Exhibit 1
2010 Agreement between OSHA and BP Products
Completed Abatement under the 2005 Settlement Agreement

The Parties agree that BP Products completed approximately 660 abatement actions imposed by the 2005 Settlement Agreement, including:

(1) Shut down and decommissioned the Isom unit to abate all hazardous conditions that contributed to the Isom incident;

(2) Abated more than 300 process safety, electrical, and other deficiencies alleged to exist at the Texas City Refinery;

(3) Expanded safety and health training at the Texas City Refinery;

(4) Retained, with the concurrence of OSHA, a qualified expert in the PSM field ("PSM Expert") to perform a comprehensive PSM systems audit, issue an audit report, conduct three semi-annual follow-up progress assessments, and issue three semi-annual progress reports;

(5) The PSM Expert issued 228 recommendations; BP Products accepted 220 of the recommendations Prepared and submitted to OSHA a statement of action to be taken on the 220 recommendations and submitted follow-up progress reports and implemented the recommendations (though the FTAN alleges that 4 recommendations related to safety instrumented systems were not implemented);

(6) BP Products retained an independent expert to conduct an audit of the adequacy of the methodology and engineering analysis the Refinery applied to its hydrocarbon pressure relief systems by examining these issues at Pipestill 3B and the Ultracracker. BP Products submitted a report of the findings and recommendations to OSHA and has implemented all 100 of the recommendations (though the FTAN alleges the audit should have been extended to the remaining process units at the Refinery).

(7) Retained, with the concurrence of OSHA, a qualified expert in the organizational communication, behavior, and analysis field ("Organizational Expert") to assess communication within the Texas City Refinery with respect to safety and safety commitment and to issue an interim and final report;

(8) Prepared and submitted to OSHA a statement of action to be taken on the recommendations set forth in the Organizational Experts interim and final reports and implemented the Organizational Experts feasible recommendations; (9) Submitted occupational injury and illness logs to OSHA semi-annually;

(10) Investigated and notified OSHA of any accident or injury involving PSM and/or Lockout-Tagout that resulted in one or more days of lost work-time; and

(11) Made a timely settlement payment of $21,361,500.

Exhibit 2
Equipment-Based Relief System Evaluations: Completion Schedule

Crude Distillation   Date
    PS3A Crude Distillation Unit A February 12, 2012
    PS3B Crude Distillation Unit B March 31, 2011
Resid Destruction    
    RHU Complex    
    RHU 200 Resid Hydroprocessing Unit 200 February 12, 2012
    RHU 300 Resid Hydroprocessing Unit 300 February 12, 2012
    RHU 400 Resid Hydroprocessing Unit 400 February 12, 2012
    RHU 500 Resid Hydroprocessing Unit 500 February 12, 2012
    RHU 600 Resid Hydroprocessing Unit 600 February 12, 2012
    Coker Complex    
    Coker B Coke Production Unit B September 30, 2011
    Coker C Coke Production Unit C September 30, 2011
    Coker Scrubber    
    RDU Resid Deasphalting Unit February 12, 2012
Cat Cracking    
    FCCU 1 Fluid Catalytic Cracker 1 September 30, 2011
    FCCU 3 Fluid Catalytic Cracker 3 February 12, 2012
    FCCU SHU    
Reforming    
    UU3 Naphtha Reformer Number 3 February 12, 2012
    UU4 Naphtha Reformer Number 4 September 30, 2011
Alkylation    
    Alky Treaters PP and BB Treaters March 31, 2011
    Alky Splitters   March 31, 2011
    Alky SHU Alkylation Selective HydroIsomerization Unit March 31, 2011
    Alky 3 HF Alkylation Unit February 12, 2012
Hydrotreating    
    ULC Distillate Hydrocracker March 31, 2011
    CFHU Cat Feed (Gas Oil) Hydrotreater February 12, 2012
    DDU Complex   February 12, 2012
    NDU Naptha Desulfurization Unit February 12, 2012
    HRU Hydrogen Recovery Unit February 12, 2012
Aromatics    
    ARU A Aromatics Sulfolane Extraction Unit A February 12, 2012
    ARU B Aromatics Sulfolane Extraction Unit B February 12, 2012
    AU2 Mobil Selective Toluene Disproportionation Unit February 12, 2012
SRU Complex    
  Amine Units    
    A Amine MEA Regeneration A February 12, 2012
    B Amine MEA Regeneration B February 12, 2012
    C Amine MEA Regeneration C February 12, 2012
    D Amine MEA Regeneration D February 12, 2012
  Sulfur Units    
    SRU A Sulfur Recovery Unit A February 12, 2012
    SRU B Sulfur Recovery Unit B February 12, 2012
    SRU C Sulfur Recovery Unit C February 12, 2012
    SRU D Sulfur Recovery Unit D February 12, 2012
  SCOT Units    
    C SCOT SCOT Tail Gas Treating Unit C February 12, 2012
    D SCOT SCOT Tail Gas Treating Unit D February 12, 2012
  Incinerators    
    C-Incinerator Incineration Facility C February 12, 2012
    D-Incinerator Incineration Facility D February 12, 2012


