks at this facility are registered with the state and local authorities (Stonefield 

Fire Department) and have current certificates of registration and special use permits required 

by the local fire code. 

Both USTs at the facility (Tanks #5 and 6) meet all requirements of Massachusetts UST 

regulation, including cathodic protection, double-wall construction, and monitoring systems, 

although Tank #6 is not subject to these requirements. 

Treated storm water runoff is discharged to Silver Creek as permitted under NPDES permit 

#MA0001990. The maximum allowable daily oil/grease concentration is 15 mg/L. Grab samples 

are taken each quarter, following the monitoring requirements specified in the NPDES permit. 

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PART 4: Discharge Prevention – SPCC Provisions for 

Onshore Facilities (Excluding Production Facilities) 

4.1 Facility Drainage (40 CFR 112.8(b)) 

Drainage from the concrete dike surrounding tanks 1, 2, and 3 is restrained by a manuallyoperated gate valve to prevent a discharge from entering the facility drainage system. The gate 

valve is normally sealed closed, except when draining the secondary containment structure. The 

content of the secondary containment dike is inspected by facility personnel prior to draining to 

ensure that only oil-free water is allowed to enter the facility storm water drainage system. The 

bypass valve is opened and resealed under direct personnel supervision. Drainage events are 

recorded in the log included in Appendix D to this SPCC Plan. 

Any potential discharge from ASTs will be restrained by secondary containment structures. 

Discharges occurring during loading/unloading operations will be restrained by the rollover 

berm. The facility includes a drainage system and an oil/water separator, which are used to as 

containment for spill sources outside the main berm areas (fuel dispensing, overfills of 500-

gallon AST (Tank#4), and transfers associated with the heating oil tank). The facility is equipped 

with an oil/water separator engineered to retain oil at the facility. This separator provides 

environmental protection equivalent to ponds, lagoons, or catchments basins required under 40 

CFR 112.8(b)(3) and (4), as allowed in 40 CFR 112.7(a)(2). Discharges outside the containment 

areas, such as those occurring in the fuel dispensing area or while unloading heating oil, will 

flow by gravity into the drainage collection area and into the oil/water separator where oil will be 

retained until it can be pumped out. 

4.2 Bulk Storage Containers (40 CFR 112.8(c)) 

Table 4-1 summarizes the construction, volume, and content of bulk storage containers at 

Unified Oil facility. 

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Table 4-1: List of Oil Containers 

Tank Location	 Capacity Content 

Standard) (gallons) 

Containment 

#1 Bulk Storage AST vertical (UL142) 20,000 Diesel 

Area Liquid level 

gauge. 

#2 Bulk Storage AST horizontal (UL142) 20,000 Premium Concrete dike. 

Area unleaded Liquid level 

gasoline gauge. 

#3 Bulk Storage AST horizontal (UL142) 20,000 Regular Concrete dike. 

Area unleaded Liquid level 

gasoline gauge. 

#4 Varies	 AST dual wall, portable 500 Regular Double-wall. 

tank (UL142) unleaded Liquid level gauge 

gasoline	 and interstitial 

monitoring 

#5	 Fuel UST dual wall (STI P3) Diesel 

Dispensing Liquid level 

Area gauge, overfill 

protection system, 

and interstitial 

monitoring. 

#6	 Outside UST dual wall (STI P3) No. 2 Fuel Oil 

Office Liquid level 

Building gauge, overfill 

protection system, 

and interstitial 

monitoring. 

#7 Bulk Storage	 AST vertical (fieldArea	 erected). Heated during
 

winter months (internal
 

coils)
 

10,000 No. 6 Fuel Oil	 

Liquid level 

gauge. 

Inside Steel drums Spill pallets with 

Maintenance used oil built-in 

Building containment 

capacity. Building 

also serves as 

containment since 

floor drains flow 

into oil/water 

separator 

Type (Construction Discharge 

Prevention & 

Concrete dike. 

system. 

5,000 Double-wall. 

1,000 Double-wall. 

Concrete dike. 

55 Motor oil and 

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4.2.1 Construction (40 CFR 112.8(c)(1)) 

All oil tanks used at this facility are constructed of steel, in accordance with industry 

specifications as described above. The design and construction of all bulk storage containers 

are compatible with the characteristics of the oil product they contain, and with temperature and 

pressure conditions. 

Piping between fixed aboveground bulk storage tanks is made of steel and placed aboveground 

on appropriate supports designed to minimize erosion and stress. 

4.2.2 Secondary Containment (40 CFR 112.8(c)(2)) 

A dike is provided around Tanks #1, 2, 3, and 7. Tanks #1, 2, and 3 each have a 20,000-gallon 

capacity. Tank #7 has a 10,000-gallon capacity. The dike has a total containment capacity of 

27,316 gallons to allow sufficient volume for the largest tank and freeboard for precipitation. 

The freeboard is sufficient to contain a 4-inch rainfall corresponding to a 25-year, 24-hour storm 

event for this region of Massachusetts, as documented in Appendix F of this Plan. The floor and 

walls of the containment dike are constructed of poured concrete reinforced with steel. The 

concrete dike was built under the supervision of a structural engineer and in conformance with 

his specifications to be impervious to oil for a period of 72 hours. The facility is unattended for a 

maximum of 40 hours (Saturday evening through Monday morning) and therefore any spill into 

the diked area would be detected before it could escape the diked area. The surface of the 

concrete floor, the inside and outside of the walls, and the interface of the floor and walls, are 

visually inspected during the monthly facility inspection to detect any crack, signs of heaving or 

settlement, or other structural damage that could affect the ability of the dike to contain oil. Any 

damage is promptly corrected to prevent migration of oil into the ground, or out of the dike. 

The 500-gallon portable AST tank is of double-wall construction and provides intrinsic 

secondary containment for 110 percent of the tank capacity. Since the secondary containment 

is not open to precipitation, this volume is sufficient to fully contain the product in the event of a 

leak from the primary container. The interstitial space between the primary and secondary 

containers is inspected on a monthly basis to detect any leak of product from the primary 

container. The container, however, is not equipped to prevent overfills as required by EPA 

policy in its memorandum on double-walled tanks. Therefore, general containment is required 

for potential tank overfills. This containment is accomplished through the facility drainage 

system and the oil/water separator, which provide environmentally equivalent protection as 

described in Section 3.1 of this Plan. 

Both USTs are of double-wall construction and provide intrinsic secondary containment for 

110 percent of the tank capacity. The interstitial space between the primary and secondary 

containers is inspected on a monthly basis to detect any leak of product from the primary 

container. 

The 55-gallon drums are placed on spill pallets inside the maintenance shop. Each spill pallet 

provides 75 gallons of containment capacity, which is more than the required 55 gallons for any 

single drum since the drums are not exposed to precipitation. The floor of the maintenance shop 

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is impervious and sloped to direct any discharge occurring in the building away from doorways 

and towards the drainage system that leads to the facility oil/water separator. 

4.2.3 Drainage of Diked Areas (40 CFR 112.8(c)(3)) 

The concrete dikes are drained under direct supervision of facility personnel. The accumulated 

water is observed for signs of oil prior to draining. The gate valves are normally kept in a closed 

position and locked except when draining the dike. Dike drainage events are recorded on the 

form included in Appendix D of this Plan; records are maintained at the facility for at least three 

years. 

4.2.4 Corrosion Protection (40 CFR 112.8(c)(4)) 

Both metallic underground storage tanks, including Tank #6, which is subject to the 

requirements of 40 CFR part 112, are coated and cathodically protected to prevent corrosion 

and leakage into the ground. Pressure testing is performed on both buried storage tanks every 

two years following the requirements of 40 CFR part 280. The cathodic protection system is 

tested annually to verify its efficacy. 

Cathodic protection is provided for both tanks in accordance with 40 CFR part 280 and meets 

the requirements of 40 CFR part 112. 

Records of pressure tests are kept for at least three years. 

4.2.5 Partially Buried and Bunkered Storage Tanks (40 CFR 112.8(c)(5)) 

This section is not applicable since there are no partially buried or bunkered storage tanks at 

this facility. 

4.2.6 Inspections and Tests (40 CFR 112.8(c)(6)) 

Visual inspections of ASTs by facility personnel are performed according to the procedure 

described in this SPCC Plan. Leaks from tank seams, gaskets, rivets, and bolts are promptly 

corrected. Records of inspections and tests are signed by the inspector and kept at the facility 

for at least three years. 

The scope and schedule of certified inspections and tests performed on the facility’s ASTs are 

specified in STI Standard SP-001. The external inspection includes ultrasonic testing of the 

shell, as specified in the standard, or if recommended by the certified tank inspector to assess 

the integrity of the tank for continued oil storage. 

Records of certified tank inspections are kept at the facility for at least three years. Shell test 

comparison records are retained for the life of the tanks. 

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Table 4-2 summarizes inspections and tests performed on bulk storage containers (“EE” 

indicates that an environmentally equivalent measure is implemented in place of the 

inspection/test, as discussed in Section 3.1 of this Plan). 

Tank ID 

Inspection/Test #1 #2 #3 #4 #5 #6 #7 Drums 

M M M M M M 

personnel (as per checklist of A A A A A A 

Appendix C) 

External inspection by certified 20 yr 20 yr 10 yr EE 10 yr EE 

inspector (as per STI Standard 

SP-001) 

Internal inspection by certified † † 20 yr* 20 yr* 

inspector (as per STI Standard 

SP-001) 

Tank tightness test meeting 2 yr 2 yr 

requirements of 40 CFR 280 

Table 4-2: Scope and Frequency of Bulk Storage Containers Inspections and Tests 

Visual inspection by facility 

EE EE 

Legend: M: Monthly 

A: Annual 

EE: Inspection not required given use of environmentally equivalent measure (refer to 

Section 3.1 of this Plan). 

* Or earlier, as recommended by the certified inspector based on findings from an external 

inspection. 

† Internal inspection may be recommended by the certified inspector based on findings 

from the external inspection. 

The frequency above is based on implementation of a scheduled inspection/testing program. To 

initiate the program, ASTs will be inspected by the following dates: 

< Tank #1: external inspection to be performed by December 31, 2009 

< Tank #2: external inspection to be performed by December 31, 2009 

< Tank #3: external inspection to be performed by December 31, 2006 

< Tank #7: external Inspection to be performed by December 31, 2006 

4.2.7 Heating Coils (40 CFR 112.8(c)(7)) 

Exhaust lines from internal heating coils for Tank #7 drain to the oil/water separator. The 

exhaust lines are monitored for signs of leakage as part of the monthly inspection of the facility. 

4.2.8 Overfill Prevention Systems (40 CFR 112.8(c)(8)) 

All tanks are equipped with a direct-reading level gauge. Additionally, all four fixed ASTs (Tanks 

#1, 2, 3, and 7) are equipped with high level alarms set at 90 percent of the rated capacity. Tank 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

#4 does not have an overfill prevention system. General secondary containment is provided in 

the event of overfills, as described in this Plan. 

Storage drums are not refilled, and therefore overfill prevention systems do not apply. 

Tanks #5 and 6 are equipped with liquid level gauges and overfill protection systems. Liquid 

level sensing devices are tested on a monthly basis during the monthly inspection of the facility, 

following manufacturer recommendations. Venting capacity is suitable for the fill and withdrawal 

rates. 

Facility personnel are present throughout the filling operations to monitor the product level in the 

tanks. 

4.2.9 Effluent Treatment Facilities (40 CFR 112.8(c)(9)) 

The facility’s storm water effluent discharged into Silver Creek is observed and records 

maintained according to the frequency required by NPDES permit MA0000157 (at least once 

per month) to detect possible upsets in the oil/water separator that could lead to a discharge. 

4.2.10 Visible Discharges (40 CFR 112.8(c)(10)) 

Visible discharges from any container or appurtenance – including seams, gaskets, piping, 

pumps, valves, rivets, and bolts – are quickly corrected upon discovery. 

Oil is promptly removed from the diked area and disposed of according to the waste disposal 

method described in Part 5 of this Plan. 

4.2.11 Mobile and Portable Containers (40 CFR 112.8(c)(11)) 

Tank #4 is of double-wall design, which provides for adequate secondary containment in the 

event of leaks in the primary container shell. The interstitial space is monitored monthly for 

signs of leakage. 

Small portable oil storage containers, such as 55-gallon drums, are stored inside the 

maintenance shop where secondary containment is provided by spill pallets and the floor is 

sloped to drain away from the floor drains and door. Any discharged material is quickly 

contained and cleaned up using sorbent pads and appropriate cleaning products. 

Unified Oil delivery trucks generally return to the facility empty or product is returned to 

inventory. Whenever they remain at the facility while full for an extended period of time (such as 

when parking overnight with an emergency load of product), they are positioned in the loading 

rack/unloading area, which provides 2,500 gallons of secondary containment capacity (i.e., 

sufficient for the capacity of the delivery truck (2,000 gallons) and additional freeboard for 4 

inches of precipitation). 

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4.3	 	 Transfer Operations, Pumping, and In-Plant Processes 

(40 CFR 112.8(d)) 

Transfer operations at this facility include: 

< The transfer of oil from the underground fuel oil storage tank to the furnace 

located in the basement of the office building. The oil is pumped from the oil 

storage tank by means of buried steel fuel lines and a suction pump system. 

< The filling of facility delivery trucks using the gasoline dispenser. 

<	 The transfer of oil into or from tanker trucks at the loading rack/unloading area. 

All buried piping at this facility is cathodically protected against corrosion and is provided with a 

protective wrapping and coating. When a section of buried line is exposed, it is carefully 

examined for deterioration. If corrosion damage is found, additional examination and corrective 

action must be taken as deemed appropriate considering the magnitude of the damage. 

Additionally, Unified Oil conducts integrity and leak testing of buried piping at the time of 

installation, modification, construction, relocation, or replacement. Records of all tests are kept 

at the facility for at least three years. 

Lines that are not in service or are on standby for an extended period of time are capped or 

blank-flanged and marked as to their origin. 

All pipe supports are designed to minimize abrasion and corrosion and to allow for expansion 

and contraction. Pipe supports are visually inspected during the monthly inspection of the 

facility. 

All aboveground piping and valves are examined monthly to assess their condition. Inspection 

includes aboveground valves, piping, appurtenances, expansion joints, valve glands and 

bodies, catch pans, pipeline supports, locking of valves, and metal surfaces. Observations are 

noted on the monthly inspection checklist provided in this Plan. 

Warning signs are posted at appropriate locations throughout the facility to prevent vehicles 

from damaging aboveground piping and appurtenances. Most of the aboveground piping is 

located within areas that are not accessible to vehicular traffic (e.g., inside diked area). Brightly 

painted bollards are placed where needed to prevent vehicular collisions with equipment. 

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Part 5: Discharge Response 

This section describes the response and cleanup procedures in the event of an oil discharge. 

The uncontrolled discharge of oil to groundwater, surface water, or soil is prohibited by state 

and possibly federal laws. Immediate action must be taken to control, contain, and recover 

discharged product. 

In general, the following steps are taken: 

< Eliminate potential spark sources; 

< If possible and safe to do so, identify and shut down source of the discharge to 

stop the flow; 

< Contain the discharge with sorbents, berms, fences, trenches, sandbags, or 

other material; 

< Contact the Facility Manager or his/her alternate; 

< Contact regulatory authorities and the response organization; and 

< Collect and dispose of recovered products according to regulation. 

For the purpose of establishing appropriate response procedures, this SPCC Plan classifies 

discharges as either “minor” or “major,” depending on the volume and characteristics of the 

material released. 

A list of Emergency Contacts is provided in Appendix H. The list is also posted at prominent 

locations throughout the facility. A list of discharge response material kept at the facility is 

included in Appendix J. 

5.1 Response to a Minor Discharge 

A “minor” discharge is defined as one that poses no significant harm (or threat) to human health 

and safety or to the environment. Minor discharges are generally those where: 

< The quantity of product discharged is small (e.g., may involve less than 10 

gallons of oil); 

< Discharged material is easily stopped and controlled at the time of the discharge; 

< Discharge is localized near the source; 

< Discharged material is not likely to reach water; 

< There is little risk to human health or safety; and 

< There is little risk of fire or explosion. 

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Minor discharges can usually be cleaned up by Unified Oil personnel. The following guidelines 

apply: 

< Immediately notify the Facility Manager. 

< Under the direction of the Facility Manager, contain the discharge with discharge 

response materials and equipment. Place discharge debris in properly labeled 

waste containers. 

< The Facility Manager will complete the discharge notification form (Appendix I) 

and attach a copy to this SPCC Plan. 

< If the discharge involves more than 10 gallons of oil, the Facility Manager will call 

the Massachusetts Department of Environmental Protection Incident Response 

Division (617-556-1133). 

5.2 Response to a Major Discharge 

A “major” discharge is defined as one that cannot be safely controlled or cleaned up by facility 

personnel, such as when: 

< The discharge is large enough to spread beyond the immediate discharge area;
 
 

< The discharged material enters water;
 
 

< The discharge requires special equipment or training to clean up;
 
 

< The discharged material poses a hazard to human health or safety; or
 
 

< There is a danger of fire or explosion.
 
 

In the event of a major discharge, the following guidelines apply: 

<	 	 All workers must immediately evacuate the discharge site via the designated exit 

routes and move to the designated staging areas at a safe distance from the 

discharge. Exit routes are included on the facility diagram and posted in the 

maintenance building, in the office building, and on the outside wall of the outside 

shed that contains the spill response equipment. 

<	 	 If the Facility Manager is not present at the facility, the senior on-site person 

notifies the Facility Manager of the discharge and has authority to initiate 

notification and response. Certain notifications are dependent on the 

circumstances and type of discharge. For example, if oil reaches a sanitary 

sewer, the publicly owned treatment works (POTW) should be notified 

immediately. A discharge that threatens Silver Creek may require immediate 

notification to downstream users such as the town drinking water plant, which 

has an intake located on Silver Creek. 

<	 	 The Facility Manager (or senior on-site person) must call for medical assistance if 

workers are injured. 

<	 	 The Facility Manager (or senior on-site person) must notify the Fire Department 

or Police Department. 

<	 	 The Facility Manager (or senior on-site person) must call the spill response and 

cleanup contractors listed in the Emergency Contacts list in Appendix H. 

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<	 	 The Facility Manager (or senior on-site person) must immediately contact the 

Massachusetts Department of Environmental Protection Incident Response 

Division (617-556-1133) and the National Response Center (888-424-8802). 

<	 	 The Facility Manager (or senior on-site person) must record the call on the 

Discharge Notification form in Appendix I and attach a copy to this SPCC Plan. 

<	 	 The Facility Manager (or senior on-site person) coordinates cleanup and obtains 

assistance from a cleanup contractor or other response organization as 

necessary. 

If the Facility Manager is not available at the time of the discharge, then the next highest person 

in seniority assumes responsibility for coordinating response activities. 

5.3	 	 Waste Disposal 

Wastes resulting from a minor discharge response will be containerized in impervious bags, 

drums, or buckets. The facility manager will characterize the waste for proper disposal and 

ensure that it is removed from the facility by a licensed waste hauler within two weeks. 

Wastes resulting from a major discharge response will be removed and disposed of by a 

cleanup contractor. 

5.4	 	 Discharge Notification 

Any size discharge (i.e., one that creates a sheen, emulsion, or sludge) that affects or threatens 

to affect navigable waters or adjoining shorelines must be reported immediately to the National 

Response Center (1-800-424-8802). The Center is staffed 24 hours a day. 

A summary sheet is included in Appendix I to facilitate reporting. The person reporting the 

discharge must provide the following information: 

‘ Name, location, organization, and telephone number 

‘ Name and address of the party responsible for the incident 

‘ Date and time of the incident 

‘ Location of the incident 

‘ Source and cause of the release or discharge 

‘ Types of material(s) released or discharged 

‘ Quantity of materials released or discharged 

‘ Danger or threat posed by the release or discharge 

‘ Number and types of injuries (if any) 

‘ Media affected or threatened by the discharge (i.e., water, land, air) 

‘ Weather conditions at the incident location 

‘ Any other information that may help emergency personnel respond to the 

incident 

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Contact information for reporting a discharge to the appropriate authorities is listed in Appendix 

H and is also posted in prominent locations throughout the facility (e.g., in the office building, in 

the maintenance building, and at the loading rack/unloading area). 

In addition to the above reporting, 40 CFR 112.4 requires that information be submitted to the 

United States Environmental Protection Agency (EPA) Regional Administrator and the 

appropriate state agency in charge of oil pollution control activities (see contact information in 

Appendix H) whenever the facility discharges (as defined in 40 CFR 112.1(b)) more than 1,000 

gallons of oil in a single event, or discharges (as defined in 40 CFR 112.1(b)) more than 42 

gallons of oil in each of two discharge incidents within a 12-month period. The following 

information must be submitted to the EPA Regional Administrator and to MADEP within 60 

days: 

< Name of the facility; 

< Name of the owner/operator; 

< Location of the facility; 

< Maximum storage or handling capacity and normal daily throughput; 

< Corrective action and countermeasures taken, including a description of 

equipment repairs and replacements; 

< Description of facility, including maps, flow diagrams, and topographical maps; 

< Cause of the discharge(s) to navigable waters and adjoining shorelines, including 

a failure analysis of the system and subsystem in which the failure occurred; 

< Additional preventive measures taken or contemplated to minimize possibility of 

recurrence; and 

< Other pertinent information requested by the Regional Administrator. 

A standard report for submitting the information to the EPA Regional Administrator and to 

MADEP is included in Appendix K of this Plan. 

5.5 Cleanup Contractors and Equipment Suppliers 

Contact information for specialized spill response and cleanup contractors are provided in 

Appendix H. These contractors have the necessary equipment to respond to a discharge of oil 

that affects Silver Creek or adjoining shorelines, including floating booms and oil skimmers. 

Spill kits are located at the loading rack/unloading area and inside the maintenance building. 

The inventory of response supplies and equipment is provided in Appendix J of this Plan. The 

inventory is verified on a monthly basis. Additional supplies and equipment may be ordered from 

the following sources: 

AA Equipment Co. (800) 555-5556
 
 

Eastern Sorbent (800) 555-5557
 
 

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Appendix A 

Site Plan and Facility Diagram 

Figure A-1: Site Plan. 

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Figure A-2: Facility Diagram. 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

Appendix B 

Substantial Harm Determination 

Facility Name: Unified Oil Company 

Facility Address: 123 A Street 

Stonefield, MA 02000 

1. Does the facility transfer oil over water to or from vessels and does the facility have a total oil 

storage capacity greater than or equal to 42,000 gallons? 

Yes G No O 

2. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and 

does the facility lack secondary containment that is sufficiently large to contain the capacity of 

the largest aboveground oil storage tank plus sufficient freeboard to allow for precipitation within 

any aboveground storage tank area? 

Yes G No O 

3. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and 

is the facility located at a distance (as calculated using the appropriate formula in 40 CFR part 

112 Appendix C, Attachment C-III or a comparable formula) such that a discharge from the 

facility could cause injury to fish and wildlife and sensitive environments? 

Yes G No O 

4. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and 

is the facility located at a distance (as calculated using the appropriate formula in 40 CFR part 

112 Appendix C, Attachment C-III or a comparable formula) such that a discharge from the 

facility would shut down a public drinking water intake? 

Yes G No O 

5. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and 

has the facility experienced a reportable oil spill in an amount greater than or equal to 10,000 

gallons within the last 5 years? 

Yes G No O 

Certification 

I certify under penalty of law that I have personally examined and am familiar with the 

information submitted in this document, and that based on my inquiry of those individuals 

responsible for obtaining this information, I believe that the submitted information is true, 

accurate, and complete. 

Facility Manager 

Signature Title 

Susan Blake May 12, 2003 

Name (type or print) Date 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

APPENDIX C 

Facility Inspection Checklists 

The following checklists are to be used for monthly and annual facility-conducted inspections. 

Completed checklists must be signed by the inspector and maintained at the facility, with this 

SPCC Plan, for at least three years. 

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Monthly Inspection Checklist

This inspection record must be completed except the month in which an annual 

inspection is performed. Provide further description and comments, if necessary, on a separate 

sheet of paper and attach to this sheet. *Any item that receives “yes” as an answer must be 

described and addressed immediately. 

Y* N 

Storage tanks 

Tank surfaces show signs of leakage 

Tanks are damaged, rusted or deteriorated 

Bolts, rivets, or seams are damaged 

Tank supports are deteriorated or buckled 

Tank foundations have eroded or settled 

Level gauges or alarms are inoperative 

Vents are obstructed 

Secondary containment is damaged or stained 

Water/product in interstice of double-walled tank 

Dike drainage valve is open or is not locked 

Piping 

Valve seals, gaskets, or other appurtenances are leaking 

Pipelines or supports are damaged or deteriorated 

Joints, valves and other appurtenances are leaking 

Buried piping is exposed 

Loading/unloading and transfer equipment 

Loading/unloading rack is damaged or deteriorated 

Connections are not capped or blank-flanged 

Secondary containment is damaged or stained 

Berm drainage valve is open or is not locked 

Oil/water separator > 2 inches of accumulated oil 

Oil/water separator effluent has a sheen 

Security 

Fencing, gates, or lighting is non-functional 

Pumps and valves are locked if not in use 

Response Equipment 

Response equipment inventory is complete 

each month 

Description & Comments 

Oil/water separator 

Date: ____________ Signature: _________________________ 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

Annual Facility Inspection Checklist 

This inspection record must be completed each year. If any response requires further 

elaboration, provide comments in Description & Comments space provided. Further description 

and comments, if necessary, must be provided on a separate sheet of paper and attached to 

this sheet. *Any item that receives “yes” as an answer must be described and addressed 

immediately. 

Y* N 

Storage tanks 

Tank #1 

Tank surfaces show signs of leakage 

Tank is damaged, rusted or deteriorated 

Bolts, rivets or seams are damaged 

Tank supports are deteriorated or buckled 

Tank foundations have eroded or settled 

Level gauges or alarms are inoperative 

Vents are obstructed 

Tank #2 

Tank surfaces show signs of leakage 

Tank is damaged, rusted, or deteriorated 

Bolts, rivets, or seams are damaged 

Tank supports are deteriorated or buckled 

Tank foundations have eroded or settled 

Level gauges or alarms are inoperative 

Vents are obstructed 

Tank #3 

Tank surfaces show signs of leakage 

Tank is damaged, rusted, or deteriorated 

Bolts, rivets, or seams are damaged 

Tank supports are deteriorated or buckled 

Tank foundations have eroded or settled 

Level gauges or alarms are inoperative 

Vents are obstructed 

Tank #4 

Tank surfaces show signs of leakage 

Tank is damaged, rusted or deteriorated 

Bolts, rivets or seams are damaged 

Tank supports are deteriorated or buckled 

Tank foundations have eroded or settled 

Level gauges or alarms are inoperative 

Description & Comments 

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Y* N 

Vents are obstructed 

Oil is present in the interstice 

Tank #7 

Tank surfaces show signs of leakage 

Tank is damaged, rusted, or deteriorated 

Bolts, rivets, or seams are damaged 

Tank supports are deteriorated or buckled 

Tank foundations have eroded or settled 

Level gauges or alarms are inoperative 

Leakage in exhaust from heating coils 

Concrete dike 

Secondary containment is stained 

Dike drainage valve is open or is not locked 

Dike walls or floors are cracked or are separating 

Dike is not retaining water (following large rainfall) 

Piping 

Valve seals or gaskets are leaking 

Pipelines or supports are damaged or deteriorated 

Joints, valves and other appurtenances are leaking 

Buried piping is exposed 

Out-of-service pipes are not capped 

Warning signs are missing or damaged 

Loading/unloading and transfer equipment 

Loading/unloading rack is damaged or deteriorated 

Connections are not capped or blank-flanged 

Rollover berm is damaged or stained 

Berm drainage valve is open or is not locked 

Drip pans have accumulated oil or are leaking 

Oil/water separator > 2 inches of accumulated oil 

Oil/water separator effluent has a sheen 

Security 

Fencing, gates, or lighting is non-functional 

Pumps and valves are not locked (and not in use) 

Response equipment 

Response equipment inventory is incomplete 

Description & Comments 

Oil/water separator 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

Annual reminders: 

< Hold SPCC Briefing for all oil-handling personnel (and update briefing log in the Plan); 

< Check contact information for key employees and response/cleanup contractors and 

update them in the Plan as needed; 

Additional Remarks: 

Date: _______________ Signature: _____________________ 

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APPENDIX D 

Record of Containment Dike Drainage 

This record must be completed when rainwater from diked areas is drained into a storm drain or 

into an open watercourse, lake, or pond, and bypasses the water treatment system. The bypass 

valve must normally be sealed in closed position. It must be opened and resealed following 

drainage under responsible supervision. 

Date Diked Area Presence of Time Time Signature 

08:00 10:00 Susan Blake 

08:20 10:30 Susan Blake 

06/05/2003 Area 1 No oil 

07/15/2003 Area 1 No oil 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

APPENDIX E 

Record of Annual Discharge Prevention 

Briefings and Training 

Briefings will be scheduled and conducted by the facility owner or operator for operating 

personnel at regular intervals to ensure adequate understanding of this SPCC Plan. The 

briefings will also highlight and describe known discharge events or failures, malfunctioning 

components, and recently implemented precautionary measures and best practices. Personnel 

will also be instructed in operation and maintenance of equipment to prevent the discharge of 

oil, and in applicable pollution laws, rules, and regulations. Facility operators and other 

personnel will have an opportunity during the briefings to share recommendations concerning 

health, safety, and environmental issues encountered during facility operations. 

Date Subjects Covered Employees in Attendance Instructor(s) 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

APPENDIX F 

Calculation of Secondary Containment Capacity 

The maximum 24-hour rainfall recorded in the last 25 years at this location is 3.75 inches. 

Bulk Storage Dike 

Capacity of Tanks within the Diked Area: 

Tank 1 = 20,000 gallons (saddle-mounted tank, no significant displacement)
 
 

Tank 2 = 20,000 gallons (saddle-mounted tank, no significant displacement)
 
 

Tank 3 = 20,000 gallons (need to account for tank displacement)
 
 

Tank 7 = 10,000 gallons (on legs, no significant displacement)
 
 

Dike Dimensions: 

Dike footprint = 50 feet x 60 feet
 
 

Dike height = 15 inches = 1.25 feet
 
 

Dike volume = 50' x 60' x 1.25' = 3750 ft3

 x 7.48 gal/ft3 = 28,050 gallons
 
 

Displacement Volume of Tank 3: 

Tank diameter = 10 feet
 
 

3.1415 * (10 ft)2

 / 4 * 1.25' = 98 ft3 x 7.48 gal/ft3 = 734 gallons
 
 

Available Freeboard for Precipitation:
 
 

28,050 gallons - (20,000 gallons + 734 gallons) = 7,316 gallons
 
 

7,316 gallons / 7.48 gallons/ft3

 / (50 ft x 60 ft) = 0.33 ft = 4 inches
 
 

The dike therefore provides sufficient storage capacity for the largest bulk storage 

container within the diked area, tank displacement, and precipitation. The 

containment capacity is equivalent to 137% of the capacity of the largest container 

((28,050 gallons - 734 gallons)/20,000 gallons). 

Loading Rack/Unloading Area Rollover Berm 

Capacity of Largest Tank Truck Compartment: 

2,000 gallons
 
 

Berm Dimensions:
 
 

Berm footprint = 28 feet x 45 feet (50% of the berm surface area is covered by the roof)
 
 

Berm height = 4.5 inches = 0.375 feet
 
 

Berm volume = 28 ft x 45 ft x 0.375 ft = 473 ft3

 x 7.48 gal/ft3 = 3,534 gallons
 
 

Available Freeboard for Precipitation:
 
 

Since 50% of the surface area of the berm is covered by a roof, the volume of
 
 

precipitation that enters the berm is reduced.
 
