Performance Metrics Guidance Document 2014 · Guidance Background In 2002, the American Chemistry Council (ACC) enhanced the Responsible Care program by requiring the public reporting

Performance Metrics Guidance Document 2014

The American Chemistry Council

ACC Members

Table of Contents

I. Background ...................................................................................................................................................... - 2 - II. Metric Definitions and Reporting Guidelines ............................................................................................... - 5 - III. Definition of Terms ......................................................................................................................................... - 6 - IV. Performance Metrics 1. Hazardous Air Pollutant (HAP) Emissions ............................................................................................... - 9 - 2. Sulphur Oxides (SOx) and Nitrogen Oxides (NOx) ................................................................................ - 10 - 3. Water Consumption ................................................................................................................................. - 11 - 4. Greenhouse Gas Intensity ........................................................................................................................ - 12 - 5. Energy Efficiency .................................................................................................................................... - 13 - 6. Process Safety Incidents – CCPS version ................................................................................................ - 14 - 7. OSHA Recordable Incidence and Lost Workday Case Rates for Employees and Contractors ............... - 34 - 8. Number of Fatalities for Employees and Contractors ............................................................................. - 36 - 9. Distribution Incidents .............................................................................................................................. - 37 - 10. Consideration of Responsible Care Partner Status .................................................................................. - 42 - 11. Security - Extension of the Responsible Care® Security Code Affirmation Statement ........................... - 43 - 12. Product Stewardship ................................................................................................................................ - 44 - 13. Certification of Responsible Care management system .......................................................................... - 48 - V. APPENDIX A – List of HAPs as subset of TRI............................................................................................. - 49 - VI. APPENDIX B – Water Consumption Flow Chart and FAQ’s ...................................................................... - 55 - VII. APPENDIX C – Greenhouse Gas and Energy Efficiency Instructions ......................................................... - 59 - VIII. APPENDIX D – Greenhouse Gas and Energy Efficiency Survey – 4 parts .................................................. - 70 - IX. APPENDIX E – Greenhouse Gases and Energy Efficiency FAQ’s .............................................................. - 75 - XI. APPENDIX F – FORM 5800 REGULATORY DEFINITION .................................................................... - 88 -

Updated: January, 2014 - 2 -

ACC Performance Metrics Overview and Reporting Guidance

Background In 2002, the American Chemistry Council (ACC) enhanced the Responsible Care

program by requiring the public reporting of certain performance measurements. Public

reporting for some metrics began in 2004, and other metrics were reported publicly for the first

time in 2005. Some metrics were reported on a company basis while others were reported as

aggregated industry statistics. It is the intention of this public reporting to enhance transparency

and accountability and drive performance of Council member companies.

In 2005 and 2006, a Performance Measures Taskforce spent approximately 12 months

reviewing, analyzing and developing proposed improvements to the ACC Responsible Care

publicly reported performance metrics. The Taskforce was guided by a set of key

considerations, including but not limited to 1) the desire to establish connectivity to the Global

Charter and ICCA performance measures resulting in harmonized reporting globally, where

possible; 2) the need to communicate effectively with our primary audiences – informed

Americans and internal company employees; 3) maximizing the internal value of metrics through

strong linkages to ACC advocacy objectives and the creation of benchmarking capabilities,

where appropriate.

The Taskforce provided continuous update and feedback opportunities to the Responsible

Care Team and Board Committee on Responsible Care. It also allowed a one-month open

comment period for all companies to provide feedback on the draft recommendations of the

Taskforce. All feedback received was fully considered. After a year’s work, the Taskforce

recommended, and the ACC Board of Directors adopted the metrics listed in the next table.

In 2012, as part of the Responsible Care Strategic Review, a few modifications were

made to the performance measures. These adjustments affected the community outreach metric

(discontinued), the public reporting of the RCMS/RC14001 metric and Reaffirmation of the

Security Code and a few slight modifications to the Greenhouse Gas and Energy Efficiency

Metric (emission factors have been aligned with the EPA GHG Rule).


Responsible Care Performance Metrics

Metric Who Collects Information to be Reported

Will Info be Reported on Company or Industry Basis

Public Reporting Begins

ENVIRONMENTAL METRICS 1. Hazardous Air Pollutant Releases to Air

ACC Company Ongoing

2. SOx and NOx Emissions

Company Company Ongoing

3. Net Water Consumption


4. Greenhouse gas intensity (pounds of CO2 equivalent net emissions per pound of production) indexed to base year

Company Industry Ongoing

5. Energy efficiency (BTUs consumed per pound of production) indexed to base year


6. Number of process safety incidents


7. OSHA recordable and lost workday incidence rates – employees and contractors


8. Fatalities for employees and contractors

Company

Company

Ongoing


Metric Who Collects Information to be Reported

Will Info be Reported on Company or Industry Basis

Public Reporting Begins

DISTRIBUTION METRICS 9. Number of DOT reportable distribution incidents, broken down by severity level

ACC. Company Ongoing

10. Is Responsible Care Partner status a consideration in your company’s supply chain business decisions?


11. Reaffirmation of Security Code Implementation Status

Company Discontinued None

12. Does your company have a process to prioritize its chemicals? Y/N


13. Is the process used to prioritize your chemicals available to the public? Y/N; If Yes, how is it available?


14. Percentage of high priority chemicals with product stewardship summaries publicly available


OUTREACH AND ACCOUNTABILITY METRICS15. Certification of Responsible Care® Management System Y/N

Company Discontinued None


Metric Definitions and Reporting Guidelines

The measurements described in this guidance document should be based only on the ACC dues

base portion of the company within the United States; in other words, that portion of the

company that is a member of the ACC. Many member companies have operations or subsidiaries

dealing with petroleum, coal, shale, or mineral mining or other fields that are not in the

mainstream of chemical industry operations and hence are not included in the company’s dues

base for Council membership. Data on these activities may confuse the picture of the U.S.

chemical industry performance record and should not be included in the reported metrics. In

addition, companies should report data only for their U.S. operations and the U.S. operations of

their subsidiaries.

The Council has developed an electronic, web-based system for reporting the Responsible Care

metrics, which was used for the first time in 2004. This system allows secure and confidential

data entry from companies for the internal and public reporting of the metrics. This website can

be accessed at http://metrics.responsiblecaretoolkit.com. For questions regarding about the

metrics site, contact Bradford Johnson at (202) 249-6188 or

[email protected].


Definition of Terms Available to the public: Information can be found with little or no interaction with the company (e.g. through a website). BTU’s consumed: Total energy, in British Thermal Units (BTUs), consumed at ACC member company facilities. Certification: Completion of independent third party evaluation and certification of a company’s Responsible Care® Management System. Contractors: Those persons who are not considered company employees for OSHA recordkeeping purposes (see definition of “employee” below), who are under contract, subcontract, or purchase order to provide on-site services at company premises that are required to keep OSHA No. 300 logs. Such premises include:

Employer-owned, directly managed, or full-time charter transport such as buses, boats, and aircraft; and

Property leased or accessed through rights secured by the employer.

Examples of work that might fall under the contractor definition include (but are not limited to): maintenance, construction, security, engineering consulting, janitorial, food service, information management, and training.

Exclusions include: A contractor that provides on-site services that amount to less than 20,000 manhours per

reporting year, equivalent to about 10 full-time employees. Employees of common carriers such as those used for truck, rail

deliveries, pipelines, and marine movements when off the employer’s premises. Visitors that don’t provide service. Contract employees that are considered to be company employees under current OSHA

rules for recordkeeping purposes. These contract employees are to be included in the company OIIR numbers submitted to the Council.

DOT Form 5800 Distribution Incident: Transportation incidents involving hazardous material or hazardous waste reported by carriers to the Department of Transportation (DOT) on Form 5800.1, as required by DOT in 49 CFR 171.16. Applicable DOT Incidents: Those that meet the criteria of DOT regulatory requirements and fall under the members’ ACC dues base. Form 5800 incidents are attributable to the ACC member if the member is listed as either the shipper or carrier on the DOT 5800 Form. Days Away from Work Incident Rate: Defined by OSHA as the number lost workday incidents for each 100 full-time employees per year, based on 2,000 hours worked per employee per year. The calculation is as follows: Days Away from Work Incident Rate = Annual # of Days Away from Work Cases x 200,000 employee hours

Annual number of employee hours worked


Employees: All persons on the company or corporation’s payroll. Under current OSHA rules, some contract employees are considered to be company employees for record keeping purposes and are to be included in the company’s OSHA 300 log. These contractor data should also be included in the company’s occupational injury and illness reporting, and reporting of total number of employees to the Council.

Fatalities: Number of fatalities included on OSHA 300 log for employees, and for contractors that occurred on the ACC member premises. Green House Gases (CO2 equivalents): Includes carbon dioxide, methane, nitrous oxides, HFC, PFC, and SF6. HAPs: Hazardous Air Pollutants. TRI air releases of HAPs covered under Title III of the Clean Air Act, that are also covered under TRI reporting requirements. See Appendix A. Non-Feedstock Electricity – the preponderance of electricity, purchased plus self-generated, used in the business of chemistry, including electricity used to power machinery. The one exclusion from non-feedstock electricity follows.

Feedstock Electricity – electricity used directly in a chemistry process, i.e., electrolysis. (The concept of feedstock electricity is for the convenience of ACC members. The U.S. Department of Energy in its published data does not categorize any electricity as feedstock electricity.)

Production, pounds: The pounds of material produced at North American Industry Classification System (NAICS) 325 facilities in the United States. This number will be reported to ACC as a single, aggregated number for each company. This includes all pounds of NAICS 325 products, including intra-company transfers of products with inherent market value. This number excludes wastes, and recycled materials. Production should be counted for that portion of a corporation or company that is used to determine ACC dues. Joint venture production is reported by the operating company. This definition is consistent with both the ACC Energy Efficiency and Greenhouse Gas Emissions Survey and the original Pollution Prevention Code of Responsible Care. Product stewardship summary: The product stewardship summary is intended to give general information about the chemical or categories of chemicals addressed. It is not intended to provide an in-depth discussion of all health and safety information. Below is a listing of recommended elements in a product stewardship summary:

• Chemical identity (or category description) • Uses - applications, functions • Physical/chemical properties • Health effects • Environmental effects • Exposure - exposure potential • Risk management - recommended measures

Reportable SOx and NOx Emissions: ACC member companies will report annual emissions inventory for criteria pollutants, NOx and SOx, for those company sources within facilities that would otherwise be required to prepare and submit annual emissions inventory as per their respective permitting/regulatory requirements.

Recordable Injury Rate: Defined by OSHA as the number of recordable incidents for each 100 full-time employees per year, based on 2,000 hours worked per employee per year. The calculation is as follows:

Recordable Incident Rate = Annual # of Recordable Cases x 200,000 employee hours



TRI releases: Releases of chemicals listed and reported to EPA under Superfund Amendments Reauthorization Act (SARA) Section 313. Releases will include air, land, and water releases as measured and reported by individual member company on EPA’s SARA 313 report. Reporting will not include underground injection or, to avoid double-counting of emissions, off-site transfers for disposal. Water Consumption: The total amount of water pumped, piped, or otherwise brought on site for use in manufacturing and related activities and not returned to the water source from which it was withdrawn. It does not include storm water (i.e., rainwater or snowmelt). Water consumption is generally tracked in three categories: groundwater, surface water, and purchased potable water. See Appendix B.


Metric

Hazardous Air Pollutant (HAP) Emissions Rationale

This is viewed as a creative forward-focused metric, which focuses specifically on air emissions and risk.

HAPs will also be the focus of new EPA residual risk regulations under the Clean Air Act, and future risk-based standards.

Many companies are already tracking these emissions due to Title V permitting requirements.

Units Pounds of HAPs released to the air in calendar year, according to the most recent TRI data released by the EPA. Definition HAPs: TRI air releases of HAPs covered under Title III of the Clean Air Act that are also covered under TRI reporting requirements. See Appendix A for the list of HAPs reportable under this metric. Member Reporting Instructions *Important* Facility ID’s: Members should first add their EPA issued Facility Identification Numbers to their profile. Once this is complete, the contractor can pull the data from EPA’s database for the next reporting year. Instructions: The ACC will upload the HAPs information into the web-based metrics data management system and member companies will be able to verify the data during the data entry period each year. Any discrepancies should be noted by each company and reconciled using the comment process embedded in the data management system. Once the company has reviewed this data and commented on any discrepancies, they will then have to approve it before the ACC will begin its approval process. Timing for Reporting Data will be due February 28, 2014.


Metric

Sulphur Oxides (SOx) and Nitrogen Oxides (NOx) Rationale

This ICCA core measure is identified in the Responsible Care Global Charter. It is important to external stakeholders and relatively easy for members to report.

Units Pounds of SOx and Pounds of NOx Definition Reportable SOx and NOx Emissions: ACC member companies will report annual emissions inventory for criteria pollutants, NOx and SOx, for those company sources within facilities that would otherwise be required to prepare and submit annual emissions inventory as per their respective permitting / regulatory requirements. Although state reporting requirements for SOx and NOx emission vary in terms of scope (e.g. some states require SOx reporting while others require only SO2), ACC’s reporting defers to the state reporting requirement. This allows ACC’s reporting to align with the data that are publicly available through state programs. In order to understand the extent of capture of these data, ACC member companies will also be required to provide data regarding number / percentage of their facility operations for which these data are required, and therefore reported. Member Reporting Instructions This information will be collect via the web-based data management system. Each member company will have to log onto this site and report:

a) Total SOx air emissions in pounds b) Total NOx air emissions in pounds c) The total number of facilities included in ACC membership d) The total number of facilities required to report SOx and NOx as a permit requirement.

Once the company has entered in this data, they will then have to approve it before the ACC will begin its approval process. Timing for Reporting Data will be due May 31, 2014.


Metric

Water Consumption Rationale

This ICCA core measure is identified in the Responsible Care Global Charter. This is important to external stakeholders. It is also a clear new generation metric.

Units Millions of gallons consumed Definitions Water Consumption: The total amount of water pumped, piped, or otherwise brought on site for use in manufacturing and related activities and not returned to the water source from which it was withdrawn. It does not include storm water (i.e., rainwater or snowmelt). Water consumption will be tracked in three categories: groundwater, surface water, and purchased potable water. Reporting will include withdrawal from river, wells, or any permitted source (including pulling from municipalities) as well as evaporation and water withdrawn for inclusion into products, bottled water, and depletion of groundwater discharged to surface water, etc.; sources to include those with a meter or where water usage is estimated. “Consumption” allows for a credit for cleaned water put back into water bodies, thereby focusing on net impact to the environment. Credit is allowed only when water is returned to its original source (e.g. surface water to surface waters). Consumption from manufacturing, research and development labs and technical centers will be counted. Incidental water consumption from office buildings are not required to be included. Stormwater runoff should be excluded from water returned, if metered separately or easily estimated. If there is a net “production” of water due to production process by-products, the member should report zero, rather than a negative consumption. See Appendix B for the water flow chart illustrating what is reported under this metric as well as FAQs for this metric. Member Reporting Instructions This information will be collect via the web-based data management system. Each member company will have to log onto this site and report:

a) Net water consumed in millions of gallons Once the company has entered in this data, they will then have to approve it before the ACC will begin its approval process. Timing for Reporting Data will be due May 31, 2014.


Metric

Greenhouse Gas Intensity Rationale

It is an important measure for global stakeholders. This is tracked by many other reporting tools and systems. It speaks to sustainability issues.

Units Expressed as pounds of carbon dioxide (CO2) equivalent net emissions per pound of production, referenced to 1990 as the base year Definitions Green House Gases (CO2 equivalents): includes carbon dioxide, methane, nitrous oxides, HFC, PFC, and SF6. Production, pounds: The pounds of material produced at North American Industry Classification System (NAICS) 325 facilities in the United States. This number will be reported to ACC as a single, aggregated number for each company. This includes all pounds of NAICS 325 products, including intra-company transfers of products with inherent market value. This number excludes wastes and recycled materials. Production should be counted for that portion of a corporation or company that is used to determine ACC dues. Joint venture production is reported by the operating company. This definition is consistent with both the ACC Energy Efficiency and Greenhouse Gas Emissions Survey and the original Pollution Prevention Code of Responsible Care. See Appendix C for instructions, Appendix D for worksheets and Appendix E for FAQ’s. Member Reporting Instructions The ACC Energy Efficiency and Greenhouse Gas Emissions Survey will be used for data collection for this metric. An on-line version of this survey must be completed by members within the data management system. Members will also have the option of completing the survey via excel spreadsheets and uploading the data directly onto the data management system. This data will be released to the public only as aggregated ACC membership data. Once the company has entered in this data, they will then have to approve it before the ACC will begin its approval process. As part of the Responsible Care Strategic Review, the GHG and EE emissions factors have been aligned with the EPA Mandatory Greenhouse Gas rule – effective 2013. Timing for Reporting Company will be due by May 31, 2014.