Exhibit 3
SUMMARY OF EQUIPMENT-BASED REVALIDATION
OF THE INSIDE UNIT BATTERY LIMIT (ISBL) PROCESS RELIEF SYSTEMS

This Exhibit 3 describes the equipment based revalidation process BP Products will implement to evaluate all of its process relief systems inside unit battery limits.

  1. BP Products will collect and ensure the accuracy of key information required to conduct the relief systems revalidation analysis. That information will include the following:
    • Heat and material balances-This includes the physical properties of the fluids in the system, the rate of fluid movement within the system, temperatures, pressures, fluid properties, and whether the material is a vapor, gas, liquid, or two phase.
    • Relief device information such as the relief device set points, blowdown, coefficients, type, manufacturer, model, orifice area, capacity, test pressure, and discharge location including whether it discharges to the atmosphere or to a flare.
    • Piping and instrumentation diagrams (P&IDs).
    • Equipment information such as the pressure vessels protected by the relief device, pressure vessel metallurgy, the applicable code to which the pressure vessel was constructed, maximum allowable working pressure or design pressure, and vessel dimensions.
    • Other data such as the piping used in the relief system, piping metallurgy, inlet and outlet size, and location of block valves within the system.
    • Process flow diagrams (PFDs) or sketch.
    • Operating conditions.
    • Piping sketches.
    • Field verification of data identified above, where needed.
  2. Conduct or confirm which pressure relief scenarios are credible within the relevant relief system. This is accomplished by reviewing the 21 scenarios defined in BP Products's engineering practices. This review identifies the reasons and causes of the overpressure. The rationale for inclusion or exclusion of these 21 scenarios will be documented in the associated relief device and system folders. Engineering design calculations are then performed to determine the adequacy of overpressure protection for all applicable scenarios.
  3. Conduct or confirm the adequacy of flare and effluent system according to BP GP 44-80 such as the hydraulic capacity of the flare header piping, the flare knockout drum, and radiation from the flare tip. This analysis will be done for various relief scenarios, such as loss of power and loss of cooling. The results of these analyses are documented in a clear and consistent format and made readily accessible.
  4. Identify all potential hazards of a device relieving to atmosphere as required by API 521.
  5. The following relief system calculations are typically made using the relevant equations from API 520 and 521 and BP Products engineering practices:
    • Required flow rate based on applicable overpressure scenarios and the capacity of the relief device for each of the scenarios.
    • Relief stream conditions used for sizing the relief devices and performing any required hydraulic calculations.
    • Hydraulic loads on the relief system during various release scenarios.
    • Proper relief device sizing.
    • Inlet and outlet piping hydraulic calculations to determine the inlet and outlet pressure drop.
    • Reaction forces of outlet piping when applicable.
    • Acoustic induced vibration of piping when applicable.
    • Flare header analysis and hydraulic calculations based on global scenarios.
    • Flare header knockout drum sizing calculations.
    • Determination of radiation levels from any flare tips.
    • Fluid properties generation using process simulations.
  6. Using the information collected in Sections 1-3 and the calculations conducted in Section 5 of this exhibit, BP Products will identify, assess, validate, rank, and take interim mitigation steps to address gaps found during the revalidation process.
  7. Key documentation developed during the activities described in Sections 1-5 of this exhibit will be included in the appropriate relief system folder. The Refinery maintains its relief system design documentation as follows: a) Relief Device Folder, b) Protected System Folder, and c) Effluent Book.