 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

Minimum freeboard required = 28 ft x 45 ft x 0.5 x 3.75/12 = 197 ft3 = 1,472 gallons 

Actual freeboard = 3,534 gallons - 2,000 gallons = 1,534 gallons 

The berm therefore provides sufficient storage capacity to contain both the largest 

compartment of tank trucks loading/unloading at the facility, and the volume of 

precipitation that enters the berm. 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

APPENDIX G 

Records of Tank Integrity and Pressure Tests 

Attach copies of official records of tank integrity and pressure tests. 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

APPENDIX H 

Emergency Contacts 

Designated person responsible for spill prevention:	 	 Susan Blake, Facility Manager 

781-555-5550 

EMERGENCY TELEPHONE NUMBERS: 

Facility 

Susan Blake, Facility Manager	 	 781-555-5550 

Local Emergency Response 

Stonefield Fire Department	 	 911 or 

781-555-5551 

St. Mary’s Hospital	 	 781-555-5552 

Response/Cleanup Contractors 

EZ Clean	 	 617-555-5554 

Stonefield Oil Removal	 	 781-555-5555 

Notification 

Massachusetts Department of Environmental Protection, Incident	 	 617-556-1133 

Response Division 

National Response Center	 	 800-424-8802 

United States Environmental Protection Agency, Region 1	 	 888-372-7341 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

APPENDIX I 
 


Discharge Notification Form 
 


Part A: Discharge Information 

General information when reporting a spill to outside authorities: 

Name: 

Address: 123 A Street 

Stonefield, MA 02000 

Telephone: (781) 555-5556 

Owner/Operator: 

20 Fairview Road 

Stonefield, MA 02000 

Work: (781)555-5550 

Cell (24 hrs): (781)555-5559 

Unified Oil Company 

Blake and Daughters, Inc. 

Primary Contact: Susan Blake, Facility Manager 

Type of oil: Discharge Date and Time: 

Quantity released: Discovery Date and Time: 

Quantity released to a waterbody: Discharge Duration: 

Location/Source: 

Actions taken to stop, remove, and mitigate impacts of the discharge: 

Affected media: 

G air G storm water sewer/POTW 

G water G dike/berm/oil-water separator 

G soil G other: _________________________ 

Notification person: Telephone contact: 

Business: 

24-hr: 

Nature of discharges, environmental/health effects, and damages: 

Injuries, fatalities or evacuation required? 

Part B: Notification Checklist 

Date and time Name of person receiving call 

Discharge in any amount 

Susan Blake, Facility Manager and Response 

Coordinator 

(781) 555-5550 / (781) 555-5559 

Discharge in amount exceeding 10 gallons and not affecting a waterbody or groundwater 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

Local Fire Department 

Fire Chief: D. Evans 

(781) 555-1258 or 911 

Massachusetts Department of Environmental 

Protection 

(888) 304-1133 or (617) 553-1133 

Local Fire Department 

Fire Chief: D. Evans 

(781) 555-1258 or 911 

Massachusetts Department of Environmental 

Protection 

(888) 304-1133 or (617) 553-1133 

National Response Center 

(800) 424-8802 

*Town of Stonefield POTW 

Plant Operator: K. Bromberg 

(781) 555-5453 

Town of Stonefield Drinking Water Plant 

Plant Operator: D. Lopez 

(781) 555-5450 

EZ Clean 

(617) 555-5554 

Discharge in any amount and affecting (or threatening to affect) a waterbody 

* The POTW should be notified of a discharge only if oil has reached or threatens sewer drains that 

connect to the POTW collection system. 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

APPENDIX J 

Discharge Response Equipment Inventory 

The discharge response equipment inventory is verified during the monthly inspection and must 

be replenished as needed. 

Tank Truck Loading/Unloading Area 

G Empty 55-gallons drums to hold contaminated material 4 

G Loose absorbent material 200 pounds 

G Absorbent pads 3 boxes 

G Nitrile gloves 6 pairs 

G Neoprene gloves 6 pairs 

G Vinyl/PVC pull-on overboots 6 pairs 

G Non-sparking shovels 3 

G Brooms 3 

G Drain seals or mats 2 

G Sand bags 12 

Maintenance Building 

G Empty 55-gallons drums to hold contaminated material 1 

G Loose absorbent material 50 pounds 

G Absorbent pads 1 box 

G Nitrile gloves 2 pairs 

G Neoprene gloves 2 pairs 

G Vinyl/PVC pull-on overboots 2 pairs 

G Non-sparking shovels 1 

G Brooms 1 

G Drain seals or mats 1 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

APPENDIX K 

Agency Notification Standard Report 

Information contained in this report, and any supporting documentation, must be submitted to 

the EPA Region 1 Regional Administrator, and to MADEP, within 60 days of the qualifying 

discharge incident. 

Blake and Daughters 

20 Fairview Road 

Stonefield, MA 02000 

Name of person filing report: 

123 A Street 

Stonefield, MA 02000 

Location: 

74,600 gallons 

8,000 gallons 

G Discharge to navigable waters or adjoining shorelines exceeding 1,000 gallons 

G Second discharge exceeding 42 gallons within a 12-month period. 

carrier via tanker truck. The products are stored in five aboveground storage tanks (ASTs) 

East by A Street, to the West by Silver Creek, and to the North by ABC Plating Co. 

Facility: Unified Oil Company 

Owner/operator: 

Maximum storage capacity: 

Daily throughput: 

Nature of qualifying incident(s): 

Description of facility (attach maps, flow diagrams, and topographical maps): 

Unified Oil distributes a variety of petroleum products to primarily commercial customers. The 

facility handles, stores, uses, and distributes petroleum products in the form of gasoline, 

diesel, No. 2 fuel oil, No. 6 fuel oil, and motor oil. Unified Oil receives products by common 

and in one underground storage tank (UST). They are delivered to customers by Unified Oil 

trucks or by independent contractors. The facility refuels its own two delivery trucks from an 

underground diesel tank connected to a fueling pump. 

Unified Oil is located in a primarily commercial area at 123 A Street in Stonefield, 

Massachusetts. The site is comprised of approximately 2 acres of land and is bordered to the 

Site improvements include an office building, a maintenance shop, a tanker truck loading rack 

and unloading area, and product storage and handling areas. Petroleum products are stored 

in the bulk storage area, the maintenance building, and the office building. 

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Unified Oil Company, Ltd. SAMPLE Spill Prevention, Control, and Countermeasure (SPCC) Plan 

Agency Notification Standard Report (cont’d) 

Cause of the discharge(s), including a failure analysis of the system and subsystems 

in which the failure occurred : 

Corrective actions and countermeasures taken, including a description of equipment 

repairs and replacements: 

Additional preventive measures taken or contemplated to minimize possibility of 

recurrence: 

Other pertinent information: 

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This page intentionally left blank. 

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Appendix E 

APPENDIX E: SAMPLE PRODUCTION FACILITY SPCC PLAN
 


U.S. Environmental Protection Agency Version 1.0, 11/28/2005 
Disclaimer - Appendix E 

The sample Spill Prevention, Control and Countermeasure (SPCC) Plan in Appendix E 

is intended to provide examples and illustrations of how a production facility could address a 

variety of scenarios in its SPCC Plan. The “facility” is not an actual facility, nor does it represent 

any actual facility or company. Rather, EPA is providing illustrative examples of the type and 

amount of information that is appropriate SPCC Plan language for these hypothetical situations. 

Because the SPCC rule is designed to give each facility owner/operator the flexibility to 

tailor the facility’s SPCC Plan to the facility’s circumstances, this sample SPCC Plan is not a 

template to be adopted by a facility; doing so does not mean that the facility will be in 

compliance with the SPCC rule requirements. Nor is the sample plan a template that must be 

followed in order for the facility to be considered in compliance with the SPCC rule. 

Version 1.0, 11/28/2005 
SPILL PREVENTION, CONTROL, AND COUNTERMEASURE PLAN 

Clearwater Oil Company 

Big Bear Lease No. 2 Production Facility 

5800 Route 417 

Madison, St. Anthony Parish, Louisiana 73506 

Prepared by 

Montgomery Engineering, Inc. 

November 23, 2003 

Version 1.0, 11/28/2005 
Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and 

Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Table of Contents 

Page
 
 

Cross-Reference with SPCC Rule 4
 
 

Introduction 5
 
 

Management Approval 6
 
 

Professional Engineer Certification 6
 
 

Plan Review 7
 
 

Location of SPCC Plan 7
 
 

Certification of Substantial Harm Determination 8
 
 

Part I - General Facility Information
 
 

1.1 Company Information 9

 1.2 Contact Information 9

 1.3 Facility Layout Diagram 10

 1.4 Facility Location and Operations 10

 1.5 Oil Storage and Handling 11

 1.6 Proximity to Navigable Waters 12

 1.7 Conformance with Applicable State and Local Requirements 12
 
 

Part II - Spill Response and Reporting

 2.1 Discharge Discovery and Reporting 13

 2.2 Spill Response Materials 14

 2.3 Spill Mitigation Procedures 15

 2.4 Disposal Plan 16
 
 

Part III - Spill Prevention, Control, and Countermeasure Provisions

 3.1 Potential Discharge Volume and Direction of Flow 18

 3.2 Containment and Diversionary Structures 19

 3.3 Other Spill Prevention Measures 22

 3.4 Inspections, Tests, and Records 23

 3.5 Personnel, Training, and Discharge Prevention Procedures 27
 
 

Appendix A - Facility Diagrams 30
 
 

Appendix B - Tank Truck Loading Procedure 32
 
 

Appendix C - Monthly Inspection Checklist 33
 
 

Appendix D - Record of Dike Drainage 34
 
 

Appendix E - Discharge Prevention Briefing Log 35
 
 

Appendix F - Discharge Notification Procedures 36
 
 

Appendix G - Equipment Shut-off Procedures 41
 
 

Appendix H - Written Commitment of Manpower, Equipment, and Materials 42
 
 

Appendix I - Oil Spill Contingency Plan 43
 
 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Page
 


 

7
 

10
 


 

18
 

21
 

24
 

25
 


 

27
 

List of Figures
 

List of Tables 

Table 0-1: Record of plan review and changes 

Table 1-1: Facility contact information 

Table 1-2: Characteristics of oil containers 11 

Table 3-1: Potential discharge volume and direction of flow 

Table 3-2: Berm capacity calculations 

Table 3-3: Scope of daily examinations 

Table 3-4: Scope of monthly inspections 

Table 3-5: Schedule of periodic condition inspection of bulk storage containers 26 

Table 3-6: Components of flowline maintenance program 

Figure A-1: Site plan. 30
 
 

Figure A-2: Production facility diagram. 31
 
 

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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and 

Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Cross-Reference with SPCC Rule
 Plan Section Page(s) 

112.3(d) 6 

112.3(e) Location of SPCC Plan 7 

112.5 7 

112.7 6 

112.7 ith SPCC Rule 4 

112.7(a)(3) 9-12 

Appendix A 

112.4 and 13-15 

112.7(a)(4) Appendix F 

112.7(a)(5) 15-16 

Appendix I 

112.7(b) low 18-19 

112.7(c) 19-21 

112.7(d) 21 

Appendix H 

Appendix I 

112.7(e) 23-26 

Appendix C 

112.7(f) 27-29 

Appendix E: Discharge Prevention Briefing Log Appendix E 

112.7(g) N/A 

112.7(h) ) N/A 

112.7(i) 26 

facility) 

112.7(j) 1.7 Conformance wi 

112.9(b) 20 

Appendix D: Record of Dike Drainage Appendix D 

112.9(c)(1) 11 

112.9(c)(2) 19-21 

112.9(c)(3) 23-26 

Appendix C 

112.9(c)(4) 

112.9(d)(1) 22-23 

112.9(d)(2) 22-23 

112.9(d)(3) l 26-27 

Provision* 

Professional Engineer Certification 

Plan Review 

Management Approval 

Cross-Reference w 

Part I - General Information and Facility Diagram 

Appendix A: Facility Diagrams 

2.1 Discharge Discovery and Reporting 

Appendix F: Discharge Notification 

2.2 Spill Mitigation Procedures 

Appendix I: Oil Spill Contingency Plan 

3.1 Potential Discharge Volume and Direction of F 

3.2 Containment and Diversionary Structures 

3.2.3 Practicability of Secondary Containment 

Appendix H: Written Commitment of manpower, equipment, and materials 

Appendix I: Oil Spill Contingency Plan 

3.4 Inspections, Tests, and Records 

Appendix C: Facility Inspection Checklists 

3.5 Personnel, Training, and Discharge Prevention Procedures 

Security – N/A (does not apply to production facilities) 

Loading/Unloading Rack – N/A (no rack present at this facility 

Brittle Fracture Evaluation – N/A (no field-erected aboveground tank at this 

th Applicable State and Local Requirements 12 

3.2.1 Oil Production Facility Drainage 

1.5.1 Production Equipment 

3.2.2 Secondary Containment for Bulk Storage Containers 

3.4 Inspections, Tests, and Records 

Appendix C: Monthly Inspection Checklist 

3.3.1 Bulk Storage Containers Overflow Prevention 22 

3.3.2 Transfer Operations and Saltwater Disposal System 

3.3.2 Transfer Operations and Saltwater Disposal System 

3.4.5 F owline Maintenance Program 

* Only relevant rule provisions are indicated. For a complete list of SPCC requirements, refer to the full text of 40 CFR 

part 112. 

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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and 

Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Introduction 

The purpose of this Spill Prevention Control and Countermeasure (SPCC) Plan is to describe 

measures implemented by Clearwater to prevent oil discharges from occurring, and to prepare 

Clearwater to respond in a safe, effective, and timely manner to mitigate the impacts of a 

discharge from the Big Bear Lease No. 2 production facility. This SPCC Plan has been 

prepared and implemented in accordance with the SPCC requirements contained in 40 CFR 

part 112. 

In addition to fulfilling requirements of 40 CFR part 112, this SPCC Plan is used as a reference 

for oil storage information and testing records, as a tool to communicate practices on preventing 

and responding to discharges with Clearwater employees and contractors, as a guide on facility 

inspections, and as a resource during emergency response. 

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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and 

Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Management Approval

40 CFR 112.7 

Clearwater Oil Company (“Clearwater”) is committed to maintaining the highest standards for
 
 

preventing discharges of oil to navigable waters and the environment through the
 
 

implementation of this SPCC Plan. This SPCC Plan has the full approval of Clearwater
 
 

management. Clearwater’s management has committed the necessary resources to implement
 
 

the measures described in this Plan.
 
 

Bill Laurier is the Designated Person Accountable for Oil Spill Prevention at this Clearwater
 
 

facility and has the authority to commit the necessary resources to implement the Plan as
 
 

described. 
 
 

Authorized Facility Representative: 
 
 Bill Laurier 

Signature: 
 
 

Title: 
 
 Field Operations Manager 

Date: November 23, 2003 

Professional Engineer Certification

40 CFR 112.3(d) 

The undersigned Registered Professional Engineer is familiar with the requirements of Part 112 

of Title 40 of the Code of Federal Regulations (40 CFR part 112) and has visited and examined 

the facility, or has supervised examination of the facility by appropriately qualified personnel. 

The undersigned Registered Professional Engineer attests that this Spill Prevention, Control, 

and Countermeasure Plan has been prepared in accordance with good engineering practice, 

including consideration of applicable industry standards and the requirements of 40 CFR part 

112; that procedures for required inspections and testing have been established; and that this 

Plan is adequate for the facility. [112.3(d)] 

This certification in no way relieves the owner or operator of the facility of his/her duty to prepare 

and fully implement this SPCC Plan in accordance with the requirements of 40 CFR part 112. 

Peter E. Trudeau November 23, 2003 

Signature Date 

Peter E. Trudeau, P.E. PE Seal 

Name of Professional Engineer Peter E. Trudeau
 
 

90535055 Louisiana LA #90535055
 
 

Registration Number Issuing State 

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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and 

Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Plan Review 

40 CFR 112.5 

In accordance with 40 CFR 112.5, Clearwater Oil periodically reviews and evaluates this SPCC 

Plan for any change in the facility design, construction, operation, or maintenance that 

materially affects the facility’s potential for an oil discharge. Clearwater reviews this SPCC Plan 

at least once every five years. Revisions to the Plan, if any are needed, are made within six 

months of this five-year review. Clearwater will implement any amendment as soon as possible, 

but not later than six months following preparation of any amendment. A registered PE certifies 

any technical amendment to the Plan, as described above, in accordance with 40 CFR 112.3(d). 

Scheduled five-year reviews and Plan amendments are recorded in Table 0-1. This log must be 

completed even if no amendment is made to the Plan. Unless a technical or administrative 

change prompts an earlier review, the next scheduled review of this Plan must occur by 

November 23, 2008. 

Table 0-1: Record of Plan Review and Changes 

Date PE 

Certification 

11/23/03 Bill Laurier Yes 

04/14/04 Bill Laurier No Changed telephone number for Field 

Operations Manager. 

Content. 

Non-technical amendments, no PE 

certification is needed. 

Authorized 

Individual 

Review Type Summary of Changes 

Initial Plan N/A 

Off-cycle review 

Corrected page numbers in Table of 

Location of SPCC Plan 

40 CFR 112.3(e) 

In accordance with 40 CFR 112.3(e), and because the facility is normally unmanned, a 

complete copy of this SPCC is maintained at the field office closest to the facility, which is 

located approximately 25 miles from the facility at 2451 Mountain Drive, Ridgeview, LA. 

Additional copies are available at the Clearwater Oil Company management office, located at 

13000 Main Street, Suite 400, Houston, TX. 

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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and 

Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Certification of Substantial Harm Determination 

40 CFR 112.20(e), 40 CFR 112.20(f)(1) 

Facility Name: Clearwater Oil Company, Big Bear Lease No. 2 

1. Does the facility transfer oil over water to or from vessels and does the facility have a total oil 

storage capacity greater than or equal to 42,000 gallons? 

Yes G No O 

2. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and 

does the facility lack secondary containment that is sufficiently large to contain the capacity of 

the largest aboveground oil storage tank plus sufficient freeboard to allow for precipitation within 

any aboveground storage tank area? 

Yes G No O 

3. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and 

is the facility located at a distance (as calculated using the appropriate formula) such that a 

discharge from the facility could cause injury to fish and wildlife and sensitive environments? 

Yes G No O 

4. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and 

is the facility located at a distance (as calculated using the appropriate formula) such that a 

discharge from the facility would shut down a public drinking water intake? 

Yes G No O 

5. Does the facility have a total oil storage capacity greater than or equal to 1 million gallons and 

has the facility experienced a reportable oil spill in an amount greater than or equal to 10,000 

gallons within the last 5 years? 

Yes G No O 

Certification 

I certify under penalty of law that I have personally examined and am familiar with the 

information submitted in this document, and that based on my inquiry of those individuals 

responsible for obtaining this information, I believe that the submitted information is true, 

accurate, and complete. 

Field Operations Manager 

Signature Title 

Bill Laurier November 23, 2003 

Name (type or print) Date 

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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and 

Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

PART I - GENERAL FACILITY INFORMATION 

40 CFR 112.7(a)(3) 

1.1 Company Information 

Name of Facility: 

Type 

Date of Initial Operation 

Location 

Name and Address of Owner 

Clearwater Oil Company 

Big Bear Lease No. 2 

Onshore oil production facility 

2002 

5800 Route 417 

Madison, St. Anthony Parish, Louisiana 73506 

Clearwater Oil Company 

Regional Field Office 

2451 Mountain Drive 

Ridgeview, LA 70180 

Corporate Headquarters 

13000 Main Street, Suite 400 

Houston, TX 77077 

1.2 Contact Information 

The designated person accountable for overall oil spill prevention and response at the facility, 

also referred to as the facility’s “Response Coordinator” (RC), is the Field Operations Manager, 

Bill Laurier. 24-hour contact information is provided in Table 1-1. 

Personnel from Avonlea Services Inc. (“Avonlea”) provide operations (pumper/gauger) support 

activities to Clearwater field personnel, including performing informal daily examinations of the 

facility equipment, as described in Section 3.4 of this SPCC Plan. Avonlea personnel regularly 

visit the facility to record production levels and perform other maintenance/inspection activities 

as requested by the Clearwater Field Operations Manager. Key contacts for Avonlea are 

included in Table 1-1. 

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Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and 

Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Table 1-1: Facility contact information 

Title 

Lester Pearson 

Operations 

(555)-289-4500 13000 Main Street, Suite 400 

Carol Campbell 

Operations 

(405) 831-6320 (office) 

(405) 831-2262 (cell) 

2451 Mountain Drive 

Bill Laurier 

Manager 

(405) 831-6322 (office) 

(405) 829-4051 (cell) 

2451 Mountain Drive 

Joe Clark (406) 545-2285 (office) 

Avonlea Services, Inc. (406) 549-9087 (cell) Avonlea, LA 70180 

William Mackenzie Pumper (406) 549-9087 (cell) 

Avonlea Services, Inc. Avonlea, LA 70180 

Name Telephone Address 

Vice-President of 

Clearwater Oil Co. 

Houston, TX 77077 

Regional Director of 

Clearwater Oil Co. 

Ridgeview, LA 70180 

Field Operations 

Clearwater Oil Co. 

Ridgeview, LA 70180 

Field Supervisor 786 Cherry Creek Road 

786 Cherry Creek Road 

1.3 Facility Layout Diagram 

Appendix A, at the end of this Plan, shows a general site plan for the facility. The site plan 

shows the site topography and the location of the facility relative to waterways, roads, and 

inhabited areas. Appendix A also includes a detailed facility diagram that shows the wells, 

flowlines, tank battery, and transfer areas for the facility. The diagram shows the location, 

capacity, and contents of all oil storage containers greater than 55 gallons in capacity. 

1.4 Facility Location and Operations 

Clearwater owns and operates the Big Bear Lease No. 2 production facility, which is located 

approximately six miles north of Madison, St. Anthony Parish, Louisiana (see Figure A-1 in 

Appendix A). The site is accessed through a private dirt/gravel road off Route 417. 

As illustrated in Figure A-2 in Appendix A, the facility is comprised of five main areas: Well A, 

Well B, the saltwater disposal well, flowlines, and a tank battery. The tank battery includes three 

400-barrel (bbl) oil storage tanks, one 500-bbl produced water tank, one 500-bbl gun barrel, and 

associated flowlines and piping. 

The production facility is generally unmanned. Clearwater's field office is located 25 miles from 

the site, at 2541 Mountain Drive, Ridgeview, Louisiana. Field operations personnel from 

Clearwater, or pumpers acting as contractors to Clearwater visit the facility daily (2-4 hours each 

day) to record production rates and ensure the proper functioning of wellhead equipment and 

pumpjacks, storage tanks, flowlines, and separation vessels. This includes performing 

equipment inspections and maintenance as needed. 

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The facility produces an average of 30 bbl (1,260 gallons) of crude oil (approximately 40 API 

contains an oil/produced water mixture. It is subject to 40 CFR part 112 and is covered by this 

SPCC Plan. 

1.5 Oil Storage and Handling 

1.5.1 

Oil storage at the facility consists of one (1) 500-bbl gun barrel, three (3) 400-bbl aboveground 

storage tanks, one (1) 500-bbl produced water tank, and associated piping, as summarized in 

Table 1-2. The total oil capacity at this facility is 2,200 bbl (92,400 gallons). 

All oil storage tanks are shop-built and meet the American Petroleum Institute (API) tank 

construction standard. Their design and construction are compatible with the oil they contain 

and the temperature and pressure conditions of storage. Tanks storing crude or produced oil 

(#1 through #4) are constructed of welded steel following API-12F Shop Welded Tanks for 

Storage of Production Liquids specifications. Steel tanks are coated to minimize corrosion. Tank 

holding produced water (#5) constructed of fiberglass following API-12P Fiberglass Reinforced 

Plastic Tanks specifications. 

Other production equipment present at the facility include the pumpjacks at each well and water 

pumps for transfer of saltwater to the injection well. These store a minimal amount of lubricating 

oil (less than 55 gallons). Lubricating oil and other substances, such as solvents and chemicals 

for downhole treatment, are also stored at the facility, but in quantities below the 55-gallon 

threshold for SPCC applicability. Table 1-2 lists all oil containers present at the facility with 

capacity of 55 gallons or more. 

Table 1-2: Characteristics of oil containers 

ID 

ion 

Primary 

(barrels) ) 

#1 Gun barrel Steel Oil 500 21,000 

#2 AST Steel Oil 400 16,800 

#3 AST Steel Oil 400 16,800 

#4 AST Steel Oil 400 16,800 

#5 AST Fiberglass 500 21,000 

and oil mixture 

92,400 

gravity) and 140 bbl (5,880 gallons) of produced water each day. The produced water tank 

Production Equipment 

Type Construct 

Content 

Capacity Capacity 

(gallons 

Produced water 

TOTAL 2,200 

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1.5.2 Transfer Activities 

Wells A and B produce crude oil, produced water (saltwater), and small amounts of natural gas. 

The oil and water are produced through the tubing, while the natural gas is produced through 

the casing. Well liquids are then routed via 2-inch steel flowlines to the gun barrel tank for 

separation, while the gas is sent to a flare. Produced saltwater is routed from the gun barrel to 

the 500-bbl saltwater storage tank first, then is pumped through flowlines to the saltwater 

disposal well where it is injected. The disposal well is located approximately 2,000 ft to the west 

of the tank battery. The crude oil is sent to the three 400-bbl (16,800-gallon) oil storage tanks. 

Crude oil from the lease is purchased by Clearwater’s crude oil purchaser and transported from 

the facility by the purchaser’s tanker truck. Although daily well production rates may vary, 

enough crude is produced and stored for approximately one 180-bbl (7,560-gallon) load of oil to 

be picked up weekly by the transporter. The largest tanker truck visiting the facility has a total 

capacity of 210 bbl (8,820 gallons). Tanker trucks come to the facility only to transfer crude oil 

and do not remain at the facility. All transfer operations are attended by the trucker or by field 

operations personnel and meet the minimum requirements of the U.S. Department of 

Transportation Hazardous Materials Regulations. Appendix B to this Plan summarizes the Tank 

Truck Loading Procedure at this facility. 

Produced saltwater is pumped via transfer pumps from the saltwater tank to the saltwater 

disposal well, located approximately 2,000 feet west of the facility, by 2-inch PVC flowlines 

(FLSW). The disposal well meets all requirements of the Underground Injection Control (UIC) 

program (40 CFR parts 144-148). 

1.6 Proximity to Navigable Waters 

The facility is located within the Mines River watershed, approximately half a mile to the west of 

Big Bear Creek, and six miles North of the Mines River. The wells and tank battery are situated 

on relatively level ground that slopes in a general southeastern direction. The site plan in Figure 

A-1 in Appendix A shows the location of the facility relative to nearby waterways. The facility 

diagram included in Figure A-2 in Appendix A indicates the general direction of drainage. In the 

event of an uncontrolled discharge from the wells, flowlines, or the tank battery areas, oil would 

follow the natural topography of the site and flow into Big Bear Creek. Big Bear Creek meets 

with the Mines River to the south just before the town of Madison. The River then flows in a 

general easterly direction following Route 101. 

1.7 Conformance with Applicable State and Local Requirements [112.7(j)] 

The SPCC regulation at 40 CFR part 112 is more stringent than requirements from the state of 

Louisiana for this type of facility. This SPCC Plan was written to conform with 40 CFR part 112 

requirements. The facility thereby conforms with general requirements for oil pollution facilities 

in Louisiana. All discharge notifications are made in compliance with local, state, and federal 

requirements. 

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PART II. SPILL RESPONSE AND REPORTING

 40 CFR 112.7 

2.1 Discharge Discovery and Reporting [112.7(a)(3)] 

Several individuals and organizations must be contacted in the event of an oil discharge. The 

Field Operations Manager is responsible for ensuring that all required discharge notifications 

have been made. All discharges should be reported to the Field Operations Manager. The 

summary table included in Appendix F to this SPCC Plan provides a list of agencies to be 

contacted under different circumstances. Discharges would typically be discovered during the 

inspections conducted at the facility in accordance with procedures set forth in Section 3.4.1 of 

this SPCC Plan, Table 3-3 and Table 3-4, and on the checklist of Appendix C. The Form 

included in Appendix F of this Plan summarizes the information that must be provided when 

reporting a discharge, including contact lists and phone numbers. 

2.1.1 Verbal Notification Requirements (Local, State, and Federal (40 CFR part 110)) 

Any unauthorized discharge into air, land or water must be reported immediately to the State 

Police and the Emergency Planning Commission as soon as the discharge is detected. 

For any discharge that reaches navigable waters, or threatens to reach navigable waters, 

immediate notification must be made to the National Response Center Hotline (800-424-8802) 

and to the Environmental Protection Agency. 

In the event of a discharge that threatens to result in an emergency condition, facility field 

personnel must verbally notify the Louisiana Emergency Hazardous Materials Hotline (225-

925-6595) immediately, and in no case later than within one (1) hour of the discovery of the 

discharge. An emergency condition is any condition that could reasonably be expected to 

endanger the health and safety of the public; cause significant adverse impact to the land, 

water, or air environment; or cause severe damage to property. This notification must be made 

regardless of the amount of the discharge. 

In the event of a discharge that does not present an emergency situation, verbal notification 

must be made to the Office of Environmental Compliance (by telephone at 225-763-3908 during 

office hours or 225-342-1234 after hours, weekends, and holidays; or by e-mail utilizing the 

Incident Report Form and procedures found at www.deq.state.la.us/surveillance) within twentyfour (24) hours of the discovery of the discharge. 

2.1.2 Written Notification Requirements (State and Federal (40 CFR part 112)) 

A written notification will be made to EPA for any single discharge of oil to a navigable waters or 

adjoining shoreline waterway of more than 1,000 gallons, or for two discharges of 1 bbl (42 

gallons) of oil to a waterway in any 12-month period. This written notification must be made 

within 60 days of the qualifying discharge, and a copy will be sent to the Louisiana Department 

of Environmental Quality (DEQ), which is the state agency in charge of oil pollution control 

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activities. This reporting requirement is separate and in addition to reporting under 40 CFR part 

110 discussed above. 

For any discharge reported verbally, a written notification must also be sent to the DEQ and to 

the St. Anthony’s Parish Local Emergency Planning Committee (LEPC), both within five (5) 

days of the qualifying discharge. 

A written notification to the State Emergency Response Commission or LEPC is required for a 

discharge of 100 lbs or more beyond the confines of the facility (equivalent to 2 mcf of natural 

gas, or 13 gallons of oil) within five (5) days of the qualifying discharge. 

2.1.3 Submission of SPCC Information 

Whenever the facility experiences a discharge into navigable waters of more than 1,000 gallons, 

or two discharges of 42 gallons or more within a 12-month period, Clearwater will provide 

information in writing to the EPA Region 6 office within 60 days of a qualifying discharge as 

described above. The required information is described in Appendix F of this SPCC Plan. 

2.2 Spill Response Materials 

Boom, sorbent, and other spill response materials are stored in the shed next to the loading 

area and are accessible by Clearwater and Avonlea personnel. The response equipment 

inventory for the facility includes: 

(4) Empty 55-gallons drums to hold contaminated material 

(3) 50-ft absorbent socks 

(4) 10-ft sections of hard skirted deployment boom 

(2) 50-ft floating booms
 
 

(200 pounds) “Oil-dry” loose absorbent material
 
 

(4 boxes) 2 ft x 3 ft absorbent pads
 
 

(3 boxes) Nitrile gloves
 
 

(3 boxes) Neoprene gloves
 
 

(6 pairs) Vinyl/PVC pull-on overboots
 
 

(3) Non-sparking shovels 

(3) Brooms 

(20) Sand bags 

(1) Combustible Gas Indicator with H2S detection capabilities 

Additional equipment and material are also kept at the field office. The inventory is checked 

monthly by Clearwater field operations personnel to ensure that used material is replenished. 