Metric

Energy Efficiency Rationale

It is an important measure for global stakeholders. It is also tracked by many other reporting tools and systems. This speaks to sustainability issues.

Units Expressed as BTUs consumed per pound of production Definitions BTUs consumed: Total energy, in British Thermal Units (BTUs), consumed at ACC member company facilities.

Production, pounds: The pounds of material produced at North American Industry Classification System (NAICS) 325 facilities in the United States. This number will be reported to ACC as a single, aggregated number for each company. This includes all pounds of NAICS 325 products, including intra-company transfers of products with inherent market value. This number excludes wastes and recycled materials. Production should be counted for that portion of a corporation or company that is used to determine ACC dues. Joint venture production is reported by the operating company. This definition is consistent with both the ACC Energy Efficiency and Greenhouse Gas Emissions Survey and the original Pollution Prevention Code of Responsible Care. See Appendix C for instructions, Appendix D for an example survey and Appendix E for FAQ’s. Member Reporting Instructions The ACC Energy Efficiency and Greenhouse Gas Emissions Survey will be used for data collection for this metric. An on-line version of this survey must be completed by members within the data management system. Members will also have the option of completing the survey via excel spreadsheets and uploading the data directly onto the data management system. This data will be released to the public only as aggregated ACC membership data. Once the company has entered in this data, they will then have to approve it before the ACC will begin its approval process. As part of the Responsible Care Strategic Review, the GHG and EE emissions factors have been aligned with the EPA Mandatory Greenhouse Gas rule – effective 2013. Timing for Reporting Company will be due by May 31, 2014.


Metric

Process Safety Incidents

I. ACC Lagging Process Safety Incident The BP US Refineries Independent Safety Review Panel (“Baker Panel”) and US Chemical Safety Board each recommended improved industry-wide process safety metrics in their final reports dealing with the 2005 explosion at the BP Texas City refinery. CCPS member companies also share the vision of a new industry-wide process safety metric, including a common set of definitions and threshold levels that will serve individual companies and industry as a whole by providing a mechanism to:

indicate changes in company or industry performance, to be used to drive continuous improvement in performance,

perform company-to-company or industry segment-to-segment benchmarking serve as a leading indicator of potential process safety issues which could result

in a catastrophic event. This section of the document describes a set of definitions and metrics recommended as industry-wide lagging metrics.

Process Safety Incident (PSI): For the purposes of the common industry-wide process safety lagging metrics, an incident is reported as a process safety incident if it meets all four of the following criteria:

1) Chemical or chemical process involvement 2) Above minimum reporting threshold 3) Location; and 4) Acute release

Chemical or Chemical Process Involvement

An incident satisfies the chemical or chemical process involvement criteria if the following is true:

A chemical or chemical process must have been directly involved in the damage caused. For this purpose, the term "process" is used broadly to include the equipment and technology needed for petrochemical production, including reactors, tanks, piping, boilers, cooling towers, refrigeration systems, etc. An incident with no direct chemical or process involvement, e.g., an office building fire, even if the office building is on a plant site, is not reportable.


An employee injury that occurs at a process location, but in which the process plays no direct part, is not reportable as a PSI (though it could be an OSHA or other agency reportable injury). The intent of this criterion is to identify those incidents that are related to process safety, as distinguished from personnel safety incidents that are not process-related. For example, a fall from a ladder resulting in a lost workday injury is not reportable simply because it occurred at a process unit. However, if the fall resulted from a chemical release, then the incident is reportable.

Reporting Thresholds

A release of material or energy from a chemical process, which results in any of the three situations below: 1. An employee or contractor lost time injury and/or fatality, or hospital admission

and/or fatality of a third party (non-employees/contractor) 2. Fires or explosions resulting in greater than or equal to $25,000 of direct cost to the

company, or; 3. An acute release of flammable, combustible, or toxic chemicals from the primary

containment (i.e., vessel or pipe) greater than the chemical release threshold quantities described on Table 1, excluding releases to properly designed and operating control device specifically designed for that event (e.g., flare, scrubber or relief devices per API Standard 521 or equivalent),

Table 1 – Process Safety Incident Threshold Values

Material Hazard classification as Defined by United Nations Dangerous "Process Safety incident" Goods definitions: threshold quantity: TIH Hazard Zone A materials1 5 kg (11 lbs.) TIH Hazard Zone B materials1 25 kg (55 lbs.) TIH Hazard Zone C materials 1 100 kg (220 lbs.) TIH Hazard Zone D materials1 200 kg (440 lbs.) Other "Packing Group I" materials2 & “Flammable Gases/Vapors” 500 kg (1100 lbs.) Other "Packing Group II" materials2 & “Flammable Liquids” 1000 kg (2200 lbs.) Other "Packing Group III" materials2 & “Combustible Liquids” 2000 kg (4400 lbs.)

& Division 2.2 - Nonflammable, Nontoxic Gases

For a full list of materials cross-referenced to the UN Dangerous Goods definitions, see chemical list or spreadsheet tools posted on the http://www.aiche.org/ccps/resources/metrics web site.

For the purposes of applying these threshold values for “Flammable Gases/Vapors”, “Flammable Liquids”, and “Combustible Liquids”, the user may use either the definitions commonly used within the petroleum

1 The TIH Hazard Zone A, B, C, and D designations are mentioned specifically in the US Department of Transportation regulations (49 CFR 172.101), and not in the UN Dangerous Goods definitions. However, these definitions do align with toxic vapor categories described in the Harmonized System of Classification and Labeling of Chemicals (GHS). . 2 Packing Group definitions based upon UN Dangerous Goods definitions. In the USA, these definitions are also described in US Department of Transportation regulations (49 CFR 172.101). These descriptions include several generic descriptions (e.g., “Toxic fluids”) or materials which are not germane to the chemical or petroleum industries (e.g., cotton, explosive ammunition). Although the specific chemicals listed in the UN Dangerous Goods listing have been used as a basis for establishing the process safety incident threshold quantities, these generic or non-applicable materials have been excluded.


refining industry (based upon National Fire Protection Association, NFPA-30, definitions), the UN Dangerous Goods (Class 2, Div. 2.1 and Class 3), or the Harmonized System of Classification and Labeling of Chemicals (GHS), Chapters 2.2 and 2.6. These different methods classify materials in a similar manner; therefore, most flammable materials will fall into the same category regardless of the definitions used. For the ease of implementation, many users may want to use the following definitions. Definitions of Combustible and Flammable materials (based upon NFPA-30):

Flammable Liquids: Low-flash liquids [flash point below 100 deg. F (38 deg. C)], and high-flash liquids [flash point 100 deg. F (38 deg. C) or higher] at temperatures above or within 15 deg. F (8 deg. C) of their closed cup (Pensky-Martens) flash points. Combustible Liquids: High-flash liquids [flash points 100 deg. F (38 deg. C) or higher] at temperatures more than 15 deg. F (8 deg. C) below their closed cup (Pensky-Martens) flash point

The benefit of the NFPA-based definitions is that the classification is influenced by the temperature of release. When a combustible liquid with a high flash point is released at a temperature above or within 15°F (8°C) of its flash point, it has the flammability characteristics of a flammable liquid. Over time, it is expected that industry will become more familiar with and implement the GHS definitions. For more information regarding the comparison of these methods see Appendix A.

Lost Time Injuries and Fatality Incidents Criteria3

Lost Time injuries and Fatality Incidents that occur as a result of process related loss of primary containment, fire, or explosion are those that fit into one of the following categories:

Employee (Lost time and/or Fatality)

Contractor and Subcontractor (Lost time and/or Fatality)

Third Party (Injury/illness resulting in Hospital Admission or Fatality)

Examples of injury or fatality cases that would be reportable include a burn injury resulting from steam released during cleaning; a physical injury from a cap blown off by pressure during a pressure test; or a chemical burn from a spill while taking a sample. Examples of injuries or fatality cases that would not be reportable include a fall from an elevated work station while performing maintenance; a burn from a fire in a laboratory or office building; or injuries from an excavation cave-in. None of these cases are directly due to the release of energy or material from the process.

3 Whether an injury is reportable or not reportable under these process safety metrics would make no difference in the facility’s responsibility to report injuries under OSHA or other regulatory requirements.


Location

An incident satisfies the location criteria if:

The incident occurs in production, distribution, storage, utilities or pilot plants of a facility reporting metrics under these definitions. This includes tank farms, ancillary support areas (e.g., boiler houses and waste water treatment plants), and distribution piping under control of the site.

All reportable incidents occurring at a location will be reported by the company that is responsible for operating that location. This applies to incidents that may occur in contractor work areas as well as other incidents. At tolling operations and multi-party sites, the company that operates the unit where the incident initiated should record the incident and count it in their PSI metric. For further clarification, look at the exclusions described in Section 6 (Applicability).

Acute Release

A “1-hour” rule applies for the purpose of the reporting under this metric, i.e. the release of material reaches or exceeds the reporting threshold in 1 hour or less. If a release does not exceed the TQ level over any 1-hour period, it would not be treated as a PSI. Typically, acute releases occur in 1-hour or less; however, there may be some releases that would be difficult to prove if the threshold amount release occurred in 1-hour. (Example: A large inventory of flammable liquid is spilled from a tank or into a dike overnight due to a drain valve being left upon prior to a transfer operation. It may not be discovered for several hours, so it is difficult to know the exact time when the threshold quantity was exceeded.) If the duration of the release cannot be determined, the duration should be assumed to be 1 hour.


Flowchart

The criteria for reporting incidents as a PSI described above are illustrated in the attached flowchart (Figure 4).

Figure 4: Determining if an incident meets definition of a reportable Process Safety Incident (PSI) under the definitions of the CCPS Industry Lagging Metric

Was a chemical or chemical process directly involved in the

damage caused?

Was there a release of material or energy from a chemical

process unit that resulted in...

An employee or contractor lost time injury and/or fatality, OR

hospital admission and/or fatality of a third party (non-

employee/contractor)?

Fires or explosions resulting in $25,000 of direct cost to the

company?

An acute release of flammable combustible, or toxic chemicals from the primary containment?

Did the incident occur in production, distribution,

storage, utilities, or pilot plants of a facility reporting these

metrics?

Reportable Process Safety Incident

Does not meet criteria for Process Safety

Incident

No

Yes

No

Yes

No

No

Yes

No

YesYes


Process Safety Incident Severity A severity level will be assigned for each consequence category for each process safety incident utilizing the criteria shown in Table 2.

Table 2: Process Safety Incidents & Severity Categories Severity

Level (Note 4)

Safety/Human Health

(Note 5)

Fire or Explosion (including

overpressure)

Potential chemical impact

(Note 3)

Community/environment impact (Note 5)

NA

Does not meet or exceed Level 4 threshold




4 (1 point used in

severity rate calculations for

each of the attributes which

apply to the incident)

Injury requiring treatment beyond first aid to employee or contractors (or equivalent, Note 1) associated with a process safety incident (In USA, incidents meeting the definitions of an OSHA recordable injury)

Resulting in $25,000 to $100,000 of direct cost

Chemical released within secondary containment or contained within the unit - see Note 2A

Short -term remediation to address acute environmental impact. No long term cost or company oversight. Examples would include spill cleanup, soil and vegetation removal.

3 (3 points used in




Lost time injury to employee or contractors associated with a process safety event

Resulting in $100,000 to1MM of direct cost.

Chemical release outside of containment but retained on company property OR flammable release without potential for vapor cloud explosives - see Note 2B

Minor off-site impact with precautionary shelter-in-place OR Environmental remediation required with cost less than $1MM. No other regulatory oversight required. OR Local media coverage

2 (9 points used in




On-site fatality - employee or contractors associated with a process safety event; multiple lost time injuries or one or more serious offsite injuries associated with a process safety event.

Resulting in $1MM to 10MM of direct cost.

Chemical release with potential for injury off site or flammable release resulting in a vapor cloud entering a building or potential explosion site (congested/confined area) with potential for damage or casualties if ignited - see Note 2C

Shelter-in-place or community evacuation OR Environmental remediation required and cost in between $1MM - 2.5 MM. State government investigation and oversight of process. OR Regional media coverage or brief national media coverage.

1 (27 points used in




Off-site fatality or multiple on-site fatalities associated with a process safety event.

Resulting in direct cost >$10MM

Chemical release with potential for significant on-site or off-site injuries or fatalities - see Note 2D

National media coverage over multiple days OR Environmental remediation required and cost in excess of $2.5 MM. Federal government investigation and oversight of process. OR other significant community impact

K = 1,000

MM = 1,000,000


NOTE 1: for personnel located or working in process manufacturing facilities. NOTE 2: It is the intent that the “Potential Chemical Impact” definitions shown in Table 2 to provide sufficient definition such that plant owners or users of this metric can select from the appropriate qualitative severity descriptors without a need for dispersion modeling or calculations. The user should use the same type of observation and judgment typically used to determine the appropriate emergency response actions to take when a chemical release occurs. However, CCPS does not want to preclude the use of a “sharper pencil” (e.g. dispersion modeling) if a company so chooses. In those cases, the following notes are being provided, as examples, to clarify the type of hazard intended with the four qualitative categories: A: AEGL-2/ERPG-2 concentrations (as available) or 50% of Lower Flammability Limits (LFL) does not extend beyond process boundary (operating unit) at grade or platform levels, or small flammable release not entering a potential explosion site (congested/confined area) due to the limited amount of material released or location of release (e.g., flare stack discharge where pilot failed to ignite discharged vapors). B: AEGL-2/ERPG-2 concentrations (as available) extend beyond unit boundary but do not extend beyond property boundary. Flammable vapors greater than 50% of LFL at grade may extend beyond unit boundaries but did not entering a potential explosion site (congested/confined area); therefore, very little chance of resulting in a VCE. C: AEGL-2/ERPG-2 concentrations (as available) exceeded off-site OR flammable release resulting in a vapor cloud entering a building or potential explosion site (congested/confined area) with potential for VCE resulting in fewer than 5 casualties (i.e., people or occupied buildings within the immediate vicinity) if ignited D: AEGL-3/ERPG-3 concentrations (as available) exceeded off-site over the defined 10/30/60 minute time frame OR flammable release resulting in a vapor cloud entering a building or potential explosion site (congested/confined area) with potential for VCE resulting in greater than 5 casualties (i.e., people or occupied buildings within the immediate vicinity) if ignited NOTE 3: The Potential Chemical Impact table reflects the recommended criteria. However, some companies may object to making a relative ranking estimate on the potential impact using the terms described. In those situations, it would be acceptable for those companies to substitute the following criteria corporate wide: Severity Level 4: 1X to 3X the TQ for that chemical, Level 3: 3X to 9X, Level 2: 9X to 20X, and Level 1: 20X or greater the TQ for that chemical. However, if a company elects to use this alternative approach they should be consistent and use this approach for all releases. They should not select between the two methods on a case-by-case basis simply to get the lowest severity score. NOTE 4: The category labels can be modified by individual companies or industry associations to align with the severity order of other metrics. It is important is to use the same severity point assignments shown. NOTE 5: The severity index calculations include a category for “Community/ Environmental” impact and a first aid (i.e., OSHA “recordable injury”) level of Safety/Human Health impact which are not include in the PSI threshold criteria. However, the purpose of including both of these values is to achieve greater differentiation of severity points for incidents that result in any form or injury, community, or environmental impacts.


Definitions

Acute Release: A sudden release of material that reaches or exceeds the reporting threshold in approximately one (1) hour or less.

BBL: Barrels; 42 U.S. gallons (35 Imperial gallons)

Company: "Company" (when designated with a capital C) or "the Company", refers to the operating company in the refining and petrochemical industries and/or any of its divisions, and/or any of its consolidated affiliates.