Table 1 Equipment not included in the Relief System - Equipment-Based Revalidation

Excluded Process Equipment Excluded Systems
  • Outside Boundary Limit (OSBL) equipment
  • Analyzer equipment
  • Maintenance equipment
  • Tank vents Inside Boundary Limits (ISBL)
  • RV's on condensing turbine surface condensers
  • Internal relief valves on pumps
  • Sentinel valves

Treatment chemicals and associated packaged equipment, storage facilities, and supply equipment used for:

  • Antifoulants
  • Dispersants
  • Coagulants
  • Anti-static
  • Neutralizers
  • Inhibitors
  • Filmers
  • Dehazers
  • Docks
  • Idled Facilities
  • Waste Water Treatment Plant
  • Tank farms
  • Remote storage
  • Oil mist systems
  • Instrument air systems
  • Freon refrigeration systems (ASHEAE 15)
  • Steam systems1
  • Cooling water systems1
  • Condensate/BFW
  • Thermal relief valves2
  • Oil Re-claimers

Ancillary Utilities:

  • Air delivery (plant air)
  • Nitrogen
  • Potable water
  • Service water
  • Fire water
  • Demin Water

Lubrication, Shaft-sealing and Oil-control systems:

  • seal oil systems
  • lube oil systems
  • gland oil
  • flushing oil
  • control oil
  • balance gas
  • buffer gas
  • sealing steam

Note 1: The process side of exchangers that utilize these utilities shall be analyzed for relief issues (e.g. tube rupture case) that would put hydrocarbons into the utility system.

Note 2: Thermal relief valves are maximum 1x2 relief valves with D orifice; installed only to protect against fluid thermal expansion in piping/equipment that is liquid full and isolated. Typically these are in OSBL areas; although there may be some in process areas.

Exhibit 4
CONTENTS OF RELIEF DEVICE FOLDER

This Exhibit 4 describes the contents of the Refinery's relief device folders.

  1. Relief device cover sheet- This summarizes key parameters about the relief device, its design basis, and the analyses performed that are described in Exhibit 3.

  2. Relief device datasheet- This summarizes relief device specifications and design basis such as the controlling scenario to which it may potentially be subjected and the relief device size, orifice size, set pressure, area, model, make, and process information required for the controlling scenario.

  3. Scenarios summary sheet- This summarizes the process information and relief loads for all applicable overpressure scenarios. This information is a summary from the detailed calculations described in Exhibit 3.

  4. A field sketch of the relief device inlet and outlet piping, including inlet and outlet equivalent length calculations.

  5. Vendor information for the relief device, as applicable.

Exhibit 5
CONTENTS OF PROTECTED SYSTEM FOLDER

A protected system as that term is used by the Refinery means the smallest related group of relief valves, piping, and process vessels that can be completely isolated from other systems by closing various isolation valves. This group of relief valves, piping, and process vessels only includes such equipment that would necessarily be subject to the same overpressure event at the same time as a result of the process and relief system designs. The protected system typically is part of a Process Unit, and is associated with an effluent (discharge) system.

The Refinery maintains its overpressure protection documentation as follows: a) Relief Device Folder, b) Protected System Folder, and c) Effluent Book.

This Exhibit 5 describes the contents of the Refinery's protected system folders.

1. Protected system executive summary-This summarizes the equipment and piping in the pressurized relief system including unique pressure vessel and piping identification numbers, and identification of the engineering drawings (P&ID) on which they are located, the results of the overpressure protection system design, and list of potential design issues, if applicable.

2. Overpressure contingency checklist-This will list each primary cause of overpressure relying on the 21 possible scenarios from BP's engineering practices, and an indication of whether or not the cause of overpressure was found to apply to the pressurized system. Each cause of overpressure should provide the rationale used for the determination of whether or not the cause of overpressure was found to apply.

3. Engineering calculation details- This documentation includes all the relief device sizing and hydraulic detailed calculations for all applicable overpressure scenarios. It is derived from the calculation software (MathCAD, or equivalent) or an equivalent calculation software used by the Refinery.

4. Process simulation printout for fluid properties (HYSYS, for example).

5. Marked up Piping and Instrumentation Diagrams (PIDs) and Process Flow Diagrams (PFDs) / sketch for the protected system.

6. Protected equipment specification or data sheets, pump curves, and any auxiliary information relevant to the protected system under consideration that was used for the analyses described in this exhibit.

7. Identification of any credit taken for existing protective measures in conducting the analyses referenced in this exhibit for the prevention of various release scenarios. This may include protective measures such as unit shutdown procedures, alternative relief paths, and safety instrumented systems (for flare header analysis only).