Supplies and equipment may be ordered from: 

(1) Rocky Mountain Equipment Co. (800) 959-3000 

(2) Quick Sorbent (800) 857-4650. 

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2.3 Spill Mitigation Procedures 

The following is a summary of actions that must be 

taken in the event of a discharge. It summarizes the Reminder: In the event of a discharge 

distribution of responsibilities among individuals and originating from Flowline A or Flowline B, 

facility personnel must immediately describes procedures to follow in the event of a 

discharge. implement the Oil Spill Contingency Plan. 

The Oil Spill Contingency Plan discusses 

the additional procedures that must be A complete outline of actions to be performed in the followed to respond to a discharge of oil to event of a discharge from flowlines reaching or navigable waters or adjoining shorelines. threatening to reach navigable waters is included in 

the facility Contingency Plan (see Appendix I of this 

SPCC Plan). 

In the event of a discharge, Clearwater or contractor field personnel and the Field Operations 

Manager shall be responsible for the following: 

2.3.1 Shut Off Ignition Sources 

Field personnel must shut off all ignition sources, including motors, electrical circuits, and open 

flames. See Appendix G for more information about shut-off procedures. 

2.3.2 Stop Oil Flow 

Field personnel should determine the source of the discharge, and if safe to do so, immediately 

shut off the source of the discharge. Shut in the well(s) if necessary. 

2.3.3 Stop the Spread of Oil and Call the Field Operations Manager 

If safe to do so, field personnel must use resources available at the facility (see spill response 

material and equipment listed in Section 2.2) to stop the spilled material from spreading. 

Measures that may be implemented, depending on the location and size of the discharge, 

include placing sorbent material or other barriers in the path of the discharge (e.g., sand bags), 

or constructing earthen berms or trenches. 

In the event of a significant discharge, field personnel must immediately contact the Field 

Operations Manager, who may obtain assistance from authorized company contractors and 

direct the response and cleanup activities. Should a discharge reach Big Bear Creek, only 

physical response and countermeasures should be employed, such as the construction of 

underflow dams, installation of hard boom and sorbent boom, use of sorbent pads, and use of 

vacuum trucks to recover oil and oily water from the creek. If water flow is low in the creek, 

construction of an underflow dam downstream and ahead of the spill flow may be 

advantageous. Sorbent material and/or boom should be placed immediately downstream of the 

dam to recover any sheen from the water. If water flow is normal in the creek, floating booms 

and sorbent boom will be deployed. Vacuum trucks will then be utilized to remove oil and oily 

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water at dams and other access points. Crews should remove oiled vegetation and debris from 

the creek banks and place them in bags for later disposal. After removal of contaminated 

vegetation, creek banks should be flushed with water to remove free oil and help it flow down to 

dams and other access points where it can be recovered by vacuum truck. At no time shall any 

surfactants, dispersants, or other chemicals be used to remove oil from the creek. 

2.3.4	 Gather Spill Information 

The Field Operations Manager will ensure that the Discharge Notification Form is filled out and 

that notifications have been made to the appropriate authorities. The Field Operations Manager 

may ask for assistance in gathering the spill information on the Discharge Notification Form 

(Appendix F) of this Plan: 

•	 Reporter’s name 

•	 Exact location of the spill 

•	 Date and time of spill discovery 

•	 Material spilled (e.g., oil, produced water containing a reportable quantity of oil) 

•	 Total volume spilled and total volume reaching or threatening navigable waters or 

adjoining shorelines 

•	 Weather conditions 

•	 Source of spill 

•	 Actions being taken to stop, remove, and mitigate the effects of the discharge 

•	 Whether an evacuation may be needed 

•	 Spill impacts (injuries; damage; environmental media, e.g., air, waterway, 

groundwater) 

•	 Names of individuals and/or organizations who have also been contacted 

2.3.5	 Notify Agencies Verbally 

Some notifications must be completed immediately upon discovering the discharge. It is 

important to immediately contact the Field Operations Manager so that timely notifications can 

be made. If the Field Operations Manager is not available, or the Field Operations Manager 

requests it, field personnel must designate one person to begin notification. Section 2.1 of this 

Plan describes the required notifications to government agencies. The Notification List is 

included in Appendix F of this SPCC Plan. The Field Operations Manager must also ensure that 

written notifications, if needed, are submitted to the appropriate agencies. 

2.4	 Disposal Plan 

The cleanup contractor will handle the disposal of any recovered product, contaminated soil, 

contaminated materials and equipment, decontamination solutions, sorbents, and spent 

chemicals collected during a response to a discharge incident. 

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Any recovered product that can be recycled will be placed into the gun barrel tank to be 

separated and recycled. Any recovered product not deemed suitable for on-site recycling will be 

disposed of with the rest of the waste collected during the response efforts. 

If the facility responds to a discharge without involvement of a cleanup contractor, Clearwater 

will contract a licensed transportation/disposal company to dispose of waste according to 

regulatory requirements. The Field Operations Manager will characterize the waste and arrange 

for the use of certified waste containers. 

All facility personnel handling hazardous wastes must have received both the initial 40-hour 

and annual 8-hour refresher training in the Hazardous Waste Operations and Emergency 

Response Standard (HAZWOPER) of the Occupational Health and Safety Administration 

(OSHA). This training is included as part of the initial training received by all field personnel. 

Training records and certificates are kept at the field office. 

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PART III. SPILL PREVENTION, CONTROL, AND

 COUNTERMEASURE PROVISIONS

 40 CFR 112.7 and 112.9 

3.1	 

Containment [112.7(a)(3)(iii)] 

Table 3-1, below, summarizes potential oil discharge scenarios. If unimpeded, oil would follow 

the site topography and reach Big Bear Creek. 

Table 3-1: Potential discharge volume and direction of flow 

Volume 

(gal) Rate (gal/hr) 

	 Rupture due to 16,800 Containment 

lightning strike, Bear Creek. berm 

seam failure 

24 

valves Bear Creek. 

1,260 

production) Bear Creek. 

Gun barrel	 21,000 Containment 

lightning strike, Bear Creek. berm 

seam failure 

42 

valves Bear Creek. 

7,140 Containment 

production) Bear Creek. berm 

Rupture/failure 3,570 Containment 

due to corrosion Bear Creek. berm 

Barrel 

Pinhole leak, or 48 

leak at Bear Creek. 

connection 

	 Rupture/failure 3,570 None; See Oil 

associated wi due to corrosion Bear Creek.	 Spill 

Contingency 

Plan 

Potential Discharge Volume and Direction of Flow [112.7(b)] and 

Source Type of failure Maximum Maximum Direction of Flow Containment 

Discharge 

Tank Battery 

Crude Oil Storage Tank 16,800 Southeast towards Big 

Leak at manway, 1 Southeast towards Big 

Overflow (1 day’s 53 Southeast towards Big 

Rupture due to 21,000 Southeast towards Big 

Leak at manway, 2 Southeast towards Big 

Overflow (1 day’s 298 Southeast towards Big 

Flowlines and Piping 

Flowlines and Piping on 148 Southeast towards Big 

Storage Tanks and Gun 

2 Southeast towards Big 

Flowlines and Piping 148 Southeast towards Big 

th wells 

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Volume 

(gal) Rate (gal/hr) 

Pinhole leak, or 48 
 

leak at 
 

connection 
 

None; See Oil 

Bear Creek. 	 Spill 

Contingency 

Plan 

Wells 

Polished rod stuffing box, Leak 24 
 

valves, fittings, gauges Bear Creek. 
 

Piping/hoses, pumps, Leak 24 Containment 
 

valves Bear Creek. berm 
 

Rupture 
 

hose Bear Creek. berm 
 

Offload line, connection Leak 42 
 

Bear Creek. berm 
 

	 1,680 Drainage ditch 
 

Bear Creek. 
 

	 3 Load line 

valve packing Bear Creek. container, curb 

Source Type of failure Maximum Maximum 

Discharge 

Direction of Flow Containment 

2 Southeast towards Big 

1 Southeast towards Big Well pad 

Saltwater Disposal 

1 Southeast towards Big 

Transfers and Loading Operations 

Transport truck loading 84 84 Southeast towards Big Downslope 

1 Southeast towards Big Downslope 

Tank truck Over-topping 1,680 Southeast towards Big 

while loading 

Transfer valve Rupture, leak of 3 Southeast towards Big 

3.2	 Containment and Diversionary Structures [112.7(c) and 112.7(a)(3)(iii)] 

The facility is configured to minimize the likelihood of a discharge reaching navigable waters. 

The following measures are provided: 

•	 Secondary containment for the oil storage tanks, saltwater tank (which may have 

small amounts of oil), and gun barrel is provided by a 60 ft x 40 ft x 2.5 ft earthen 

berm that provides a total containment volume of 867 barrels (36,423 gallons), as 

described in Section 3.2.2 below. The berm is constructed of native soils and 

heavy clay that have been compacted, then covered with gravel. A clay layer in 

the shallow subsurface exists naturally and will stop any spilled oil from seeping 

to deeper groundwater. 

•	 The tank truck loading area is flat but gently slopes to the southeast, where a 

crescent-shaped, open berm has been placed to catch any potential spills from 

tanker transport trucks. The bermed area provides a catchment basin of 40 

barrels (1,680 gallons), the maximum expected amount of a spill from the tanker 

due to overtopping of the truck during loading. In addition, the end of the load line 

is equipped with a load line drip bucket designed to prevent small discharges that 

may occur when disconnecting the hose. 

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•	 Booms, sorbents, shovels, and other discharge response materials are stored in 

a shed located in close proximity to the loading area. This material is sufficient to 

contain small discharges (up to approximately 200 gallons). 

These measures are described in more details in the following sections. 

3.2.1	 Oil Production Facility Drainage [112.9(b)] 

Facility drainage in the production/separation area but outside containment berms is designed 

to flow into drainage ditches located on the eastern and southern boundaries of the site. These 

ditches usually run dry. The ditches are visually examined by facility personnel on a daily basis 

during routine facility rounds, during formal monthly inspections, and after rain events, to detect 

any discoloration or staining that would indicate the presence of oil from small leaks within the 

facility. Any accumulation of oil is promptly removed and disposed off site. Formal monthly 

inspections are documented. 

Discharges from ASTs are restrained by the secondary containment berm, as described in 

Section 3.2.2 of this Plan. Discharges occurring during transfer operations will be contained at 

each well by the rock pad or will flow into the drainage ditch located at the facility. 

3.2.2	 Secondary Containment for Bulk Storage Containers [112.9(c)(2)] 

In order to further minimize the potential for a discharge to navigable waters, bulk storage 

containers such as all tank battery, separation, and treating equipment are placed inside a 2.5-ft 

tall earthen berm (fire wall). The berm capacity exceeds the SPCC and Louisiana requirements. 

It provides secondary containment sufficient for the size of the largest tank, plus at least 1 ft of 

freeboard to contain precipitation. This secondary containment capacity is equivalent to 173 

percent of the capacity of the largest tank within the containment area (500 barrels) and 

exceeds the 10 percent freeboard recommended by API for firewalls around production tanks 

(API-12R1). The amount of freeboard also exceeds the amount of precipitation anticipated at 

this facility, which is estimated to average 3.5 inches for a 24-hour, 25-year storm, based on 

data from the nearby Ridgeview Regional Airport. Details of the berm capacity calculation are 

provided in Table 3-2. 

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Table 3-2: Berm capacity calculations 
 

Berm Capacity 
 

Berm height 2.5 ft 

Berm dimensions 2 

B 122 2 

Net volume 2.5 ft x (2,400 - 452) 3

Ratio to largest tank 

100% of tank volume 3 

Net area (minus tank footprint) 2,400 ft2

 - 452 ft2 2 

Minimum berm height for 100% of tank volume 2,807 ft3

 / 1,948 ft2

60 ft x 40 ft = 2,400 ft

Tank footprint 4 tanks @ 12 ft dia. each = 4 x ( /4) = 452 ft

= 4,869 ft = 36,423 gallons 

36,423 / 21,000 = 173% 

Corresponding Amount of Freeboard 

21,000 gallons = 2,807 ft

 = 1,948 ft

 = 1.44 ft 

Freeboard 2.5 ft - 1.44 ft = 1.06 ft 

The floor and walls of the berm are constructed of compacted earth with a layer of clay that 

ensures that the berm is able to contain the potential release of oil from the storage tanks until 

the discharge can be detected and addressed by field operations personnel. Facility personnel 

inspect the berm daily for the presence of oil. The sides of the berm are capped with gravel to 

minimize erosion. 

The berm is equipped with a manual valve of open-and-closed design. The valve is used to 

drain the berm and is normally kept closed, except when draining water accumulation within the 

berm. Drainage from the berm flows into the drainage ditch to the south of the production/ 

separation area. All water is closely inspected by field operations personnel (who are the 

persons providing “responsible supervision”) prior to draining water accumulation to ensure that 

no free oil is present (i.e., there is no sheen or discoloration upon the surface, or a sludge or 

emulsion deposit beneath the surface of the water). The bypass valve for the containment 

structure is opened and resealed following drainage under the responsible supervision of field 

operations personnel. Free oil is promptly removed and disposed of in accordance with waste 

regulations. Drainage events are recorded on the form provided in Appendix D, including the 

time, date, and name of the employee who performed the drainage. The records are maintained 

with this SPCC Plan at the Ridgeview field office for a period of at least three years. 

3.2.3 Practicability of Secondary Containment [112.7(d)] 

Flowlines adjacent to the production equipment and storage tanks are located within the berm, 

and therefore have secondary containment. Aboveground flowlines that go from the wells to the 

production equipment and buried flowlines, however, lack adequate secondary containment. 

The installation of double-wall piping, berms, or other permanent structures (e.g., remote 

impoundment) are impracticable at this facility due to the long distances involved and physical 

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and road/fenceline right-of-way constraints. Additionally, such permanent structures would 

create land erosion and access problems for the landowner’s farming operations and current 

uses of the land (e.g., agricultural production, animal grazing). 

Other measures listed under 40 CFR 112.7(c) such as the use of sorbents are also 

impracticable as means of secondary containment since the volumes involved may exceed the 

sorbent capacity and the facility is attended for only a few hours each day. 

Because secondary containment for flowlines outside of the tank battery is impracticable, 

Clearwater has provided with this Plan additional elements required under 40 CFR 112.7(d), 

including: 

•	 A written commitment of manpower, equipment, and materials required to 

expeditiously control and remove any quantity of oil discharged that may be 

harmful (see Appendix H). 

•	 An Oil Spill Contingency Plan following the provisions of 40 CFR 109 (see 

Appendix I). 

3.3	 Other Spill Prevention Measures 

3.3.1	 Bulk Storage Containers Overflow Prevention [112.9(c)(4)] 

The tank battery is designed with a fail-safe system to prevent discharge, as follows: 

•	 The capacity of the oil storage tanks is sufficient to ensure that oil storage is 

adequate in the event where facility personnel are unable to perform the daily 

visit to unload the tanks or the pumper is delayed in stopping production. The 

maximum capacity of the wells linked to the tank battery is approximately 600 

barrels per day. The oil tanks are sized to provide sufficient storage for at least 

two days. 

•	 The tanks are connected with overflow equalizing lines to ensure that a full tank 

can overflow to an adjacent tank. 

3.3.2	 Transfer Operations and Saltwater Disposal System [112.9(d)] 

All aboveground valves and piping associated with transfer operations are inspected daily by 

the pumper and/or tank truck driver, as described in Section 3.4 of this Plan. The inspection 

procedure includes observing flange joints, valve glands and bodies, drip pans, and pipe 

supports. The conditions of the pumping well polish rod stuffing boxes, and bleeder and gauge 

valves, are inspected monthly. 

Components of the produced water disposal system are inspected on a monthly basis by field 

operation personnel as described in Section 3.4 and following the checklist provided in 

Appendix C of this SPCC Plan. This includes the pumps and motors for working condition and 

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leaks, hoses, valves, flowlines, and the saltwater injection wellhead. Maintenance and operation 

of the well itself and the downhole injection comply with EPA’s and the state’s Underground 

Injection Control (UIC) rules and regulations (40 CFR parts 144-148). 

3.4 Inspections, Tests, and Records [112.7(e)] 

This Plan outlines procedures for inspecting the facility equipment in accordance with SPCC 

requirements. Records of inspections performed as described in this Plan and signed by the 

appropriate supervisor are a part of this Plan, and are maintained with this Plan at the 

Ridgeview field office for a minimum of three years. The reports include a description of the 

inspection procedure, the date of inspection, whether drainage of accumulated rainwater was 

required, and the inspector’s signature. 

The program established in this SPCC Plan for regular inspection of all oil storage tanks and 

related production and transfer equipment follows the American Petroleum Institute’s 

Recommended Practice for Setting Maintenance, Inspection, Operation, and Repair of Tanks in 

Production Service (API RP 12R1, Fifth Edition, August 1997). Each container is inspected 

monthly by field operation personnel as described in this Plan section and following the 

checklist provided in Appendix C of this SPCC Plan. The monthly inspection is aimed at 

identifying signs of deterioration and maintenance needs, including the foundation and support 

of each container. Any leak from tank seams, gaskets, rivets, and bolts is promptly corrected. 

This Plan also describes provisions for monitoring the integrity of flowlines through a 

combination of monthly visual inspections and periodic pressure testing or through the use of an 

alternate technology. The latter element is particularly important for this facility since flowlines 

do not have adequate secondary containment. 

The inspection program is comprised of informal daily examinations, monthly scheduled 

inspections, and periodic condition inspections. Additional inspections and/or examinations are 

performed whenever an operation alert, malfunction, shell or deck leak, or potential bottom leak 

is reported following a scheduled examination. Written examination/inspection procedures and 

monthly examination/inspection reports are signed by the field inspector and are maintained at 

the field office for a period of at least three years. 

3.4.1 Daily Examinations 

The facility is visited daily by field operations personnel. The daily visual examination consists of 

a walk through of the tank battery and around the wells. Field operations personnel check the 

wells and production equipment for leaks and proper operation. They examine all aboveground 

valves, polished rod stuffing boxes, wellheads, fittings, gauges, and flowline piping at the 

wellhead. Personnel inspect pumps to verify proper function and check for damage and 

leakage. They look for accumulation of water within the tank battery berms and verify the 

condition and position of valves. The storage tanks are gauged every day. A daily production 

report is maintained. All malfunctions, improper operation of equipment, evidence of leakage, 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Manager. 

Table 3-3: Scope of daily examinations 

Item 

Leaks 

Fl 

Leak 

Leaks 

Puddles containing spilled or leaked material 

Corrosion 

stained or discolored soil, etc. are logged and communicated to the Clearwater Field Operations 

Puddles containing spilled or leak material 

Cracks in metal 

Excessive soil or vegetation buildup against base 

Puddles containing spilled or leaked material 

Settling 

Gaps at base 

Corrosion (pitting, flaking) 

Settling 

Evidence of stored material seepage from valves or 

seals 

Evidence of oil seepage from pumping rod stuffing 

Facility Area Observations 

Storage Tanks (Oil 

and Produced water) 

Foundation problems 

owlines problems 

Wells 

SW Pumps Leaks at seals, flowlines, valves, hoses 

Tank liquid level gauged 

Drip marks, leaks from weld seams, base of tank 

Corrosion, especially at base (pitting, flaking) 

Cracks 

Evidence of leaks, especially at connections/collars 

boxes, wellhead and wellhead flowlines, valves, gauges 

3.4.2 Monthly Inspections 

Table 3-4 summarizes the scope of monthly inspections performed by field personnel. 

The monthly inspection covers the wellheads, flowlines, and all processing equipment. It also 

includes verifying the proper functioning of all detection devices, including high-level sensors on 

oil storage tanks, heater treater, and separators. Storage tanks are inspected for signs of 

deterioration, leaks, or accumulation of oil inside the containment area, or other signs that 

maintenance or repairs are needed. The secondary containment area is checked for proper 

drainage, general conditions, evidence of oil, or signs of leakage. The monthly inspection also 

involves visually inspecting all aboveground valves and pipelines and noting the general 

condition of items such as transfer hoses, flange joints, expansion joints, valve glands and 

bodies, catch pans, pipeline supports, pumping well pumping rod stuffing boxes, bleeder and 

gauge valves, locking of valves, and metal surfaces. 

The checklist provided in Appendix C is used during monthly inspections. These inspections are 

performed in accordance with written procedures such as API standards (e.g., API RP 12R1), 

engineering specifications, and maintenance schedule developed by the equipment 

manufacturers. 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

results are maintained with this Plan at Clearwater’s field office. Testing of the safety devices is 

conducted in accordance with guidelines API RP-14C published by the American Petroleum 

Institute, or in accordance with instructions from the device’s manufacturer. Written test 

request. 

Twice a year, facility personnel drive to the pre-established response staging areas located at 

three different points along Big Bear Creek (see Oil Spill Contingency Plan in Appendix I) to 

ensure that the dirt/gravel roads are accessible using field vehicles and that the Oil Spill 

Creek. 

Table 3-4: Scope of monthly inspections 

Equipment 

Storage tanks 

Area 

Offload lines, drip pans, 

valves, catchment berm 

Production equipment 


 

Leakage, gaskets, hatches 
 


 


 

Vacuum vents 
 


 

Piping, valves, and bull plugs 
 

Corrosion, paint condition 
 


 


 

Pressure relief valves* 
 

Berm and curbing 
 


 

Excessive vegetation 
 

Equipment protectors and signs 
 

Engine drip pans and sumps 
 

General housekeeping 
 

Valve closed and in good condition 
 

Cap or bull plug at end of offload line/connection 
 


 


 

Sign of oil in surrounding area 
 


 


 

Pressure relief valves* 
 

Area Spills and leaks (e.g., stuffing box) 
 

Equipment protectors and signs 
 

General housekeeping 
 

All safety devices are tested quarterly by a third party inspector. The tests are recorded and the 

procedures are kept at the offices of the third party testing company and are available upon 

Contingency Plan can be implemented in the event of a discharge from flowlines reaching the 

Facility Area Inspection Item 

Tank Battery 

Truck Loading 

Emergency shut-down system(s)* 

Tank liquid level checked 

Tank welds in good condition 

Overflow lines 

Pressure / level safety devices* 

Emergency shut-down system(s)* 

Presence of contaminated/stained soil 

Sign of oil or standing water in drip pan(s) 

Sign of oil or standing water in catchment berm 

Gauges (pressure, temperature, and liquid level) 

Pressure / level safety devices* 

Wells (including 

saltwater disposal 

well) 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Equipment 

Leasehold area 

Other	 

Oils 

Response staging Area 

areas 

Exposed line of buried piping 

connections/collars 

Corrosion (pitting, flaking) 

Pipe supports 

Storage conditions 

Area clear of excessive vegetation 

Facility Area 

Flowlines 

between wells and 

Tank Battery 

Road and Field Ditches 

Chemicals, Fuels and Lube 

* Tested quarterly by third party inspection company. 

Inspection Item 

Flowline between the well and tank battery/gun barrel 

Valves (condition of, whether locked or sealed) 

Evidence of leaks and/or damage, especially at 

Evidence/puddles of crude oil and/or produced water 

Road practicable by field vehicle 

3.4.3 Periodic Condition Inspection of Bulk Storage Containers 

A condition inspection of bulk storage containers is performed by a qualified inspector according 

to the schedule and scope specified in API RP 12R1. The schedule is determined based on the 

corrosion rate; with the first inspection performed no more than 15 years after the tank 

construction, as detailed in Table 3-5. 

Three bulk storage containers installed at this facility were moved from another facility 

decommissioned by Clearwater. These bulk storage containers were leak tested after relocation 

to the facility. 

Table 3-5: Schedule of periodic condition inspection of bulk storage containers 

#1 1983 11/5/1998 11/5/2008* 

#2 2002 None Fi 

#3 1995 None Fi 

#4 2002 None Fi 

#5 1991 None Fi 

Tank Year Built Last Inspection Next inspection by 

rst inspection to be performed by 12/31/2017* 

rst inspection to be performed by 12/31/2010* 

rst inspection to be performed by 12/31/2017* 

rst inspection to be performed by 12/31/2006* 

* Dates for subsequent external inspections must follow the recommendations of the certified inspector, not to exceed 

three-quarters of the predicted shell/roof deck corrosion rate life, or maximum of 15 years. 

3.4.4 Brittle Fracture Evaluation [112.7(i)] 

At the present time, none of the bulk storage containers at this site was field-erected, and 

therefore no brittle fracture evaluation is required. 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

3.4.5 

Because the facility is relying on a contingency plan to address discharges, the flowline 

maintenance program is specifically implemented to maintain the integrity of the primary 

container (in this case piping) to minimize releases of oil from this part of the production facility. 

The facility’s gathering lines and flowlines are configured, inspected monthly for leaks at 

connections and on each joint, corrosion (pitting, flaking), and maintained to minimize the 

potential for a discharge as summarized in Table 3-6. Records of integrity inspections, leak 

tests, and part replacements are kept at the facility for at least three years (integrity test results 

are kept for ten years). 

Table 3-6: Components of flowline maintenance program 

Component 

Configuration • 

• 

• 

i 

l 

Inspection • 

• 

• 

l 

Maintenance • 

• 

retested, or replaced. 

Flowline Maintenance Program [112.9(d)(3)] 

Measures/Activities 

Well pumps are equipped w th low-pressure shut-off systems that detect 

pressure drops and minimize spill volume in the event of a flowline leak. 

Flowlines are identified on facility maps and are marked in the field to facilitate 

access and inspection by facility personnel. Flowline maps and field tags 

indicate the location of shutdown devices and valves that may be used to 

isolate portions of the flowline. 

With the exception of a portion of F owline B under an access road, the 

flowlines and appurtenances (valves, flange joints, supports) can be visually 

observed for signs of leakage, deterioration, or other damage. 

Lines are visually inspected for leaks and corrosion as part of the monthly 

rounds by field personnel, as discussed in Section 3.4 above. 

The buried portions of F owline B are coated/wrapped and visually observed 

for damage or coating condition whenever they are repaired, replaced, or 

otherwise exposed. 

Every five years, flowlines are tested using ultrasonic techniques to determine 

remaining wall thickness and mechanical integrity. Copies of test results are 

maintained at the facility for ten years to allow comparison of successive tests. 

Any leak in the flowline or appurtenances is promptly addressed by isolating 

the damaged portion and repairing or replacing the faulty piece of equipment. 

Clearwater does not accept pipe clamps and screw-in plugs as forms of repair. 

Any portion of a flowline that fails the mechanical integrity test is repaired and 

3.5 Personnel, Training, and Discharge Prevention Procedures [112.7(f)] 

The Field Operations Manager has been designated as the point of contact for all oil discharge 

prevention and response at this facility. 

All Clearwater field personnel receive training on proper handling of oil products and procedures 

to respond to an oil discharge prior to entering any Clearwater production facility. The training 

ensures that all facility personnel understand the procedures described in this SPCC Plan and 

are informed of the requirements under applicable pollution control laws, rules and regulations. 

The training also covers risks associated with potential exposure to hydrogen sulfide (H2S) gas. 

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All Clearwater field personnel also receive an initial 40-hour HAZWOPER training (and 8-hour 

annual refresher training) as per OSHA standard. 

Clearwater ensures that all contractor personnel are familiar with the facility operations, safety 

procedures, and spill prevention and control procedures described in this Plan prior to working 

at the facility. All contractors working at the facility receive a copy of this SPCC Plan. Avonlea 

personnel visiting the facility receive training similar to that provided to Clearwater oil handling 

employees. 

Clearwater management holds briefings with field operations personnel (including contractor 

personnel as appropriate) at least once a year, as described below. 

3.5.1	 Spill Prevention Briefing 

The Field Operations Manager conducts Spill Prevention Briefings annually to ensure adequate 

understanding and effective implementation of this SPCC Plan. These briefings highlight and 

describe known spill events or failures, malfunctioning components, and recently developed 

precautionary measures. The briefings are conducted in conjunction with the company safety 

meetings. Sign-in sheets, which include the topics of discussion at each meeting, are 

maintained with this Plan at Clearwater’s field office. A Discharge Prevention Briefing Log form 

is provided in Appendix E to this Plan and is used to document the briefings. The scheduled 

annual briefing includes a review of Clearwater policies and procedures relating to spill 

prevention, control, cleanup, and reporting; procedures for routine handling of products (e.g., 

loading, unloading, transfers); SPCC inspections and spill prevention procedures; spill reporting 

procedures; spill response; and recovery, disposal, and treatment of spilled material. 

Personnel are instructed in operation and maintenance of equipment to prevent the discharge of 

oil, and in applicable federal, state, and local pollution laws, rules, and regulations. Facility 

operators and other personnel have an opportunity during the briefings to share 

recommendations concerning health, safety, and environmental issues encountered during 

facility operations. 

The general outline of the briefings is as follows: 

•	 Responsibilities of personnel and Designated Person Accountable for Spill 

Prevention; 

•	 Spill prevention regulations and requirements; 

•	 Spill prevention procedures; 

•	 Spill reporting and cleanup procedures; 

•	 History/cause of known spill events; 

•	 Equipment failures and operational issues; 

•	 Recently developed measures/procedures; 

•	 Proper equipment operation and maintenance; and 

•	 Procedures for draining rainwater from berms. 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

3.5.2 Contractor Instructions 

In order that there will be no misunderstanding on joint and respective duties and 

responsibilities to perform work in a safe manner, contractor personnel also receive instructions 

on the procedures outlined in this SPCC Plan. The instructions cover the contractor activities 

such as servicing a well or equipment associated with the well, such as pressure vessels. 

All contractual agreements between Clearwater and contractors specifically state: 

Personnel must, at all times, act in a manner to preserve life and property, and prevent 

pollution of the environment by proper use of the facility’s prevention and containment 

systems to prevent hydrocarbon and hazardous material spills. No pollutant, regardless of 

the volume, is to be disposed of onto the ground or water, or allowed to drain into the 

ground or water. Federal regulations impose substantial fines and/or imprisonment for 

willful pollution of navigable waters. Failure to report accidental pollution at this facility, or 

elsewhere, can be cause for equally severe penalties to be imposed by federal 

regulations. To this end, all personnel must comply with every requirement of this SPCC 

Plan, as well as taking necessary actions to preserve life, and property, and to prevent 

pollution of the environment. It is the contractor’s (or subcontractor’s) responsibility to 

maintain his equipment in good working order and in compliance with this SPCC Plan. 

The contractor (or subcontractor) is also responsible for the familiarity and compliance of 

his personnel with this SPCC Plan. Contractor and subcontractor personnel must secure 

permission from Clearwater’s Field Operations Manager before commencing any work on 

any facility. They must immediately advise the Field Operations Manager of any 

hazardous or abnormal condition so that the Field Operations Manager can take 

corrective measures. 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

APPENDIX A: Facility Diagrams 

Figure A-1: Site plan. 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Figure A-2: Production Facility Diagram. -31- Version 1.0, 11/28/2005 
Clearwater Oil Company, Ltd. SAMPLE Spill Prevention, Control, and 

Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

APPENDIX B: Tank Truck Loading Procedures 

Loading Tank Truck 

Make sure the vehicle tank is properly vented before starting to load or unload. If you are not 

certain that the trailer is properly vented, you must contact your supervisor and request 

permission to open the trailer dome before starting to load or unload. 

To Load from Storage Tank to Tank Truck 

•	 Attach ground cable or bonding clamp to trailer. 

•	 Use wheel chocks or other similar barrier to prevent premature departure. 

•	 Hook up load hose and open all appropriate valves from storage tank to trailer 

entry. 

•	 Disengage clutch and place pump in load position. 

•	 Release clutch slowly. 

•	 Adjust throttle to proper engine RPM. 

•	 When trailer is loaded to appropriate level, slow engine speed. 

•	 Close valve to storage tank. 

•	 Loosen loading hose to allow enough air to drain loading hose dry. 

•	 Ensure that drips from the hose drain into the spill bucket at the loading area. 

•	 Disconnect loading hose completely, close load valve, plug and fasten securely. 