Contractor: Any individual not on the Company payroll, including subcontractors, whose exposure hours, injuries and illnesses are routinely tracked by the host Company.

Direct Cost: Cost directly attributed to the fire and/or explosion, such as the replacement value of equipment lost, cost of repairs, cleanup, emergency response and/or fines. Direct cost does not include indirect costs, such as business opportunity losses, loss of profits due to equipment outages, cost of obtaining or operating temporary facilities or cost of obtaining replacement products to meet customer demand.

Employee: Any individual on the Company payroll and whose exposure hours, injuries and illnesses are routinely tracked by the Company. Unpaid individuals, such as government sponsored interns or secondees providing services under direct Company supervision are also included.

Explosion: the term "explosion" includes both detonations (regardless of whether or not they cause the rupture of equipment or piping) and overpressure incidents that cause the rupture of equipment or piping (regardless of whether or not they result in a chemical release or personnel injury).

Incident: An unusual or unexpected event, which either resulted in, or had the potential to result in serious injury to personnel, significant damage to property, adverse environmental impact, or a major interruption of process operations.

Loss Of Primary Containment (LOPC): An unplanned or uncontrolled release of material from primary containment.

Primary Containment: A tank, vessel, pipe, rail car or equipment intended to serve as the primary container or used for the transfer of the material. Primary containers may be designed with secondary containment systems to contain and control the release. Secondary containment systems include, but are not limited to, tank dikes, curbing around process equipment, drainage collection systems into segregated oily drain systems, the outer wall of double walled tanks, etc.

PSI: Process Safety Incident.

Third Party: Any individual other than an employee, contractor or subcontractor of the Company.


Total employee, contractor & subcontractor work hours: Total hours worked for refining, petrochemical, or chemical facilities. Using the same definitions that would be applicable for the OSHA injury/illness formula. UN Dangerous Goods hazard categories: A classification system used to evaluate the potential hazards of various chemicals, if released, used by most international countries as part of the product labeling or shipping information. In the United States, these hazard categories are defined in US Department of Transportation regulations (49 CFR 172.101). For more information on this ratings, see the UN web site (http://www.unece.org/trans/danger/publi/adr/adr2007/07ContentsE.html)

Rate Adjusted Metrics Utilizing the definitions described above, there are a variety of rate-based metrics which can be generated. These include:

Process Safety Total Incident Rate (PSTIR): Total PS incidents x 200,000 ___ Total employee & contractor work hours Process Safety Incident Severity Rate (PSISR) (i.e., severity-weighted Process Safety incident rate formula): Total severity score for all PS incidents x 200,000___ PSISR = Total employee, contractor & subcontractor work hours In determining this rate, 1 point is assigned for each Level 4 incident attribute, 3 points for each Level 3 attribute, 9 points for each Level 2 attributes, and 27 points for each Level 1 attributes. Theoretically, a PSI could be assigned a minimum of 1 point (i.e., the incident meets the attributes of a Level 4 incident in only one category) or a maximum of 108 points (i.e., the incident meets the attributes of a Level 1 incident in each of the four categories. PS Level “X*” incident rate: Total Severity Level “X*” PS incidents x 200,000 Total employee, contractor & subcontractor work hours Where X* can be the total count of Severity Level 4, 3, 2, or 1 incidents. The severity level of an incident is the maximum severity rating of the four consequence categories.


Industry Process Safety Metrics It is recommended that companies implement and publicly report the following three process safety metrics: Total Count of Process Safety Incidents (PSIC): The count of all incidents which meet the definitions of a PSI described within this document. Process Safety Total Incident Rate (PSTIR): The cumulative (annual) count of incidents normalized by man-hours, per the formula described in section 4.0. Process Safety Incident Severity Rate (PSISR): The cumulative (annual) severity-weighted rate of process safety incidents per the formula described in section 4.0. To assist in benchmarking, it would be beneficial if trade associations or consortiums collect and publish this information for member companies.

Applicability It is recommended that companies record and report PSIs occurring at Company-owned or operated facilities, except as noted below:

1. PSIs that originated off Company property;

2. Marine transport vessel incidents, except when the vessel is connected to the facility for the purposes of crude or product transfer;

3. Truck and/or rail incidents, except when the truck or rail car is connected to the facility for the purposes of crude or product transfer;

4. Routine emissions that are allowable under permit or regulation;

5. Releases to a properly designed and operating emissions control device, such as a flare, scrubber, or relief device designed per API Standard 521 or equivalent, as long as the release did not result in (1) a liquid carryover that created a reportable PSI related to the liquid (e.g., days away from work incident, fatality, a fire or explosion that caused $25,000 or more of direct cost, liquid release or toxic aerosol release at or above threshold amounts, etc.), or (2) on-site activation of a shelter-in-place response, or (3) public protective measures being taken;

6. Underground contamination that had no process safety consequences. Note: The exclusion does not apply if the release resulted in an aboveground reportable PSI, such as release of toxic vapors or pooling of flammable liquids (e.g., 7 bbls or more within 1 hour).

7. Office building incidents (e.g., office heating equipment explosions, fires, spills, releases, personnel injury or illness, etc.);

8. Personnel safety "slip/trip/fall" incidents that are not directly associated with evacuating from, or responding to a loss of containment incident;


9. Loss of Primary Containment (LOPC) incidents from ancillary equipment not connected to the process (e.g., small sample containers);

10. Planned and controlled drainage of material to collection or drain system designed for such service (Note: Exclusion does not apply to an unintended and uncontrolled release of material from primary containment that flows to a collection or drain system);

11. Mechanical work being conducted outside of process units or in maintenance shops; and,

12. Quality Assurance (QA), Quality Control (QC) and Research and Development (R&D) laboratories are excluded. (Pilot plants are not excluded.)

Interpretations and Examples The following interpretations and examples have been prepared to help clarify areas of potential uncertainty in the evaluation of reportable Process Safety Incidents (PSI).

They are for illustrative purposes only. The following areas are addressed:

Company Premises

PSIs With Multiple Outcomes

Loss Of Containment

Acute Releases

Flares & Emission Control Devices

Safety Relief Device/System

Toxic Gas, Vapor or Aerosol

Lost Time Incidents

Pipelines

Fires not associated with chemical release

Marine Vessels

Truck and Rail

Office Building

Man-Machine Interface Incidents

Examples of use of assignment of Severity scores

Mixtures


COMPANY PREMISES

1. A third-party truck loading a flammable product on Company Premises, experiences a leak and subsequent fire and property loss damages of $75,000 (direct costs). Although the truck is "Operated-by-Others", it is connected to the process. The incident would be a reportable PSI if property losses in direct costs were equal to or greater than $25K or some other PSI threshold was met or exceeded (e.g., a fatality).

2. Similar example as #1. The truck loaded with flammable product overturns in route out of the plant, resulting in a fire and loss of the truck. This would not be reported as a PSI since the truck is no longer connected to the plant.

PSIs WITH MULTIPLE OUTCOMES

3. There is a 200 bbl spill of flammable liquid that results in significant flammable vapor being released, ignited and causing a fire. The fire damages other equipment resulting in a toxic gas release above the reporting threshold, along with multiple lost time injuries, including a fatality. This event should be reported as a single PSI, but with multiple outcomes. When applying the severity metric, the appropriate severity point assignment (1, 3, 9, or 27 points each) would be selected from Table 2 for the fire damage, the chemical release potential impact, the human health impact, and the community/environmental impact. The sum of these individual severity points will be used in calculating the overall severity rate metric.

LOSS OF CONTAINMENT

4. Ten barrels of gasoline (1400 kg, 3100 lbs.) leak from piping onto concrete and the gasoline doesn't reach soil or water. Site personnel estimate that the leak was "acute" (e.g., occurred within a 1-hour timeframe). This is a reportable PSI because there was an "acute” loss of primary containment (e.g., within "1 hour") of 1000 kg (2200 lbs) or more of ”Flammable Liquid”.

5. A faulty tank gauge results in the overfilling of a product tank containing “flammable liquids”. Approximately 7000 kg (15500 lbs) of liquid overflows into the tank's diked area. This incident is a reportable PSI since it is an "acute" spill greater than 2200 lbs, regardless of secondary containment.

6. A maintenance contractor opens a process valve and gets sprayed with sulfuric acid resulting in a severe burn and lost time injury. This would be a reportable PSI. It is an unintended event involving a material and a loss of containment. For fatalities and days away from work injuries and illnesses, there is no release threshold amount.

7. An operator opens a quality control sample point to collect a routine sample of product and receives a bad hand laceration requiring stitches due to a broken glass bottle and misses the next day of work. This is not a reportable PSI because it is not related to a loss of containment.

8. A bleeder valve is left open after a plant turnaround. On startup, an estimated 10 bbls of fuel oil (1700 kg, 3750 lbs.) is released, at 100°F, onto the ground and


into the plant’s drainage system before the bleeder is found and closed. This would not be a PSI because it is less then the release criteria of 2000 kg or 4400 lbs of a ”Combustible Liquid”. Given the release conditions, this material would be treated as a “Combustible Liquid” (or Packing Group III Flammable Liquid under the UN DG definitions) regardless of whether the NFPA-30 or UN Dangerous Goods definitions of flammables are utilized.

9. Operations is draining water off of a crude oil tank (operated at 120°F) into a drainage system designed for that purpose. The operator leaves the site and forgets to close the valve. 20 bbls of crude oil is released into the drainage system. This would be a PSI because the release of crude oil, a “Combustible Liquid”, is unintended and it is greater then the release criteria of 2000 kg or 4400 lbs.

10. A pipe corrodes and leaks 10 Bbls (1700 kg, 3750 lbs.) of Heavy Cycle Oil (HCO) at the operations temperature of 550°F to the ground. The HCO has a flash point of 300°F. If the company has elected to base reporting criteria upon the NFPA-30 definitions of flammable materials described in Section 1, this would be a PSI because the HCO was released at a temperature above the flash point and it is greater then the release criteria of 1000 kg (2200 lbs.). IF the company has elected to base reporting criteria upon the UN Dangerous Goods definitions, this would not be a PSI since the HCO would be considered a Packing Group III material, with a 2000 kg (4400 lbs) threshold quantity. There will be a few situations were the NPFA definitions will have a lower TQ and other situations where the UN DG definitions will have a lower TQ. If a company consistently uses the same definitions for all reporting decisions, the annual statistics should be similar. A company should not select the definitions to use for reporting on a case-by-case basis simply to achieve the lowest overall statistics.

11. An operator purposely drains 20 bbls of combustible material into an oily water collection system within one hour as part of a vessel cleaning operation. The drainage is planned and controlled and the collection system is designed for such service. This is not a reportable PSI since it is consistent with a specific exclusion. If the material had been unintentionally released and flowed to an open drain, sewer or other collection system, it would be a reportable PSI.

ACUTE RELEASES

12. There is a 10 bbl spill of gasoline (1400 kg, 3100 lbs.) that steadily leaked from piping onto soil over a two-week time period. Simple calculations show the spill rate was approximately 0.03 bbls per hour (9 lbs./hr). This is not a reportable PSI since the spill event was not an "acute" release (e.g., the 1000 kg (2200 lbs.) threshold exceeded in 1 hour).

13. Same example as above, except that the 10 bbl leak was estimated to have spilled at a steady rate over a period of 1 hour and 30 minutes. Simple calculations show that the spill rate was 6.7 bbls (933 kg or 2060 lbs.) per hour. The spill rate was slightly less that the reporting threshold of 1000 kg (2200 lbs.) within "1 hour", and therefore is still not a reportable PSI.


14. While troubleshooting a higher-than-expected natural gas flow rate, operating personnel find a safety valve on the natural gas line that did not reseat properly and was relieving to the atmospheric vent stack through a knock-out drum. Upon further investigation, it is determined that a total of 1 Million lbs of natural gas was relieved at a steady rate over a 6 month period. This is not a reportable PSI as the release rate (~100 kg per hour) is not “acute”, (i.e. does not exceed the 500 kg TQ for flammable vapors per 1 hour time period).

FLARES & EMISSION CONTROL DEVICES (e.g., scrubbers)

15. If a chemical is routed to a flare or emission control device (e.g., scrubber), it would not be classified as a PSI as long as that flare or control device operates as designed.

16. If a scrubber is overwhelmed by a flowrate greater than the design of the scrubber system and discharges a chemical in excess of the reporting threshold, it would be reported as a PSI.

SAFETY RELIEF DEVICE / SYSTEM

17. There is a unit upset and the relief valve opens to an atmospheric vent which has been designed per API Standard 521 for that scenario, resulting in a gas release to the atmosphere with no adverse consequences. This would not be a reportable PSI since vapors and gases released to atmosphere from safety valves, high-pressure rupture disks, and similar safety devices that are properly designed for that event per API Standard 521 or equivalent are excluded, as long as the release did not result in (1) a liquid carryover that created a reportable PSI related to the liquid (e.g., lost time incident, fatality, a fire or explosion that caused $25,000 or more of direct cost, liquid release or toxic aerosol release at or above threshold amounts, etc.), or (2) activation of a shelter-in-place response on-site, or (3) public protective measures be taken.

18. Similar example to #17. If the relief device is not designed to API Standard 521 (e.g., the inlet pressure is less than 50 psig) or there is no documentation to validate that the installation was designed to comply with such standards. This would be a reportable PSI since the exemption only applies to vapor or gas releases from safety valves or high pressure rupture disks which comply with API Standard 521 or equivalent.

19. There is a unit upset and the relief valve fails to open, resulting in overpressure of the equipment and an "acute" release of flammable gas from a leaking flange. The amount released is above the 500 kg (within 1 hour) threshold. This is a reportable PSI. Releases from flanges are not excluded from PSI reporting.


TOXIC GAS, VAPOR OR AEROSOL

20. A leak on a high pressure hydrochloric acid line results in a spill of 1900 lbs of hydrochloric acid. Flash calculations indicate that greater than 220 lbs. of hydrogen chloride would be released as a vapor. The 1900 lbs release of hydrochloric acid is not a reportable PSI since this liquid is categorized as a “Packing Group II” corrosive liquid, with a 2200 lbs reporting threshold. However, since the liquid flashed or was sprayed out as an aerosol, producing more than 220 lbs of hydrogen chloride as vapor the event would be reportable due to exceeding the 100 kg (~220 lbs) or more of Toxic Inhalation Hazard Zone C material within 1 hour.

21. A pipe containing CO2 and 10,000 vppm (1% by volume) H2S leaks and 7,000 kg (15,400 lbs) of the gas is released within a short time period (e.g., less than one hour). Calculations show that the release involved about 55 kg (120 lbs) of H2S. The release is a reportable PSI since the reporting threshold for Toxic Inhalation Hazard Zone B chemicals is any amount greater than 25 kg (55 lbs) of the toxic chemical (e.g., H2S). Further, the release is a reportable PSI since the reporting threshold for CO2 is exceeded, as the chemical is a Division 2.2 - Nonflammable, nontoxic gas with a threhold of 2,000 kg. (Note: The incident would not be reportable if it was released from a properly designed and operating safety devices since there is a specific exclusion provided, as long as the release did not result in (1) a liquid carryover that created a reportable LOPC, or (2) on-site activation of a shelter-in-place response, or (3) public protective measures being taken.)

22. Same as above, except that the H2S concentration in the pipe is 50 vppm, rather than 10,000 vppm. The threshold remains unchanged at 25 kg for H2S and 2,000 kg for CO2.The incident would still be reportable as a PSI. However, it is now the 2,000 kg (4400 lb.) threshold for CO2 that triggers the reporting criteria rather than the H2S.

DAYS AWAY FROM WORK INCIDENTS

A ”days away from work” incident (or fatality) inclusion as a reportable Process Safety Incident depends upon it being caused by the loss of containment of a material.

23. An operator is walking, then slips and falls to the floor and suffers a lost time injury. The slip/fall is due to weather conditions, "chronic" oily floors and slippery shoes. This is not a reportable PSI. Personnel safety "slip/trip/fall" incidents that are not directly associated with evacuating from or responding to a loss of containment incident are specifically excluded from PSI reporting.