Exhibit 6
SIS Lifecycle Management System
Completion Schedule

Issue life cycle manual and supporting procedures March 31, 2011
Engage accountable people in policy implementation March 31, 2011
Ensure tools and detailed work processes are in place March 31, 2011
Train on terms, policy and process September 30, 2011
Meet policy requirements September 30, 2011
Meet policy requirements retroactively on existing SIS February 12, 2012
Internal audit of meeting policy requirements February 12, 2012


Exhibit 7
SIS Lifecycle Manual Table of Contents

Table of Contents

Introduction

2.   Normative references

3.   Terms and definitions

4.   Symbols and abbreviations

5.  Safety instrumented system program implementation

  5.1.   Currently installed safety instrumented functions

  5.2.   Deviation process

  5.3.   Safety Action Item List

6.   Accountabilities

7.   Competencies

8.   Life cycle description

  8.1.   Workflow drawing and Document map

9.   Life cycle elements

  9.1.   General

  9.2.   Projects

  9.3.   Management of functional safety

Annex A

A.1.   Accountability chart

A.2.   Texas City Refinery Safety Lifecycle Management Overview

A.3.   BP TCR SIS Policy and Procedure Roadmap

A.4.   CVP to SIS Lifecycle Document Reference

Bibliography

Exhibit 8
LOPA of Record: Completion Schedule

Crude Distillation   Date
    PS3A Crude Distillation Unit A March 31, 2011
    PS3B Crude Distillation Unit B March 31, 2011
Resid Destruction    
    RHU Complex    
    RHU 200 Resid Hydroprocessing Unit 200 March 31, 2011
    RHU 300 Resid Hydroprocessing Unit 300 March 31, 2011
    RHU 400 Resid Hydroprocessing Unit 400 March 31, 2011
    RHU 500 Resid Hydroprocessing Unit 500 March 31, 2011
    RHU 600 Resid Hydroprocessing Unit 600 March 31, 2011
    Coker Complex    
    Coker B Coke Production Unit B March 31, 2011
    Coker C Coke Production Unit C March 31, 2011
    Coker Scrubber   March 31, 2011
    RDU Resid Deasphalting Unit March 31, 2011
Cat Cracking    
    FCCU 1 Fluid Catalytic Cracker 1 March 31, 2011
    FCCU 3 Fluid Catalytic Cracker 3 March 31, 2011
    FCCU SHU   March 31, 2011
Reforming    
    UU3 Naphtha Reformer Number 3 March 31, 2011
    UU4 Naphtha Reformer Number 4 March 31, 2011
Alkylation    
    Alky Treaters Treaters PP and BB Treaters March 31, 2011
    Alky Splitters   March 31, 2011
    Alky SHU Alkylation Selective HydroIsomerization Unit March 31, 2011
    Alky 3 HF Alkylation Unit March 31, 2011
Hydrotreating    
    ULC Distillate Hydrocracker March 31, 2011
    CFHU Cat Feed (Gas Oil) Hydrotreater March 31, 2011
    DDU Complex   March 31, 2011
    NDU Naptha Desulfurization Unit September 30, 2011
    HRU Hydrogen Recovery Unit September 30, 2011
Aromatics    
    ARU A Aromatics Sulfolane Extraction Unit A September 30, 2011
    ARU B Aromatics Sulfolane Extraction Unit B September 30, 2011
    AU2 Mobil Selective Toluene Disproportionation Unit March 31, 2011
SRU Complex    
  Amine Units    
    A Amine MEA Regeneration A March 31, 2011
    B Amine MEA Regeneration B March 31, 2011
    C Amine MEA Regeneration C March 31, 2011
    D Amine MEA Regeneration D March 31, 2011
  Sulfur Units    
    SRU A Sulfur Recovery Unit A March 31, 2011
    SRU B Sulfur Recovery Unit B March 31, 2011
    SRU C Sulfur Recovery Unit C March 31, 2011
    SRU D Sulfur Recovery Unit D March 31, 2011
  SCOT Units    
    C SCOT SCOT Tail Gas Treating Unit C March 31, 2011
    D SCOT SCOT Tail Gas Treating Unit D March 31, 2011
  Incinerators    
    C-Incinerator Incineration Facility C March 31, 2011
    D-Incinerator Incineration Facility D March 31, 2011