•	 Close belly valve on trailer. 

•	 Disconnect ground cable. 

•	 Promptly clean up any spilled oil. 

•	 Inspect lowermost drains and valves of the vehicle for discharges/leaks and 

ensure that they are tightened, adjusted, or replaced as needed to prevent 

discharges while vehicle is in transit. 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

APPENDIX C: Monthly Inspection Checklist 

Further description and comments, if needed, should be provided on a separate sheet of paper and attached to this 

sheet. Any item answered “YES” needs to be promptly reported, repaired, or replaced, as it may result in noncompliance with regulatory requirements. Records are maintained w th the SPCC Plan at the Ridgeview field office. i

Date: _________________ 	 Signature: ____________________________ 

Yes 	 Description & Comments 

(Note tank/equipment ID) 


 


 

Bolts, rivets or seams are damaged 
 


 


 

Gaskets are leaking 
 

Level gauges or alarms are inoperative 
 

Vents are obstructed 
 


 


 

Berm is breached or eroded or has vegetation 
 

Berm drainage valves are open/broken 
 


 

Equipment protectors, labels, or signs are missing 
 

Valve seals or gaskets are leaking. 
 


 

Buried pipelines are exposed. 
 


 

Connections are not capped or blank-flanged 
 

Secondary containment is damaged or stained 
 


 

needs replacement 
 

No 

Storage tanks and Separation Equipment 

Tank surfaces show signs of leakage 

Tanks show signs of damage, rust, or deterioration 

Aboveground tank supports are deteriorated or buckled 

Aboveground tank foundations have eroded or settled 

Thief hatch and vent valve does not seal air tight 

Containment berm shows discoloration or stains 

Tank area clear of trash and vegetation 

Piping/Flowlines and Related Equipment 

Pipelines or supports are damaged or deteriorated. 

Transfer equipment 

Loading/unloading lines are damaged or deteriorated. 

Response Kit Inventory 

Discharge response material is missing or damaged or 

Additional Remarks (attach sheet as needed): 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

APPENDIX D: Record of Dike Drainage 

This record must be completed when rainwater from diked areas is drained into a storm drain or into an open 

watercourse, lake, or pond, and bypasses the water treatment system. The bypass valve must normally be sealed in 

closed position and opened and resealed following drainage under responsible supervision. Records are maintained 

with the SPCC Plan at the Ridgeview field office. 

Date Area Presence of 

Oil 

Time 

Started 

Time 

Finished 

Signature 

12/5/2003 Tank battery No oil 08:00 8:40 William Mackenzie 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

APPENDIX E: Discharge Prevention Briefing Log 

Date Instructor(s) 

12/5/2003 Scheduled refresher. All field personnel. 

11/25/2004 Scheduled refresher. All field personnel. 

Type of Briefing 

Helena Berry, Optimal H&S Inc. 

Bill Laurier 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

APPENDIX F: Discharge Notification Procedures 

Circumstances, instructions, and phone numbers for reporting a discharge to the National 

Response Center and other federal, state, and local agencies, and to other affected parties, are 

provided below. They are also posted at the facility in the storage shed containing the discharge 

response equipment. Note that any discharge to water must be reported immediately to the 

National Response Center. 

Field Operations Manager, Bill Laurier (24 hours) (405) 829-4051 

Agency / Organization Agency Contact Circumstances When to Notify 

Local Emergency (fire, explosion, or other hazards) 911 

Federal Agencies 

National Response 

Center 

EPA Region VI 

(Hotline) 

EPA Region VI 

Regional Administrator 

State Agencies 

Office of State Police, 

Transportation and 

Environmental Safety 

Section, Hazardous 

Materials Hotline 

Office of State Police, 

Transportation and 

Environmental Safety 

Section, Hazardous 

Materials Hotline 

Louisiana Department 

of Environmental 

Quality, Office of 

Environmental 

Compliance 

1-800-424-8802 	 Discharge reaching navigable 

waters. 

1-800-887-6063 
 

First Interstate Bank Discharge 1,000 gallons or 
 

Tower at Fountain more; or second discharge of 42 
 

Place gallons or more over a 12-month 
 

1445 Ross Avenue, period. 
 

12th floor, Suite 1200 
 

Dallas TX 75202 
 

225-925-6595 1) Injury requiring hospitalization 
 

or or fatality. 
 

1-877-925-6595 2) Fire, explosion, or other 
 

impact that could affect public 

safety. 

3) Release exceeding 24-hour 

reportable quantity. 

4) Impact to areas beyond the 

facility’s confines. 

225-925-6595 Discharges that pose 

or emergency conditions, 

1-877-925-6595 regardless of the volume 

discharged. 

225-763-3908 Discharges that do not pose 

or 225-342-1234 emergency conditions. 

(after business 

hours, weekends 

and holidays) 

Immediately (verbal) 

Immediately (verbal) 

Written notification within 

60 days (see Section 2.1 of 

this Plan) 

Immediately (verbal) 

Written notification to be 

made within 5 days. 

Within 1 hour of discovery 

(verbal). 

Written notification within 7 

working days. 

Within 24 hours of 

discovery (verbal). 

Written notification within 7 

working days. 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

	 

Local Agencies 

337-828-1960 

Committee ithin 7 

including to the air. 

Others 

Response/cleanup As needed 

contractors (800) 521-3211 

respond and cleanup. 

Armadillo Oil 

Removal Co. 

(214) 566-5588 

l (405) 235-6893 

(agricultural irrigation 

intake) 

As needed 

affect neighboring properties 

and irrigation intakes. 

Agency / Organization Agency Contact Circumstances When to Notify 

St. Anthony’s Parish 

Emergency Planning 

Any discharge of 100 lbs or Immediately (verbal) 

more that occur beyond the 

boundaries of the facility, Written notification w 

days. 

EZ Clean Any discharge that exceeds the 

capacity of facility personnel to 

Howard F eming Farm Any discharge that threatens to 

The person reporting the discharge must provide the following information: 

•	 Name, location, organization, and telephone number; 

•	 Name and address of the owner/operator; 

•	 Date and time of the incident; 

•	 Location of the incident; 

•	 Source and cause of discharge; 

•	 Types of material(s) discharged; 

•	 Total quantity of materials discharged; 

•	 Quantity discharged in harmful quantity (to navigable waters or adjoining 

shorelines); 

•	 Danger or threat posed by the release or discharge; 

•	 Description of all affected media (e.g., water, soil); 

•	 Number and types of injuries (if any) and damaged caused; 

•	 Weather conditions; 

•	 Actions used to stop, remove, and mitigate effects of the discharge; 

•	 Whether an evacuation is needed; 

•	 Name of individuals and/or organizations contacted; and 

•	 Any other information that may help emergency personnel respond to the 

incident. 

Whenever the facility discharges more than 1,000 gallons of oil in a single event, or discharges 

more than 42 gallons of oil in each of two discharge incidents within a 12-month period, the 

Manager of Field Operations must provide the following information to the U.S. Environmental 

Protection Agency’s Regional Administrator within 60 days: 

•	 Name of the facility; 

•	 Name of the owner or operator; 

•	 Location of the facility; 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

•	 Maximum storage or handling capacity and normal daily throughput; 

•	 Corrective actions and countermeasures taken, including a description of 

equipment repairs and replacements; 

•	 Description of facility, including maps, flow diagrams, and topographical maps; 

•	 Cause of the discharge(s) to navigable waters, including a failure analysis of the 

system and subsystems in which the failure occurred; 

•	 Additional preventive measures taken or contemplated to minimize possibility of 

recurrence; and 

•	 Other pertinent information requested by the Regional Administrator. 

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Discharge Notification Form 

*** Notification must not be delayed if information or individuals are not available. 

Facility:	 Clearwater Oil Company Big Bear Lease No. 2 Production Facility 

5800 Route 417, Madison, Louisiana 73506 

Date/time Release date: 

Release time: 

Duration: 

Description of Discharge 

Discovery date: 

Discovery time: 

Reporting Individual 

Location of discharge 

Equipment source 

Product 

Appearance and 

description 

Environmental conditions 

Impacts 

Quantity 

Receiving medium 

Describe circumstances 

of the release 

Assessment of impacts 

and remedial actions 

Disposal method for 

recovered material 

Action taken to prevent 

incident from reoccurring 

Safety issues 

Name: 

Tel. #: 

Latitude: 

Longitude: 

G piping 

G flowline 

G well 

G unknown 

G stock, flare 

G crude oil 

G saltwater 

G other* 

Wind direction: 

Wind speed: 

Released: 

G water** 

G land 

G other (describe): 

G Injuries 

G Fatalities 

G Evacuation 

Description: 

Description: 

Equipment ID: 

* Describe other: 

Rainfall: 

Current: 

Recovered: 

G Release confined to company property. 

G Release outside company property. 

** If water, indicate extent and body of water: 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

Notifications 

Name Date/time reported & Comments 

Response Coordinator 

Agency 

Company Spill 

National Response 

Center 

1-800-424-8802 

State police 

Parish Emergency 

Response Commission 

oil spill removal 

organization/cleanup 

contractor 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

APPENDIX G: Equipment Shut-off Procedures 

Manifold, transfer i 

pumps or hose failure header/manifold or appropriate valve(s). Shut off transfer pumps. 

i 

valve(s) 

i 

Fl i 

Fl i 

Explosion or fire 

ith fire extinguishers 

available on site. 

Equipment failure 

Source Action 

Shut in the well supply ng oil to the tank battery if appropriate. Immediately close the 

Tank overflow Shut in the well supply ng oil to the tank battery. Close header/manifold or appropriate 

Tank failure Shut in the well supply ng oil to the tank battery. Close inlet valve to the storage tanks. 

owline rupture Shut in the well supply ng oil to the flowline. Close nearest valve to the rupture site to 

top the flow of oil. 

owline leak Shut in the well supply ng oil to the flowline. Immediately close the nearest valve to stop 

the flow of oil to the leaking section. 

Immediately evacuate personnel from the area until the danger is over. Immediately 

shut in both wells if safe to do so. If possible, close all manifold valves. If the fire is 

small enough such that it is safe to do so, attempt to extinguish w 

Immediately close the nearest valve to stop the flow of oil into the leaking area. 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

APPENDIX H: Written Commitment of Manpower, 

Equipment, and Materials 

In addition to implementing the preventive measures described in this Plan, Clearwater will also 

specifically: 

•	 In the event of a discharge: 

•	 Make available all trained field personnel (three employees) to perform response 

actions 

•	 Obtain assistance from an additional three full-time employees from its main 

operations contractor (Avonlea Services) 

•	 Collaborate fully with local, state, and federal authorities on response and 

cleanup operations 

•	 Maintain all on-site oil spill control equipment described in this Plan and in the attached 

Oil Spill Contingency Plan. The equipment is estimated to contain oil spills of up to 500 

gallons. 

•	 Maintain all communications equipment in operating condition at all times. 

•	 Ensure that staging areas to be used in the event of a discharge to Big Bear Creek are 

accessible by field vehicles. 

•	 Review the adequacy of on-site and third-party response capacity with pre-established 

response/cleanup contractors on an annual basis and update response/cleanup 

contractor list as necessary. 

•	 Maintain formal agreements/contracts with response and cleanup contractors who will 

provide assistance in responding to an oil discharge and/or completing cleanup (see 

contract agreements maintained separately at the Ridgeview field office and lists of 

associated equipment and response contractor personnel capabilities). 

Authorized Facility Representative: Bill Laurier 
 
 

Signature: 
 
 

Title: Field Operations Manager
 
 

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Big Bear Lease No. 2 Production Facility Countermeasure (SPCC) Plan 

APPENDIX I: Oil Spill Contingency Plan 

The oil spill contingency plan is maintained separately at the Ridgeview field office. 

[Refer to the sample Contingency Plan also available from EPA for more information on the 

content and format of that Plan] 

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Appendix F 

APPENDIX F: SAMPLE CONTINGENCY PLAN
 


U.S. Environmental Protection Agency Version 1.0, 11/28/2005 
DISCLAIMER - APPENDIX F 

The sample Contingency Plan in Appendix F is intended to provide examples of 

contingency planning as a reference when a facility determines that the required secondary 

containment is impracticable, pursuant to 40 CFR §112.7(d). The sample Contingency Plan 

presents a variety of scenarios for purposes of illustration only. It is not a template to be 

adopted by a facility; doing so does not mean that the facility will be in compliance with the 

SPCC rule requirements for a contingency plan. Nor is the sample plan a template that must be 

followed in order for the facility to be considered in compliance with the contingency plan 

requirement. 

Version 1.0, 11/28/2005 
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Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
 

CLEARWATER OIL COMPANY
 


BIG BEAR LEASE NO. 2 P RODUCTION FACILITY
 


OIL SPILL CONTINGENCY PLAN
 


NOTE: Throughout this document, shaded 

boxes identify relevant sections of 40 CFR 

part 109 and part 112. PART I 

Introduction 

1.1 Purpose and Scope 

This Oil Spill Contingency Plan is prepared in accordance with 40 CFR 112.7(d) to 

address areas of the facility where secondary containment is impracticable, as 

documented in the facility Spill Prevention, Control, and Countermeasure (SPCC) Plan. 

The purpose of this Oil Spill Contingency Plan (“Contingency Plan”) is to define 

procedures and tactics for responding to discharges of oil into navigable waters or 

adjoining shorelines of the United States, originating more specifically from flowlines at 

Clearwater Oil Company (“Clearwater”) Big Bear Lease No. 2 Production Facility. The 

Contingency Plan is implemented whenever a discharge of oil has reached, or threatens, 

navigable waters or adjoining shorelines. 

The objective of procedures described in this Contingency Plan is to protect the public, 

Clearwater personnel, and other responders during oil discharges. In addition, the Plan 

is intended to minimize damage to the environment, natural resources, and facility 

installations from a discharge of oil. This Oil Spill Contingency Plan complements the 

prevention and control measures presented in the facility’s SPCC Plan by addressing 

areas of the facility that have inadequate secondary containment and impacts that may 

result from a discharge from these areas. The facility implements a detailed and 

stringent flowline maintenance program to prevent leaks from the primary system (in this 

case, piping). Areas lacking adequate containment at the Big Bear Lease No. 2 

Production Facility include the flowlines that run between the extraction wells and the 

tank battery area and between the tank battery area and the saltwater disposal area. 

This Oil Spill Contingency Plan follows the content and organization of 40 CFR part 109 

and describes the distribution of responsibilities and basic procedures for responding to 

an oil discharge and performing cleanup operations. 

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1.2 Resources at Risk 

40 CFR 109.5(b)(1) Clearwater’s Big Bear Lease No. 2 Production Facility is located approximately 6 miles 

North of Madison, LA, within the Mines River watershed (see Figure C-1 in Appendix C). 

The waterways closest to the facility are Big Bear Creek, which flows approximately 1⁄2 

mile to the east of the facility, and the Mines River, which flows 6 miles to the south in a 

west-to-east direction and receives water from Big Bear Creek. The facility diagram 

included in Appendix C (Figure C-2) indicates the location of the oil extraction, 

production, and storage areas. Ground cover at the facility consists of compacted soil, 

gravel, and low lying vegetation. The natural topography of the land is graded in an eastsoutheast direction, and all surface drainage from the facility therefore flows towards Big 

Bear Creek. The slope is relatively mild: approximately 4 feet vertical per mile (5,280 

feet) horizontal. 

Three flowlines (which contain oil) at the facility lack adequate secondary containment 

(see Figure C-2): 

•	 Flowline A. The flowline from Well A to the tank battery (FLA) is approximately 

2,100 feet long. It runs aboveground in a north-south direction to the tank battery 

area. 

•	 Flowline B. The flowline between Well B and the tank battery (FLB) is 

approximately 3,400 feet long. It travels in a southwest direction to the tank 

battery area. This flowline runs the closest to navigable waters. At the closest 

point, the flowline is located 1⁄2 mile from Big Bear Creek. 

•	 Flowline SWD. The flowline between the tank battery and the saltwater disposal 

well is approximately 2,000 feet long. It runs in an east-west direction. 

All three flowlines are aboveground, with the exception of a short portion of Flowline B 

that is buried under the dirt/gravel access road. A drainage ditch runs along the access 

road to the east of the tank battery and along Route 417. The ditch flows into Big Bear 

Creek. Given the direction of surface drainage, a discharge from any of the three 

flowlines could reach Big Bear Creek, either directly or via the drainage ditch, and from 

there, flow southward to the Mines River. 

Neither Big Bear Creek nor the Mines River is used as a public drinking water supply, 

although animals grazing on the nearby land are often seen drinking from Big Bear 

Creek and the Howard Fleming Farm has an agricultural irrigation intake on Big Bear 

Creek (see the Notification Form later in this Plan for contact information). The two 

waterways, however, provide habitat for a number of aquatic species and mammals and 

are used by local residents for recreational purposes. The Mines River runs through the 

center of Madison. Recreational and scenic areas are located on both banks of the river. 

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A public park is located approximately 1 mile east from the town center and 8 miles from 

the facility. Recreational uses on the Mines River include picnic areas, walking trails, 

canoeing, and nature watching. 

There are no residences within the immediate vicinity of the facility. The closest 

residence is located 1 mile to the north of the site, upstream on Big Bear Creek. The 

closest residence downstream from the site is located 3 miles away. Both residences 

have private drinking water wells. Clearwater will coordinate with the Madison fire and/or 

police departments and with its residential neighbors to provide the appropriate warnings 

in the event of a discharge that could affect public health and safety. 

1.3 Risk Assessment 

The facility is comprised of approximately 7,500 feet of 2-inch diameter flowlines. With 

the exception of a short road crossing, the flowlines are located aboveground. The 

flowlines do not have secondary containment, since such containment is impracticable at 

this facility (see discussion on impracticability of secondary containment in the facility’s 

SPCC Plan). 

40 CFR 109.5(c)(2) The total daily production rate at the facility varies, but can reach as much as 1,260 

gallons of crude oil and 5,880 gallons of produced water. The two wells have 

approximately equal production rates (each 3,570 gallons per day). Flowline B, the 

longest of the three flowlines and the one closest to navigable waters, contains up to 

555 gallons of oil/water when charged. The facility is visited daily. For planning 

purposes, the worst-case discharge is therefore the volume of oil within the flowline plus 

24 hours of production, or 4,125 gallons. 

A discharge of this quantity of oil could potentially reach Big Bear Creek. The velocity of 

oil over land is estimated, based on past experience and a simple calculation of flow 

over short grass pastureland, at approximately 0.2 feet/second.1

 Considering the 

distance between Flowline B and Big Bear Creek (1⁄2 mile) and the 2-foot elevation 

gradient, the oil, if unimpeded, could reach Big Bear Creek in as little as 4 hours. The 

water current in Big Bear Creek averages approximately 0.3 feet/second during high 

stages. Over a 24-hour period, the oil could travel approximately 5 miles downstream 

from the release point. The Mines River, which is located only 6 miles downstream to the 

south of the tank battery area, could therefore possibly be affected by a discharge. 

1

 Calculated using sheet flow transport equations. 

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1.4 Response Strategy 

Clearwater personnel and contractors are equipped and trained to respond to certain 

“minor discharges” confined within the facility. Minor discharges can generally be 

described as those where the quantity of product discharged is small, the discharged 

material can be easily stopped and controlled, the discharge is localized, and the 

product is not likely to seep into groundwater or reach surface water or adjoining 

shorelines. Procedures for responding to these minor discharges are covered in the 

SPCC Plan. 

This Contingency Plan addresses all discharge incidents, including those that affect 

navigable waters or during which the oil cannot be safely controlled by facility personnel 

and confined within the boundaries of the facility. Response to such incidents may 

necessitate the assistance of outside contractors or other responders to prevent 

imminent impact to navigable waters. 

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PART II 

Spill Discovery and Response 

2.1 
 Distribution of Responsibilities 

40 CFR 109.5(a) 

40 CFR 109.5(d)(2) 

Clearwater has the primary responsibility for providing the initial response to oil 

discharge incidents originating from its facility. To accomplish this, Clearwater has 

designated the Field Operations Manager, Bill Laurier, as the qualified oil discharge 

Response Coordinator (RC) in the event of an oil discharge. 

The RC plays a central coordinating role in any emergency situation, as illustrated in the 

emergency organization chart in Figure 2-1. 

40 CFR 109.5(b)(2) 

The RC has the authority to commit the necessary services and equipment to respond to 

the discharge and to request assistance from Madison fire and/or police departments, 

contractors, or other responders, as appropriate. 

The RC will direct notifications and initial response actions in accordance with training 

and capabilities. In the event of a fire or emergency situation that threatens the health 

and safety of those present at the site, the RC will direct evacuations and contact the fire 

and police departments. 

In the event of an emergency involving outside response agencies, the RC’s primary 

responsibility is to provide information regarding the characteristics of the materials and 

equipment involved and to provide access to Clearwater resources as requested. The 

RC shall also take necessary measures to control the flow of people, emergency 

equipment, and supplies and obtain the support of the Madison Police Department as 

needed to maintain control of the site. These controls may be necessary to minimize 

injuries and confusion. 

Finally, the RC serves as the coordinator for radio communications by acquiring all 

essential information and ensuring clear communication of information to emergency 

response personnel. The RC has access to reference material at the field office either as 

printed material or on computer files that can further assist the response activities. 

Whenever circumstances permit, the RC transmits assessments and recommendations 

to Clearwater Senior Management for direction. Senior Management is contacted in the 

following order: (1) Regional Director of Operations; (2) Vice-President of Operations. 

In the event that the Field Operations Manager is not available, the responsibility and 

authority for initiating a response to a discharge rests with the most senior Clearwater 

employee on site at the time the discharge is discovered (Crew Lead) or with the 

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contractor Field Supervisor (or next person in command) if contractor personnel are the 

only personnel on site. 

Figure 2-1. Distribution of response authority and communication. 

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2.2 Response Activities 

2.2.1	 

40 CFR 109.5(d) 

40 CFR 109.5(e) 

In the event of a discharge, the first priority is to stop the product flow and to shut off all 

ignition sources, followed by the containment, control, and mitigation of the discharge. 

This Contingency Plan breaks actions to be performed to respond to an oil discharge 

into different phases, described in greater detail in the checklists below. 

Minor Discharge. A minor discharge (i.e., small volume leak from flowlines or other 

equipment) will be discovered by Clearwater facility personnel or by contractor personnel 

during scheduled daily or monthly visits to the facility. Aboveground flowlines are visually 

inspected formally once a month during the normal inspection rounds. 

Major Discharge. A more severe and sudden discharge will trigger the automatic shut 

down of the pumping units and will affect oil production. The impact will be detected 

during the daily visit to the production area by Clearwater or contractor field personnel. 

The maximum amount of time until a major discharge is detected can be up to 24 hours. 

Notifications to the National Response Center, Louisiana authorities, and St. Anthony’s 

Parish Emergency Committee must occur immediately upon discovery of reportable 

discharges. 

Completed 

Immediately report the discharge to the RC, providing the following information: 

• 

• 

• 

• Topographic and environmental conditions; 

• 

• Injuries, if any. 

Turn off all sources of ignition. 

Turn off lift pumps that charge or provide flow to the flowline. 

Locate the flowline break. 

If safe to do so, isolate the affected section of piping by closing off the closest 

valves upstream and downstream from the break. 

Discharge Discovery and Source Control 

Actions 

Exact location; 

Material involved; 

Quantity involved; 

Circumstances that may hinder response; and 

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2.2.2 Assessment and Notifications 

Completed 

Investigate the discharge to assess the actual or potential threat to human health 

or the environment: 

• Location of the discharge relative to receiving waterbodies; 

• 

• 

• 

• 

Request outside assistance from local emergency responders, as needed. 

Evaluate the need to evacuate facility and evacuate employees, as needed. 

Notify the fire/police departments and St. Anthony’s Parish Emergency Committee 

to assess whether community evacuation is needed. 

Notify immediately: 

• 911 

• 

• 

• 

• 

Communicate with neighboring property owners regarding the discharge and 

actions taken to mitigate the damage. 

If the oil reaches (or threatens to reach) the Mines River, notify the local fire/police 

departments to limit access to the River by local residents until the oil has been 

contained and recovered. 

Additionally, notify downstream water users of the spill and of actions that will be 

taken to protect these downstream receptors. 

Actions 

Quantity of spilled material; 

Ambient conditions (temperature, rain); 

Other contributing factors such as fire or explosion hazards; and 

Sensitive receptors downstream. 

National Response Center 

Response contractor(s) 

St. Anthony’s Parish Emergency Planning Committee 

State authorities 

2.2.3 Control and Recovery 

The RC directs the initial control of the oil flow by Clearwater, Avonlea Oil Services, and 

other contractor personnel. The actions taken will depend on whether the oil has 

reached water or is still on land. All effort will be made to prevent oil from reaching water. 

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If the oil has not yet reached water: 

Completed 

Deploy sand bags and absorbent socks downgradient from the oil, or erect 

temporary barriers such as trenches or mounds to prevent the oil from flowing 

towards Big Bear Creek. 

Implement land based response actions (countermeasure) such as digging 

temporary containment pits, ponds, or curbs to prevent the flow of oil into the 

river. 

Deploy absorbent sock and sorbent material along the shoreline to prevent oil 

from entering waters. 

Completed 

Contact cleanup contractor(s). 

Creek is narrow and shallow. Floating boom deployment does not require the use 

of a boat. 

Control oil flow on the ground by placing absorbent socks and other sorbent 

material or physical barriers (e.g., “kitty litter,” sandbags, earthen berm, trenches) 

across the oil flow path. 

Deploy additional floating booms across the whole width of the Creek at the next 

access point downstream from the release point. Access points and staging areas 

along the shoreline are identified on Figure C-1 of this Contingency Plan. 

Deploy protective booming measures for downstream receptors that may be 

impacted by the spill. 

If the oil has reached water: 

Actions 

Actions 

Deploy floating booms immediately downstream from the release point. Big Bear 

2.2.4 Disposal of Recovered Product and Contaminated Response Material 

The RC ensures that all contaminated materials classified as hazardous waste are 

disposed of in accordance with all applicable solid and hazardous waste regulations. 

Completed 

Place any recovered product that can be recycled into the gun barrel tank to be 

separated and recycled. 

Dispose of recovered product not suitable for on-site recycling with the rest of the 

waste collected during the response efforts. 

Actions 

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Collect all debris in properly labeled waste containers (impervious bags, drums, or 

buckets). 

Dispose of contaminated material in accordance with all applicable solid and 

hazardous waste regulations using a licensed waste hauler and disposal facility, 

after appropriately characterizing the material for collection and disposal. 

Dispose of all contaminated response material within 2 weeks of the discharge. 

2.2.5 Termination 

The RC ensures that cleanup has been completed and that the contaminated area has 

been treated or mitigated according to the applicable regulations and state/federal 

cleanup action levels. The RC collaborates with the local, state and federal authorities 

regarding the assessment of damages. 

Completed 

Ensure that all repairs to the defective equipment or flowline section have been 

completed. 

Review circumstances that led to the discharge and take all necessary 

precautions to prevent a recurrence. 

Evaluate the effectiveness of the response activities and make adjustments as 

necessary to response procedures and personnel training. 

Carry out personnel and contractor debriefings as necessary to emphasize 

prevention measures or to communicate changes in operations or response 

procedures. 

Submit any required follow-up reports to the authorities. 

In the case where the discharge (as defined in 40 CFR 112.1(b)) was greater than 

1,000 gallons or was the second discharge (as defined in 40 CFR 112.1(b)) of 42 

gallons or more within any 12-month period, the RC is responsible for submitting 

following the procedures outlined in Appendix B. 

the required information within 60 days to the EPA Regional Administrator 

Within 30 days of the discharge, the RC will convene an incident critique including 

all appropriate persons that responded to the spill. The goal of the incident 

critique is to discuss lessons learned, the efficacy of the Contingency Plan and its 

implementation, and coordination of the plan/RC and other state and local plans. 

40 CFR 112.4(a) 

Within 60 days of the critique, the Contingency Plan will be updated (as needed) 

to incorporate the results, findings, and suggestions developed during the critique. 

Actions 

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2.3 Discharge Notification 

Instructions and phone numbers for reporting a discharge to the National Response 

Center and other federal, state, and local authorities are provided in Appendix B to this 

Plan. Any discharge to water must be reported immediately to the National Response 

Center. The Response Coordinator must ensure that details of the discharge are 

recorded on the Discharge Notification Form provided in Appendix B. 40 CFR109.5(b)(2) 

If the discharge qualifies under 40 CFR part 112 (see Appendix B for conditions), the RC 

is responsible for ensuring that all pertinent information is provided to the EPA Regional 

Administrator. 

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PART III 

Response Resources and Preparedness Activities 

3.1 Equipment, Supplies, Services, and Manpower 

40 CFR 109.5(c)(1) 

and (c)(2) 

Spill kits are provided in a storage shed at the production site that is accessible by both 

Clearwater and Avonlea personnel (see Figure C-2 in Appendix C). Response 

equipment and material present at the site include: 

(4) Empty 55-gallons drums to hold contaminated material 

(1) 50-ft absorbent socks 

(2) 10-ft sections of hard skirted deployment boom 

(2) 50-ft floating booms 

(200 pounds) “Oil-dry” Loose absorbent material 

(4 boxes) 2 ft x 3 ft absorbent pads 

(3 boxes) Nitrile gloves 

(3 boxes) Neoprene gloves 

(6 pairs) Vinyl/PVC pull-on overboots 

(3) Non-sparking shovels 

(3) Brooms 

(20) Sand bags 

(1) Combustible Gas Indicator with H2S detection capabilities 

This material is sufficient to respond to most minor discharges occurring at the facility 

and to initially contain a major discharge while waiting for additional material or support 

from outside contractors. The inventory is verified on a monthly basis during the 

scheduled facility inspection by designated personnel and is replenished as needed. 

40 CFR 109.5(d)(3) 

40 CFR 109.5(d)(2)	 

Additional material and equipment is kept at Clearwater’s field office, located 25 miles 

from the facility. This additional material includes empty storage drums, absorbent socks 

and booms, containment booms, sand bags, personal protective gear, etc. It also 

includes all necessary communication equipment to coordinate response activities (cell 

phones, two-way radios). The Field Office serves as the response operation center 

during a response. 

Clearwater has three employees trained and available to respond to an oil discharge. 

Clearwater personnel may be assisted by three additional employees from the facility’s 

main contractor, Avonlea Oil Services. All employees are familiar with the facility layout, 

location of spill response equipment and staging areas, and response strategies, and 

with the SPCC and Oil Spill Contingency Plans for this facility. All have received training 

in the deployment of response material and handling of hazardous waste (HAZWOPER) 

and have attended the required refresher courses. 

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40 CFR 109.5(c)(3) To respond to larger discharges and ensure the removal and disposal of cleanup debris, 

Clearwater has established agreements with two specialized cleanup contractors: 

EZClean and Armadillo Oil Removal, with EZClean contacted first and acting as the 

primary response/cleanup contractor and Armadillo Oil Removal acting as the alternate 

or in a supporting role. Contact information is provided in Appendix A. These contractors 

have immediate access to an assortment of equipment and materials, including 

mechanical recovery equipment for use on water and on land, small boats, floating 

booms, and large waste containers. Each contractor has sufficient response equipment 

to contain and recover the maximum possible discharge of 4,125 gallons. EZClean and 

Armadillo Oil Removal are able to respond within 4 hours of receiving a verbal request 

from the RC. Clearwater discusses response capacity needs on an annual basis with 

each contractor to ensure that sufficient equipment and material are available to respond 

to a potential 4,125-gallon discharge. The inventories of EZClean and Armadillo Oil 

Removal equipment are maintained with the response agreements and updated 

annually. 