24. Same as above, except that the operator slipped and fell while responding to a small flammable liquid spill (e.g., less than 1000 kg in 1 hour). This would be PSI reportable since the operator was responding to a loss of containment incident. A PSI is reportable if the loss of primary containment occurs on Company Premises and results in a lost time incident or fatality. For fatalities and lost time incidents, there is no release threshold amount.


25. Same as above, except that the operator slipped and fell several hours after the incident had concluded. This would not be PSI reportable. The terms "evacuating from" and "responding to" in the reporting exclusion mean that the loss of containment and associated emergency response activities are on-going. Slips/trip/falls after the event have concluded (such as "after-the-fact" clean-up and remediation) are excluded from PSI reporting.

26. A scaffold builder suffers a lost time injury after falling from a scaffold ladder while evacuating from a loss of containment incident on nearby equipment. This is a reportable PSI.

27. An operator walks past an improperly designed steam trap. The steam trap releases and the operator's ankle is burned by the steam, resulting in a lost time injury. This is a reportable PSI because even though the loss of containment was steam (vs. hydrocarbon or chemical), the physical state of the material was such that it caused a lost time injury.

28. An enclosure has been intentionally purged with nitrogen. A contractor bypasses safety controls, enters the enclosure and dies. This is a reportable fatality, but not a reportable PSI since there was no unplanned or uncontrolled loss of primary containment.

29. Same as above, except that nitrogen inadvertently leaked into the enclosure. This would be a reportable PSI (and fatality) since there was a fatality associated with an unplanned loss of primary containment.

30. An operator responding to an H2S alarm collapses and has a “days away from work” injury. If the alarm was triggered by an actual unplanned or uncontrolled H2S LOPC, the event would be a reportable PSI. If the alarm was a false alarm, the event would not be a reportable PSI because there was no actual release.

PIPELINES

31. An underground pipeline leaks and releases 1,000 bbls of diesel (combustible material). The spill results in contaminated soil that is subsequently remediated. This is not a reportable PSI since there were no safety consequences. If the material resulted in "acute" surface pooling 14 bbls or greater (e.g., within "1 hour"), then the event would be PSI reportable and you would report the entire amount of released material (e.g., 1,000 bbls).

32. A pipeline leaks and releases 2000 lbs. of flammable vapor above ground within 1 hour. However, the release occurred in a remote location within the site. The release is PSI reportable, since "remoteness" is not a consideration.


FIRES or ENERGY RELEASES NOT ASSOCIATED WITH CHEMICAL RELEASE

As a general rule, a fire or energy release is reported as a PSI only if caused by chemical release or results in a chemical release in excess of the reporting quantities. Examples include:

33. An electrical fire impacts the operation of the process resulting in the release of 4000 lbs. of toluene. This event would be reported as a PSI since if the chemical release exceeds the 2200 lb. reporting threshold for toluene.

34. An electrical fire, loss of electricity, or any other loss of utility occurs which may cause a plant shutdown and possibly incidental equipment damage greater than $25,000 (e.g., damage to reactors or equipment due to inadequate shutdown) but does not create a chemical release greater than the threshold quantity, or cause a fatality or serious injury. This event would not be reported as a PSI since the equipment damage was not caused by a chemical process fire/explosion and there was not a chemical release greater than the threshold quantity.

35. A bearing fire, lube oil system fire, electric motor failure, or similar fire occurs which damages the equipment but does not create a chemical release greater than the threshold quantity or cause a fatality or serious injury. This event would not be reported as a PSI since no chemical release greater than the threshold quantity or injuries occurred.

36. If in the examples #34 or #35, if either an injury or chemical release exceeding the threshold quantity had occurred these would have been reportable PSI events.

37. An internal deflagration in a vessel causes equipment damage > $25,000. This event would be reported as a PSI since the definition of “explosion” includes detonations regardless of whether or not they cause the rupture of equipment or piping, therefore this event would be included if damages exceeded $25,000.

38. The vent on a storage tank containing chemicals becomes plugged and vacuum caused by routine pump out collapses the tank resulting in equipment damages >$25,000. This event would not be reported as a PSI since chemicals were not released and the definition of “explosion” does not include under-pressure events.

39. If in the example #38, if a tank seam failed resulting in a spill of contents in excess of the TQ quantity for that chemical, it would have been reported as a PSI (even if the contents were captured in secondary containment dikes).

MARINE TRANSPORT VESSELS

40. A company operated Marine Transport Vessel has an onboard "acute" spill of combustible material greater than 14 bbls. The event is not PSI reportable since Marine Transport Vessel incidents are specifically excluded, except when the vessel is connected to the refinery, petrochemical, or chemical manufacturing facility for the purposes of crude or product transfer.

41. A third-party barge is being pushed by a tug and hits the company dock. A barge compartment is breached and releases 50 bbl of diesel to the water. The event is not a reportable PSI since the marine vessel was not berthed at the dock and actively involved in crude or product transfer operations.


TRUCK AND RAIL

42. A company railcar derails and spills more than 7 bbls of gasoline while in transit. The incident is not PSI reportable since rail incidents off company property are specifically excluded.

43. A third-party truck/trailer overturns while in the Company Premises, resulting in an "acute" spill of gasoline greater than 7 bbls. The incident is not reported as a PSI reportable if the truck is no longer connected to the loading/unloading facilities. However, it is recommended that companies also have transportation incident metrics, which would capture this event.

44. A contract truck hauler is unloading caustic and the hose separates and generates an airborne aerosol and/or liquid caustic spill of 2500 kg. The event is a reportable PSI since the caustic TQ of 1000 kg was exceeded and the truck was still connected to the loading/unloading facility immediately prior to the incident.

OFFICE BUILDING

45. There is a boiler fire at the Main Office complex, and direct cost damages totaled $75,000. The incident is not PSI reportable since Office Building incidents are specifically excluded.

MAN-MACHINE INTERFACE INCIDENTS

46. An operations technician is injured while working around the finishing equipment in a polymers plant. The injury is caused by the mechanical, man-machine interface with the equipment. This would not be a reportable Process Safety Incident because there was no loss of containment of hazardous material.

ASSIGNMENT OF SEVERITY SCORES

47. A leak on a high pressure hydrochloric acid line results in a spill of 4000 lbs of hydrochloric acid. Flash calculations indicate that greater than 500 lbs. of hydrogen chloride would be released as a vapor. Three employees in the plant received inhalation injuries, resulting in hospitalization for multiple days. The toxic cloud was witnessed by emergency response crews to extend into adjacent plants within the site, but there was no evidence that a harmful toxic concentration extended beyond the plant fenceline. However, a precautionary shelter-in-place and closure of adjacent interstate highway occurred for 2 hours. Resulting in extensive local media coverage and brief national media coverage. This incident clearly is a reportable PSI incident since the Hydrochloric acid and HCL vapors released each exceeded the chemical release TQ. Furthermore, the injuries to employees exceeded the health effects threshold for reporting. The Safety/Human Health severity level is a “2” (9 severity points) due to multiple lost-time injuries; the Fire/Explosion severity level is “N/A” (0 severity points) due to no equipment damages or clean-up costs greater than $25,000; the Potential Chemical Impact severity level is a “3” (3 severity points) since the chemical release extended outside of containment but retained on company property; and the Community/Environmental Impact severity level is a “2” (9 severity points) due to the shelter-in-place and media attention. The maximum of the four


categories was a Severity level “2”; therefore, the overall incident could be classified as a Severity Level “2” PSI. The Severity points which would be used in the Process Safety Incident Severity Rate (PSISR) calculation would be 21 points (9+0+3+9=21).

48. The release of 10,000 lbs of ethylene (flammable vapor) occurs when a flange on a compressor fails. The flammable vapor cloud collects within the compressor building and adjacent pipe rack (i.e., a Potential Explosion Site), but fortunately does not ignite. As a precautionary measure, the occupants of the plant and surrounding plants are evacuated. But no injuries or substantial damages occur. There is no off-site impact. This incident is a reportable PSI incident since the ethylene vapors released exceeded the 1100 lb chemical release TQ for a flammable vapor. The Safety/Human Health, Fire/Explosion, and Community/Environmental severity levels are each “N/A” (0 severity points) due to none of these impacts of this event exceeding the thresholds for classification as a Severity Level “4” for that category. The Potential Chemical Impact severity level is a “2” (9 severity points) since the flammable vapor release resulted in a vapor cloud entering a building or potential explosion site (congested/confined area) with potential for damage or casualties if ignited. The maximum of the four categories was a Severity level “2”; therefore, the overall incident could be classified as a Severity Level “2” PSI. The Severity points which would be used in the Process Safety Incident Severity Rate (PSISR) calculation would be 9 points (0+0+9+0=9).

49. The release of 10,000 lbs of ethylene (flammable vapor) occurs when a flange on a compressor fails. The flammable vapor cloud collects within the compressor building and adjacent pipe rack and ignites. The resulting vapor cloud explosion causes $30MM in damages or other direct costs, severely injures 3 employees (i.e., the injuries each meet the definition of “lost time injury”), and gains regional media attention for several days. The Safety/Human Health severity level of this event meets the threshold for classification as a Severity Level “2” (9 severity points) due to the multiple lost time injuries, the Fire/Explosion severity level would be classified at the Severity Level “1” (27 severity points), the Potential Chemical Impact severity level is a “2” (9 severity points) since the flammable release resulting in a vapor cloud entering a potential explosion site (congested/ confined area) as demonstrated by the results, and the Community/ Environmental severity level meets the threshold for classification as Severity Level “2“ (9 severity points) due to the media coverage. The maximum of the four categories was a Severity level “1”; therefore, the overall incident could be classified as a Severity Level “1” PSI. The Severity points which would be used in the Process Safety Incident Severity Rate (PSISR) calculation would be 54 points (9+27+9+9=54). A company could argue that the potential chemical impact severity level for this even should be “N/A” (0 points) since much of the fuel is consumed in the explosion. However, since there is a potential that all fuel was not consumed and/or the event could have been even more significant under slightly different circumstances – the Potential Chemical Impact severity level of “2” (9 severity points) is appropriate.


MIXTURES

50. A chemical manufacturer spills 10,000 lbs of a formulated product containing multiple chemicals downstream of a mixing operation. This material is marketed as specific product (e.g., a heating fluid, brake fluid, etc.). Since this material is shipped in this formulation, the company has previously evaluated the mixture per all of the UN Dangerous Goods definitions (or DOT regulations in the USA) and classified the mixture as a “Packing Group III” material. Since the spill exceeded the 2000 kg (4400 lb.) threshold quantity of a Packing Group III material, this spill would be reported as a PSI.

51. A pipe fitting in a specialty chemicals plant fails, releasing 2000 lbs of a mixture of 10% formaldehyde, 20% methanol, 20% Chloromethylmethylether (CMME), and 50% water. This mixture is not one that is commonly transported, so the classification of the mixture has not been performed per the UN Dangerous Goods / US DOT protocols. For the purposes of this PSI metric, a simplified approach can be used by evaluating each individual component relative to the threshold value for that chemical. The pure component reporting threshold of formaldehyde, methanol, and CMME is 4400 lbs, 2200 lbs, and 11 lbs, respectively. This release would be reported as a PSI since the CMME release quantity exceeds the pure component reporting threshold quantity, as shown below:

Component %wt. Release Qty, lbs TQ, lbs Formaldehyde 10% 200 4400 methanol 20% 400 2200 CMME 20% 400 11 Water 50% 1000 n/a

For more information about CCPS or these metrics, go to: www.aiche.org/ccps

Timing for Reporting Company will be due by February 28, 2014.


Metric

OSHA Recordable Incidence and Lost Workday Case Rates for Employees and Contractors Rationale

It is a proven safety metric, universally used. Also, it is a historic ACC measure with high benchmarking value. It has the ability to demonstrate performance improvement.

Units a) OSHA Recordable and Days Away from Work Incident Rate for employees b) OSHA Recordable and Days Away from Work Incident Rate for contractors Definitions Contractors: Those persons who are not considered company employees for OSHA recordkeeping purposes (see definition of “employee” below), who are under contract, subcontract, or purchase order to provide on-site services at company premises that are required to keep OSHA No. 300 logs. Such premises include:

Employer-owned, directly managed, or full-time charter transport such as buses, boats, and aircraft; and

Property leased or accessed through rights secured by the employer. Examples of work that might fall under the contractor definition include (but are not limited to): maintenance, construction, security, engineering consulting, janitorial, food service, information management, and training.

Exclusions include:

A contractor that provides on-site services that amount to less than 20,000 manhours per reporting year, equivalent to about 10 full-time employees.

Employees of common carriers such as those used for truck, rail deliveries, pipelines, and marine movements when off the employer’s premises.

Visitors that don’t provide service. Contract employees that are considered to be company employees under current

OSHA rules for recordkeeping purposes. These contract employees are to be included in the company OIIR numbers submitted to the Council.

Employees: All persons on the company or corporation’s payroll. Under current OSHA rules, some contract employees are considered to be company employees for record keeping purposes and are to be included in the company’s OSHA 300 log. These contractor data should also be included in the company’s occupational injury and illness reporting, and reporting of total number of employees to the Council.


Recordable Injury Rate: Defined by OSHA as the number of recordable incidents for each 100 full-time employees per year, based on 2,000 hours worked per employee per year. The calculation is as follows: Recordable Incident Rate = Annual # of Recordable Cases x 200,000 employee hours


Days Away from Work Incident Rate: Defined by OSHA as the number lost workday incidents for each 100 full-time employees per year, based on 2,000 hours worked per employee per year. The calculation is as follows: Days Away from Work Incident Rate = Annual # of Days Away from Work Cases x 200,000 employee hours


Member Reporting Instructions This information will be collect via the web-based data management system. American Chemistry Council member companies are required by law (Department of Labor/Occupational Safety and Health Administration (OSHA)) to document the number of recordable and days away from work injury and illness cases that they experience on a worksite. The data required for this metric are based on the information that member company’s record for OSHA recordkeeping purposes on an annual basis. All criteria for classifying injuries, illnesses, and fatalities should be consistent with those prescribed by OSHA. Additional information regarding occupational injury and illness recordkeeping can be accessed at www.osha.gov. Each company must provide complete information for the entire company for both employee and contractor data.

For contractor data, reporting definitions for injuries, illnesses, fatalities, and number of hours worked are the same as the OSHA definitions used for employee reporting, except that “contractor” should be substituted for “employee” as necessary.

Companies must develop their own systems for collecting contractor OIIR information. This can be accomplished in at least two ways: 1) solicit data directly from contractors; or 2) estimate the data via best available information. Direct collection of data from contractors will provide the most accurate information. Many companies have begun to require in their contract or purchase order agreements that contractors provide information on injuries and illnesses that occur during performance of the work, and contractor manhours worked can be obtained in the same way. Even where there is not an existing reporting obligation established through the procurement agreements, most contractors will voluntarily provide this information when asked. Whatever means a company chooses for collecting contractor information, it will need to be sure that a system is put in place to consolidate information for reporting to the Council, keeping in mind that the Council requires a single report consolidating the experience of all contractors used by your company, not a contractor-by-contractor report. As stated previously, companies need not include data from contractors that provide services that amount to less than 20,000 manhours per calendar year, which is equivalent to approximately 10 full-time employees.

Timing for Reporting Company will be due by February 28, 2014.


Metric

Number of Fatalities for Employees and Contractors Rationale

It is important to stakeholders. It is a measure of most the severe and significant safety factor. A key consideration in Responsible Care awards.

Units Number of fatalities, by company Definitions Fatalities: Number of fatalities included on OSHA 300 log for employees and for contractors that occurred on the ACC member premises. Member Reporting Instructions This information will be collect via the web-based data management system. Each member company will have to log onto this site and report the number of fatalities that company had (Column G total on the OSHA 300 log). This metric will be reported under the OSHA Recordable Incidence Rate Metric. Once the company has entered in this data, they will then have to approve it before the ACC will begin its approval process. Timing for Reporting Company will be due by February 28, 2014.


Metric

Distribution Incidents Rationale

This is a critical metric to demonstrate product stewardship and beyond the fence line accountability for products in transit.

This is a critical metric to address stakeholder concerns about chemicals traveling through their communities.

If incidents are broken down by severity, we can communicate more effectively about those incidents with actual environmental, safety, community or infrastructure impacts.

It is a key connection to Responsible Care Partners (Partners are reporting the number of DOT Form 5800 incidents).