Exhibit 9
Safety Instrumented Systems: Pre-February 12, 2012 Completion Schedule

Crude Distillation   Date
    PS3A Crude Distillation Unit A  
    PS3B Crude Distillation Unit B  
Resid Destruction    
    RHU Complex    
    RHU 200 Resid Hydroprocessing Unit 200  
    RHU 300 Resid Hydroprocessing Unit 300  
    RHU 400 Resid Hydroprocessing Unit 400  
    RHU 500 Resid Hydroprocessing Unit 500  
    RHU 600 Resid Hydroprocessing Unit 600  
    Coker Complex    
    Coker B Coke Production Unit B  
    Coker C Coke Production Unit C  
    Coker Scrubber    
    RDU Resid Deasphalting Unit  
Cat Cracking    
    FCCU 1 Fluid Catalytic Cracker 1  
    FCCU 3 Fluid Catalytic Cracker 3  
    FCCU SHUM    
Reforming    
    UU3 Naphtha Reformer Number 3  
    UU4 Naphtha Reformer Number 4  
Alkylation    
    Alky Treaters PP and BB Treaters  
    Alky Splitters    
    Alky SHU Alkylation Selective HydroIsomerization Unit  
    Alky 3 HF Alkylation Unit  
Hydrotreating    
    ULC Distillate Hydrocracker February 12, 2012
    CFHU Cat Feed (Gas Oil) Hydrotreater March 31, 2011
    DDU Complex    
    NDU Naptha Desulfurization Unit  
    HRU Hydrogen Recovery Unit  
Aromatics    
    ARU A Aromatics Sulfolane Extraction Unit A  
    ARU B Aromatics Sulfolane Extraction Unit B  
    AU2 Mobil Selective Toluene Disproportionation Unit  
SRU Complex    
  Amine Units    
    A Amine MEA Regeneration A March 31, 2011
    B Amine MEA Regeneration B March 31, 2011
    C Amine MEA Regeneration C March 31, 2011
    D Amine MEA Regeneration D March 31, 2011
  Sulfur Units    
    SRU A Sulfur Recovery Unit A February 12, 2012
    SRU B Sulfur Recovery Unit B February 12, 2012
    SRU C Sulfur Recovery Unit C February 12, 2012
    SRU D Sulfur Recovery Unit D March 31, 2011
  SCOT Units    
    C SCOT SCOT Tail Gas Treating Unit C February 12, 2012
    D SCOT SCOT Tail Gas Treating Unit D March 31, 2011
  Incinerators    
    C-Incinerator Incineration Facility C March 31, 2011
    D-Incinerator Incineration Facility D March 31, 2011


Exhibit 10
Safety Instrumented Systems: Post-February 12, 2012 Completion Schedule

Crude Distillation   Date
    PS3A Crude Distillation Unit A March 31, 2016
    PS3B Crude Distillation Unit B March 31, 2014
Resid Destruction    
    RHU Complex    
    RHU 200 Resid Hydroprocessing Unit 200 March 31, 2014
    RHU 300 Resid Hydroprocessing Unit 300 March 31, 2014
    RHU 400 Resid Hydroprocessing Unit 400 March 31, 2014
    RHU 500 Resid Hydroprocessing Unit 500 March 31, 2014
    RHU 600 Resid Hydroprocessing Unit 600 March 31, 2014
    Coker Complex    
    Coker B Coke Production Unit B December 31, 2016
    Coker C Coke Production Unit C December 31, 2016
    Coker Scrubber   December 31, 2016
    RDU Resid Deasphalting Unit December 31, 2016
Cat Cracking    
    FCCU 1 Fluid Catalytic Cracker 1 March 31, 2015
    FCCU 3 Fluid Catalytic Cracker 3 March 31, 2013
    FCCU SHU   March 31, 2015
Reforming    
    UU3 Naphtha Reformer Number 3 March 31, 2014
    UU4 Naphtha Reformer Number 4 March 31, 2016
Alkylation    
    Alky Treaters PP and BB Treaters March 31, 2015
    Alky Splitters   March 31, 2015
    Alky SHU Alkylation Selective HydroIsomerization Unit March 31, 2015
    Alky 3 HF Alkylation Unit March 31, 2013
Hydrotreating ULC Distillate Hydrocracker  
    ULC Distillate Hydrocracker  
    CFHU Cat Feed (Gas Oil) Hydrotreater  
    DDU Complex   December 31, 2016
    NDU Naptha Desulfurization Unit March 31, 2016
    HRU Hydrogen Recovery Unit December 31, 2016
Aromatics    
    ARU A Aromatics Sulfolane Extraction Unit A March 31, 2016
    ARU B Aromatics Sulfolane Extraction Unit B December 31, 2016
    AU2 Mobil Selective Toluene Disproportionation Unit December 31, 2016
SRU Complex    
  Amine Units    
    A Amine MEA Regeneration A  
    B Amine MEA Regeneration B  
    C Amine MEA Regeneration C  
    D Amine MEA Regeneration D  
  Sulfur Units    
    SRU A Sulfur Recovery Unit A  
    SRU B Sulfur Recovery Unit B  
    SRU C Sulfur Recovery Unit C  
    SRU D Sulfur Recovery Unit D  
  SCOT Units    
    C SCOT SCOT Tail Gas Treating Unit C  
    D SCOT SCOT Tail Gas Treating Unit D  
  Incinerators    
    C-Incinerator Incineration Facility C  
    D-Incinerator Incineration Facility D  


Agreement