3.2 Access to Receiving Waterbody 

40 CFR 109.5(d)(5) Big Bear Creek would be the first waterbody affected 

in the event of a discharge. From there, the oil would 

flow into the Mines River. The response strategy 

consists of: (1) deploying booms and other response 

equipment at various points downstream from the oil 

plume to prevent its migration; and (2) deploying 

booms as a protective measure for an irrigation water 

intake and other downstream sensitive receptors. 

Vehicular access to Big Bear Creek is essential to 

ensure that the response equipment can be effectively 

deployed to contain oil at various points along the Figure 3-2: Boom deployed waterway and prevent further migration of the oil across Big Bear Creek. towards the Mines River. 

Three access points have been established along Big 

Bear Creek and are marked on the map in Figure C-1 

(BB1, BB2, and BB3). These access points provide 

sufficient cleared land for a staging area from which 

Clearwater or contractor personnel can deploy 

response equipment, and recover and store spilled oil. 

Twice a year, as part of the monthly inspection of the 

facility, Clearwater facility personnel drive to each Figure 3-3: Boom deployed at access point and make sure that it remains Route 54 bridge crossing. accessible (e.g., vegetation is not overgrown and the 

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dirt trail is not impassable for a field vehicle). The respective property owners have agreed to 

allow access to Clearwater’s personnel and contractors for response and maintenance 

purposes. Although no further approval is needed prior to the deployment of response 

equipment, the RC will contact the property owners as necessary to inform them of activities 

being carried out. 

If necessary, three access points are also available along the Mines River. One is 

located in the center of Madison, at the bridge crossing for Route 101, the second is 

located at the public park two miles downstream from the center, and the third one is 

located at the bridge crossing for Route 54, four miles downstream from the center. 

Coordination with the Madison police/fire departments is necessary to stage equipment 

at these three access points. 

3.3	 Communications and Control 

40 CFR 109.5(b)(3) 

40 CFR 109.5(d)(3) 

A central coordination center will be set up at the field office in the event of a discharge. 

The field office is equipped with a variety of fixed and mobile communication equipment 

(telephone, fax, cell phones, two-way radios, computers) to ensure continuous 

communication with Clearwater management, responders, authorities, and other 

interested parties. 

Communications equipment includes: 

•	 Portable hand-held radios. Clearwater maintains a two-way base station and 

four portable radio units. These radio units are kept at the field office as part of 

the response equipment. Local emergency responders have been provided with 

the response frequencies that will be used during an incident. 

•	 Cell phones. Each field vehicle and the RC are provided with a cell phone. The 

RC and/or his alternate (Site Supervisor when the Field Operations Manager is 

not “on call”) can be reached by cell phone 7 days a week, 24 hours a day. 

•	 Additional equipment. Additional equipment will be obtained from EZClean 

and/or Armadillo Oil Removal in the event that more communications equipment 

is necessary. 

The RC is responsible for communicating the status of the response operations and for 

sharing relevant information with involved parties, including local, state, and federal 

authorities. 

In the event that local response agencies, Louisiana authorities, or a federal On Site 

Coordinator (OSC) assumes Incident Command, the RC will function as the facility 

representative in the Unified Command structure. 

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3.4 Training Exercises and Updating Procedures 

40 CFR 109.5(d)(1)	 Clearwater has established and maintains an ongoing training program to ensure that 

Clearwater personnel responding to oil discharges are properly trained and that all 

necessary equipment is available to them. The program includes on-the-job training on 

the proper deployment of response equipment and periodic practice drills during which 

Clearwater personnel are asked to deploy equipment and material in response to a 

simulated discharge. The RC is responsible for implementing and evaluating employee 

preparedness training. 

Following a response to an oil discharge, the RC will evaluate the actions taken and 

identify procedural areas where improvements are needed. The RC will conduct a 

briefing with field personnel, contractors, and local emergency responders to discuss 

lessons learned and will integrate the outcome of the discussion in subsequent SPCC 

briefings and employee training seminars. As necessary, the RC will amend this 

Contingency Plan or the SPCC Plan to reflect changes made to the facility equipment 

and procedures. A Professional Engineer will certify any technical amendment to the 

SPCC Plan. 

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40 CFR 109.5(b)(2) APPENDIX A 
 


EMERGENCY CONTACTS 
 


Title 

Bill Laurier 

Manager 

(405) 831-6322 (office) 

(405) 829-4051 (cell) 

2451 Mountain Drive 

Carol Campbell 

Operations 

(405) 831-6320 (office) 

(405) 831-2262 (cell) 

2451 Mountain Drive 

Lester Pearson 

Operations 

(555)-289-4500 13000 Main Street, Suite 

400 

Joe Clark 

Avonlea Services, Inc. 

(406) 545-2285 (office) 

(406) 549-9087 (cell) 

William Mackenzie Pumper 

Avonlea Services, Inc. 

(406) 549-9087 (cell) 

Avonlea, LA 70180 

Fire/Police Departments 911 

(405) 830-2000 

Emerson Hospital (405) 831-9558 

Cleanup Contractors 

(800) 521-3211 

Armadillo Oil Removal (214) 566-5588 

Maurice Richard (405) 830-2186 70180 BB1 

Jim Larouche (405) 832-2645 70180 BB2 

Peter Martin (405) 832-5527 70180 BB3 

(405) 235-6893 70180 

Facility Operations 

Name Telephone Address 

Field Operations 

Clearwater Oil Co. 

Ridgeview, LA 70180 

Regional Director of 

Clearwater Oil Co. 

Ridgeview, LA 70180 

Vice-President of 

Clearwater Oil Co. Houston, TX 77077 

Field Supervisor 786 Cherry Creek Road 

Avonlea, LA 70180 

786 Cherry Creek Road 

2451 Mountain Drive, Madison, LA 70180 

Local Emergency Responders 

Name Telephone Address 

13000 Main Street, Madison, LA 70180 

Name Telephone Address 

EZClean 1200 Industry Park Drive, Gardner, LA 70180 

25 B Street, Suite #6, Madison, LA 70180 

Neighboring Property Owners 

Name Telephone Address Location 

5540 Route 417, Madison, LA 

6075 Greenfield Drive, Madison, LA 

1644 Oilfield Road, Madison, LA 

Howard Fleming 531 Horseshoe Road, Madison, LA 

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Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
 
 

APPENDIX B 

DISCHARGE NOTIFICATION PROCEDURES 

Circumstances, instructions, and phone numbers for reporting a discharge to the National 

Response Center and other federal, state, and local agencies, and to other affected parties, are 

provided below. They are also posted at the facility in the storage shed containing the discharge 

response equipment. Note that any discharge to water must be reported immediately to the 

National Response Center. 

Field Operations Manager, Bill Laurier (24 hours) (405) 829-4051 

Local Emergency (fire, explosion, or other hazards) 911 

Agency / Organization Agency Contact Circumstances When to Notify 

Federal Agencies 

National Response 1-800-424-8802 

Center 

EPA Region VI 1-800-887-6063 

(Hotline) 

EPA Region VI 	 	 First Interstate Bank 

Regional Administrator 	 	 Tower at Fountain 

Place 

1445 Ross Avenue, 

12th floor, Suite 1200 

Dallas TX 75202 

State Agencies 

Office of State Police, 225-925-6595 

Transportation and or 

Environmental Safety 1-877-925-6595 

Section, Hazardous 

Materials Hotline 

Office of State Police, 225-925-6595 

Transportation and or 

Environmental Safety 1-877-925-6595 

Section, Hazardous 

Materials Hotline 

Discharge reaching navigable 

waters. 

Discharge 1,000 gallons or 

more; or second discharge of 42 

gallons or more over a 12-month 

period. 

1) Injury requiring hospitalization 

or fatality. 

2) Fire, explosion, or other 

impact that could affect public 

safety. 

3) Release exceeding 24-hour 

reportable quantity. 

4) Impact to areas beyond the 

facility’s confines. 

Discharges that pose 

emergency conditions, 

regardless of the volume 

discharged. 

Immediately (verbal) 

Immediately (verbal) 

Written notification within 

60 days (see Section 2.1 of 

this Plan) 

Immediately (verbal) 

Written notification to be 

made within 5 days. 

Within 1 hour of discovery 

(verbal). 

Written notification within 7 

working days. 

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Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
 
 

As needed 

Agency / Organization Agency Contact Circumstances When to Notify 

Louisiana Department 

of Environmental 

Quality, Office of 

Environmental 

Compliance 

225-763-3908 

or 225-342-1234 

(after business 

hours, weekends 

and holidays) 

Local Agencies 

St. Anthony’s Parish 337-828-1960 

Emergency Planning 

Committee 

Others 

Response/cleanup EZClean 

contractors (800) 521-3211 

Armadillo Oil 

Removal Co. 

(214) 566-5588 

Howard Fleming Farm (405) 235-6893 

(agricultural irrigation 

intake) 

Maurice Richard 405-830-2186 

Jim Larouche 405-832-2645 

Peter Martin 405-832-5527 

Discharges that do not pose 

emergency conditions 

Any discharge of 100 lbs or 

more that occurs beyond the 

boundaries of the facility, 

including to the air. 

Any discharge that exceeds the 

capacity of facility personnel to 

respond and clean up. 

Any discharge that threatens to 

affect neighboring properties 

and irrigation intakes. 

When deploying response 

equipment from Access Point 

BB1 on Big Bear Creek. 

When deploying response 

equipment from Access Point 

BB2 on Big Bear Creek. 

When deploying response 

equipment from Access Point 

BB3 on Big Bear Creek. 

Within 24 hours of 

discovery (verbal). 

Written notification within 7 

working days. 

Immediately (verbal) 

Written notification within 7 

days. 

As needed 

As needed 

As needed 

As needed 

The person reporting the discharge must provide the following information: 

•	 Name, location, organization, and telephone number 

•	 Name and address of the owner/operator 

•	 Date and time of the incident 

•	 Location of the incident 

•	 Source and cause of discharge 

•	 Types of material(s) discharged 

•	 Total quantity of materials discharged 

•	 Quantity discharged in harmful quantity (to navigable waters or adjoining 

shorelines) 

•	 Danger or threat posed by the release or discharge 

•	 Description of all affected media (e.g., water, soil) 

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Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
 

•	 Number and types of injuries (if any) and damaged caused 

•	 Weather conditions 

•	 Actions used to stop, remove, and mitigate effects of the discharge 

•	 Whether an evacuation is needed 

•	 Name of individuals and/or organizations contacted 

•	 Any other information that may help emergency personnel respond to the 

incident 

Whenever the facility discharges more than 1,000 gallons of oil in a single event, or discharges 

more than 42 gallons of oil in each of two discharge incidents within a 12-month period, the 

Manager of Field Operations must provide the following information to the U.S. Environmental 

Protection Agency’s Regional Administrator within 60 days: 

•	 Name of the facility 

•	 Name of the owner or operator 

•	 Location of the facility 

•	 Maximum storage or handling capacity and normal daily throughput 

•	 Corrective actions and countermeasures taken, including a description of 

equipment repairs and replacements 

•	 Description of facility, including maps, flow diagrams, and topographical maps 

•	 Cause of the discharge(s) to navigable waters, including a failure analysis of the 

system and subsystems in which the failure occurred. 

•	 Additional preventive measures taken or contemplated to minimize possibility of 

recurrence 

•	 Other pertinent information requested by the Regional Administrator. 

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Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
 


Discharge Notification Form 

*** Notification must not be delayed if information or individuals are not available. Additional pages may be attached to 

supplement information contained in the form. 

Facility:	 	 Clearwater Oil Company Big Bear Lease No. 2 Production Facility 
 

5800 Route 417 
 

Madison, Louisiana 73506 
 

Date/time Release date: 

Release time: 

Duration: 

Description of Discharge 

Discovery date: 

Discovery time: 

Reporting Individual 

Location of discharge 

Equipment source 

Product 

Appearance and 

description 

Environmental conditions 

Impacts 

Quantity 

Receiving medium 

Describe circumstances 

of the release 

Assessment of impacts 

and remedial actions 

Disposal method for 

recovered material 

Action taken to prevent 

incident from reoccurring 

Name: 

Latitude: 

Longitude: 

G piping 

G flowline 

G well 

G unknown 

G stock, flare 

G crude oil 

G saltwater 

G other* 

Wind direction: 

Wind speed: 

Released: 

G water** 

G land 

G other (describe): 

Tel. #: 

Description: 

Description: 

Equipment ID: 

* Describe other: 

Rainfall: 

Current: 

Recovered: 

G Release confined to company property. 

G Release outside company property. 

** If water, indicate extent and body of water: 

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Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
 
 

G Injuries 

G Fatalities 

G Evacuation 

Notifications 

Name Date/time reported & Comments 

Response Coordinator 

National Response 

Center 

1-800-424-8802 

State police 

Parish Emergency 

Response Commission 

OSRO/cleanup 

contractor 

Safety issues 

Agency 

Company Spill 

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Clearwater Oil Company, Ltd. 
 

Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
 

Appendix C
 
 

SITE PLAN AND FACILITY DIAGRAM
 
 

Figure C-1: Site Plan (pre-designated staging areas are indicated). 

BB1 5540 Route 417, Madison, LA (access from path to the 

right of the storage shed). 

Maurice Richard; 405-830-2186 

BB2 Jim Larouche; 405-832-2645 

BB3 

Staging area Location Contact Information 

6075 Greenfield Drive, Madison, LA. 

1644 Oilfield Road, Madison, LA Peter Martin; 405-832-5527 

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Clearwater Oil Company, Ltd. 
 
 

Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
 
 

Figure C-2: Facility Diagram. 

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Clearwater Oil Company, Ltd. 
 


Big Bear Lease No. 2 Production Facility Oil Spill Contingency Plan
 


This page intentionally left blank. 

-24- Version 1.0, 11/28/2005 
Appendix G 

APPENDIX G: SPCC INSPECTION CHECKLISTS 

Onshore Facilities (excluding production)
 


Onshore Oil Production, Drilling, and Workover Facilities
 


Offshore Oil Production, Drilling, and Workover Facilities
 


U.S. Environmental Protection Agency Version 1.0, 11/28/2005 
U.S. ENVIRONMENTAL PROTECTION AGENCY 

SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST 

FOR USE AT ONSHORE FACILITIES (EXCLUDING PRODUCTION) 

Overview of the Checklist 

This checklist is designed to assist EPA inspectors in conducting a thorough and consistent 

inspection of a facility’s compliance with the Spill Prevention, Control, and Countermeasure 

(SPCC) rule at 40 CFR part 112. It is a tool to help federal inspectors (or their contractors) 

record observations during the site visit and review of the SPCC Plan. While the checklist is 

comprehensive, the inspector should always refer to the SPCC rule in its entirety, the SPCC 

Regional Inspector Guidance Document, and other relevant guidance for evaluating 

compliance. This checklist must be completed in order for an inspection to count toward an 

agency measure (i.e., OEM/OECA inspection measures or GPRA). 

The checklist is organized according to the SPCC rule. Each item in the checklist identifies the 

relevant section and paragraph in 40 CFR part 112 where that requirement is stated. 

Sections 112.1 through 112.5 specify the applicability of the rule and requirements for the 

preparation, implementation, and amendment of SPCC Plans. For these sections, the checklist 

includes data fields to be completed, as well as several questions with “yes” or “no” answers. 

Sections 112.7 through 112.12 specify requirements for spill prevention, control, and 

countermeasures. For these sections, the inspector needs to evaluate whether the requirement 

is addressed adequately or inadequately in the SPCC Plan and whether it is implemented 

adequately in the field (either by field observation or record review). For the SPCC Plan and 

implementation in the field, if a requirement is addressed adequately, mark the “Yes” box in the 

appropriate column. If a requirement is not addressed adequately, mark the “No” box. If a 

requirement does not apply to the particular facility, mark the “NA” box. If a provision of the rule 

applies only to the SPCC Plan, the “Field” column is shaded. 

Space is provided in each section to record comments. Additional space is available on the 

comments page at the end of the checklist. Comments should remain factual and support the 

evaluation of compliance. 

Appendix A is for recording information about containers and other locations at the facility that 

require secondary containment. 

Appendix B is a checklist for documentation of the tests and inspections the facility operator is 

required to keep with the SPCC Plan. 

Appendix C is a checklist for oil removal contingency plans. A contingency plan is required if a 

facility determines that secondary containment is impracticable as provided in 40 CFR 112.7(d). 

Onshore Facilities (Excluding Production) Page 1 of 16 Version 1.0, 11/28/2005 
U.S. ENVIRONMENTAL PROTECTION AGENCY 

SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST 

FOR USE AT ONSHORE FACILITIES (EXCLUDING PRODUCTION) 

FACILITY INFORMATION 

ADDRESS: LONG: 

OWNER NAME: 

OWNER ADDRESS: 

NAICS CODE: 

G YES G NO 

INSPECTION INFORMATION 


 


 


 

INSPECTOR ACKNOWLEDGMENT 

FACILITY NAME: 

LAT: 

CITY: STATE: ZIP: COUNTY: 

TELEPHONE: FACILITY REPRESENTATIVE NAME: 

CITY: STATE: ZIP: 

TELEPHONE: OWNER CONTACT PERSON: 

FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER – IF NOT, PRINT “SAME”): 

OPERATOR ADDRESS: 

CITY: STATE: ZIP: 

TELEPHONE: OPERATOR CONTACT PERSON: 

FACILITY TYPE: 

HOURS PER DAY FACILITY ATTENDED: TOTAL FACILITY CAPACITY: 

TYPE(S) OF OIL STORED: 

IS FACILITY LOCATED IN INDIAN COUNTRY? IF YES, RESERVATION NAME: 

INSPECTION DATE: TIME: INSPECTION NUMBER: 

LEAD INSPECTOR: 

OTHER INSPECTOR(S): 

I performed an SPCC inspection at the facility specified above. 

INSPECTOR SIGNATURE: DATE: 

Onshore Facilities (Excluding Production) Page 2 of 16 Version 1.0 
FACILITY RESPONSE PLAN (FRP) APPLICABILITY 

G	 

OR 

ing is true: 
 

G 
 

sufficient freeboard for precipitation. 

G 

G 

G 

G Yes G No G Not Required 

Criteria.” G Yes G No 

Comments: 

SPCC GENERAL APPLICABILITY—40 CFR 112.1 


 

OR 
 

gallons G Yes G No 
 


 


 

G Yes G No 
 


 

i 

• 	 

• 	 i 

• 	 

. 

• 	 

• 	 

	 G Yes G No 

Comments: 

REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN—40 CFR 112.3 


 

Current plan version (date/number): 
 

112.3(a) 
 

• 	 G Yes G No G NA 

• G Yes G No G NA 

G Yes G No G NA 

A non-transportation related onshore facility is required to prepare and implement an FRP as outlined in 40 CFR 112.20 if: 

The facility transfers oil over water to or from vessels and has a total oil storage capacity greater than or equal to 42,000 gallons, 

The facility has a total oil storage capacity of at least 1 million gallons, and at least one of the follow 

The facility does not have secondary containment sufficiently large to contain the capacity of the largest aboveground tank plus 

The facility is located at a distance such that a discharge could cause injury to fish and wildlife and sensitive environments. 

The facility is located such that a discharge would shut down a public drinking water intake. 

The facility has had a reportable discharge greater than or equal to 10,000 gallons in the past 5 years. 

Facility has FRP: FRP Number: 

Facility has a completed and signed copy of Appendix C, Attachment C-II, “Certification of the Applicability of the Substantial Harm 

IS THE FACILITY REGULATED UNDER 40 CFR part 112? 

The completely buried oil storage capacity is over 42,000 gallons, the aggregate aboveground oil storage capacity is over 1,320 

AND 

The facility is a non-transportation-related facility engaged in drilling, producing, gathering, storing, processing, refining, transferring, 

distributing, using, or consuming oil and oil products, which due to its location could reasonably be expected to discharge oil into or 

upon the navigable waters of the United States (as defined in 40 CFR 110.1). 

AFFECTED WATERWAY(S): DISTANCE: 

PATH: 

Note: The following storage capacity is not considered in determ ning applicability of SPCC requirements: 

Completely buried tanks subject to all the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR part 281. 

Equipment subject to the authority of the U.S. Department of Transportation, U.S. Department of the Interior, or M nerals Management Service, 

as defined in Memoranda of Understanding dated November 24, 1971, and November 8, 1993. 

Any facility or part thereof used exclusively for wastewater treatment (production, recovery or recycling of oil is not considered wastewater 

treatment) 

Containers smaller than 55 gallons. 

Permanently closed containers. 

Does the facility have an SPCC Plan? 

Date facility began operations: 

Date of initial SPCC Plan preparation: 

For facilities in operation prior to August 16, 2002: 

Plan amended by February 17, 2006 

Amended Plan implemented by August 18, 2006 

For facilities beginning operation between August 17, 2002, and August 18, 

2006, Plan prepared and fully implemented by August 18, 2006 

Onshore Facilities (Excluding Production) Page 3 of 16 Version 1.0 
REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN—40 CFR 112.3 

112.3(b) 

& (c) 

112.3(d) 

• 	 PE is familiar with the requirements of 40 CFR part 112 

• 	 

• 	 

• 	 

• 	 

PE Name: 	 State: 

112.3(e) 	 

) 

Comments: 

G Yes G No G NA 

G Yes G No 

G Yes G No 

G Yes G No 

G Yes G No 

G Yes G No 

Date of certification: 

G Yes G No G NA 

112.4(a) G Yes G No 

• 	 

• 	 

• 

Comments: 

G Yes G No G NA 

G Yes G No G NA 

G Yes G No G NA 

AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR—40 CFR 112.5 

112.5(a) 

112.5(b) 

112.5(c) 

Name: 

G Yes G No G NA 

• ithin six months of the change? G Yes G No G NA 

G Yes G No G NA 

• 	 i ithin six G Yes G No G NA 

ith G Yes G No G NA 

§112.3(d) 

	 State: 

Reason for amendment: 
 

Amendments implemented wi G Yes G No G NA 
 

Comments: 
 

For facilities beginning operation after August 18, 2006, Plan prepared and fully 

implemented before beginning operations 

Professional Engineer certification includes statement that the PE attests: 

PE or agent has visited and examined the facility 

Plan is prepared in accordance with good engineering practice including consideration of 

applicable industry standards and the requirements of 40 CFR part 112 

Procedures for required inspections and testing have been established 

Plan is adequate for the facility 

License No.: 

Plan available onsite if facility is attended at least 4 hours/day 

(If located at nearest field office, please note contact information below 

AMENDMENT OF SPCC PLAN BY REGIONAL ADMINISTRATOR (RA)—40 CFR 112.4 

Has the facility discharged a reportable quantity of oil in amounts considered harmful: more 

than 1,000 gallons of oil in a single discharge or more than 42 gallons in each of two 

discharges in any 12-month period (see 40 CFR part 110)? 

If yes, was information submitted to the RA as required in §112.4(a)? 

Date(s) of reportable discharges(s): 

Were they reported to the NRC? 

112.4(d), (e) Have changes required by the RA been implemented in the Plan and/or facility? 

Has there been a change at the facility that materially affects the potential for a discharge? 

If so, was the Plan amended w 

Review and evaluation of the Plan documented at least once every 5 years? 

Follow ng Plan review, and if amendment was required, was Plan amended w 

months to include more effective prevention and control technology, if available? 

Professional Engineer certification of any technical Plan amendments in accordance w 

License No.: Date of certification: 

thin six months of any Plan amendment 

Onshore Facilities (Excluding Production) Page 4 of 16 	 Version 1.0 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

GENERAL SPCC REQUIREMENTS—40 CFR 112.7 FIELD 

G Yes G No 

Name: Title: Date: 

G 

G No 

and start-up are discussed 

G 

G No 

G NA 

112.7(a)(2) 

nonconformance 

G 

G No 

G NA 

(Note: G 

G No 

G NA 

G 

G No 

G NA 

Describe each deviation and reasons for nonconformance: 

112.7(a)(3) i 

buried tanks otherwi 

G 

G No 

G NA 

G 

G No 

G NA 

pipes 

112.7(a)(3) Plan addresses each of the following: 

(i) G 

G No 

G 

G No 

G NA G NA 

(ii) G 

G No 

G 

G No 

G NA G NA 

G 

G No 

G NA 

G 

G No 

G NA 

resources) 

G 

G No 

G NA 

G 

G No 

G NA 

(v) ith applicable legal requirements G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

PLAN 

Management approval at a level of authority to commit the necessary resources to fully implement the Plan 

Plan follows sequence of the rule or provides a cross-reference of requirements in the Plan and the rule Yes 

If Plan calls for facilities, procedures, methods, or equipment not yet fully operational, details of their installation 

(Note: Relevant for inspection evaluation and testing baselines.) 

 Yes 

If there are deviations from the requirements of the rule, the Plan states reasons for Yes 

Alternative measures described in detail and provide equivalent environmental protection 

Inspector should document if the environmental equivalence is implemented in the field) 

 Yes Yes 

Plan includes diagram w th location and contents of all regulated containers (including completely 

se exempt from the SPCC requirements), transfer stations, and connecting 

 Yes Yes 

For each container, type of oil and storage capacity (see Appendix A) Yes Yes 

Discharge prevention measures, including procedures for routine handling of products Yes Yes 

(iii) Discharge or drainage controls, such as secondary containment around containers, and other 

structures, equipment, and procedures for the control of a discharge 

 Yes Yes 

(iv) Countermeasures for discharge discovery, response, and cleanup (both facility’s and contractor’s Yes Yes 

Methods of disposal of recovered materials in accordance w Yes 

(vi) Contact list and phone numbers for the facility response coordinator, National Response Center, 

cleanup contractors contracted to respond to a discharge, and all Federal, State, and local agencies 

who must be contacted in the case of a discharge as described in §112.1(b) 

 Yes 

Onshore Facilities (Excluding Production) Page 5 of 16 Version 1.0 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

GENERAL SPCC REQUIREMENTS—40 CFR 112.7 FIELD 

; 

G 

G No 

G NA 

G 

G No 

G NA 

112.7(b) 

potential for equipment failure 

G 

G No 

G NA 

G 

G No 

G NA 

112.7(c) G 

G No 

G NA 

G 

G No 

G NA 

For onshore facilities, one of the following or its 

, , 

ponds, 

112.7(d) G 

G No 

If YES, G 

G No 

G 

G No 

G NA G NA 

ith the container is conducted 

G 

G No 

G NA 

G 

G No 

G NA 

(1) 

G 

G No 

G NA 

(2) G 

G No 

G NA 

G 

G No 

G NA 

112.7(e) i G 

G No 

G NA 

ith Plan for at least 3 G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

PLAN 

112.7(a)(4) Plan includes information and procedures that enable a person reporting a discharge as described 

in §112.1(b) to relate information on the exact address or location and phone number of the facility 

the date and time of the discharge; the type of material discharged; estimates of the total quantity 

discharged; estimates of the quantity discharged as described in §112.1(b); the source of the 

discharge; a description of all affected media; the cause of the discharge; any damages or injuries 

caused by the discharge; actions being used to stop, remove, and mitigate the effects of the 

discharge; whether an evacuation may be needed; and the names of individuals and/or 

organizations who have also been contacted (Not required if a facility has an FRP) 

 Yes 

112.7(a)(5) Plan organized so that portions describing procedures to be used when a discharge occurs will be 

readily usable in an emergency (Not required if a facility has an FRP) 

 Yes 

Plan includes a prediction of the direction, rate of flow, and total quantity of oil that could be 

discharged for each type of major equipment failure where experience indicates a reasonable 

 Yes Yes 

Appropriate containment and/or diversionary structures provided to prevent a discharge as 

described in §112.1(b) before cleanup occurs. The entire containment system, including walls and 

floors, are capable of containing oil and are constructed to prevent escape of a discharge from the 

 Yes Yes 

containment system before cleanup occurs. (1) 

equivalent: (i) dikes, berms, or retaining walls sufficiently impervious to contain oil, (ii) curbing, (iii) 

culverting, gutters or other drainage systems (iv) weirs, booms or other barriers (v) spill diversion 

(vi) retention ponds, or (vii) sorbent materials (See Appendix A) 

Determination(s) of impracticability of secondary containment Yes 

is the impracticability of secondary containment clearly demonstrated? Yes Yes 

Comments concerning impracticability determination(s) for secondary containment: 

If impracticability determination is made, for bulk storage containers, periodic integrity testing of 

containers and leak testing of the valves and piping associated w

 Yes Yes 

If impracticability determination is made, unless facility has FRP: 

Contingency Plan following 40 CFR part 109 (see Appendix C checklist) is provided AND 

 Yes 

Written commitment of manpower, equipment, and materials required to control and remove 

any quantity of oil discharged that may be harmful 

 Yes Yes 

Inspections and tests conducted in accordance w th written procedures Yes 

Record of inspections or tests signed by supervisor or inspector and kept w 

years (see Appendix B checklist) 

 Yes Yes 

Onshore Facilities (Excluding Production) Page 6 of 16 Version 1.0 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

GENERAL SPCC REQUIREMENTS—40 CFR 112.7 FIELD 

(1) 

operations; and contents of SPCC Plan 

G 

G No 

G NA 

G 

G No 

G NA 

(2) G 

G No 

G 

G No 

G NA G NA 

(3) G 

G No 

G 

G No 

G NA G NA 

(1) G 

G No 

G 

G No 

G NA G NA 

(2) G 

G No 

G NA 

G 

G No 

G NA 

(3) G 

G No 

G NA 

G 

G No 

G NA 

(4) G 

G No 

G NA 

G 

G No 

G NA 

(5) i 

acts of vandalism 

G 

G No 

G NA 

G 

G No 

G NA 

(1) 

G Yes G No 

• 

G 

G No 

G NA 

G 

G No 

G NA 

loaded/unloaded at the facility 

G 

G No 

G NA 

G 

G No 

G NA 

(2) 

areas (the location adjacent to the ) to prevent vehicles from departing before 

G 

G No 

G NA 

G 

G No 

G NA 

(3) G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

PLAN 

112.7(f) Personnel, training, and oil discharge prevention procedures 

Training of oil-handling personnel in operation and maintenance of equipment to prevent discharges; 

discharge procedure protocols; applicable pollution control laws, rules and regulations; general facility 

 Yes Yes 

Person designated as accountable for discharge prevention at the facility Yes Yes 

Discharge prevention briefings conducted at least once a year for oil handling personnel Yes Yes 

112.7(g) Security (excluding production facilities) 

Facility fully fenced and gates are locked and/or guarded when facility is unattended Yes Yes 

Master flow and drain valves and any other valves permitting direct outward flow of the container’s 

contents to the surface have adequate security measures so that they remain in the closed position when 

in non-operating or non-standby status 

 Yes Yes 

Pump starter controls locked in “off” position and accessible only to authorized personnel when in nonoperating/non-standby status 

 Yes Yes 

Loading/unloading connections of oil pipelines or facility piping securely capped or blank-flanged when not 

in service or when in standby service for an extended period of time, including piping that is emptied of 

liquid content either by draining or by inert gas pressure 

 Yes Yes 

Adequate facility lighting commensurate w th the type and location of the facility that assists in the 

discovery of discharges occurring during hours of darkness and to prevent discharges occurring through 

 Yes Yes 

112.7(h) Tank car and tank truck loading/unloading rack* 

Does loading/unloading area (the location adjacent to the loading or unloading rack) drainage flow to 

catchment basin or treatment facility? 

If NO, quick drainage system used 

 Yes Yes 

Containment system holds capacity of the largest single compartment of a tank car/truck Yes Yes 

Physical barriers, warning signs, wheel chocks, or vehicle brake interlock system in loading/unloading 

loading or unloading rack

 Yes Yes 

complete disconnection of flexible or fixed oil transfer lines 

Lower-most drains and all outlets on tank cars/trucks inspected prior to filling/departure, and, if necessary 

ensure that they are tightened, adjusted, or replaced to prevent liquid discharge while in transit 

 Yes Yes 

* Note that a tank car/truck loading/unloading rack must be present for §112.7(h) to apply 

Onshore Facilities (Excluding Production) Page 7 of 16 Version 1.0 
INDICATE IF ITEM IS ADDRESSED GENERAL SPCC REQUIREMENTS—40 CFR 112.7 ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FI FIELDELD. 