Units Number of DOT Form 5800 incidents attributable to each member (member listed as the shipper or carrier on the DOT 5800 Form) in total, and broken down by severity categories, Levels 4 through 1. A level 4 incident is the least significant and a level 1 incident is the most significant. The electronic database will automatically sort the DOT 5800 incidents and assign severity ratings based on the information in the DOT database. Members will have an opportunity to review, validate and if necessary, modify the system-assigned ratings. If you do not see incidents on your profile, you should check the Aliases Listings for your company. As aliases change sometime for companies, please ensure that the aliases listings for your company are current. See Appendix G for DOT 5800 Regulatory Definitions. Internal Reporting (optional): There will be an optional reporting of number of shipments, for internal reporting of number of 5800 incidents (in total and by severity level) per 1000 hazmat shipments. The normalized figures will be shared internally only between only those companies that provide the number of shipments data. The rationale for this optional reporting is that some ACC members cannot separate hazmat and non-hazmat shipments, making this denominator impossible to report at this time. Other members track this number closely and would like to use the normalized figure for benchmarking purposes. Therefore, this portion of the metric is optional at this time for those companies interested in using it for benchmarking purposes.


Definitions Applicable Incidents: Those that meet the criteria of DOT regulatory requirements and fall under the members’ ACC dues base. Form 5800 incidents are attributable to the ACC member if the member is listed as either the shipper or carrier on the DOT 5800 Form. Incidents Severity Categorization (Levels 1-4): See Tables below. Hazardous Material Shipments (optional): Based on the definition of shipment provided below, which is taken from, “Hazardous Materials Shipments” prepared by The Office of Hazardous Materials Safety, Research and Special Programs Administration, U.S. Department of Transportation, in Washington, D.C. Shipment: an individual movement of commodities from your establishment to one customer OR to another location of your company (including a warehouse, distribution center, retail or wholesale outlet). A shipment uses one or more modes of transportation, including parcel delivery, U.S. Postal Service, courier, private truck, for-hire truck, rail, water, pipeline, air and other modes. A full or partial truckload can be considered one shipment only if all the commodities are destined for one buyer/receiver location. If the truck makes multiple deliveries on a route, each stop is considered (at least) one shipment. Movement: transportation by a single vehicle, rail car, aircraft, vessel or other mode from a point of origin to a point of either a)transfer to another vehicle, train, aircraft, vessel or other mode or b) final delivery of the freight, whichever comes first. Example : If a single container of freight is hauled by truck to a rail intermodal terminal; placed on a rail car and hauled 1,000 miles to a second rail intermodal terminal; then placed on a truck for final delivery, that one shipment is entails three separate movements: 1)highway, 2)rail, 3) and then highway again. Member Reporting Instructions This information will be collect via the web-based data management system. ACC will download 5800 incident information directly from DOT website and companies will validate the data. Companies have the ability to set the aliases for searching the DOT database and eliminate incidents that are not applicable. The ACC database will automatically determine the severity levels for each incident, as the criteria are captured in the DOT report and database. Once the company has entered in this data, they will then have to approve it before the ACC will begin its approval process. Timing for Reporting Company will be due by February 28, 2014.


DISTRIBUTION INCIDENT SEVERITY RATINGS Note: Current definitions for applicable distribution incidents remain the same. An incident can be removed by the ACC member if it: 1. Is an over-report by the carrier (i.e. does not meet the regulatory criteria of a 5800 incident.

2. Is outside of the member's ACC dues base.

Distribution Incidents Severity Breakdown Severity

Level Safety Impact Systems Impact Chemical

Impact Community

Impact NEG Does not meet or

exceed Level 4 threshold Does not meet or exceed Level 4 threshold Environmental impact mitigation costs of: < $1K



4 Single injury of employee, emergency responder and/or general public, w/o hospitalization, due to chemical exposure or release-related injury

Property, product and/or transportation equipment loss of $25K – 100K Environmental impact mitigation costs of: $1K - $25K

See Chemical Impact Assessment Table.

Police/EMS response

3 Multiple injuries of employee, emergency responder and/or general public, w/o hospitalization, due to chemical exposure or release-related injury

Property, product and/or transportation equipment loss of $100K-$250K; Environmental impact mitigation costs of : $25K – $100K


Major transportation artery closed, substantiated due to incident.

2 Injuries of employee, emergency responder and/or general public, w/ hospitalization, due to chemical exposure or release-related injury

Property, product and/or transportation equipment loss of $250K-500K; Environmental impact mitigation of: $100K-$250K


Evacuation of employees, emergency responders or general public required.

1 Any fatality of employee, emergency responder and/or general public due to chemical exposure or release-related injury

Property, product and/or transportation equipment loss of >$500K; Environmental impact mitigation of: >$250K


Evacuation of employees, emergency responders or general public required, longer than 24 hours.

K = 1,000 MM = 1,000,000


Chemical Impact Classification DOT Class Code (tied to CFR Code and Definitions - See Table below)

08, 22, 90

15, 16, 17, 18, 19, 20, 30, 44,

51, 80

12, 13, 14, 21, 41, 42, 43, 52, 65

01, 11, 23, 61, 62, 70

Haz Mat Amount Released/ Relative Amount

Severity Level for Chemical Impact

10 lbs or less Minimal level NEG NEG NEG 4

10 < X < 400 lbs Less than one drum

4 4 3 3

400 < x < 2,500 lbs Several drums 4 3 3 2

2,500 < x <10,000 lbs Less than a truckload

3 3 2 2

10,000 < x < 100,000 lbs

Truckload quantity; partial railcar

3 2 2 1

> 100,000 lbs Railcar 2 2 1 1

For each company’s public reporting, total distribution incidents along with the number of incidents at each severity level would be reported. Incidents would be reported and classified at the highest level of impact rating for each of the four impact categories: safety, on-site systems, chemical and community.

Distribution Incidents Normalized by # of Hazardous Material Shipments and Incident Severity Index– reported internally only for benchmarking purposes for companies opting to submit hazardous shipment information

Proposed factors

Level Factor Multiplier NEG 0 Negligible Consequences

4 1 Minor Consequences

3 3 Moderate Consequences 2 9 Significant Consequences 1 27 Severe consequences

Distribution Incidents Index = Total Number of 5800 Incidents/1000 hazmat shipments

Distribution Severity Index =

[(# Level 4 incidents x 1) + (# Level 3 incidents x 3) + (# Level 2 incidents x 9) + (# Level 1 incidents x 27)] [1000 hazmat shipments]


Hazard Class Codes This Table is the one DOT uses in the maintenance and management of their 5800 database system.

CLASS CODE

ABBREVIATION CODE

CFR 49 HAZARD CLASS

(CFR 49) DEFINITION CODE

01 FORBID Forbidden 173.21 08 ORM-D Other Regulated

Material, Class D 173.144

11 EXPLO 1 1.1 Explosive Mass Explosion Hazard 173.50

12 EXPLO 2 1.2 Explosive Projection Hazard 173.50

13 EXPLO 3 1.3 Explosive Fire Hazard 173.50 14 EXPLO 4 1.4 Explosive No Blast

Hazard 173.50

15 EXPLO 5 1.5 Very Insensitive Explosive 173.50

16 EXPLO 6 1.6 Extremely Insensitive Detonating 173.50

17 EXPL.A. Explosives, Class A 173.53 18 EXPL.B. Explosives, Class B 173.53 19 EXPL.C. Explosives, Class C 173.53 20 COMB L Combustible Liquid 173.120 21 F. G. 2.1 Flammable

Compressed Gas 173.115

22 NONF.G. 2.2 Nonflammable Compressed Gas 173.115

23 POI GAS 2.3 Poisonous Gas 173.115 30 F. L. 3.0 Flammable -

Combustible Liquid 173.120

41 F. S. 4.1 Flammable Solid 173.124 42 SPONTAN 4.2 Spontaneously

Combustible 173.124

43 DAN WET 4.3 Dangerous When Wet Material 173.124

44 F. S. Flammable Solid (Pre 1991) 173.150

51 OXIDIZR 5.1 Oxidizer 173.127 52 ORG PER 5.2 Organic Peroxide 173.128 61 POISON 6.1 Poisonous Materials 173.132 62 INF SUB 6.2 Infectious Substance

(Etiologic) 173.134

65 IRR Irritating Material 173.132 70 R.A.M. 7 Radioactive Material 173.403 80 CORROS 8 Corrosive Material 173.136 90 MISCEL 9 Miscellaneous

Hazardous Material 173.140

92 ORM-A Other Regulated Material, Class A P Pre-1991 173.140

94 ORM-B Other Regulated Material, Class B Pre-1991 173.140

96 ORM-C Other Regulated Material, Class C Pre-1991 173.140

99 ORM-E Other Regulated Material, Class E Pre-1991 173.140

NOTE: Reclassification of some commodities has occurred due to changes in the regulations.


Metric

Consideration of Responsible Care Partner Status Rationale

This metric supports supply chain activities called for in both the Responsible Care Global Charter and Global Product Strategy.

It potentially improves recognition of Partnership program. Promotes use of common ethic throughout the chemical supply chain.

Units This will be a ‘YES or NO’ metric. If a company answers yes, the company will be asked how Responsible Care Partners are considered from a list of options provided. Further optional comments will also be accepted. Definitions Question: Does your company consider ACC Responsible Care Partnership Program participation in you procurement and logistics vendor selection processes? Member Reporting Instructions This information will be collect via the web-based data management system. Each member company will have to log onto this site and report:

a) Yes or No to the metric. b) If yes, please tell us how by checking off the following ways:

1) Partner Program participation a criteria for doing business with your company 2) Partner status explicitly stated as a criteria used by your company to weigh a supply chain company’s bid 3) Partner status explicitly stated as a selection criteria on your company’s bid form 4) Partner status is a critical consideration for your company when establishing business with a new supply chain company 5) Your company tracks its use of Responsible Care Partners as a percentage of supply chain business as a performance indicator

After checking all that apply, we will then provide a place for you to add additional comments. Once the company has entered in this data, they will then have to approve it before the ACC will begin its approval process. Timing for Reporting Company will be due by February 28, 2014.


Metric

Security - Extension of the Responsible Care® Security Code Affirmation Statement Rationale

This is a very important measure for domestic stakeholders, relevant to legislative and potential regulatory issues.

It supports the ongoing implementation of the Security Code and management of security issues through the management system approach.

It also encourages ongoing improvement of security programs. This supports ongoing coordination with DHS in the development of risk based and

responsible chemical facility security legislation and regulation. Units This will be a ‘YES or NO’ metric. “Since signing the Responsible Care Security Code Implementation Affirmation Statement, my company continues to maintain their Responsible Care Security Code implementation at all company operations through periodic SVAs, training, drills, guidance, audits, revising and updating plans, planning and response to both potential threats and incidents, sharing and implementing best practices, and other appropriate activities. These practices apply to existing and new facilities and employees as well as contractors and service providers.” This will be reported in the aggregate as percentage of member companies. Definitions Extension of the Responsible Care Security Code: Currently, members must sign a Responsible Care Security Code Affirmation Statement that notes the following: “As an ACC member or Responsible Care Partner, our company has implemented a management system based upon the Responsible Care Security Code. In accordance with the principles of Responsible Care, we will continuously seek to improve our processes and systems related to security performance and implement management practices consistent with the Security Code.” Tracking of member submittal of this Affirmation Statement is currently reported in the aggregate on http://www.responsiblecare-us.com. However, the Security Code requires that all of its thirteen management practices be addressed in an ongoing manner through periodic reviews of a quality management system, with some management practices being specifically required on a periodic basis (e.g., SVAs, training, drills, and guidance). This new metric will track in an aggregate fashion whether members can attest that they are maintaining their Responsible Care® Security Code implementation at all company operations, as required. Member Reporting Instructions This information will be collect via the web-based data management system. Each member company will have to log onto this site and report ‘Yes’ or ‘No’ to the metric. Once the company has entered in this data, they will then have to approve it before the ACC will begin its approval process. Starting in 2013, as part of the Responsible Care Strategic Review, the metric will no longer be publically reported. It is still required as a reporting obligation.


Metric

Product Stewardship 1. Has your company implemented a process to prioritize its chemicals and to identify “high priority” chemicals? Y/N 2. Is the process used to prioritize your chemicals available to the public? Y/N; If yes, how/where is it available? 3. Percentage of both high priority chemicals and non-high priority chemicals with completed product stewardship summaries publicly available. 4. Include Product Stewardship Summaries in ICCA IT Portal? (Optional and preset to “NO”) Rationale

It is an important measure for global stakeholders. It will drive GPS and Global Charter implementation, as well as inform management

system implementation. This is a key area of improvement in Responsible Care.

Units

1. Yes/No 2. Yes/No; Location of prioritization process 3. Total number of chemicals (an estimate will suffice); total number of high priority

chemicals and number of non-high priority chemicals; number of high priority chemicals with publicly available risk characterizations and number of non-high priority chemicals with publicly available risk characterizations( reporting zero is acceptable )

4. Yes/No. Preset to “NO”. If changed to “YES”, additional information is required. Definitions Available to the public: Information can be found with little or no interaction with the company (e.g., through a website, through an e-mail request, through a request to a toll-free phone number). Product stewardship summary: The product stewardship summary is intended to give general information about the chemical or categories of chemicals addressed. It is not intended to provide an in-depth discussion of all health and safety information. Below is a listing of recommended elements in a product stewardship summary:

• Chemical identity (or category description) • Uses - applications, functions • Physical/chemical properties • Health effects • Environmental effects • Exposure - exposure potential • Risk management - recommended measures

Updated: January, 2014

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Although recommended, there may be company-specific reasons for not including one or more of these elements in the summary document for a particular chemical. There are other elements that might strengthen a company’s stewardship message, such as:

• Benefits of chemical • Product stewardship programs • Special considerations • Production • Findings by agencies /scientific organizations • Regulatory compliance • Sources for additional information • Conclusion statement • Contact information • Date

More details on these elements are included in the document “Elements to Include in Publicly Available Product Stewardship Summaries,” which is included in the ACC GPS Resource library. Chemicals: For purposes of reporting under the product metrics, a company should focus on those chemicals that the company manufactures/imports and puts into commerce. A company would not be expected to develop summary documents for chemicals that it purchases. Nor would a company expected to develop a summary document for waste, R&D products or intermediates. As a general rule, companies should look to the reporting obligations under the TSCA Inventory Update Rule (IUR) to determine whether a certain chemical is applicable under the performance metrics. If your company would consider a specific chemical as part of its potential IUR obligations, then that chemical should be included under the metrics and should have a product stewardship summary developed. Member Reporting Instructions: Product Stewardship Metric 1: Members will report a simple ‘yes’ or ‘no’ response to whether or not they are compliant with this metric. A process for prioritizing chemicals might consider the factors listed below. These factors are intended to be applied with a view to the circumstances of each individual company.

Chemicals with testing and/or risk evaluation work already completed or underway in response to current or impending regulatory scrutiny

Categories of chemicals of particular concern under national or regional regulatory programs; such as those listed as known carcinogens, mutagens, or substances that are toxic to reproduction.

Chemicals listed as candidates under the Stockholm Convention (Persistent Organic Pollutants or the Rotterdam Convention (Prior Informed Consent)

Chemicals restricted by other national or regional regulations or international conventions Whether the chemical could be classified as Persistent, Bioaccumulative and Toxic (PBT) Whether and to what extent the chemical has potential for (significant) human exposure,

especially when children and other sensitive subpopulations could be impacted. Whether and to what extent the chemical has a potential for significant environmental

exposure when these chemicals are not regulated under a specific regime.


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Whether the chemical presents a significant acute hazard because, for example, it is highly flammable, corrosive, reactive, etc.

Whether the chemical is a high production volume chemical Whether and to what extent the chemical is a focus of broader or increasing societal concern Whether there are attributes of the value chain for a particular chemical that could raise

significant concern (for example, customers are very numerous and /or lack sophistication and competency in managing chemicals, or they do not have adequate product stewardship practices in place).

Whether a company wants to make a chemical high priority for business or other purposes (for example, a new product or an existing product in a new application).