112.7(i) 

112.7(i) G 

G No 

G NA 

G 

G No 

G NA 

112.7(j) i 

112.7(j) Discussion of conformance wi G 

G No 

G NA 

Comments: 

ONSHORE FACILITIES (EXCLUDING PRODUCTION)—112.8/112.12 FIELD 

(1) OR 

discharged. 

G 

G No 

G NA 

G 

G No 

G NA 

(2) G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

(3) Drainage from undiked areas wi G 

G No 

G NA 

G 

G No 

G NA 

(4) i G 

G No 

G NA 

G 

G No 

G NA 

(5) 

G Yes G No If YES: 

• G 

G No 

G NA 

G 

G No 

G NA 

• 

equipment failure or human error 

G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

PLAN 

Brittle fracture evaluation of field-constructed aboveground containers 

Brittle fracture evaluation is conducted after tank repair/alteration/change in service that might affect 

the risk of a discharge or after a discharge/failure due to brittle fracture or other catastrophe, and 

appropriate action taken as necessary (for field-constructed aboveground containers) 

 Yes Yes 

State rules, regulations and guidelines and conformance w th applicable sections of 40 CFR part 112 

th applicable more stringent State rules, regulations, and guidelines and 

other effective discharge prevention and containment procedures listed in 40 CFR part 112 

 Yes 

PLAN 

112.8(b)/112.12(b) Facility Drainage 

Drainage from diked storage areas is restrained by valves, manually activated pumps or ejectors are 

used and the condition of the accumulation is inspected prior to discharge to ensure no oil will be 

 Yes Yes 

Valves from diked storage areas are manual, open-and-closed design (not flapper-type drain valves) Yes Yes 

If drainage is released directly to a watercourse and not into an onsite wastewater treatment plant, storm 

water inspected per §112.8(c)(3)(ii), (iii), and (iv) or §112.12(c)(3)(ii), (iii), and (iv) 

 Yes Yes 

th a potential for discharge designed to flow into ponds, lagoons, or 

catchment basins to retain oil or return it to facility. Catchment basin located away from flood areas.* 

 Yes Yes 

If facility drainage not engineered as in (b)(3), facility equipped w th a diversion system to retain oil in the 

facility in the event of a discharge* 

 Yes Yes 

Are facility drainage waters continuously treated in more than one treatment unit and pump transfer is needed? 

Two “lift” pumps available and at least one permanently installed Yes Yes 

Facility drainage systems engineered to prevent a discharge as described in §112.1(b) in the case of Yes Yes 

* These provisions apply only when a facility drainage system is used for containment. 

Onshore Facilities (Excluding Production) Page 8 of 16 Version 1.0 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

ONSHORE FACILITIES (EXCLUDING PRODUCTION)—112.8/112.12 FIELD 

(1) i G 

G No 

G NA 

G 

G No 

G NA 

(2) G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

basin or holding pond 

G 

G No 

G NA 

G 

G No 

G NA 

G Yes G No If YES: 

(i) G 

G No 

G NA 

G 

G No 

G NA 

(ii) 

§112.1(b) 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

accordance with 40 CFR 122.41(j)(2) and (m)(3) 

G 

G No 

G NA 

G 

G No 

G NA 

• i ith local soil conditions G 

G No 

G NA 

G 

G No 

G NA 

• G 

G No 

G NA 

G 

G No 

G NA 

i 

compatible with local soil conditions 

G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

PLAN 

112.8(c)/112.12(c) Bulk Storage Containers (See Appendix A of this checklist) 

Containers compatible w th material stored and conditions of storage such as pressure and temperature Yes Yes 

Secondary containment to hold capacity of largest container and sufficient freeboard for precipitation Yes Yes 

Diked areas sufficiently impervious to contain discharged oil Yes Yes 

Alternatively, any discharge to a drainage trench system will be safely confined in a facility catchment Yes Yes 

(3) Is there drainage of uncontaminated rainwater from diked areas into a storm drain or open watercourse? 

Bypass valve normally sealed closed Yes Yes 

Retained rainwater is inspected to ensure that its presence will not cause a discharge as described in Yes Yes 

(iii) Bypass valve opened and resealed under responsible supervision Yes Yes 

(iv) Adequate records of drainage are kept; for example, records required under permits issued in Yes Yes 

(4) For completely buried metallic tanks installed on or after January 10, 1974 (if not exempt from SPCC regulation because subject 

to all of the technical requirements of 40 CFR part 280 or 281): 

Corrosion protection w th coatings or cathodic protection compatible w Yes Yes 

Regular leak testing conducted Yes Yes 

(5) Partially buried or bunkered metallic tanks protected from corrosion w th coatings or cathodic protection Yes Yes 

Onshore Facilities (Excluding Production) Page 9 of 16 Version 1.0 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

ONSHORE FACILITIES (EXCLUDING PRODUCTION)—112.8/112.12 FIELD 

(continued) 

(6) G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G 

G No 

G NA G NA 

inside diked areas 

G 

G No 

G NA 

G 

G No 

G NA 

Records of inspections and tests maintained G 

G No 

G 

G No 

G NA G NA 

• 

G 

G No 

G NA 

G 

G No 

G NA 

monitored for contamination, OR 

• 

ith at least one of the following for liquid level sensing: (i) high liquid level alarms 

wi 

G 

G No 

G NA 

G 

G No 

G NA 

discharge as described in §112.1(b) 

G 

G No 

G NA 

G 

G No 

G NA 

removed 

G 

G No 

G NA 

G 

G No 

G NA 

(11) 

§112.1(b). 

G 

G No 

G NA 

G 

G No 

G NA 

i G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

PLAN 

112.8(c)/112.12(c) Bulk Storage Containers 

Aboveground containers integrity tested by visual inspection and another technique such as hydrostatic 

testing, radiographic testing, ultrasonic testing, acoustic emissions testing, or another system of nondestructive shell testing on a regular schedule and whenever material repairs are made 

 Yes Yes 

Container supports and foundations regularly inspected Yes Yes 

Outside of containers frequently inspected for signs of deterioration, discharges, or accumulation of oil Yes Yes 

 Yes Yes 

(7) Leakage through defective internal heating coils controlled: 

Steam returns and exhaust lines from internal heating coils that discharge into an open water source are 

 Yes Yes 

Steam returns and exhaust lines pass through a settling tank, skimmer, or other separation or retention 

system 

(8) Each container equipped w 

th an audible or visual signal at a constantly attended operation or surveillance station, or audible air vent 

 Yes Yes 

in smaller facilities, (ii) high liquid level pump cutoff devices set to stop flow at a predetermined container 

content level, (iii) direct audible or code signal communication between container gauger and pumping 

station, (iv) fast response system (such as digital computers, telepulse, or direct vision gauges) and a 

person is present to monitor gauges and the overall filling of bulk storage containers, (v) liquid level sensing 

devices regularly tested to ensure proper operation 

(9) Effluent treatment facilities observed frequently enough to detect possible system upsets that could cause a Yes Yes 

(10) Visible discharges which result in a loss of oil from the container, including but not limited to seams, 

gaskets, piping, pumps, valves, rivets, and bolts are promptly corrected and oil in diked areas is promptly 

 Yes Yes 

Mobile or portable containers positioned to prevent a discharge to prevent a discharge as described in Yes Yes 

Mobile or portable containers have secondary containment w th sufficient capacity to contain the largest 

single compartment or container and sufficient freeboard for precipitation 

 Yes Yes 

Onshore Facilities (Excluding Production) Page 10 of 16 Version 1.0 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

ONSHORE FACILITIES (EXCLUDING PRODUCTION)—112.8/112.12 FIELD 

(1) G 

G No 

G NA 

G 

G No 

G NA 

ise G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

(2) G 

G No 

G NA 

G 

G No 

G NA 

(3) 

contraction 

G 

G No 

G NA 

G 

G No 

G NA 

(4) G 

G No 

G NA 

G 

G No 

G NA 

relocation, or replacement 

G 

G No 

G NA 

G 

G No 

G NA 

(5) G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

PLAN 

112.8(d)/112.12(d) Facility transfer operations, pumping, and facility process 

Buried piping installed or replaced on or after August 16, 2002 has protective wrapping or coating Yes Yes 

Buried piping installed or replaced on or after August 16, 2002 is cathodically protected or otherw 

satisfies corrosion protection standards for piping in 40 CFR part 280 or 281 

 Yes Yes 

Exposed buried piping is inspected for deterioration and corrosion damage is examined and corrected Yes Yes 

Piping terminal connection at the transfer point is marked as to origin and capped or blank-flanged when 

not in service or in standby service for an extended time 

 Yes Yes 

Pipe supports are properly designed to minimize abrasion and corrosion and allow for expansion and Yes Yes 

Aboveground valves, piping, and appurtenances such as flange joints, expansion joints, valve glands 

and bodies, catch pans, pipeline supports, locking of valves, and metal surfaces are inspected regularly 

 Yes Yes 

Integrity and leak testing conducted on buried piping at time of installation, modification, construction, Yes Yes 

Vehicles warned so that no vehicle endangers aboveground piping and other oil transfer operations Yes Yes 

Onshore Facilities (Excluding Production) Page 11 of 16 Version 1.0 
ADDITIONAL COMMENTS 

Rule Provision Comment 

Onshore Facilities (Excluding Production) Page 12 of 16 Version 1.0 
) 

PHOTO DOCUMENTATION LOG 

Photo Number Description (include date and location 

Onshore Facilities (Excluding Production) Page 13 of 16 Version 1.0 
SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
 
 

Appendix A: Documentation of Field Observations for Containers and Associated Requirements 

Inspectors should use this table to document observations of containers as needed. 


 


 


 

Check foundation for: 
 


 


 


 

)
 


 


 

erosion, corrosion, and valve conditions.
 


 


 

ithin diked areas.
 


 

vegetation.
 


 


 


 

Containers and Piping 

Check containers for leaks, specifically looking for: drip marks, discoloration of tanks, puddles containing spilled or leaked material, 

corrosion, cracks, and localized dead vegetation, and standards/specifications of construction.

 cracks, discoloration, puddles containing spilled or leaked material, settling, gaps between container and 

foundation, and damage caused by vegetation roots. 

Check piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored material 

seepage from valves or seals, and localized dead vegetation. (Document in comments section of §112.8(d) / §112.12(d).) 

Secondary Containment (Active and Passive 

Check secondary containment for: containment system (including walls and floor) ability to contain oil such that oil will not escape the 

containment system before cleanup occurs, proper sizing, cracks, discoloration, presence of spilled or leaked material (standing liquid), 

Check dike or berm systems for: level of precipitation in dike/available capacity, operational status of drainage valves (closed), dike 

or berm impermeability, debris, erosion, impermeability of the earthen floor/walls of diked area, and location/status of pipes, inlets, 

drainage around and beneath containers, presence of oil discharges w 

Check retention and drainage ponds for: erosion, available capacity, presence of spilled or leaked material, debris, and stressed 

Check active measures (countermeasures) for: amount indicated in plan is available and appropriate; deployment procedures are 

realistic; material is located so that they are readily available; efficacy of discharge detection; availability of personnel and training, 

appropriateness of measures to prevent a discharge as described in §112.1(b). 

Container ID/ General Condition Storage Capacity and 

Type of Oil 

Type of Containment/ 

Drainage Control 

Overfill Protection and 

Testing & Inspections 

Onshore Facilities (Excluding Production) Page 14 of 16 Version 1.0 
SPCC INSPECTION AND TESTING CHECKLIST 

Appendix B: Required Documentation of Tests and Inspections 

Records of inspections and tests required by 40 CFR part 112 signed by the appropriate supervisor or inspector must be kept with the 

SPCC Plan for a period of three years. Records of inspections and tests conducted under usual and customary business practices will 

suffice. Documentation of the following inspections and tests should be kept with the SPCC Plan. 

Not 

Not 

112.7–General SPCC Requirements 

(d) ith no secondary 

made 

(d) ith bulk storage 

containers wi 

(i) 

a repair, alteration, 

reconstruction or change in service 

(b)(2) 

inspected and records of drainage are kept 

(c)(3)(iv) 

(c)(4) 

(c)(6) 

regular schedule 

(c)(6) 

accumulations of oil inside diked areas 

(c)(8)(v) 

(c)(9) 

§112.1(b) 

(d)(1) 

corrosion damage is corrected 

(d)(4) 

the general condition of flange joints, expansion joints, valve glands and 

bodies, catch pans, pipeline supports, locking of valves, and metal surfaces 

are assessed 

(d)(4) 

Comments: 

Documentation 

Inspection or Test Applicable Present Present 

Integrity testing is conducted for bulk storage containers w 

containment system and for which an impracticability determination has been 

Integrity and leak testing of valves and piping associated w 

th no secondary containment system and for which an 

impracticability determination has been made 

Evaluate field-constructed aboveground containers for potential for brittle fracture 

or other catastrophic failure when the container undergoes 

112.8/112.12–Onshore facilities (excluding production) 

Storm water released from facility drainage directly to a watercourse is 

Rainwater released directly from diked containment areas to a storm drain 

or open watercourse is inspected and records of drainage are kept 

Regular leak testing of completely buried metallic storage tanks 

Aboveground containers, supports and foundations tested for integrity on a 

Outside of containers frequently inspected for deterioration, discharges or 

 Liquid level sensing devices regularly tested to ensure proper operation 

Effluent treatment facilities are observed frequently enough to detect 

possible system upsets that could cause a discharge as described in 

When buried piping is exposed, it is carefully inspected for deterioration and 

Aboveground valves, piping and appurtenances are regularly inspected and 

Integrity and leak testing of buried piping is conducted at time of installation, 

modification, construction, relocation or replacement 

Onshore Facilities (Excluding Production) Page 15 of 16 Version 1.0 
SPCC CONTINGENCY PLAN REVIEW CHECKLIST 

Appendix C: 40 CFR Part 109–Criteria for State, Local and Regional Oil 

Removal Contingency Plans 

If a facility makes an impracticability determination for secondary containment in accordance with §112.7(d), it is required to provide 

an oil spill contingency plan following 40 CFR part 109. 

* Yes 

involved in planning or directing oil removal operations. 

discharge including: 

(1) 

(2) 

(3) 

i 

(4) 

including: 

(1) 

(2) 

discharge to be anticipated. 

(3) 

equipment, materials and supplies to be used in responding to such a discharge. 

including: 

(1) 

operating personnel. 

(2) ith the 

(3) 

(4) 

(5) 

109.5–Development and implementation criteria for State, local and regional oil removal contingency plans No 

(a) Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to be 

(b) Establishment of notification procedures for the purpose of early detection and timely notification of an oil 

The identification of critical water use areas to facilitate the reporting of and response to oil discharges. 

A current list of names, telephone numbers and addresses of the responsible persons (with alternates) and 

organizations to be notified when an oil discharge is discovered. 

Provisions for access to a reliable communications system for timely notification of an oil discharge, and 

the capability of interconnection w th the communications systems established under related oil removal 

contingency plans, particularly State and National plans (e.g., NCP). 

An established, prearranged procedure for requesting assistance during a major disaster or when the 

situation exceeds the response capability of the State, local or regional authority. 

(c) Provisions to assure that full resource capability is known and can be committed during an oil discharge situation 

The identification and inventory of applicable equipment, materials and supplies which are available locally 

and regionally. 

An estimate of the equipment, materials and supplies which would be required to remove the maximum oil 

Development of agreements and arrangements in advance of an oil discharge for the acquisition of 

(d) Provisions for well defined and specific actions to be taken after discovery and notification of an oil discharge 

Specification of an oil discharge response operating team consisting of trained, prepared and available 

Predesignation of a properly qualified oil discharge response coordinator who is charged w 

responsibility and delegated commensurate authority for directing and coordinating response operations 

and who knows how to request assistance from Federal authorities operating under existing national and 

regional contingency plans. 

A preplanned location for an oil discharge response operations center and a reliable communications 

system for directing the coordinated overall response operations. 

Provisions for varying degrees of response effort depending on the severity of the oil discharge. 

Specification of the order of priority in which the various water uses are to be protected where more than 

one water use may be adversely affected as a result of an oil discharge and where response operations 

may not be adequate to protect all uses. 

(e) Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided 

for by State and local statutes and ordinances. 

* The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the National 

Contingency Plan (NCP). 

Onshore Facilities (Excluding Production) Page 16 of 16 Version 1.0 
U.S. ENVIRONMENTAL PROTECTION AGENCY 

SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST 

ONSHORE OIL PRODUCTION, DRILLING, AND WORKOVER FACILITIES 

Overview of the Checklist 

This checklist is designed to assist EPA inspectors in conducting a thorough and consistent 

inspection of a facility’s compliance with the Spill Prevention, Control, and Countermeasure 

(SPCC) rule at 40 CFR part 112. It is a tool to help federal inspectors (or their contractors) 

record observations during the site visit and review of the SPCC Plan. While the checklist is 

comprehensive, the inspector should always refer to the SPCC rule in its entirety, the SPCC 

Regional Inspector Guidance Document, and other relevant guidance for evaluating 

compliance. This checklist must be completed in order for an inspection to count toward an 

agency measure (i.e., OEM/OECA inspection measures or GPRA). 

The checklist is organized according to the SPCC rule. Each item in the checklist identifies the 

relevant section and paragraph in 40 CFR part 112 where that requirement is stated. 

Sections 112.1 through 112.5 specify the applicability of the rule and requirements for the 

preparation, implementation, and amendment of SPCC Plans. For these sections, the checklist 

includes data fields to be completed, as well as several questions with “yes” or “no” answers. 

Sections 112.7 through 112.11 specify requirements for spill prevention, control, and 

countermeasures. For these sections, the inspector needs to evaluate whether the requirement 

is addressed adequately or inadequately in the SPCC Plan and whether it is implemented 

adequately in the field (either by field observation or record review). For the SPCC Plan and 

implementation in the field, if a requirement is addressed adequately, mark the “Yes” box in the 

appropriate column. If a requirement is not addressed adequately, mark the “No” box. If a 

requirement does not apply to the particular facility, mark the “NA” box. If a provision of the rule 

applies only to the SPCC Plan, the “Field” column is shaded. 

Space is provided in each section to record comments. Additional space is available on the 

comments page at the end of the checklist. Comments should remain factual and support the 

evaluation of compliance. 

Appendix A is for recording information about containers and other locations at the facility that 

require secondary containment. 

Appendix B is a checklist for documentation of the tests and inspections the facility operator is 

required to keep with the SPCC Plan. 

Appendix C is a checklist for oil removal contingency plans. A contingency plan is required if a 

facility determines that secondary containment is impracticable as provided in 40 CFR 112.7(d). 

Onshore Oil Production, Drilling, & Workover Facilities Page 1 of 14 Version 1.0, 11/28/2005 
U.S. ENVIRONMENTAL PROTECTION AGENCY 

SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST 

ONSHORE OIL PRODUCTION, DRILLING, AND WORKOVER FACILITIES 

FACILITY INFORMATION 

FACILITY NAME: 

ADDRESS: LAT: LONG: 

CITY: STATE: ZIP: COUNTY: 

TELEPHONE: FACILITY REPRESENTATIVE NAME: 

OWNER NAME: 

OWNER ADDRESS: 

CITY: STATE: ZIP: 

TELEPHONE: OWNER CONTACT PERSON: 

FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER – IF NOT, PRINT “SAME”): 

OPERATOR ADDRESS: 

CITY: STATE: ZIP: 

TELEPHONE: OPERATOR CONTACT PERSON: 

FACILITY TYPE: NAICS CODE: 

HOURS PER DAY FACILITY ATTENDED: TOTAL FACILITY CAPACITY: 

TYPE(S) OF OIL STORED: 

IS FACILITY LOCATED IN INDIAN COUNTRY? G YES G NO IF YES, RESERVATION NAME: 

INSPECTION INFORMATION 

INSPECTION DATE: TIME: INSPECTION NUMBER: 
 

LEAD INSPECTOR: 
 


 

INSPECTOR ACKNOWLEDGMENT 

OTHER INSPECTOR(S): 

I performed an SPCC inspection at the facility specified above. 

INSPECTOR SIGNATURE: DATE: 

Onshore Oil Production, Drilling, & Workover Facilities Page 2 of 14 Version 1.0, 11/28/2005 
FACILITY RESPONSE PLAN (FRP) APPLICABILITY 

G	 

OR 

ing is true: 
 

G 
 

sufficient freeboard for precipitation. 

G 

G 

G 

G Yes G No G Not Required 

Criteria” G Yes G No 

Comments: 

SPCC GENERAL APPLICABILITY—40 CFR 112.1 


 

OR 
 

gallons G Yes G No 
 


 


 

G Yes G No 
 


 

i 

• 	 

• 	 i 

• 	 

. 

• 	 

• 	 

	 G Yes G No 

Comments: 

REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN—40 CFR 112.3 


 

Current plan version (date/number): 
 

112.3(a) 
 

• 	 G Yes G No G NA 

• 	 G Yes G No G NA 


 

G Yes G No G NA 
 

A non-transportation related onshore facility is required to prepare and implement an FRP as outlined in 40 CFR 112.20 if: 

The facility transfers oil over water to or from vessels and has a total oil storage capacity greater than or equal to 42,000 gallons, 

The facility has a total oil storage capacity of at least 1 million gallons, and at least one of the follow 

The facility does not have secondary containment sufficiently large to contain the capacity of the largest aboveground tank plus 

The facility is located at a distance such that a discharge could cause injury to fish and wildlife and sensitive environments. 

The facility is located such that a discharge would shut down a public drinking water intake. 

The facility has had a reportable discharge greater than or equal to 10,000 gallons in the past 5 years. 

Facility has FRP: FRP Number: 

Facility has a completed and signed copy of Appendix C, Attachment C-II, “Certification of the Applicability of the Substantial Harm 

IS THE FACILITY REGULATED UNDER 40 CFR part 112? 

The completely buried oil storage capacity is over 42,000 gallons, the aggregate aboveground oil storage capacity is over 1,320 

AND 

The facility is a non-transportation-related facility engaged in drilling, producing, gathering, storing, processing, refining, transferring, 

distributing, using, or consuming oil and oil products, which due to its location could reasonably be expected to discharge oil into or 

upon the navigable waters of the United States (as defined in 40 CFR 110.1). 

AFFECTED WATERWAY(S): DISTANCE: 

PATH: 

Note: The following storage capacity is not considered in determ ning applicability of SPCC requirements: 

Completely buried tanks subject to all the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR part 281. 

Equipment subject to the authority of the U.S. Department of Transportation, U.S. Department of the Interior, or M nerals Management Service, 

as defined in Memoranda of Understanding dated November 24, 1971, and November 8, 1993. 

Any facility or part thereof used exclusively for wastewater treatment (production, recovery or recycling of oil is not considered wastewater 

treatment) 

Containers smaller than 55 gallons. 

Permanently closed containers. 

Does the facility have an SPCC Plan? 

Date facility began operations: 

Date of initial SPCC Plan preparation: 

For facilities in operation prior to August 16, 2002: 

Plan amended by February 17, 2006 

Amended Plan implemented by August 18, 2006 

For facilities beginning operation between August 17, 2002, and August 18, 

2006, Plan prepared and fully implemented by August 18, 2006 

Onshore Oil Production, Drilling, & Workover Facilities Page 3 of 14 	 Version 1.0, 11/28/2005 
REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN—40 CFR 112.3 

112.3(b) 

& (c) 

112.3(d) 	 

• 	 PE is familiar with the requirements of 40 CFR part 112 

• 	 

• 	 

• 	 

• 	 

PE Name: 	 State: 

112.3(e) 	 

) 

Comments: 

G Yes 

G Yes 

G Yes 

G Yes 

G Yes 

G Yes 

Date of certification: 

G Yes 

G No G NA 

G No 

G No 

G No 

G No 

G No 

G No G NA 

112.4(a) 

• 	 

• 	 

• 	 

Comments: 

G Yes 

G Yes 

G Yes 

G Yes 

G No G NA 

G No G NA 

G No G NA 

G No G NA 

AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR—40 CFR 112.5 

112.5(a) 	 

• ithin six months of the change? 

112.5(b) 

• 	 i ithin six 

112.5(c) 	 ith 

§112.3(d) 

G Yes 

G Yes 

G Yes 

G Yes 

G Yes 

Name: State: 

Reason for amendment: 

Amendments implemented wi G Yes 

Comments: 

G No G NA 

G No G NA 

G No G NA 

G No G NA 

G No G NA 

G No G NA 

For facilities beginning operation after August 18, 2006, Plan prepared and fully 

implemented before beginning operations 

Professional Engineer certification includes statement that the PE attests: 

PE or agent has visited and examined the facility 

Plan is prepared in accordance with good engineering practice including consideration of 

applicable industry standards and the requirements of 40 CFR part 112 

Procedures for required inspections and testing have been established 

Plan is adequate for the facility 

License No.: 

Plan available onsite if facility is attended at least 4 hours/day 

(If located at nearest field office, please note contact information below 

AMENDMENT OF SPCC PLAN BY REGIONAL ADMINISTRATOR (RA)—40 CFR 112.4 

Has the facility discharged a reportable quantity of oil in amounts considered harmful more 

than 1,000 gallons of oil in a single discharge or more than 42 gallons in each of two 

discharges in any 12-month period (see 40 CFR part 110)? 

If yes, was information submitted to the RA as required in §112.4(a)? 

Date(s) of reportable discharge(s): 

Were they reported to the NRC? 

112.4(d), (e) Have changes required by the RA been implemented in the Plan and/or facility? 

Has there been a change at the facility that materially affects the potential for a discharge? 

If so, was the Plan amended w 

Review and evaluation of the Plan documented at least once every 5 years? 

Follow ng Plan review, and if amendment was required, was Plan amended w 

months to include more effective prevention and control technology, if available? 

Professional Engineer certification of any technical Plan amendments in accordance w 

License No.: Date of certification: 

thin six months of any Plan amendment 

Onshore Oil Production, Drilling, & Workover Facilities Page 4 of 14 	 Version 1.0, 11/28/2005 
GENERAL SPCC REQUIREMENTS—40 CFR 112.7 FIELD 

G Yes G No 

Name: Title: Date: 

G 

G No 

and start-up are discussed 

G 

G No 

G NA 

112.7(a)(2) 

nonconformance 

G 

G No 

G NA 

(Note: G 

G No 

G NA 

G 

G No 

G NA 

Describe each deviation and reasons for nonconformance: 

112.7(a)(3) i 

buried tanks otherwi 

pipes 

G 

G No 

G NA 

G 

G No 

G NA 

112.7(a)(3) Plan addresses each of the following: 

(i) G 

G No 

G NA 

G 

G No 

G NA 

(ii) G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

resources) 

G 

G No 

G NA 

G 

G No 

G NA 

(v) ith applicable legal requirements G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

PLAN 

Management approval at a level of authority to commit the necessary resources to fully implement the Plan 

Plan follows sequence of the rule or provides a cross-reference of requirements in the Plan and the rule Yes 

If Plan calls for facilities, procedures, methods, or equipment not yet fully operational, details of their installation 

(Note: Relevant for inspection evaluation and testing baselines.) 

 Yes 

If there are deviations from the requirements of the rule, the Plan states reasons for Yes 

Alternative measures described in detail and provide equivalent environmental protection 

Inspector should document if the environmental equivalence is implemented in the field) 

 Yes Yes 

Plan includes diagram w th location and contents of all regulated containers (including completely 

se exempt from the SPCC requirements), transfer stations, and connecting 

 Yes Yes 

For each container, type of oil and storage capacity (see Appendix A) Yes Yes 

Discharge prevention measures, including procedures for routine handling of products Yes Yes 

(iii) Discharge or drainage controls, such as secondary containment around containers, and other 

structures, equipment, and procedures for the control of a discharge 

 Yes Yes 

(iv) Countermeasures for discharge discovery, response, and cleanup (both facility’s and contractor’s Yes Yes 

Methods of disposal of recovered materials in accordance w Yes 

(vi) Contact list and phone numbers for the facility response coordinator, National Response Center, 

cleanup contractors contracted to respond to a discharge, and all Federal, State, and local 

agencies who must be contacted in the case of a discharge as described in §112.1(b) 

 Yes 

Onshore Oil Production, Drilling, & Workover Facilities Page 5 of 14 Version 1.0, 11/28/2005 
GENERAL SPCC REQUIREMENTS—40 CFR 112.7 FIELD 

; 

G 

G No 

G NA 

G 

G No 

G NA 

112.7(b) 

potential for equipment failure 

G 

G No 

G NA 

G 

G No 

G NA 

112.7(c) 

For onshore facilities, one of the following or its 

, , 

ponds, 

G 

G No 

G NA 

G 

G No 

G NA 

112.7(d) G 

G No 

If YES, G 

G No 

G NA 

G 

G No 

G NA 

ith the container) is conducted 

G 

G No 

G NA 

G 

G No 

G NA 

(1) 

G 

G No 

G NA 

(2) G 

G No 

G NA 

G 

G No 

G NA 

112.7(e) i G 

G No 

G NA 

ith Plan for at least 3 G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

PLAN 

112.7(a)(4) Plan includes information and procedures that enable a person reporting a discharge as described 

in §112.1(b) to relate information on the exact address or location and phone number of the facility 

the date and time of the discharge; the type of material discharged; estimates of the total quantity 

discharged; estimates of the quantity discharged as described in §112.1(b); the source of the 

discharge; a description of all affected media; the cause of the discharge; any damages or injuries 

caused by the discharge; actions being used to stop, remove, and mitigate the effects of the 

discharge; whether an evacuation may be needed; and the names of individuals and/or 

organizations who have also been contacted (Not required if a facility has an FRP) 

 Yes 

112.7(a)(5) Plan organized so that portions describing procedures to be used when a discharge occurs will be 

readily usable in an emergency (Not required if a facility has an FRP) 

 Yes 

Plan includes a prediction of the direction, rate of flow, and total quantity of oil that could be 

discharged for each type of major equipment failure where experience indicates a reasonable 

 Yes Yes 

Appropriate containment and/or diversionary structures provided to prevent a discharge as 

described in §112.1(b) before cleanup occurs. The entire containment system, including walls and 

floors, is capable of containing oil and is constructed to prevent escape of a discharge from the 

containment system before cleanup occurs. (1) 

equivalent: (i) dikes, berms, or retaining walls sufficiently impervious to contain oil, (ii) curbing, (iii) 

culverting, gutters or other drainage systems (iv) weirs, booms or other barriers (v) spill diversion 

(vi) retention ponds, or (vii) sorbent materials (See Appendix A) 

 Yes Yes 

Determination(s) of impracticability of secondary containment Yes 

is the impracticability of secondary containment clearly demonstrated? Yes Yes 

Comments concerning impracticability determination(s) for secondary containment: 

If impracticability determination is made, for bulk storage containers, periodic integrity testing of 

containers and leak testing of the valves and piping (associated w

 Yes Yes 

If impracticability determination is made, unless facility has FRP: 

Contingency Plan following 40 CFR part 109 (see Appendix C) is provided AND 

 Yes 

Written commitment of manpower, equipment, and materials required to control and 

remove any quantity of oil discharged that may be harmful 

 Yes Yes 

Inspections and tests conducted in accordance w th written procedures Yes 

Record of inspections or tests signed by supervisor or inspector and kept w 

years (see Appendix B checklist) 

 Yes Yes 

Onshore Oil Production, Drilling, & Workover Facilities Page 6 of 14 Version 1.0, 11/28/2005 
GENERAL SPCC REQUIREMENTS—40 CFR 112.7 FIELD 

(1) 

operations; and contents of SPCC Plan 

G 

G No 

G NA 

G 

G No 

G NA 

(2) G 

G No 

G NA 

G 

G No 

G NA 

(3) G 

G No 

G NA 

G 

G No 

G NA 

(1) ) drainage flow 

G Yes G No 

• 

G 

G No 

G NA 

G 

G No 

G NA 

loaded/unloaded at the facility 

G 

G No 

G NA 

G 

G No 

G NA 

(2) 

areas (the location adjacent to the ) to prevent vehicles from departing before 

G 

G No 

G NA 

G 

G No 

G NA 

(3) G 

G No 

G NA 

G 

G No 

G NA 

112.7(i) 

112.7(i) G 

G No 

G NA 

G 

G No 

G NA 

112.7(j) i 

112.7(j) Discussion of conformance wi G 

G No 

G NA 

Comments: 

INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

PLAN 

112.7(f) Personnel, training, and oil discharge prevention procedures 

Training of oil-handling personnel in operation and maintenance of equipment to prevent discharges; 

discharge procedure protocols; applicable pollution control laws, rules and regulations; general facility 

 Yes Yes 

Person designated as accountable for discharge prevention at the facility Yes Yes 

Discharge prevention briefings conducted at least once a year for oil handling personnel Yes Yes 

112.7(h) Tank car and tank truck loading/unloading rack* 

Does loading/unloading area (the location adjacent to the loading or unloading rack 

to catchment basin or treatment facility? 

If NO, quick drainage system used 

 Yes Yes 

Containment system holds capacity of the largest single compartment of a tank car/truck Yes Yes 

Physical barriers, warning signs, wheel chocks, or vehicle brake interlock system in loading/unloading 

loading or unloading rack 

complete disconnection of flexible or fixed oil transfer lines 

 Yes Yes 

Lower-most drains and all outlets on tank cars/trucks inspected prior to filling/departure, and if necessary 

ensure that they are tightened, adjusted, or replaced to prevent liquid discharge while in transit 

 Yes Yes 

Brittle fracture evaluation of field-constructed aboveground containers 

Brittle fracture evaluation is conducted after tank repair/alteration/change in service that might affect 

the risk of a discharge or after a discharge/failure due to brittle fracture or other catastrophe and 

appropriate action taken as necessary (for field-constructed aboveground containers) 

 Yes Yes 

State rules, regulations and guidelines and conformance w th applicable sections of 40 CFR part 112 

th applicable more stringent State rules, regulations, and guidelines 

and other effective discharge prevention and containment procedures listed in 40 CFR part 112 

 Yes 

* Note that a tank car/truck loading/unloading rack must be present for §112.7(h) to apply. Though this requirement applies to all 

facilities, loading and unloading rack equipment is often not present at typical production facilities. 

Onshore Oil Production, Drilling, & Workover Facilities Page 7 of 14 Version 1.0, 11/28/2005 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

ONSHORE OIL PRODUCTION FACILITIES—112.9 FIELD 

(1) 

ith legally 

approved methods 

G 

G No 

G NA 

G 

G No 

G NA 

• 

as described in §112.1(b) 

G 

G No 

G NA 

G 

G No 

G NA 

• G 

G No 

G 

G No 

G NA G NA 

• 

issued in accordance with §122.41(j)(2) and (m)(3) 

G 

G No 

G NA 

G 

G No 

G NA 

(2) G 

G No 

G NA 

G 

G No 

G NA 

(1) i G 

G No 

G 

G No 

G NA G NA 

(2) i G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G 

G No 

G NA G NA 

(3) G 

G No 

G NA 

G 

G No 

G NA 

(4) ith good engineering practices to prevent 

discharges including at least one of the followi 

G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

PLAN 

112.9(b) Oil production facility drainage 

At tank batteries, separation and treating areas where there is a reasonable possibility of a discharge as 

described in §112.1(b), drainage is closed and sealed except when draining uncontaminated rainwater. 

Accumulated oil on the rainwater is returned to storage or disposed of in accordance w

 Yes Yes 

Prior to drainage, diked area inspected and action taken as provided in §112.8(c)(3)(ii), (iii), and (iv): 

112.8(c)(3)(ii) Retained rainwater is inspected to ensure that its presence will not cause a discharge Yes Yes 

112.8(c)(3)(iii) Bypass valve opened and resealed under responsible supervision Yes Yes 

112.8(c)(3)(iv) Adequate records of drainage are kept; for example, records required under permits Yes Yes 

Field drainage systems and oil traps, sumps, or skimmers inspected at regularly scheduled intervals for oil, 

and accumulations of oil promptly removed 

 Yes Yes 

112.9(c) Oil production facility bulk storage containers 

Containers used are compatible w th material stored and conditions of storage Yes Yes 

Secondary containment provided for all tank battery, separation and treating facilities w th capacity to 

hold the largest single container and sufficient freeboard for precipitation 

 Yes Yes 

Drainage from undiked areas safely confined in a catchment basin or holding pond Yes Yes 

Periodically and upon a regular schedule, visually inspect containers on or above the surface of the ground 

for deterioration and maintenance needs, including foundations and supports 

 Yes Yes 

New and old tank batteries engineered/updated in accordance w 

ng: (i) adequate container capacity to prevent overfill if 

regular pumping/gauging is delayed; (ii) overflow equalizing lines between containers so that a full 

 Yes Yes 

container can overflow to an adjacent container; (iii) vacuum protection to prevent container collapse; or 

(iv) high level sensors to generate and transmit an alarm to the computer where the facility is subject to a 

computer production control system 

Onshore Oil Production, Drilling, & Workover Facilities Page 8 of 14 Version 1.0, 11/28/2005 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

ONSHORE OIL PRODUCTION FACILITIES—112.9 FIELD 

(1) i G 

G No 

G NA 

G 

G No 

G NA 

(2) 

i 

G 

G No 

G NA 

G 

G No 

G NA 

(3) G 

G No 

G 

G No 

G NA G NA 

Comments: 

ONSHORE OIL DRILLING AND WORKOVER FACILITIES—112.10 FIELD 

§112.1(b) 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

112.10(d) G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

PLAN 

112.9(d) Facility transfer operations 

All aboveground valves and piping associated w th transfer operations are inspected periodically and upon 

a regular schedule. Include the general condition of flange joints, valve glands and bodies, drip pans, pipe 

supports, pumping well polish rod stuffing boxes, bleeder and gauge valves, and other such items. 

 Yes Yes 

Saltwater (oil field brine) disposal facilities inspected often to detect possible system upsets capable of 

causing a discharge, particularly follow ng a sudden change in atmospheric temperature 

 Yes Yes 

Flowline maintenance program to prevent discharges from each flowline is established Yes Yes 

PLAN 

112.10(b) Mobile drilling or workover equipment is positioned or located to prevent a discharge as described in Yes Yes 

112.10(c) Catchment basins or diversion structures are provided to intercept and contain discharges of fuel, 

crude oil, or oily drilling fluids. 

 Yes Yes 

Blowout prevention (BOP) assembly and well control system installed before drilling below any 

casing string or during workover operations 

 Yes Yes 

BOP assembly and well control system capable of controlling any well-head pressure that may be 

encountered while on the well 

 Yes Yes 

Onshore Oil Production, Drilling, & Workover Facilities Page 9 of 14 Version 1.0, 11/28/2005 
ADDITIONAL COMMENTS 

Rule Provision Comment 

Onshore Oil Production, Drilling, & Workover Facilities Page 10 of 14 Version 1.0, 11/28/2005 
) 

PHOTO DOCUMENTATION LOG 

Photo Number Description (include date and location 

Onshore Oil Production, Drilling, & Workover Facilities Page 11 of 14 Version 1.0, 11/28/2005 
SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
 
 

Appendix A: Documentation of Field Observations of Containers and Associated Requirements 

Inspectors should use this table to document observations of containers, as needed. 

ithin diked areas. 

vegetation. 

Containers and Piping 

Check containers for leaks, specifically looking for: drip marks, discoloration of tanks, puddles containing spilled or leaked material, 

corrosion, cracks, and localized dead vegetation, and standard/specifications of construction.. 

Check aboveground container foundation for: cracks, discoloration, puddles containing spilled or leaked material, settling, gaps 

between container and foundation, and damage caused by vegetation roots. 

Check all piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored material 

seepage from valves or seals, evidence of leaks from flowlines, and localized dead vegetation. For all aboveground piping, include the 

general condition of flange joints, valve glands and bodies, drip pans, pipe supports, pumping well polish rod stuffing boxes, bleeder and 

gauge valves, and other such items. (Document in comments section of §112.9(d)). 

Secondary Containment 

Check secondary containment for: containment system (including walls and floor) ability to contain oil such that oil will not escape the 

containment system before cleanup occurs, proper sizing, cracks, discoloration, presence of spilled or leaked material (standing liquid), 

erosion, corrosion, penetrations in the containment system, and valve conditions. 

Check dike or berm systems for: level of precipitation in dike/available capacity, operational status of drainage valves (closed), dike 

or berm impermeability, debris, erosion, impermeability of the earthen floor/walls of diked area, and location/status of pipes, inlets, 

drainage around and beneath containers, presence of oil discharges w 

Check drainage systems for: an accumulations of oil that may have resulted from any small discharge, including field drainage 

systems (such as drainage ditches or road ditches), and oil traps, sumps, or skimmers. Ensure any accumulations of oil have been 

promptly removed. 

Check retention and drainage ponds for: erosion, available capacity, presence of spilled or leaked material, debris, and stressed 

Container ID/ General Condition Storage Capacity and 

Type of Oil 

Type of Containment/ 

Drainage Control 

Overfill Protection and 

Testing & Inspections 

Onshore Oil Production, Drilling, & Workover Facilities Page 12 of 14 Version 1.0, 11/28/2005 
SPCC INSPECTION AND TESTING CHECKLIST 

Appendix B: Required Documentation of Tests and Inspections 

Records of inspections and tests required by 40 CFR part 112 signed by the appropriate supervisor or inspector must be kept with the 

SPCC Plan for a period of three years. Records of inspections and tests conducted under usual and customary business practices will 

suffice. Documentation of the following inspections and tests should be kept with the SPCC Plan. 

Not 

Not 

112.7–General SPCC Requirements 

(a) ith no secondary 

made 

(d) ith bulk storage 

containers wi 

(i) 

a repair, alteration, 

reconstruction or change in service 

112.9–Onshore oil production facilities 

(b)(1) 

(b)(2) 

(c)(3) 

deterioration and maintenance needs 

(d)(1) ith transfer operations are 

(d)(2) 

capable of causing a discharge 

(d)(3) 

Comments: 

Documentation 

Inspection or Test Applicable 

Present Present 

Integrity testing is conducted for bulk storage containers w 

containment system and for which an impracticability determination has been 

Integrity and leak testing of valves and piping associated w 

th no secondary containment system and for which an 

impracticability determination has been made 

Evaluate field-constructed aboveground containers for potential for brittle fracture 

or other catastrophic failure when the container undergoes 

Rainwater released directly from diked containment areas to a storm drain or 

open watercourse inspected and records of drainage kept 

Field drainage systems, oil traps, sumps, and skimmers inspected regularly for 

oil, and accumulations of oil promptly removed 

Regular visual inspections of containers, foundations and supports for 

All aboveground valves and piping associated w 

regularly inspected 

Saltwater disposal facilities inspected often to detect possible system upsets 

Specific and individual inspection, testing, and/or evaluation requirements as 

required by facility’s flowline maintenance program 

Onshore Oil Production, Drilling, & Workover Facilities Page 13 of 14 Version 1.0, 11/28/2005 
SPCC CONTINGENCY PLAN REVIEW CHECKLIST 

Appendix C: 40 CFR Part 109–Criteria for State, Local and Regional Oil 

Removal Contingency Plans 

If a facility makes an impracticability determination for secondary containment in accordance with §112.7(d), it is required to provide 

an oil spill contingency plan following 40 CFR part 109. 

* Yes 

involved in planning or directing oil removal operations. 

discharge including: 

(1) 

(2) 

(3) 

i 

(4) 

including: 

(1) 

(2) 

discharge to be anticipated. 

(3) 

equipment, materials and supplies to be used in responding to such a discharge. 

including: 

(1) 

operating personnel. 

(2) ith the 

(3) 

(4) 

(5) 

109.5–Development and implementation criteria for State, local and regional oil removal contingency plans No 

(a) Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to be 

(b) Establishment of notification procedures for the purpose of early detection and timely notification of an oil 

The identification of critical water use areas to facilitate the reporting of and response to oil discharges. 

A current list of names, telephone numbers and addresses of the responsible persons (with alternates) and 

organizations to be notified when an oil discharge is discovered. 

Provisions for access to a reliable communications system for timely notification of an oil discharge, and 

the capability of interconnection w th the communications systems established under related oil removal 

contingency plans, particularly State and National plans (e.g., NCP). 

An established, prearranged procedure for requesting assistance during a major disaster or when the 

situation exceeds the response capability of the State, local or regional authority. 

(c) Provisions to assure that full resource capability is known and can be committed during an oil discharge situation 

The identification and inventory of applicable equipment, materials and supplies which are available locally 

and regionally. 

An estimate of the equipment, materials and supplies which would be required to remove the maximum oil 

Development of agreements and arrangements in advance of an oil discharge for the acquisition of 

(d) Provisions for well defined and specific actions to be taken after discovery and notification of an oil discharge 

Specification of an oil discharge response operating team consisting of trained, prepared and available 

Predesignation of a properly qualified oil discharge response coordinator who is charged w 

responsibility and delegated commensurate authority for directing and coordinating response operations 

and who knows how to request assistance from Federal authorities operating under existing national and 

regional contingency plans. 

A preplanned location for an oil discharge response operations center and a reliable communications 

system for directing the coordinated overall response operations. 

Provisions for varying degrees of response effort depending on the severity of the oil discharge. 

Specification of the order of priority in which the various water uses are to be protected where more than 

one water use may be adversely affected as a result of an oil discharge and where response operations 

may not be adequate to protect all uses. 

(e) Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided 

for by State and local statutes and ordinances. 

* The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the National
 
 

Contingency Plan (NCP).
 
 

Onshore Oil Production, Drilling, & Workover Facilities Page 14 of 14 Version 1.0, 11/28/2005 
SPCC Guidance for Regional Inspectors 

This page intentionally left blank. 

U.S. Environmental Protection Agency Version 1.0, 11/28/2005 
U.S. ENVIRONMENTAL PROTECTION AGENCY 

SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST 

FOR USE AT OFFSHORE DRILLING, PRODUCTION, AND WORKOVER FACILITIES 

Overview of the Checklist 

This checklist is designed to assist EPA inspectors in conducting a thorough and consistent 

inspection of a facility’s compliance with the Spill Prevention, Control, and Countermeasure 

(SPCC) rule at 40 CFR part 112. It is a tool to help federal inspectors (or their contractors) 

record observations during the site visit and review of the SPCC Plan. While the checklist is 

comprehensive, the inspector should always refer to the SPCC rule in its entirety, the SPCC 

Regional Inspector Guidance Document, and other relevant guidance for evaluating 

compliance. This checklist must be completed in order for an inspection to count toward an 

agency measure (i.e., OEM/OECA inspection measures or GPRA). 

The checklist is organized according to the SPCC rule. Each item in the checklist identifies the 

relevant section and paragraph in 40 CFR part 112 where that requirement is stated. 

Sections 112.1 through 112.5 specify the applicability of the rule and requirements for the 

preparation, implementation, and amendment of SPCC Plans. For these sections, the checklist 

includes data fields to be completed, as well as several questions with “yes” or “no” answers. 

Sections 112.7 through 112.11 specify requirements for spill prevention, control, and 

countermeasures. For these sections, the inspector needs to evaluate whether the requirement 

is addressed adequately or inadequately in the SPCC Plan and whether it is implemented 

adequately in the field (either by field observation or record review). For the SPCC Plan and 

implementation in the field, if a requirement is addressed adequately, mark the “Yes” box in the 

appropriate column. If a requirement is not addressed adequately, mark the “No” box. If a 

requirement does not apply to the particular facility, mark the “NA” box. If a provision of the rule 

applies only to the SPCC Plan, the “Field” column is shaded. 

Space is provided in each section to record comments. Additional space is available on the 

comments page at the end of the checklist. Comments should remain factual and support the 

evaluation of compliance. 

Appendix A is for recording information about containers and other locations at the facility that 

require secondary containment. 

Appendix B is a checklist for documentation of the tests and inspections the facility operator is 

required to keep with the SPCC Plan. 

Appendix C is a checklist for oil removal contingency plans. A contingency plan is required if a 

facility determines that secondary containment is impracticable as provided in 40 CFR 112.7(d). 

OFFSHORE FACILITIES Page 1 of 14 Version 1.0, 11/28/2005 
U.S. ENVIRONMENTAL PROTECTION AGENCY 

SPCC FIELD INSPECTION AND PLAN REVIEW CHECKLIST 

FOR USE AT OFFSHORE DRILLING, PRODUCTION, AND WORKOVER FACILITIES 

FACILITY INFORMATION 

FACILITY NAME: 

ADDRESS: LAT: LONG: 

CITY: STATE: ZIP: COUNTY: 

TELEPHONE: FACILITY REPRESENTATIVE NAME: 

OWNER NAME: 

OWNER ADDRESS: 

CITY: STATE: ZIP: 

TELEPHONE: OWNER CONTACT PERSON: 

FACILITY OPERATOR NAME (IF DIFFERENT FROM OWNER – IF NOT, PRINT “SAME”): 

OPERATOR ADDRESS: 

CITY: STATE: ZIP: 

TELEPHONE: OPERATOR CONTACT PERSON: 

FACILITY TYPE: NAICS CODE: 

HOURS PER DAY FACILITY ATTENDED: TOTAL FACILITY CAPACITY: 

TYPE(S) OF OIL STORED: 

IS FACILITY LOCATED IN INDIAN COUNTRY? G YES G NO IF YES, RESERVATION NAME: 

INSPECTION INFORMATION 

INSPECTION DATE: TIME: INSPECTION NUMBER: 
 

LEAD INSPECTOR: 
 


 

INSPECTOR ACKNOWLEDGMENT 

OTHER INSPECTOR(S): 

I performed an SPCC inspection at the facility specified above. 

INSPECTOR SIGNATURE: DATE: 

OFFSHORE FACILITIES Page 2 of 14 Version 1.0, 11/28/2005 
GENERAL APPLICABILITY—40 CFR 112.1 


 

OR 
 

gallons G Yes G No 
 


 


 

G Yes G No 
 


 

i 

• 	 

• 	 i 

• 	 

. 

• 	 

• 	 

	 G Yes G No 

Comments: 

REQUIREMENTS FOR PREPARATION AND IMPLEMENTATION OF A SPCC PLAN—40 CFR 112.3 


 

Current plan version (date/number): 
 

112.3(a) 
 

• 	 G Yes G No G NA 

• 	 G Yes G No G NA 


 

G Yes G No G NA 
 

112.3(b) G Yes G No G NA 

& (c) 

112.3(d) 

• PE is familiar with the requirements of 40 CFR part 112 

• 

• 

• 

• 

G Yes G No 

G Yes G No 

G Yes G No 

G Yes G No 

G Yes G No 

PE Name: State: Date of certification: 

112.3(e) G Yes G No G NA 

Comments: 

IS THE FACILITY REGULATED UNDER 40 CFR part 112? 

The completely buried oil storage capacity is over 42,000 gallons, the aggregate aboveground oil storage capacity is over 1,320 

AND 

The facility is a non-transportation-related facility engaged in drilling, producing, gathering, storing, processing, refining, transferring, 

distributing, using, or consuming oil and oil products, which due to its location could reasonably be expected to discharge oil into or 

upon the navigable waters of the United States (as defined in 40 CFR 110.1). 

AFFECTED WATERWAY(S): DISTANCE: 

PATH: 

Note: The following storage capacity is not considered in determ ning applicability of SPCC requirements: 

Completely buried tanks subject to all the technical requirements of 40 CFR part 280 or a state program approved under 40 CFR part 281. 

Equipment subject to the authority of the U.S. Department of Transportation, U.S. Department of the Interior, or M nerals Management Service, 

as defined in Memoranda of Understanding dated November 24, 1971, and November 8, 1993. 

Any facility or part thereof used exclusively for wastewater treatment (production, recovery or recycling of oil is not considered wastewater 

treatment) 

Containers smaller than 55 gallons. 

Permanently closed containers. 

Does the facility have an SPCC Plan? 

Date facility began operations: 

Date of initial SPCC Plan preparation: 

For facilities in operation prior to August 16, 2002: 

Plan amended by February 17, 2006 

Amended Plan implemented by August 18, 2006 

For facilities beginning operation between August 17, 2002, and August 18, 

2006, Plan prepared and fully implemented by August 18, 2006 

For facilities beginning operation after August 18, 2006, Plan prepared and fully 

implemented before beginning operations 

Professional Engineer certification includes statement that the PE attests: 

PE or agent has visited and examined the facility 

Plan is prepared in accordance with good engineering practice including consideration of 

applicable industry standards and the requirements of 40 CFR part 112 

Procedures for required inspections and testing have been established 

Plan is adequate for the facility 

License No.: 

Plan available onsite if facility is attended at least 4 hours/day 

(If located at nearest field office, please note contact information below.) 

OFFSHORE FACILITIES Page 3 of 14 	 Version 1.0, 11/28/2005 
112.4(a) 	 G Yes G No 

• 	 G Yes G No G NA 

• 	 

• G Yes G No G NA 

G Yes G No G NA 

Comments: 

AMENDMENT OF SPCC PLAN BY THE OWNER OR OPERATOR—40 CFR 112.5 

112.5(a) G Yes G No G NA 

• ithin six months of the change? G Yes G No G NA 

112.5(b) G Yes G No G NA 

• 	 i ithin six G Yes G No G NA 

112.5(c) ith G Yes G No G NA 

§112.3(d) 

Name: State: 

Reason for amendment: 
 

Amendments implemented wi G Yes G No G NA 
 

Comments: 

AMENDMENT OF SPCC PLAN BY REGIONAL ADMINISTRATOR (RA)—40 CFR 112.4 

Has the facility discharged a reportable quantity of oil in amounts considered harmful: more 

than 1,000 gallons of oil in a single discharge or more than 42 gallons in each of two 

discharges in any 12-month period (see 40 CFR part 110)? 

If yes, was information submitted to the RA as required in §112.4(a)? 

Date(s) of reportable discharge(s): 

Were they reported to the NRC? 

112.4(d), (e) Have changes required by the RA been implemented in the Plan and/or facility? 

Has there been a change at the facility that materially affects the potential for a discharge? 

If so, was the Plan amended w 

Review and evaluation of the Plan documented at least once every 5 years? 

Follow ng Plan review, and if amendment was required, was Plan amended w 

months to include more effective prevention and control technology, if available? 

Professional Engineer certification of any technical Plan amendments in accordance w 

License No.: Date of certification: 

thin six months of any Plan amendment 

OFFSHORE FACILITIES Page 4 of 14 	 Version 1.0, 11/28/2005 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

GENERAL SPCC REQUIREMENTS—40 CFR 112.7 FIELD 

G Yes G No 

Name: Title: Date: 

G 

G No 

and start-up are discussed 

G 

G No 

G NA 

112.7(a)(2) 

nonconformance 

G 

G No 

G NA 

(Note: G 

G No 

G NA 

G 

G No 

G NA 

Describe each deviation and reasons for nonconformance: 

112.7(a)(3) i 

buried tanks otherwi 

G 

G No 

G NA 

G 

G No 

G NA 

pipes 

112.7(a)(3) Plan addresses each of the following: 

(i) G 

G No 

G 

G No 

G NA G NA 

(ii) G 

G No 

G 

G No 

G NA G NA 

G 

G No 

G NA 

G 

G No 

G NA 

resources) 

G 

G No 

G NA 

G 

G No 

G NA 

(v) ith applicable legal requirements G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

PLAN 

Management approval at a level of authority to commit the necessary resources to fully implement the Plan 

Plan follows sequence of the rule or provides a cross-reference of requirements in the Plan and the rule Yes 

If Plan calls for facilities, procedures, methods, or equipment not yet fully operational, details of their installation 

(Note: Relevant for inspection evaluation and testing baselines.) 

 Yes 

If there are deviations from the requirements of the rule, the Plan states reasons for Yes 

Alternative measures described in detail and provide equivalent environmental protection 

Inspector should document if the environmental equivalence is implemented in the field.) 

 Yes Yes 

Plan includes diagram w th location and contents of all regulated containers (including completely 

se exempt from the SPCC requirements), transfer stations, and connecting 

 Yes Yes 

For each container, type of oil and storage capacity (see Appendix A) Yes Yes 

Discharge prevention measures, including procedures for routine handling of products Yes Yes 

(iii) Discharge or drainage controls, such as secondary containment around containers, and other 

structures, equipment, and procedures for the control of a discharge 

 Yes Yes 

(iv) Countermeasures for discharge discovery, response, and cleanup (both facility’s and contractor’s Yes Yes 

Methods of disposal of recovered materials in accordance w Yes 

(vi) Contact list and phone numbers for the facility response coordinator, National Response Center, 

cleanup contractors contracted to respond to a discharge, and all Federal, State, and local agencies 

who must be contacted in the case of a discharge as described in §112.1(b) 

 Yes 

OFFSHORE FACILITIES Page 5 of 14 Version 1.0, 11/28/2005 
GENERAL SPCC REQUIREMENTS—40 CFR 112.7 FIELD 

; 

G 

G No 

G NA 

G 

G No 

G NA 

112.7(b) 

potential for equipment failure 

G 

G No 

G NA 

112.7(c) 

For offshore facilities: (i) curbing or drip pans, 

G 

G No 

G NA 

G 

G No 

G NA 

112.7(d) G 

G No 

If YES, G 

G No 

G NA 

G 

G No 

G NA 

ith the container is conducted 

G 

G No 

G NA 

G 

G No 

G NA 

(1) 

G 

G No 

G NA 

(2) G 

G No 

G NA 

G 

G No 

G NA 

112.7(e) i G 

G No 

G NA 

ith Plan for at least 3 G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

PLAN 

112.7(a)(4) Plan includes information and procedures that enable a person reporting a discharge as described 

in §112.1(b) to relate information on the exact address or location and phone number of the facility 

the date and time of the discharge; the type of material discharged; estimates of the total quantity 

discharged; estimates of the quantity discharged as described in §112.1(b); the source of the 

discharge; a description of all affected media; the cause of the discharge; any damages or injuries 

caused by the discharge; actions being used to stop, remove, and mitigate the effects of the 

discharge; whether an evacuation may be needed; and the names of individuals and/or 

organizations who have also been contacted 

 Yes 

112.7(a)(5) Plan organized so that portions describing procedures to be used when a discharge occurs will be 

readily usable in an emergency 

 Yes 

Plan includes a prediction of the direction, rate of flow, and total quantity of oil that could be 

discharged for each type of major equipment failure where experience indicates a reasonable 

 Yes 

Appropriate containment and/or diversionary structures provided to prevent a discharge as 

described in §112.1(b) before cleanup occurs. The entire containment system, including walls and 

floors, is capable of containing oil and is constructed to prevent escape of a discharge from the 

containment system before a cleanup occurs. ... (2) 

or (ii) sumps and collection systems (See Appendix A) 

 Yes Yes 

Determination(s) of impracticability of secondary containment Yes 

 is the impracticability of secondary containment clearly demonstrated? Yes Yes 

Comments concerning impracticability determination(s) for secondary containment: 

If impracticability determination is made, for bulk storage containers, periodic integrity testing of 

containers and leak testing of the valves and piping associated w

 Yes Yes 

If impracticability determination is made: 

Contingency Plan following 40 CFR part 109 (see Appendix C) is provided AND 

 Yes 

Written commitment of manpower, equipment, and materials required to control and remove 

any quantity of oil discharged that may be harmful 

 Yes Yes 

Inspections and tests conducted in accordance w th written procedures Yes 

Record of inspections or tests signed by supervisor or inspector and kept w 

years (see Appendix B checklist) 

 Yes Yes 

OFFSHORE FACILITIES Page 6 of 14 Version 1.0, 11/28/2005 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

GENERAL SPCC REQUIREMENTS—40 CFR 112.7 FIELD 

(1) 

operations; and contents of SPCC Plan 

G 

G No 

G NA 

G 

G No 

G NA 

(2) G 

G No 

G NA 

G 

G No 

G NA 

(3) G 

G No 

G NA 

G 

G No 

G NA 

(1) Does loading/unloading area (the location adjacent to the 

G Yes G No 

• 

G 

G No 

G NA 

G 

G No 

G NA 

loaded/unloaded at the facility 

G 

G No 

G NA 

G 

G No 

G NA 

(2) 

areas (the location adjacent to the ) to prevent vehicles from departing before 

G 

G No 

G NA 

G 

G No 

G NA 

(3) G 

G No 

G NA 

G 

G No 

G NA 

112.7(i) 

112.7(i) G 

G No 

G NA 

G 

G No 

G NA 

112.7(j) i 

112.7(j) Discussion of conformance wi G 

G No 

G NA 

Comments: 

PLAN 

112.7(f) Personnel, training, and oil discharge prevention procedures 

Training of oil-handling personnel in operation and maintenance of equipment to prevent discharges; 

discharge procedure protocols; applicable pollution control laws, rules and regulations; general facility 

 Yes Yes 

Person designated as accountable for discharge prevention at the facility Yes Yes 

Discharge prevention briefings conducted at least once a year for oil handling personnel Yes Yes 

112.7(h) Tank car and tank truck loading/unloading rack* 

 loading or unloading rack) drainage flow to 

catchment basin or treatment facility? 

If NO, quick drainage system used 

 Yes Yes 

Containment system holds capacity of the largest single compartment of a tank car/truck Yes Yes 

Physical barriers, warning signs, wheel chocks, or vehicle brake interlock system in loading/unloading 

 loading or unloading rack 

complete disconnection of flexible or fixed oil transfer lines 

 Yes Yes 

Lower-most drains and all outlets on tank cars/trucks inspected prior to filling/departure, and if necessary 

ensure that they are tightened, adjusted, or replaced to prevent liquid discharge while in transit 

 Yes Yes 

Brittle fracture evaluation of field-constructed aboveground containers 

Brittle fracture evaluation is conducted after tank repair/alteration/change in service that might affect 

the risk of a discharge or after a discharge/failure due to brittle fracture or other catastrophe, and 

appropriate action taken as necessary (for field-constructed aboveground containers) 

 Yes Yes 

State rules, regulations and guidelines and conformance w th applicable sections of 40 CFR part 112 

th applicable more stringent State rules, regulations, and guidelines and 

other effective discharge prevention and containment procedures listed in 40 CFR part 112 

 Yes 

* Note that a tank car/truck loading/unloading rack must be present for §112.7(h) to apply. Though this requirement applies to all 

facilities, loading and unloading rack equipment is often not present at typical offshore production facilities. 

OFFSHORE FACILITIES Page 7 of 14 Version 1.0, 11/28/2005 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

OFFSHORE OIL DRILLING, PRODUCTION, OR WORKOVER FACILITIES—112.11 PLAN FIELD 

112.11(b) 

associated equipment 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

112.11(c) G 

G No 

G 

G No 

G NA G NA 

not escape 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G 

G No 

G NA G NA 

112.11(d) i 

ith high liquid level 

G 

G No 

G NA 

G 

G No 

G NA 

dump valves 

112.11(e) 

ise prevent discharges 

G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

Oil drainage collection equipment used to prevent and control small discharges around pumps, 

glands, valves, flanges, expansion joints, hoses, drain lines, separators, treaters, tanks, and 

 Yes Yes 

Facility drains are controlled and directed toward a central collection sump to prevent a discharge 

as described in §112.1(b); if drains and sumps not practicable, oil in collection equipment removed 

as often as necessary to prevent overflow 

 Yes Yes 

For facilities using a sump system, sump and drains adequately sized Yes Yes 

For facilities using a sump system, spare pump available to remove liquids and assure that oil does Yes Yes 

Regularly scheduled preventive maintenance inspection and testing program to assure reliable 

operation of liquid removal system and pump start-up device 

 Yes Yes 

Redundant automatic sump pumps and control devices are installed if necessary Yes Yes 

If separators and treaters are equipped w th dump valves which predominantly fail in the closed 

position and where pollution risk is high, facility equipped to prevent discharges by (1) extending the 

flare line to a diked area if the separator is near shore, (2) equipping separator w

 Yes Yes 

sensor to automatically shut in wells producing to the separator, OR (3) installing parallel redundant 

Atmospheric storage or surge containers equipped with high liquid level sensing devices that activate 

an alarm or control the flow, or otherw

 Yes Yes 

OFFSHORE FACILITIES Page 8 of 14 Version 1.0, 11/28/2005 
INDICATE IF ITEM IS ADDRESSED ADEQUATELY (Yes), INADEQUATELY (No), OR IS NOT APPLICABLE (NA) IN PLAN AND FIELD. 