Product Stewardship Metric 2: Members will report a simple ‘yes’ or ‘no’ response to whether or not they are compliant with this metric. If yes, companies should provide a web link to the available summary or provide a contact phone number or email if the summary is not posted. It is intended that the publicly available summary for this metric reflect the overall prioritization process used by the reporting company. It should provide a general explanation of the considerations used to prioritize the chemical line. This metric does not require a list of the company’s identified high priority chemicals to be made public. An appropriate summary of the considerations used to prioritize that enables the public to understand how the company identified high priority chemicals will satisfy this metric. Although this product-related metric has not been specifically tested with focus groups, this metric is expected to address the public concerns about transparency that have been raised in public opinion polling in recent years. This metric is not intended to create any new legal obligations and is not intended to expand the legal risks already faced by ACC member companies. Product Stewardship Metric 3: Members will report on the 1) total number of chemicals it produces or imports; 2) the number of high priority chemicals it has identified through its prioritization process; 3) the total number of non-high priority chemicals it has identified through its prioritization process; 4) the number of high priority chemicals with publicly available summaries and 5) the number of non-high priority chemicals with publicly available summaries. ACC will aggregate the data submitted by member companies to determine the percentage of high priority chemicals and non-high priority chemicals with publically available summaries for the overall membership. Product Stewardship Metric 4: ICCA IT Product Stewardship Portal – New for 2011 Reporting Year The International Council of Chemical Associations (ICCA) in October 2010 created a Product Stewardship Portal (view here) similar to ACC’s Product Stewardship Portal (view here). When an ACC member company includes a single web link to their publically available product stewardship summaries in Metric 2 of this performance measure, that link goes to ACC’s Product Stewardship Portal. New in this 2011 Reporting year, ACC now has an option for members to automatically participate in ICCA’s IT Portal.


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To participate in ICCA’s IT Portal, indicate “YES” on Metric 4. Metric 4 is optional and reads, “Include Product Stewardship Summaries in ICCA IT Portal?” This metric is preset to “NO”. If an ACC member company would like their product stewardship summaries also displayed on the ICCA IT Portal, change the response to “YES” and include the required information. More information on these product metrics and on product stewardship summaries is available in the Global Product Strategy resource library, on ACC’s MemberExchange, http://memberexchange.americanchemistry.com Once you log into MemberExchange, in the middle of the page there will be a section titled ‘Advocacy’. In this section, the second option under Advocacy will read ‘Health, Product Stewardship and Chemical Regulation’. After clicking on that option, you will be redirected to a page that houses all of the documents related to this metric. Timing for Reporting Company will be due by February 28, 2014.


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Metric

Certification of Responsible Care management system Either RCMS® or RC14001®, for both headquarters and sampling of facilities Rationale

A critical component of new ACC Responsible Care paradigm. It provides credibility to Responsible Care.

Units Company has met ACC certification requirements; check mark or no check mark. A member company is required to indicate:

Name of Facility or Headquarters City and State Name of Approved Auditing Firm Date of Certification Certification type, RCMS or RC14001

Definition Certification: Completion of independent third party evaluation and certification of a company’s Responsible Care management system. Member Reporting Instructions This information will be collect via the web-based data management system. The ACC will collect information about each facility certification and whether or not your company’s headquarters have been certified. Starting in 2013, as part of the Responsible Care Strategic Review, the metric will no longer be publically reported. It is still required as a reporting obligation.


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APPENDIX A– List of HAPs as subset of TRI

Name CAS Notes

acetaldehyde 75-07-0

acetamide 60-35-5

acetonitrile 75-05-8

acetophenone 98-86-2

2-acetylaminofluorene 53-96-3

acrolein 107-02-8

acrylamide 79-06-1

acrylic acid 79-10-7

acrylonitrile 107-13-1

allyl chloride 107-05-1

4-aminobiphenyl 92-67-1

aniline 62-53-3

o-anisidine 90-04-0

anthracene 120-12-7 (3)

antimony 7440-36-0 (4)

antimony compounds N010 (4)

arsenic compounds (not included) N020 (5)

asbestos (friable) 1332-21-4

benzene 71-43-2

benzidine 92-87-5

benzo(g,h,i)perylene 191-24-2 (3)

benzo(j,k)fluorene (fluoranthrene) 206-44-0 (3)

benzoic trichloride 98-07-7

benzyl chloride 100-44-7

beryllium 7440-41-7 (4)

beryllium compounds N050 (4)

biphenyl 92-52-4

bis(chloromethyl) ether 542-88-1

bromoform 75-25-2

bromomethane 74-83-9

1,3-butadiene 106-99-0

methyl tert-butyl ether 1634-04-4

1,2-butylene oxide 106-88-7

cadmium 7440-43-9 (4)

cadmium compounds N078 (4)

calcium cyanamide 156-62-7

captan 133-06-2

carbaryl 63-25-2

carbon disulfide 75-15-0

carbon tetrachloride 56-23-5

carbonyl sulfide 463-58-1

catechol 120-80-9

certain glycol ethers N230 (2)


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Name CAS Notes

chloramben 133-90-4

chlordane 57-74-9

chlorine 7782-50-5

chloroacetic acid 79-11-8

2-chloroacetophenone 532-27-4

chlorobenzene 108-90-7

chlorobenzilate 510-15-6

chloroethane 75-00-3

bis(2-chloroethyl) ether 111-44-4

chloroform 67-66-3

chloromethane 74-87-3

chloromethyl methyl ether 107-30-2

chloroprene 126-99-8

chromium 7440-47-3 (4)

chromium compounds (except chromite ore mined in the Transvaal Region) N090 (4)

cobalt 7440-48-4 (4)

cobalt compounds N096 (4)

m-cresol 108-39-4

o-cresol 95-48-7

p-cresol 106-44-5

cresol (mixed isomers) 1319-77-3

cumene 98-82-8

cyanide compounds N106 (1)

2,4-D 94-75-7

2,4-diaminotoluene 95-80-7

diazomethane 334-88-3

dibenzofuran 132-64-9

1,2-dibromo-3-chloropropane 96-12-8

1,2-dibromoethane 106-93-4

dibutyl phthalate 84-74-2

1,4-dichlorobenzene 106-46-7

3,3'-dichlorobenzidine 91-94-1

1,2-dichloroethane 107-06-2

dichloromethane 75-09-2

1,2-dichloropropane 78-87-5

1,3-dichloropropylene 542-75-6

dichlorvos 62-73-7

diethanolamine 111-42-2

diethyl sulfate 64-67-5

3,3'-dimethoxybenzidine 119-90-4

1,1-dimethyl hydrazine 57-14-7

dimethyl phthalate 131-11-3

dimethyl sulfate 77-78-1

4-dimethylaminoazobenzene 60-11-7

N,N-dimethylaniline 121-69-7


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Name CAS Notes

3,3'-dimethylbenzidine 119-93-7

dimethylcarbamyl chloride 79-44-7

N,N-dimethylformamide 68-12-2

4,6-dinitro-o-cresol 534-52-1

2,4-dinitrophenol 51-28-5

2,4-dinitrotoluene 121-14-2

1,4-dioxane 123-91-1

1,2-diphenylhydrazine 122-66-7

epichlorohydrin 106-89-8

2-ethoxyethanol 110-80-5 (2)

ethyl acrylate 140-88-5

ethylbenzene 100-41-4

ethylene glycol 107-21-1

ethylene oxide 75-21-8

ethylene thiourea 96-45-7

ethyleneimine 151-56-4

di(2-ethylhexyl) phthalate 117-81-7

ethylidene dichloride 75-34-3

formaldehyde 50-00-0

heptachlor 76-44-8

1,2,3,4,6,7,8-heptachlorodibenzofuran 67562-39-4 (6)

1,2,3,4,7,8,9-heptachlorodibenzofuran 55673-89-7 (6)

1,2,3,4,6,7,8-heptachlorodibenzo-p-dioxin 35822-46-9 (6)

hexachloro-1,3-butadiene 87-68-3

hexachlorobenzene 118-74-1

hexachlorocyclopentadiene 77-47-4

1,2,3,4,7,8-hexachlorodibenzofuran 70648-26-9 (6)




1,2,3,4,7,8-hexachlorodibenzo-p-dioxin 39227-28-6 (6)



hexachloroethane 67-72-1

hexamethylphosphoramide 680-31-9

hexane 110-54-3

n-hexane 110-54-3

hydrazine 302-01-2

hydrochloric acid 7647-01-0

hydrogen cyanide 74-90-8 (1)

hydrogen fluoride 7664-39-3

hydroquinone 123-31-9

lead 7439-92-1 (4)

lead compounds N420 (4)

lindane 58-89-9


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Name CAS Notes

maleic anhydride 108-31-6

manganese 7439-96-5 (4)

manganese compounds N450 (4)

mercury 7439-97-6 (4)

mercury compounds N458 (4)

methanol 67-56-1

methoxychlor 72-43-5

2-methoxyethanol 109-86-4 (2)

3-methycholanthrene 56-49-5 (3)

methyl hydrazine 60-34-4

methyl iodide 74-88-4

methyl isobutyl ketone 108-10-1

methyl isocyanate 624-83-9

methyl methacrylate 80-62-6

4,4'-methylenebis(2-chloroaniline) 101-14-4

methylenebis(phenylisocyanate) 101-68-8

4,4'-methylenedianiline 101-77-9

naphthalene 91-20-3

nickel 7440-02-0 (4)

nickel compounds N495 (4)

nitrobenzene 98-95-3

4-nitrobiphenyl 92-93-3

4-nitrophenol 100-02-7

2-nitropropane 79-46-9

N-nitrosodimethylamine 62-75-9

N-nitrosomorpholine 59-89-2

N-nitroso-N-methylurea 684-93-5

1,2,3,4,6,7,8,9-octachlorodibenzofuran 39001-02-0 (6)

1,2,3,4,6,7,8,9-octachlorodibenzo-p-dioxin 3268-87-9 (6)

parathion 56-38-2

1,2,3,7,8-pentachlorodibenzofuran 57117-41-6 (6)

2,3,4,7,8-pentachlorodibenzofuran 57117-31-4 (6)

1,2,3,7,8-pentachlorodibenzo-p-dioxin 40321-76-4 (6)

pentachlorophenol 87-86-5

phenanthrene 85-01-8 (3)

phenol 108-95-2

p-phenylenediamine 106-50-3

phosgene 75-44-5

phosphine 7803-51-2

phosphoric acid 7664-38-2

phosphorus (yellow or white) 7723-14-0

phthalic anhydride 85-44-9

polychlorinated biphenyls 1336-36-3

propane sultone 1120-71-4

beta-propiolactone 57-57-8


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Name CAS Notes

propionaldehyde 123-38-6

propoxur 114-26-1

propylene oxide 75-56-9

propyleneimine 75-55-8

quinoline 91-22-5

quinone 106-51-4

quintozene 82-68-8

selenium 7782-49-2 (4)

selenium compounds N725 (4)

styrene 100-42-5

styrene oxide 96-09-3

2,3,7,8-tetrachlorodibenzofuran 51207-31-9 (6)

2,3,7,8-tetrachlorodibenzo-p-dioxin 1746-01-6 (6)

1,1,2,2-tetrachloroethane 79-34-5

tetrachloroethylene 127-18-4

titanium tetrachloride 7550-45-0

toluene 108-88-3

toluene-2,4-diisocyanate 584-84-9

o-toluidine 95-53-4

toxaphene 8001-35-2

1,2,4-trichlorobenzene 120-82-1

1,1,1-trichloroethane 71-55-6

1,1,2-trichloroethane 79-00-5

trichloroethylene 79-01-6

2,4,5-trichlorophenol 95-95-4

2,4,6-trichlorophenol 88-06-2

triethylamine 121-44-8

trifluralin 1582-09-8

urethane 51-79-6

vinyl acetate 108-05-4

vinyl bromide 593-60-2

vinyl chloride 75-01-4

vinylidene chloride 75-35-4

m-xylene 108-38-3

o-xylene 95-47-6

p-xylene 106-42-3

xylene (mixed isomers) 1330-20-7


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Notes

(1) Cyanide compounds - X'CN where X = H' or any other group where a formal dissociation may occur. For example KCN or Ca(CN)2. Individual chemicals in the list are noted as such.

(2) The HAP glycol ethers group includes mono- and di- ethers of ethylene glycol, diethylene glycol, and triethylene glycol R-(OCH2CH2)n -OR' where n = 1, 2, or 3; R = alkyl or aryl groups; R' = R, H, or groups which, when removed, yield glycol ethers with the structure: R-(OCH2CH)n-OH. Ethylene glycol monobutyl ether and polymers are excluded from the glycol category. The definition of the "certain glycol ethers" group in the TRI database is similar to the HAP glycol ether group, but differs in some respects. Most glycol ethers in the TRI database are combined under the "certain glycol ethers" group name; individual chemicals still listed in the TRI database are noted as such in the list.

(3) Includes organic compounds with more than one benzene ring, and which have a boiling point greater than or equal to 100 º C. Individual chemicals in the list are noted as such.

(4) For all the "metal compounds" listings above (e.g., antimony compounds, cobalt compounds, etc.), unless otherwise specified, these listings are defined as including any unique chemical substance that contains the named metal (i.e., antimony, cobalt etc.) as part of that chemical's infrastructure/molecular formula.

(5) Arsenic and arsenic compounds are TRI chemicals; however, inorganic and organic forms are not listed separately in the TRI database. The HAP list only includes inorganic arsenic-containing chemicals. Because the inorganic portion cannot be determined in the TRI records, neither arsenic or arsenic compounds are listed in this table.

(6) Part of 2,3,7,8- dioxin/furan congener HAP group.


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APPENDIX B – Water Consumption Flow Chart and FAQ’s

}

}

}Processing Unit / Facility

(includes manufacturing, R&D labs and technical centers)

Direct Surface Water(fresh or salt)

I1

Purchased Water

I2

Plant-Operated well water or other

ground waterI3

Stormwaterrunoff

Reuse-Steam-Condensation-Cooling water

Formula for calculating water consumptionCt = (I1 - R1) + (I2 - R2) + (I3 - R3)

If Ct = negative, report zero

R = Returns I = InputC = Consumption

Water Consumption Flow Chart

Intakes

Consumption

Returns

Products

C1

ChemicalReactionsC2

EmissionsLost SteamEvaporationC3

Returns to surface water if treated to specific discharge standards

R1

Returns to Purchased water sources

R2

Returns to groundwater

R3


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Frequently Asked Questions Regarding Water Consumption

Q1: How should we account for water associated with deep well injection? A1: Since deep water injection is not a return to the original source of water, we should assume that water is consumed. Q2: How should we account for produced water? A2: If produced water is released back into the environment with other waters, it can be counted as a credit against consumption. If there is a net production overall, you should not report a negative consumption, but rather, just report zero consumption.

Q3: A site draws water from an aquifer and then returns the water to the river next to the site. The aquifer is mostly replenished by the river. Would this count this as returned water? A3: If you are generally certain that the aquifer is replenished by the river, this water can be counted as returned to its source. Q4: My company "purchases" potable water from a City supplier, who actually draws the water from a river, treats it to potable standards, then provides it to my company, who then uses the water and returns some back to the same river, treated, then can we "credit" ourselves for the water returned to the river even though City (provider) is between the river (source) and my company? A4: Yes, you can credit this water as returned water. Q5: Additionally, what if my company sends wastewater "off-site" for treatment by a POTW, who treats it for us, and returns it to the same river from which the City originally withdrew the water from? Can we credit ourselves for wastewater discharged to the POTW when it returned to the same river that the City originally withdrew it from? A5: Yes, this can be credited as returned water. Q6: How should we account for solution mined brine? A6: It is a water source, so it should be counted as water intake. If the situation is as you described it below, that you pay to have this solution mined and then pipelined into your facility for use in chemical creation, you should count this brine solution as water consumption. If you return any remaining solution back to the ground, appropriately treated, then you can count these returns as credit for consumption. Q7: If I purchase water from Public Company A and return it to Public Company B (i.e a POTW), can I count the water sent to Public Company B a return to Purchased Water Source? A7: Yes, you can treat this as returned water as long and Public Company B returns it to the same source that Public Company A withdrew it from.