OFFSHORE OIL DRILLING, PRODUCTION, OR WORKOVER FACILITIES—112.11 PLAN FIELD 

112.11(f) Pressure containers equipped wi 

control the flow 

G 

G No 

G NA 

G 

G No 

G NA 

112.11(g) G 

G No 

G 

G No 

G NA G NA 

112.11(h) G 

G No 

G NA 

112.11(i) 

periodic basis commensurate wi 

G 

G No 

G NA 

G 

G No 

G NA 

112.11(j) 

manual or remote control mechanisms 

G 

G No 

G NA 

112.11(k) G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

G 

G No 

G NA 

112.11(l) Manifolds (headers) equipped wi G 

G No 

G 

G No 

G NA G NA 

112.11(m) 

OR 

G 

G No 

G NA 

G 

G No 

G NA 

112.11(n) ith protective coatings or 

cathodic protection 

G 

G No 

G NA 

G 

G No 

G NA 

112.11(o) 

activities such as fishing operations 

G 

G No 

G NA 

G 

G No 

G NA 

112.11(p) G 

G No 

G NA 

G 

G No 

G NA 

Comments: 

th high and low pressure sensing devices that activate an alarm or Yes Yes 

Containers equipped with suitable corrosion protection Yes Yes 

Written procedures maintained in the SPCC plan for inspecting and testing pollution prevention 

equipment and systems 

 Yes 

Testing and inspection of pollution prevention equipment and systems conducted on a scheduled 

th the complexity, conditions, and circumstances of the facility and any 

other applicable regulations. Simulated discharges are used for testing and inspecting human and 

equipment pollution control and countermeasure systems 

 Yes Yes 

Detailed records are provided that describe surface and subsurface well shut-in valves and devices in 

use at the facility for each well. Records are sufficient to determine the method of activation or control, 

such as pressure differential, change in fluid or flow conditions, combination of pressure and flow, or 

 Yes 

Blowout prevention (BOP) assembly and well control system installed before drilling below any 

casing string and during workover operations 

 Yes Yes 

BOP assembly and well control system capable of controlling any well-head pressure that may be 

encountered while on the well 

 Yes Yes 

th check valves on individual flowlines Yes Yes 

If the shut-in well pressure is greater than the working pressure of the flowline and manifold valves up 

to and including the header valves, flowlines are equipped with a high pressure sensing device and 

shut-in valve at the wellhead, pressure relief system provided for flowlines 

 Yes Yes 

Piping appurtenant to the facility is protected from corrosion, such as w Yes Yes 

Sub-marine piping appurtenant to the facility is protected against environmental stresses and other Yes Yes 

Sub-marine piping maintained in good operating condition at all times. Piping periodically inspected or 

tested on a regular schedule for failures. Documentation of inspections or tests kept at facility. 

 Yes Yes 

OFFSHORE FACILITIES Page 9 of 14 Version 1.0, 11/28/2005 
ADDITIONAL COMMENTS 

Rule Provision Comment 

OFFSHORE FACILITIES Page 10 of 14 Version 1.0, 11/28/2005 
PHOTO DOCUMENTATION LOG 

Photo Number Description (include date and location )

OFFSHORE FACILITIES Page 11 of 14 Version 1.0, 11/28/2005 
SPCC FIELD INSPECTION AND PLAN REVIEW TABLE
 
 

Appendix A: Documentation of Field Observations for Containers and Associated Requirements 

Inspectors should use this table to document observations of containers, as needed. 

Containers 

i i 

wi 

valve conditions. 

Check containers for the following: (1) atmospheric storage or surge containers are equipped with high liquid level sensing devices 

that activate an alarm or control the flow, or otherw se prevent discharges (2) pressure containers are equipped w th high and low 

pressure sensing devices that activate an alarm or control the flow (3) containers are equipped th suitable corrosion protection. 

Check piping for: droplets of stored material, discoloration, corrosion, bowing of pipe between supports, evidence of stored material 

seepage from valves or seals, and localized dead vegetation. 

Secondary Containment 

Check secondary containment for: containment system (including walls and floor) ability to contain oil such that oil will not escape the 

containment system before cleanup occurs, cracks, discoloration, presence of spilled or leaked material (standing liquid), corrosion, and 

Container ID/General Condition Storage Capacity and 

Type of Oil 

Type of Containment/ 

Drainage Control 

Overfill Protection and 

Testing & Inspections 

OFFSHORE FACILITIES Page 12 of 14 Version 1.0, 11/28/2005 
SPCC INSPECTION AND TESTING CHECKLIST 

Appendix B: Required Documentation of Tests and Inspections 

Records of inspections and tests required by 40 CFR part 112 signed by the appropriate supervisor or inspector must be kept with the 

SPCC Plan for a period of three years. Records of inspections and tests conducted under usual and customary business practices will 

suffice. Documentation of the following inspections and tests should be kept with the SPCC Plan. 

Not 

Not 

112.7–General SPCC Requirements 

(d) ith no secondary 

made 

(d) ith bulk storage 

containers wi 

(i) 

a repair, alteration, 

reconstruction or change in service 

(c) 

(i) 

(p) 

Comments: 

Documentation 

Inspection or Test Applicable Present Present 

Integrity testing is conducted for bulk storage containers w 

containment system and for which an impracticability determination has been 

Integrity and leak testing of valves and piping associated w 

th no secondary containment system and for which an 

impracticability determination has been made 

Evaluate field-constructed aboveground containers for potential for brittle fracture 

or other catastrophic failure when the container undergoes 

112.11–Offshore oil drilling, production and workover facilities 

Regularly scheduled preventive maintenance inspection and testing program to 

assure reliable operation of liquid removal system and pump start-up device 

Testing and inspection of pollution prevention equipment and systems performed 

on a scheduled periodic basis. Simulated discharges are used for testing and 

inspecting human and equipment pollution control and countermeasure systems 

Submarine piping periodically inspected or tested for failures. 

OFFSHORE FACILITIES Page 13 of 14 Version 1.0, 11/28/2005 
SPCC CONTINGENCY PLAN REVIEW CHECKLIST 

Appendix C: 40 CFR Part 109–Criteria for State, Local and Regional Oil 

Removal Contingency Plans 

If a facility makes an impracticability determination for secondary containment in accordance with §112.7(d), it is required to provide 

an oil spill contingency plan following 40 CFR part 109. 

* Yes 

involved in planning or directing oil removal operations. 

discharge including: 

(1) 

(2) 

(3) 

i 

(4) 

including: 

(1) 

(2) 

discharge to be anticipated. 

(3) 

equipment, materials and supplies to be used in responding to such a discharge. 

including: 

(1) 

operating personnel. 

(2) ith the 

(3) 

(4) 

(5) 

109.5–Development and implementation criteria for State, local and regional oil removal contingency plans No 

(a) Definition of the authorities, responsibilities and duties of all persons, organizations or agencies which are to be 

(b) Establishment of notification procedures for the purpose of early detection and timely notification of an oil 

The identification of critical water use areas to facilitate the reporting of and response to oil discharges. 

A current list of names, telephone numbers and addresses of the responsible persons (with alternates) and 

organizations to be notified when an oil discharge is discovered. 

Provisions for access to a reliable communications system for timely notification of an oil discharge, and 

the capability of interconnection w th the communications systems established under related oil removal 

contingency plans, particularly State and National plans (e.g., NCP). 

An established, prearranged procedure for requesting assistance during a major disaster or when the 

situation exceeds the response capability of the State, local or regional authority. 

(c) Provisions to assure that full resource capability is known and can be committed during an oil discharge situation 

The identification and inventory of applicable equipment, materials and supplies which are available locally 

and regionally. 

An estimate of the equipment, materials and supplies which would be required to remove the maximum oil 

Development of agreements and arrangements in advance of an oil discharge for the acquisition of 

(d) Provisions for well defined and specific actions to be taken after discovery and notification of an oil discharge 

Specification of an oil discharge response operating team consisting of trained, prepared and available 

Predesignation of a properly qualified oil discharge response coordinator who is charged w 

responsibility and delegated commensurate authority for directing and coordinating response operations 

and who knows how to request assistance from Federal authorities operating under existing national and 

regional contingency plans. 

A preplanned location for an oil discharge response operations center and a reliable communications 

system for directing the coordinated overall response operations. 

Provisions for varying degrees of response effort depending on the severity of the oil discharge. 

Specification of the order of priority in which the various water uses are to be protected where more than 

one water use may be adversely affected as a result of an oil discharge and where response operations 

may not be adequate to protect all uses. 

(e) Specific and well defined procedures to facilitate recovery of damages and enforcement measures as provided 

for by State and local statutes and ordinances. 

* The contingency plan should be consistent with all applicable state and local plans, Area Contingency Plans, and the National
 
 

Contingency Plan (NCP).
 
 

OFFSHORE FACILITIES Page 14 of 14 Version 1.0, 11/28/2005 
Appendix H 

APPENDIX H: OTHER POLICY DOCUMENTS 

Letter to Melissa Young of Petroleum Marketers Association of America (2001)
 


Letter to Daniel Gilligan of Petroleum Marketers Association of America (May 25, 2004)
 


Letter to Mr. Chris Early of Safety-Kleen Corporation (July 14, 2004)
 


DOT/EPA Memo “Jurisdiction over Breakout Tanks/Bulk Oil Storage Tanks (Containers) at
 


Transportation-Related and Non-Transportation-Related Facilities” (February 4, 2000)
 


FRP rule attachments C-I and C-II
 


U.S. Environmental Protection Agency Version 1.0, 11/28/2005 
Melissa Young, Esq. 

Government Affairs Counsel 

Petroleum Marketers Association of America 

1901 N. Fort Meyer Drive 

Suite 1200 

Arlington, Virginia 22209-1604 

Dear Ms. Young: 

Thank you for your letter to Administrator Whitman of February 5, 2001, which she 

has referred to me for an answer. 

You explained that a marketer was notified by an Environmental Protection Agency 

(EPA) inspector that her facility, which is below the 42,000 gallon underground storage 

tank threshold capacity, would need a Spill Prevention, Control, and Countermeasure 

(SPCC) Plan, because she parks her 2,500 gallon cargo tank motor vehicle at the facility 

in the evenings. You noted that it is used to deliver petroleum products in commerce, not 

as a mobile fueling facility and that it is emptied before it is parked for the evening. 

EPA presumes that a cargo tank motor vehicle that contains no oil, other than any 

residual oil present in an emptied vehicle when it is parked at the facility in the evening, is 

a highway vehicle used for the transport of oil in interstate or intrastate commerce, and is 

therefore transportation-related, and not subject to SPCC jurisdiction. 40 CFR 112, 

Appendix A, Section II(2)(D). You should be aware, however, if the vehicle were to be 

used at any time in a fixed operating non-transportation mode, such as the storage or 

transfer of oil in any amount, other than any residual oil present in an emptied vehicle at the 

end of the day, then it would become subject to the SPCC rule if there were a reasonable 

possibility of discharge from the vehicle to navigable waters or adjoining shorelines. See 

40 CFR 112.3(c); and 40 CFR 112, Appendix A, Section II(1)(F). 

To determine if a fixed operating non-transportation mode has begun, and therefore 

EPA SPCC jurisdiction arises, an EPA inspector would will look at all the circumstances at 

a particular facility. Here, such circumstances might include whether the vehicle is 

functioning as a storage tank, supplementing storage capacity or transferring oil at the 

facility. We believe the vehicle you described is operating in a transportation-related 
mode, and therefore, no EPA SPCC regulatory jurisdiction arises. We note that if the 

vehicle itself were to be subject to the SPCC rule, it exceeds the SPCC regulatory 

threshold regardless of any other storage or use of oil at the facility. We also note that if it 

is used for the transport of oil exclusively within the confines of a facility and is not intended 

to transport oil in interstate or intrastate commerce, it may be subject to the SPCC rule. 40 

CFR 112, Appendix A, Section II(1)(J). 

Again, thank you for your letter. Please do not hesitate to contact us again 

if you have other questions concerning EPA’s oil program. If you have any questions about 

this letter, please contact Hugo Fleischman at 703-603-8769 or Mark Howard at 703-603-

8715.

 Sincerely,

 Stephen F. Heare, Acting Deputy Director,

 Office of Emergency and Remedial Response 

cc: Clifford J. Harvison, NTTC

 James Malcolm, MC 2131

 Susan Gorsky, DOT 
SPCC Guidance for Regional Inspectors 

This page intentionally left blank. 

U.S. Environmental Protection Agency Version 1.0, 11/28/2005 
Daniel Gilligan, President 

Petroleum Marketers Association of America 

Arlington, VA 22209-1604 

Dear Mr. Gilligan: 

1901 N. Fort Myer Drive- Suite 500 

This letter is in response to your request for the Agency’s view regarding whether several 

approaches under consideration by your members would satisfy 40 CFR §112.7(a)(2)’s 

“equivalent environmental protection” provision and for clarification of the scope of the 

requirements in 40 CFR §112.7(h)(entitled “Facility tank car and tank truck loading/unloading 

rack (excluding offshore facilities)”). We discuss each of your proposals and questions below. 

Please note that the guidance provided in this letter is based on generalized assumptions and may 

not be applicable in a particular case based on site-specific circumstances. 

“Equivalent Environmental Protection” 

Integrity Testing 

The newly amended SPCC provisions regarding bulk storage container integrity require, 

among other things, that each aboveground container be tested for integrity “on a regular 

schedule.” 40 CFR §112.8(c)(6). These regulations further provide that “you must combine 

visual inspection with another testing technique such as hydrostatic testing, radiographic testing, 

ultrasonic testing, acoustic emissions testing, or another system of non-destructive shell testing.” 

As you know, however, the regulations also allow deviations from this requirement where “you 

provide equivalent environmental protection by some other means of spill prevention, control, or 

countermeasure.” 40 CFR §112.7(a)(2). You have asked whether, for shop-built containers, 

visual inspection plus certain actions to ensure that the containers are not in contact with the soil 

would likely be considered to provide “equivalent environmental protection” to visual inspection 

plus another form of testing. 

It is our view that for well-designed shop-built containers with a shell capacity of 30,000 

gallons or under, combining appropriate visual inspection with the measures described below 

would generally provide environmental protection equivalent to that provided by visual 

inspection plus another form of testing. Specifically, the Agency generally believes that visual 

inspection plus elevation of a shop-built container in a manner that decreases corrosion potential 
(as compared to a container in contact with soil)1

 and makes all sides of the container, including 

the bottom, visible during inspection (e.g., where the containers are mounted on structural 

supports, saddles, or some forms of grillage) would be considered “equivalent.” In a similar 

vein, we’d also generally believe an approach that combines visual inspection with placement of 

a barrier between the container and the ground, designed and operated in a way that ensures that 

any leaks are immediately detected, to be considered “equivalent.” For example, we believe it 

would generally provide equivalent environmental protection to place a shop-built container on 

an adequately designed, maintained, and inspected synthetic liner.2 We believe these approaches 

would generally provide equivalent environmental protection when used for shop-built 

containers (which generally have a lower failure potential than field-erected containers), because 

these approaches generally reduce corrosion potential and ensure detection of any container 

failure before it becomes significant. 

In determining the appropriate SPCC plan requirements for visual inspection of 

containers managed as described above, we suggest that the professional engineer (PE) begin by 

consulting appropriate industry standards, such as those listed in Steel Tank Institute Standard 

SP001 and American Petroleum Institute Standard 653.3

 Similarly, in assessing whether a shopbuilt container is well designed, the PE may wish to consult industry standards such as 

Underwriters Laboratory 142 or American Petroleum Institute Standard 650, Appendix J. Where 

a facility is considering the use of the above approaches for containers that are currently resting 

on the ground, or have otherwise been managed in a way that presents risks for corrosion or are 

showing signs of corrosion, we recommend the facility first evaluate the condition of the 

1

Additionally, we recommend that special attention be paid to the characteristics of the 

material used for the support structure to ensure that they do not actually accelerate corrosion. 

2

Note, however, that a facility may not rely solely on measures that are required by other 

sections of the rule (e.g., secondary containment) to provide “equivalent environmental 

protection.” Otherwise, the deviation provision would allow for approaches that provide a lesser 

degree of protection overall. 

3

Note that the Agency intends in the near future to develop guidance on appropriate visual 

inspection of shop-built containers. In that guidance, we intend to address issues such as 

inspection frequency, scope (e.g., internal and /or external), training and/or qualifications of 

persons conducting the inspections, and other measures that may be appropriate at a given site 

(e.g., measures to detect the presence of water in a container). We expect to use the referenced 

industry standards in developing such guidance. 

It is also important to note, however, that depending on site circumstances, the 

appropriate requirements for visual inspection may exceed those normally conducted in 

accordance with recognized industry standards. 
container in accordance with good engineering practices, including seeking expert advice, where 

appropriate. 

Security 

The SPCC regulations state that you must “fully fence each facility handling, processing, 

or storing oil, and lock and/or guard entrance gates when the facility is not in production or is 

unattended.” 40 CFR §112.7(g)(1). You have asked whether two specific sets of circumstances 

would likely be determined to provide “equivalent environmental protection” to this requirement. 

The first is where the area of the facility directly involved in the handling, processing and storage 

of oil is adequately fenced. The second is where the facility is equipped with a “pump house” or 

“pump shack,” which contains, among other appropriate things, a master disconnect switch from 

which all power to pumps and containers is cut off when the facility is unattended. 

With respect to your first scenario, it is our view that, as a general matter, adequately 

fencing all discrete areas directly involved in the handling, processing and storage of oil would 

provide equivalent environmental protection to fencing the entire footprint of the facility, since it 

is potential for harm to this equipment that poses the risk addressed by the fencing requirement. 

With respect to the second scenario, the approach you suggest would appear to generally 

provide environmental protection equivalent to fencing for risks associated with the potential for 

unauthorized access to pumping equipment. In other words, cutting off power in the manner you 

suggest would likely provide the added layer of protection offered by a fence should the other 

security measures offered by the rule, in this case 40 CFR §112.7(g)(3)’s requirements for 

securing pumps, fail. However, because cutting off power as suggested does not address risks to 

containers, piping and appurtenances not associated with the pumps at the facility, it does not 

appear to provide protection equivalent to fencing as it relates to risks to such equipment. 

Conclusion 

Please note that determinations of “equivalent environmental protection” must be 

implemented and documented in accordance with 40 CFR §112.7(a)(2). In addition, please be 

aware that the conclusions drawn in this letter are only for the purposes of meeting the 

“environmental equivalence” standard in the SPCC regulation. PE’s might nevertheless decide 

to recommend non-destructive shell testing and fencing of the entire footprint of the facility for 

reasons other than compliance with the SPCC rule (e.g., to protect an owner’s investment in 

equipment or to meet other local, state or federal requirements). 
Finally, this letter is meant to provide guidance on the “equivalent environmental 

protection” standard. It does not, however, substitute for EPA's statutes or regulations, nor does 

it itself constitute a regulation. Thus, it cannot impose legally-binding requirements on EPA, 

States, or the regulated community, and its recommendations may not be appropriate at an 

individual site based on site-specific circumstances. 

Sincerely, 

Marianne Larmont Horinko 

Assistant Administrator 





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-�'-�-���)�&�	������������������������������������������������������������������������������������������������������� 
BREAKOUT TANKAGE

Fence 

Product

M Tank (Breakout) M

PumpValve

M Meter

Main Line

OE

SOURCE: US EPA REV: 11/09/99 
STORAGE TANKAGE

Fence

(Storage) (Storage)

M

MeterIsolationFlange

M

Product

Tank

Product

Tank

PumpValve

OE

Main Line

* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose o

311(j) (33 USC 1321(j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change in jur

meter, valve, or isolation flange at or inside the facility property line. When the pipeline operator and the storage or breakout tank o

change in jurisdiction occurs at the change in operational responsibility or at the first meter, valve, or isolation flange at or inside the of the above situations, the location of the property line should not solely be used to determine jurisdiction when operational activitie

beyond the property line.

SOURCE: US EPA REV: 11/09/99 
Plant

(Storage)

M Meter

M

M

STORAGE TANKAGE

Processin

Product

Tank

PumpValve

E

J

OPS jurisdipressure infwhich effecof the main 

Main Line

* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose of th

Section 311(j) (33 USC 1321(j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change i

at the first and last pressure influencing device, meter, valve, or isolation flange, at or inside the facility property line. When the pipeline 

or breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first an

influencing device, valve, or isolation flange, at or inside the facility property line. In either of the above situations, the location of the pr

should not solely be used to determine jurisdiction when operational activities (loading/offloading) extend beyond the property line.

SOURCE: US EPA REV: 11/09/99 
BREAKOUT AND STORAGE TANKAGE - JOINT EPA - OPS 

(A) (B)

Fence Fenc

M

Product

Tank

(Breakout)

&

(Storage)

M

M

Product

Tank

(Breakout)

&

(Storage)

Loading Area

M

M

Truck transferring

to Facility

Main Line

PumpValve

M Meter

OPS 

EPA 

Join

* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose of the 

Section 311(j) (33 USC 1321(j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change in 

at the first and last pressure influencing device, meter, valve, or isolation flange, at or inside the facility property line. When the pipeline o

or breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first and 

influencing device, valve, or isolation flange, at or inside the facility property line. In either of the above situations, the location of the pro

should not solely be used to determine jurisdiction when operational activities (loading/offloading) extend beyond the property line.

SOURCE: US EPA REV: 11/09/99 
STORAGE AND BREAKOUT TANKAGE - JOINT EPA - OPS 

Fence

(Storage)

&

(Breakout)

(Storage)

&

(Breakout)

M M

MeterIsolationFlange

M

Product

Tank

Product

Tank

PumpValve

O

EP

JoO

OPS jurisdicpressure inflwhich effects 

pressure of t

Main Line

* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose 

Section 311(j) (33 USC 1321(j)). When the pipeline operator and the storage or breakout tank operator remain the same, the cha

at the first and last pressure influencing device, meter, valve, or isolation flange, at or inside the facility property line. When the pip

or breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the fi

influencing device, valve, or isolation flange, at or inside the facility property line. In either of the above situations, the location of t

should not solely be used to determine jurisdiction when operational activities (loading/offloading) extend beyond the property line.

SOURCE: US EPA REV: 11/09/99
Fence

( (Storage)

(Storage) (Storage)

M

(Stora

Mix

( )Storage

M

MeterIsolationFlange

M

STORAGE TANKAGE

Product

Tank

Storage)

Product

Tank

Product

Tank

Product

Tank

Tank Tan

O

EP

PumpValve

Main Line

* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose of th

311(j) (33 USC 1321(j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change in jurisdi

meter, valve, or isolation flange at or inside the facility property line. When the pipeline operator and the storage or breakout tank oper

change in jurisdiction occurs at the change in operational responsibility or at the first meter, valve, or isolation flange at or inside the facof the above situations, the location of the property line should not solely be used to determine jurisdiction when operational activities

(loading/offloading) extend beyond the property line.

SOURCE: US EPA REV: 11/09/99 
STORAGE & BREAKOUT TANKAGE - JOINT EPA - OPS J

(Storage) (

(Breakout

&

Storage)

(Breakout

&

Storage)

M Meter

Mix

&

(Storage)

(

M

Product

Tank

Product

Tank

Storage)

Product

Tank

Product

Tank

PumpValve

Tank

(Breakout)

(

OPEPA Joi

Main Line

* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose of 

311(j) (33 USC 1321(j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change in juris

meter, valve, or isolation flange at or inside the facility property line. When the pipeline operator and the storage or breakout tank ope

change in jurisdiction occurs at the change in operational responsibility or at the first meter, valve, or isolation flange at or inside the faof the above situations, the location of the property line should not solely be used to determine jurisdiction when operational activities 

beyond the property line. 

SOURCE: US EPA REV: 11/09/99
STORAGE TANKAGE ASSOCIATED WITH

PRODUCTION/GATHERING

M

ValveMeter

O

Production/Gathering

Flowline

Main Line

Product

Tank

(Storage)

Gathering Line

G

G

Pump

LINES

M

Product

M Tank

(Storage

A

B

The gathering line between

points A and B is the subject

of continuing jurisdictional

discussions.

Gathering Line**

*In 40 CFR 112.1 and 112.7 EPA regulates onshore oil production facilities including wells, flowlines, separation equipment, stora

gathering lines and auxiliary non-transportation-related equipment and facilities in a single geographical oil or gas field operated 

**In 49 CFR 195 OPS does not regulate gathering lines (8 5/8 inch or less nominal outside diameter) that transports petroleum fr

in rural areas. See 49 CFR 195.1 and 195.2. The gathering line is subject to OPS response planning requirements in 49 CFR 19

SOURCE: US EPA REV: 12/06/99 
JURISDICTION

M Meter

(Storage)

(Storage)

&

M

M

BREAKOUT ANDSTORAGE TANKAGE ­

JOINT EPA - OPS Refinery

PumpValve

Product

Tank

Product

Tank

(Breakout) OPS Ju

EPA Ju

Joint EP

Main Line

* This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the purpose of th

Section 311(j) (33 USC 1321(j)). When the pipeline operator and the storage or breakout tank operator remain the same, the change i

at the first and last pressure influencing device, meter, valve, or isolation flange, at or inside the facility property line. When the pipeline 

or breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at the first an

influencing device, valve, or isolation flange, at or inside the facility property line. In either of the above situations, the location of the pr

should not solely be used to determine jurisdiction when operational activities (loading/offloading) extend beyond the property line. 

SOURCE: US EPA REV: 11/09/99
EPA, OPS, AND COAST GUARD JURISDICTIO

Product

(Storage)

&

(Breakout)

Pump

jurisdiction.

2 1

2

1

AT A COMPLEX FACILITY

Tank

MARINE LOADING DOCK

CG JurisdiOPS JurisdEPA Jurisd

Valve

The tank depicted is used f

storage associated with theMTR facility and is under EP

If tank is also u

as a breakout tank it is subje

to both OPS and EPA jurisd

Marine Transportation--Related Facility (MTR) is defined in 33

CFR 154.1020. This segment

of a complex is under CG

jurisdiction for the purposes of

CWA Section 311(j).

OPS jurisdiction extends topressure influencing device

which effects operatingpressure of the main pipeline.

Joint EPA-O

This diagram does not identify the precise location where the change in jurisdiction occurs between EPA and OPS for the pur

Section 311(j) (33 USC 1321(j)). When the pipeline operator and the storage or breakout tank operator remain the same, the 

at the first and last pressure influencing device, meter, valve, or isolation flange, at or inside the facility property line. When th

or breakout tank operator are not the same, the change in jurisdiction occurs at the change in operational responsibility or at t

influencing device, valve, or isolation flange, at or inside the facility property line. In either of the above situations, the location 

should not solely be used to determine jurisdiction when operational activities (loading/offloading) extend beyond the property 

SOURCE: US EPA REV: 12/13/99

ER30JN00.061</GPH>

Pt. 112, App. C 40 CFR Ch. I (7–1–03 Edition) 

ATTACHMENTS TO APPENDIX C 

52
 
 

Environmental Protection Agency 

ATTACHMENT C–II—CERTIFICATION OF THE APPLICABILITY OF THE SUBSTANTIAL HARM CRITERIA 

Facility Name: lllllllllllllll 

Facility Address: llllllllllllll 

1. Does the facility transfer oil over water 

to or from vessels and does the facility have 

a total oil storage capacity greater than or 

equal to 42,000 gallons? 

Yes lll No lll 

2. Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and does the facility lack secondary 

containment that is sufficiently large to 

contain the capacity of the largest aboveground oil storage tank plus sufficient 

freeboard to allow for precipitation within 

any aboveground oil storage tank area? 

Yes lll No lll 

3. Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and is the facility located at a distance (as calculated using the appropriate 

formula in Attachment C–III to this appendix or a comparable formula 1) such that a 

discharge from the facility could cause injury to fish and wildlife and sensitive environments? For further description of fish and 

wildlife and sensitive environments, see Appendices I, II, and III to DOC/NOAA’s ‘‘Guidance for Facility and Vessel Response Plans: 

Fish and Wildlife and Sensitive Environments’’ (see Appendix E to this part, section 

13, for availability) and the applicable Area 

Contingency Plan. 

Yes lll No lll 

4. Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and is the facility located at a distance (as calculated using the appropriate 

formula in Attachment C-III to this appendix 

or a comparable formula 1) such that a discharge from the facility would shut down a 

public drinking water intake 2 ? 

Yes lll No lll 

5. Does the facility have a total oil storage 

capacity greater than or equal to 1 million 

gallons and has the facility experienced a reportable oil discharge in an amount greater 

than or equal to 10,000 gallons within the last 

5 years? 

Yes lll No lll 

Certification 

I certify under penalty of law that I have 

personally examined and am familiar with 

the information submitted in this document, 

1 If a comparable formula is used, documentation of the reliability and analytical 

soundness of the comparable formula must 

be attached to this form. 2 For the purposes of 40 CFR part 112, public drinking water intakes are analogous to 

public water systems as described at 40 CFR 

143.2(c). 

Pt. 112, App. C 

and that based on my inquiry of those individuals responsible for obtaining this information, I believe that the submitted information is true, accurate, and complete. 

llllllllllllllllllllllll 

Signature 

llllllllllllllllllllllll 

Name (please type or print) 

llllllllllllllllllllllll 

Title 

llllllllllllllllllllllll 

Date 

ATTACHMENT C-III—CALCULATION OF THE 

PLANNING DISTANCE 

1.0 Introduction 

1.1 The facility owner or operator must 

evaluate whether the facility is located at a 

distance such that a discharge from the facility could cause injury to fish and wildlife 

and sensitive environments or disrupt operations at a public drinking water intake. To 

quantify that distance, EPA considered oil 

transport mechanisms over land and on still, 

tidal influence, and moving navigable waters. EPA has determined that the primary 

concern for calculation of a planning distance is the transport of oil in navigable waters during adverse weather conditions. 

Therefore, two formulas have been developed 

to determine distances for planning purposes 

from the point of discharge at the facility to 

the potential site of impact on moving and 

still waters, respectively. The formula for oil 

transport on moving navigable water is 

based on the velocity of the water body and 

the time interval for arrival of response resources. The still water formula accounts for 

the spread of discharged oil over the surface 

of the water. The method to determine oil 

transport on tidal influence areas is based on 

the type of oil discharged and the distance 

down current during ebb tide and up current 

during flood tide to the point of maximum 

tidal influence. 

1.2 EPA’s formulas were designed to be 

simple to use. However, facility owners or 

operators may calculate planning distances 

using more sophisticated formulas, which 

take into account broader scientific or engineering principles, or local conditions. Such 

comparable formulas may result in different 

planning distances than EPA’s formulas. In 

the event that an alternative formula that is 

comparable to one contained in this appendix is used to evaluate the criterion in 40 

CFR 112.20(f)(1)(ii)(B) or (f)(1)(ii)(C), the 

owner or operator shall attach documentation to the response plan cover sheet contained in Appendix F to this part that demonstrates the reliability and analytical 

soundness of the alternative formula and 

shall notify the Regional Administrator in 

53