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Q8: Please help to define the "purchased water" category. Does this only include potable water or does it refer to anything purchased? Technically, we pay for water that is being used at our facilities even if it’s drawn directly from a surface water or ground water source. A8: "Purchased water" includes potable water or water that is purchased from other companies. Purchased water that is returned to its source can be credited against the consumption. Water drawn directly from surface water or ground water should be considered against returns to those sources regardless of whether that water is purchased or not. Q9: We have some facilities that are co-located and highly integrated with plants owned and operated by other companies. Our facilities often take all water and steam directly from the other plant and return all wastewater and condensate to them as well. Should all of these intakes and discharges be accounted for in the purchased water category? A9: Yes, these intakes and discharges should be grouped in the purchased water category. Q10: We have a co-located facility that is highly integrated with a neighboring plant owned and operated by another company. All water is taken from and returned to the other plant. Unlike our other facilities, there are no meters present that directly quantify the amount of water being used. They simply pay for a fixed percentage of the total water that the other company uses. Is there any guidance for estimating water consumption in this case? A10: A mass balance or simple engineering judgment based on pipe diameter and flow would be acceptable in estimating the intake and return from this source if a water meter is not possible. Q11: Stormwater is often in our process water returns. The guide states that "Stormwater runoff should be excluded from water returned, if metered separately or easily estimated." If stormwater is not metered and can't be estimated accurately should it just be left in? If it should be included, is there any guidance to estimating stormwater quantities? A11: Yes, if you cannot estimate the stormwater runoff and there are not meters in the stormwater outfalls, merely keep these flows in the return calculation. However, one can generally estimate stormwater runoff using local rainfall from the National Weather Service, surface area of the outfall, and absorption rate of the terrain, based on the land use. Resources can be found at http://cfpub.epa.gov/npdes/home.cfm?program_id=6. Q12: The guide states that "Credit is allowed only when water is returned to its original source." This is confirmed by Q3 in the Frequently Asked Questions. However, the opposite guidance is given in Q4. In this scenario purchased water is returned to a surface water source but is credited. Is water taken from the city accounted for as purchased water or surface water?


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A12: The spirit of the measure is that you must count water as consumed, if it is not ultimately returned to the water source (surface, ground) from which it was taken. Since many companies do not fully understand the sources of their purchased water, nor the final discharge points of their returned water to the purchased source, we generally allow companies to consider these intakes and returns separately and account for them uniquely. If a company has knowledge of the source of its purchased water as well as the final discharge of the returns to the purchased sources, these flows could be counted in the surface water or ground water categories as appropriate. This is the reason for the answer given to question 4 in the FAQs. Q13: In relation to the question above, if water is drawn from one river but returned to a different river, is this credited? I believe it should be credited because it is a surface water source being returned to a surface water source. However, it is not the exact same source. A13: No, credit should not be given in this case, as the return is not to the same specific source of surface water. The intent is to measure impact to a watershed and water source. In this case, each river is impacted by the discharge without a return, and likewise a return without a discharge.


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APPENDIX C – Greenhouse Gas and Energy Efficiency Instructions

INSTRUCTIONS - AMERICAN CHEMISTRY COUNCIL ENERGY EFFICIENCY AND GREENHOUSE GAS EMISSIONS SURVEY

TABLE OF CONTENTS

1. Confidentiality of submitted data. ........................................................................................................................... 2. Frequency of survey. ............................................................................................................................................... 3. Reasons for the survey ............................................................................................................................................. 4. Survey distribution. ................................................................................................................................................. 5. Data requested ......................................................................................................................................................... 6. Facility data to be reported. ..................................................................................................................................... 8. Reporting energy consumed at a site where products other than NAICS 325 products are also produced. ............ 9. Exclusion of energy used in transportation of chemical products or feedstocks. .................................................... 10. Exclusion of energy use, sales dollars, pounds of production, CO2 or other greenhouse gas emissions data from

operations in Puerto Rico or other U.S. territories. ..................................................................................................... 11. Higher heating value .............................................................................................................................................. 12. Data availability; judgment. .................................................................................................................................. 13. Energy conversion factors provided ...................................................................................................................... 14. Energy conversion factors to be provided by respondents .................................................................................... 15. NAICS classifications ........................................................................................................................................... 16. Revisions to the survey forms ............................................................................................................................... 17. Whom to contact for additional information about the survey .............................................................................. 1-1. Reason for requesting the company sales dollar amount...................................................................................... 1-2. Reason for requesting data on "pounds of production” ........................................................................................ 1-3. Include the value and quantity of exports respectively in the sales dollars and pounds of production reported. . 1-4. Estimated CO2 emission factors for typical on-site generated and other fuels which are burned as fuel. ........... 1-5. Purchased electricity (including feedstock electricity). ........................................................................................ 1-6. Purchased steam ................................................................................................................................................... 1-7. Process-generated steam ...................................................................................................................................... 1-8. Steam and electricity purchased from cogeneration facilities .............................................................................. 1-9. Reason for requesting data for on-site produced energy ...................................................................................... 1-10. Energy sources to report ..................................................................................................................................... 2-1. Reason for requesting data on non-combustion CO2 greenhouse gases ............................................................... 2-2. Rationale for the particular set of gases listed in the survey ................................................................................ 2-3. Sources to report; exclusion of “de minimis” quantities ...................................................................................... 2-4. Reporting emissions of the manufactured gases (HFCs, PFCs and SF6) already included in the company’s response to survey question 1b. (pounds of production) ............................................................................................. 2-5. Converting emissions of gases other than CO2 to CO2 equivalents ..................................................................... 2-6. Sinks; “removal by sinks” .................................................................................................................................... 2-7. Rationale for requesting information on greenhouse gas “removal by sinks ....................................................... 2-8. Use of this data on greenhouse gases ................................................................................................................... 2-9. Completing Sheet 2 .............................................................................................................................................. 3-1. Major Changes ..................................................................................................................................................... 3-2. Participation in American Chemistry Council Voluntary Programs ....................................................................


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GENERAL INFORMATION Beginning in calendar year 2002 data, there will no longer be a small energy user exemption at the company level, but rather an individual plant site small user exemption. Single site deminimis reporting levels are being used starting this year for both energy and greenhouse gas emission reporting. Those single facility annual deminimis levels are 100 billion Btu for total energy use and 5000 tons total equivalent net CO2 emissions per individual greenhouse gas (CO2, CH4, N2O, HFCs, PFCs, SF6). If all of your company’s facilities are below the energy and GHG deminimis levels, and your company prefers not to complete the survey this year, indicate this response in the metrics website.

1. Confidentiality of submitted data. The confidentiality of individual company responses will be rigorously safeguarded by American Chemistry Council (Council) staff. Council staff will review and if necessary verify submitted data. The data will then be entered in the Council’s confidential database. Individual company survey responses will be destroyed after one year. Individual company data will be retained by the Council in its confidential data base for use in correlating and verifying data reported subsequently, and to assess survey respondent companies’ aggregate efficiency and emissions trends over time. Only the aggregated industry-wide data will be reported to Council members and used by the Council in its advocacy activities. This aggregated data is reported to the public at www.americanchemistry.com/rc , as an industry-wide performance measurement under the Responsible Care® program. When default conversion factors are changed, time-series aggregate performance will be corrected to use consistent conversion factors.

2. Frequency of survey. This is an annual survey which will provide a running annual tabulation of energy consumption, CO2 and other greenhouse gas emissions and related output measures such as constant dollar value of sales and aggregate pounds of production. This will allow an evaluation of chemical industry performance trends in the areas of energy efficiency and greenhouse gas emissions.

3. Reasons for the survey The business of chemistry is energy-intensive and the cost of purchasing energy and using it in compliance with laws and regulations is substantial for most companies. During the last few years high and volatile energy prices and tightness in U.S. energy markets adversely impacted many Council member companies. In addition, for more than a decade the issue of potential anthropogenic global climate change has been of intense interest to many government officials, scientists, environmental interest groups and citizens in the United States and abroad. Many policymakers continue to be interested in mandatory greenhouse gas emissions reduction measures which if not carefully crafted would adversely affect Council member companies' access to competitively-priced energy. The Council is conducting a high level effort to achieve reliable and affordable energy supplies, continued international competitiveness of the U.S. business of chemistry, and protection of the environment. In 2002, the Council adopted specific performance metrics for the new Responsible Care® program. Energy efficiency and greenhouse gas emissions were among the adopted measures that are reported to the public as an indication of industry performance in these areas. Starting with the reporting of 2003 data, portions of this survey became mandatory for all members in order to provide the information necessary to track energy efficiency and greenhouse gas intensity. Our ability to demonstrate that Council members are voluntarily continuing to improve their energy efficiency, lower the carbon intensity of their NAICS 325 manufacturing, and reduce emissions of other greenhouse gases greatly strengthens our credibility in arguing for rational energy policies. Therefore, additional voluntary sections of this report will also be used to further the Council’s advocacy goals.


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4. Survey distribution. The survey is sent to the Executive Contact of each Council member company, and, for companies which responded to the previous year’s survey, to each company’s survey contact person for that year. In addition, the survey will be posted as a downloadable Excel spreadsheet, under the ‘Help’ section of the performance measures reporting site: http://metrics.responsiblecaretoolkit.com. It is also posted under the ‘Guidance’ section of ‘Metrics’ area at www.rctoolkit.com.

5. Data requested The survey is designed to capture total energy use and greenhouse gas emissions by member companies each year , in NAICS 325, chemical manufacturing (formerly SIC 28, chemicals and allied products), in the United States. Purchased energy used as fuel, purchased steam, and purchased electricity, including both purchased non-feedstock and feedstock electricity, as well as fuels produced on-site, are to be reported on Part 2 (Sheet 1) with related fuel combustion CO2e

emissions and indirect purchased electricity-associated CO2e emissions. Beginning with 2013 reporting, purchased and on-feedstock electricity is reported as one number. Total CO2 equivalent (CO2e) emissions are to be reported where factors are available. EPA GHG Mandatory Reporting Rule (40 CFR Part 98) default heating values and GHG emission factors for combustion sources (Table C-1 to Subpart C of Part 98) are used for energy and CO2 emission factors, and Table C-2 to Subpart C are used for CH4 and N2O emission factors for combustion sources. The default emission factors used in this survey are the composite of the CO2, CH4, and N2O emissions on a CO2e basis. All heating value and emission factors are updated to match the EPA revisions to 40 CFR Part 98 promulgated in the Federal Register on November 29, 2013 so that this ACC reporting is on the same basis as the mandatory EPA reporting. Emissions of other important greenhouse gases are to be reported on Part 3 (Sheet 2). Non-purchased electricity energy (i.e. fossil energy-based self-generation) used as feedstocks is not reported. Major facility or operational changes, and voluntary energy efficiency and greenhouse gas emissions reduction measures are tallied on Part 4 (Sheet 3); Part 4 information is optional; however, all members are strongly encouraged to complete Part 4 in order for ACC to explain indicated changes in performance on an aggregated basis.

6. Facility data to be reported. Energy and GHG emissions and other data for sites or facilities that support ACC dues-based operations should be reported. For example, office or laboratory facilities that are over 50% supportive of non-NAICS 325 production are not reportable. Office or laboratory facilities that are over 50% in support of NAICS 325 production are reportable. Similarly, parts of single sites that are over 50% in support of non-NAICS 325 production are not reportable, however, if it is easier to keep all data together for the total site, that can be included in the reported data. The key is to be consistent in your company’s reporting method year to year.

7. Individual facility data should not be submitted

Member companies may find it useful to track their energy use on a site, plant, or product basis. For this Council survey, however, individual facility totals are neither necessary nor desired. This survey requests aggregate information for the company for NAICS 325 manufacturing in the United States. We request that each company submit only one response.

8. Reporting energy consumed at a site where products other than NAICS 325 products are also produced. Where a plant or company's product mix is part NAICS 325 and part others, please allocate energy as appropriate. Company responders' judgments are acceptable. The critical aspect of this allocation is to be consistent year-to-year. Allocations made for the EIA MECS survey or for prior years' Council surveys may provide useful guidance.


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9. Exclusion of energy used in transportation of chemical products or feedstocks. The intent of the survey is to capture manufacturing sector energy use only, and not to include fleet transport energy.

10. Exclusion of energy use, sales dollars, pounds of production, CO2 or other greenhouse gas emissions data from operations in Puerto Rico or other U.S. territories. The energy consumption data should include only that consumed in the 50 states, the sales dollars should include that derived from products produced in the 50 states (whether sold in the U.S. or exported), the total production should include products produced in the 50 states (whether sold in the U.S. or exported), and CO2 and other greenhouse gas

emissions data should include only those emissions from sources located in the 50 states.

11. Higher heating value The report will be based on the use of higher heating value for all fuels when converting to MM Btu/year.

12. Data availability; judgment. ACC anticipates that data needed to respond to this survey will be readily available from company records. To minimize the burden of responding, estimates or judgments may be used where necessary to file a comprehensive report. Consistency in methodology from year to year is important in order to accurately monitor energy efficiency and greenhouse gas emissions trends.

13. Energy conversion factors provided The survey form includes standard energy conversion factors to convert the physical units of energy to MM Btu. A default conversion factor of 10,000 Btu/kWh is used for purchased electricity to reflect typical electric utility efficiency and transmission losses. Where the actual fuel heating value is known to differ from the default standard conversion value listed on the survey form, indicate the appropriate alternate conversion factor in the space provided on the form and use the alternate factor in your calculations. Similarly, default standard CO2e emission factors are given on the

survey form. Again, if actual CO2e emission rates as LB/MMBtu are known to differ from the standard values given,

indicate the appropriate alternative factor on the form and use it in your calculations. EPA GHG Mandatory Reporting Rule factors are used in the ACC survey where applicable.

14. Energy conversion factors to be provided by respondents Please note that in two cases on Part 2 (Sheet 1) (items 2h., Purchased Steam and 2i, Other Purchased) we are requesting respondents to provide the appropriate energy conversion and CO2e emissions factors. If a more accurate figure is not

available, the default steam energy conversion factor of 1200 Btu/lb steam may be used.

15. NAICS classifications For your guidance, a copy of the NAICS (North American Industrial Classification System) codes for chemical manufacturing is given at the end of these instructions.


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16. Whom to contact for additional information about the survey

Contact Bradford Johnson at the American Chemistry Council: telephone (202) 249-6188; e-mail: [email protected]

Part 2 (SHEET 1): SALES; PRODUCTION; PURCHASED ELECTRICITY & FUELS PLUS ON-SITE GENERATED FUELS

SALES

1-1. Reason for requesting the company sales dollar amount. Reported aggregate energy use, CO2e and other greenhouse gas emissions will be compared to sales dollars, corrected

for inflation, to assess aggregate trends and cross check with pounds of production. Member companies already report their "sales" to the Council, according to an agreed formula, for the purpose of calculating their Council dues. However, this information is confidential and Council staff working on this energy efficiency and greenhouse gas emissions survey do not have access to it. This is why we request that sales dollar value be reported on this survey, for all NAICS 325 products including exports, on a corporate total basis comparable to the energy use basis. Intra-company sales and transfers within and out of NAICS 325 should be included. (This should be similar to the method of shipments dollar accounting as reported in the Annual Survey of Manufactures (ASM) of the Census Bureau.) POUNDS OF PRODUCTION

1-2. Reason for requesting data on "pounds of production” The Council recognizes that measures such as the constant dollar value of sales, shipments or value-added all have weaknesses when used as the measure of output against which to compare energy input and greenhouse gas emissions. While pounds of production is not a perfect measure, it is useful as a measure of industry trends. To minimize the reporting burden on member companies, we are asking for a single, aggregate number for pounds of production. This will include pounds of all NAICS 325 products resulting from the energy consumption reported on the survey. This information can be assembled by summing individual sites' pounds of production totals to obtain an aggregate pounds of production total for the company. We recognize this may result in some double-counting because one site's output may be another site's input. Nevertheless, this method seems straightforward and if followed consistently will accurately indicate the trend in pounds of production over time. Furthermore, this method parallels in concept the Census Bureau's method for collecting data on company shipments. This method will be used for reporting our progress toward our greenhouse gas intensity commitment.

1-3. Include the value and quantity of exports respectively in the sales dollars and pounds of production reported. The basic idea is to count all sales and production attributable to domestic manufacture, i.e. that which consumes the energy reported. Sales and production of products manufactured outside the United States, or manufactured outside the United States and imported into the United States, should not be included in the sales dollar total or the production total.

1-4. Estimated CO2e emission factors for typical on-site generated and other fuels which are burned as fuel. A list of estimated emission factors appears at the end of these instructions for those cases where the correct factor is not known by the respondent but the fuel stream source is known. PURCHASED NON FEEDSTOCK ENERGY & FEEDSTOCK ELECTRICITY

1-5. Purchased electricity (including feedstock electricity). Purchased electricity used for heating or power plus purchased “feedstock” electricity used directly in the process (such as electrolysis) should be listed on Sheet 1. Total purchased electricity quantity is needed is order to quantify total


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electricity use and associated indirect CO2 emissions. Electricity used for non-feedstock purposes should be listed on line 2a-1, while feedstock electricity (electrolysis processes) should be listed on line 2a-2. Self-generated electricity should not be listed anywhere, since it is generated from the fuels which will be listed either as purchased or on-site produced. This method will allow accounting for the fuel-to-electricity conversion process efficiency and allow for tabulation of total CO2 emissions. If the facility sells or exports electricity or steam, the quantity sold or exported should

be subtracted from the amount of purchased electricity or steam in the appropriate row so that net consumption or utilization is reported. For this survey a conversion factor of 10,000 Btu/kWh is used to account for typical electric utility efficiency and transmission line losses. CO2 emissions attributable to purchased electricity will be calculated using a CO2 “output rate” which in turn is calculated from data contained in the latest “Annual Energy Review” of the Energy Information Administration. This CO2 output rate, expressed in LbCO2/MMBtu, appears on the survey form and is embedded in the Excel spreadsheet. In the event publication of a later edition of the “Annual Energy Review” occurs after this survey is distributed but before Council staff aggregate and analyze survey responses, staff will use the latest data to calculate a new output rate and will use that new rate in their compilation of survey results. Where the individual company has determined an overall equivalent CO2e emission rate per kWh or per MMBtu based on its determination of emissions from purchased electricity using EPA eGRID or other data, that conversion factor can be inserted into the response, or the total kWh and CO2e emissions can simply be provided.

1-6. Purchased steam Purchased steam should be listed on Part 2 (Sheet 1). Do not list steam produced on-site from fuels that are themselves listed on Part 2 (Sheet 1). That would be double counting, as the fuel energy input has already been reported. Similarly, except as given in instruction 1-7 below, do not report steam produced on-site by process heat recovery (process stream cooling which generates steam). An example would be formaldehyde manufacturing, where steam is generated by process cooling and used elsewhere on-site. In many cases, the steam quantity is not metered so the quantity may not be readily available.

1-7. Process-generated steam If steam is generated by the process and that steam is sold or transferred off-site by the reporting company to another company, the steam sold or transferred should be accounted for by the reporting company (the steam generator) as a negative value in the purchased steam row of Part 2 (Sheet 1). Similarly, if steam generated in a process by another company is purchased by the reporting company site, that purchased steam should be reported by the reporting company (the purchaser) as a positive value on Part 2 (Sheet 1). No CO2e emissions should be reported on Sheet 1 for purchased

steam generated in a process (that is, that portion of total purchased steam that is produced in a process).

1-8. Steam and electricity purchased from cogeneration (Combined Heat and Power-CHP) facilities should be reported as follows: 1.8. a Steam Steam energy purchased from a cogeneration facility should be valued at the default standard 1200 Btu/LB unless an actual value is known; however, the 1200 Btu/LB figure includes consideration of typical boiler efficiency, so an actual known value should consider actual steam enthalpy rise and steam generator efficiency. For simplicity, any credit for increased overall efficiency with cogeneration would be applied to the net electrical heat rate rather than toward any steam credit. CO2e emissions associated with steam purchased from a cogeneration facility would be calculated based

on the total Btu of that steam, calculated per the above, and applying the CO2e emission rate for the primary fuel being

fired by the cogeneration facility, e.g., 207.3 LB/MMBtu for coal and 117.1 LB/MMBtu for natural gas.

1-8. b Electricity Electricity purchased from a cogeneration facility should be valued at the default standard 10,000 Btu/kWh unless an actual value is known. The actual value would be the average net heat rate as Btu/kWh calculated by deducting the steam enthalpy value from the energy input, prior to dividing the net heat input by the net electricity output. In all cases, Higher Heating Value (HHV) of the fuel should be used.


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1-8 .c Alternative cogeneration allocation As an alternative to the method shown in 1-8.a and b if specific values are not known for a CHP unit, individual cogeneration unit energy and CO2e emissions can be distributed to steam output and electricity output based on design performance conditions of the specific cogeneration unit. A recommended method is the “CHP Efficiency Method” as provided in the WRI greenhouse Gas Protocol Initiative calculation tool Allocation of Emissions from a Combined Heat and Power (CHP) Plant, located at the following web site: http://www.ghgprotocol.org/calculation-tools/all-tools However, if this method is used, at least the company submissions to ACC for the three years prior to the methodology change should be adjusted to the same basis so that performance trends can be maintained. If a new cogeneration facility comes on line, this alternative allocation method should be used upon startup unless specific data is known. As noted elsewhere, use of the same methodology year to year is critical to maintain an accurate performance trend.

FUEL PRODUCED ON SITE

1-9. Reason for requesting data for on-site produced energy Council member companies are major users of on-site produced energy including combustible byproduct streams. The use of on-site produced energy displaces the purchase of direct fossil fuel energy. If only purchased non-feedstock energy and resultant CO2e emissions were reported, our industry's energy efficiency would be overstated and our CO2e

emissions understated. To correctly report and assess energy efficiency and CO2e emissions trends, on-site produced

energy and its CO2e emissions must also be counted. Therefore, for this purpose, energy and CO2e data aggregated on

Part 2 (Sheet 1) of the survey include both purchased and on-site produced energy, as indicated on Part 2 (Sheet 1) line 6.

1-10. Energy sources to report Fuels produced on-site should include those produced in the process from feedstock energy inputs or non-energy inputs and which are combusted to produce heat and power, generate electricity, etc. The on-site fuels are to include those considered to be byproduct fuels, including byproduct gases, even if low Btu content or if mixed with other fuels. Low-value byproducts which are destroyed in flares or incinerators without heat recovery – that is, not used as fuels – result in combustion CO2e emissions which should be included as Process CO2 on Sheet 2 (item 7.a); the energy associated with those uses should not be reported. Low-value byproducts destroyed in incinerators with heat recovery should be reported on Part 2 (Sheet 1), item 4- Fuel Produced On-site; report energy and CO2 emissions. Appropriate energy conversion factors and CO2e emission factors should be used in the conversion calculations. For reference, a list of approximate

conversion factors based on byproduct fuels generally available provided below.

PART 3 (SHEET 2): EMISSIONS OF GREENHOUSE GASES OTHER THAN CO2 PRODUCED FROM COMBUSTION OF FUELS

2-1. Reason for requesting data on non-combustion CO2e greenhouse gases The 1992 U.N. Framework Convention on Climate Change (UNFCCC, also called “the Rio Convention”), resulted in an agreement that is in force and has been ratified by the U.S. That convention, ongoing international negotiations and domestic U.S. government initiatives are all directed to reducing greenhouse gas emissions, and those include consideration of the basket of six gases. In addition, the EPA GHG Mandatory Reporting Rule requires reporting of the six gases.


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2-2. Rationale for the particular set of gases listed in the survey The gases of particular domestic and international interest are carbon dioxide (CO2, including CO2 other than CO2 produced from combustion of fuels), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride (SF6). These are the gases that are typically included in the GHG “basket of gases”.

2-3. Sources to report; exclusion of “de minimis” quantities We want to follow a rule of reason. We would like members to provide reasonably available data regarding significant emissions sources. We are not interested in “de minimis” quantities. Therefore, there is a single facility deminimis emission level of 5000 Tons per year of CO2 equivalent emissions, with no total company deminimis level. Individual site totals would be summed to provide a single net emission of the six gases on a CO2 equivalent basis.

2-4. Reporting emissions of the manufactured gases (HFCs, PFCs and SF6) already included in the company’s response to survey question 1b. (pounds of production) Part 2 (Sheet 1) requests data on your company’s pounds of production, including pounds of these manufactured gases. Part 3 (Sheet 2) requests data on emissions of these gases, which DOES NOT include production. For example, fugitive emissions of HFCs from equipment would be reported on Part 3 (Sheet 2) if emissions of any listed HFC amount to 5000 tons or more in net CO2 equivalent per single facility. The total value on Part 3 (Sheet 2) is the total of all company sites that each exceeds the 5000 ton net CO2 equivalent emission level.

2-5. Converting emissions of gases other than CO2 to CO2 equivalents The necessary conversion factors have been developed by the Intergovernmental Panel on Climate Change (IPCC). Greenhouse gases vary greatly in their power to trap the earth’s heat. They also vary greatly in the length of time they remain in the atmosphere. Taking both of these factors into account, the IPCC has developed “global warming potentials” for different “time horizons”. The “conversion factors” used in this survey are the IPCC global warming potentials for a 100 year time horizon resulting from the ICPP Fourth Assessment Report. Using these factors, for instance, a ton of methane emitted would be equivalent to 25 tons of CO2. A ton of SF6 emitted is equivalent to 22,800 tons of CO2. The factors used in this survey are the IPCC AR4 factors, which are currently used by the US EPA (78 Fed. Reg. 71904, November 29, 2013) and for individual country reporting. As factors are revised in the future by the IPCC and generally accepted for reporting purposes, they will be incorporated into this survey at the appropriate time.

2-6. Sinks; “removal by sinks” The terms “sinks” and “sequestration” are used loosely to refer to actions and/or processes which remove greenhouse gases from the atmosphere and store them elsewhere. The most common example in the case of CO2 is the function performed by growing trees. The trees remove the gas from the atmosphere (sequester it) and store it as part of the living organism above and below ground. The tree is the sink. Following the tree’s death, the CO2 may continue to be sequestered for many years in remaining sinks such as lumber, other wood products or mass on the forest floor. Other types of sequestration activities (e.g., geologic) should also be included in Part 3 (Sheet 2), item 11.

2-7. Rationale for requesting information on greenhouse gas “removal by sinks Removal of greenhouse gases by sinks reduces net emissions and slows the increase in atmospheric concentrations of greenhouse gases. Potential means of removal of particular interest at this time include three types of direct, human-induced land use change and forestry activities: afforestation, reforestation and deforestation which have taken place since 1990. Other types of sequestration should also be reported. While guidelines have not been established for sinks, information on these activities could prove valuable when quantifying voluntary chemical industry activities.


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2-8. Use of this data on greenhouse gases As always, the confidentiality of individual company data will be rigorously safeguarded by Council staff. Only aggregate data will be compiled and included in the annual report of the survey or any summary document and in the overall Responsible Care metrics. We will be measuring our performance by tracking over time our “greenhouse gas intensity.” This will be expressed as the ratio of ACC member aggregated greenhouse gas emissions to aggregate production (pounds net CO2 equivalent emitted per pound of production).

2-9. Completing Part 3 (Sheet 2) On Part 3 (Sheet 2), data on emissions (not production quantities) of specified greenhouse gases are requested. For the chemical industry as a whole, combustion CO2 is overwhelmingly the most important greenhouse gas. However, the quantity of the other gases emitted is significant for the industry, and emissions of some gases can be important for some individual companies. Respondents should review their respective company’s operations, identify sources (if any) of emissions of the various gases, and assemble the relevant data. Don’t forget the “de minimis” exclusion of small quantities (instruction 2-3 above). Enter the respective quantity of any listed greenhouse gas, in tons, in the left hand column of the appropriate line (7.a. through 7.f.). Convert those tons to CO2 equivalent tons using the conversion factors given on the form, and enter the results in the right hand column of the respective line. Total the entries in the right hand column of lines 7.a. through 7.f. and enter this total in the right hand column of line 8. From Part 2 (Sheet 1), line 6, carry forward to Part 3 (Sheet 2) the total tons of combustion CO2 emissions from nonfeedstock energy and purchased electricity and enter this number in the right hand column of line 9. Add the entries in lines 8 and 9 to obtain the company’s grand total of the specified greenhouse gases expressed in equivalent tons of CO2. Enter this result on line 10. (For those respondents using the spreadsheet in electronic form, Excel will perform all of the above calculations after entry of the physical quantity of each gas.) Enter on line 11 any net data regarding your company’s removal of greenhouse gases by sinks. Report annual equivalent tons of CO2 removed by land use/forestry activities or other sequestration activities instituted since 1990. Determine your Net Total Emissions Less Removals By Sinks by summing lines 10 and 11 and enter the result on line 12.

PART 4 (SHEET 3): MAJOR CHANGES; VOLUNTARY PROGRAMS (this sheet is optional; however, ACC strongly encourages members to provide this information to help explain shifts in ACC member aggregated performance.)

3-1. Major Changes On Part 4 (Sheet 3), please list any major facility or operational changes during the reporting year which substantially affected your company's energy consumption, energy efficiency and/or greenhouse gas emissions. This information is very helpful in assessing the factors underlying year-to-year trends.

3-2. Participation in Voluntary Programs Please also indicate on Part 4 (Sheet 3) the extent of your company's activity in the areas listed. Questions? If you have any questions or believe you need to report additional items, please contact Bradford Johnson at the American Chemistry Council: telephone 202.249.6188; e-mail: [email protected]


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NAICS CODES – NAICS 325 – CHEMICAL MANUFACTURING 325 Chemical Manufacturing 3251 Basic Chemical Manufacturing 32511 Petrochemical Manufacturing 32512 Industrial Gas Manufacturing 32513 Synthetic Dye and Pigment Manufacturing 325131 Inorganic Dye and Pigment Manufacturing 325132 Synthetic Organic Dye and Pigment Manufacturing 32518 Other Basic Inorganic Chemical Manufacturing 325181 Alkalies and Chlorine Manufacturing 325182 Carbon Black Manufacturing 325188 All Other Basic Inorganic Chemical Manufacturing 32519 Other Basic Organic Chemical Manufacturing 325191 Gum and Wood Chemical Manufacturing 325192 Cyclic Crude and Intermediate Manufacturing 325193 Ethyl Alcohol Manufacturing 325199 All Other Basic Organic Chemical Manufacturing 3252 Resin, Synthetic Rubber, and Artificial and Synthetic Fibers and Filaments Manufacturing 32521 Resin and Synthetic Rubber Manufacturing 325211 Plastics Material and Resin Manufacturing 325212 Synthetic Rubber Manufacturing 32522 Artificial and Synthetic Fibers and Filaments Manufacturing 325221 Cellulosic Organic Fiber Manufacturing 325222 Noncellulosic Organic Fiber Manufacturing 3253 Pesticide, Fertilizer, and Other Agricultural Chemical Manufacturing 32531 Fertilizer Manufacturing 325311 Nitrogenous Fertilizer Manufacturing 325312 Phosphatic Fertilizer Manufacturing 325314 Fertilizer (Mixing Only) Manufacturing 32532 Pesticide and Other Agricultural Chemical Manufacturing 3254 Pharmaceutical and Medicine Manufacturing 32541 Pharmaceutical and Medicine Manufacturing 325411 Medicinal and Botanical Manufacturing 325412 Pharmaceutical Preparation Manufacturing 325413 In-Vitro Diagnostic Substance Manufacturing 325414 Biological Product (except Diagnostic) Manufacturing 3255 Paint, Coating, and Adhesive Manufacturing 32551 Paint and Coating Manufacturing 32552 Adhesive Manufacturing 3256 Soap, Cleaning Compound, and Toilet Preparation Manufacturing 32561 Soap and Cleaning Compound Manufacturing 325611 Soap and Other Detergent Manufacturing 325612 Polish and Other Sanitation Good Manufacturing 325613 Surface Active Agent Manufacturing 32562 Toilet Preparation Manufacturing 3259 Other Chemical Product and Preparation Manufacturing 32591 Printing Ink Manufacturing 32592 Explosives Manufacturing 32599 All Other Chemical Product and Preparation Manufacturing 325991 Custom Compounding of Purchased Resins 325992 Photographic Film, Paper, Plate, and Chemical Manufacturing 325998 All Other Miscellaneous Chemical Product and Preparation Manufacturing


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ALTERNATIVE ESTIMATED CO2e EMISSION FACTORS

FUEL TYPE CO2e EMISSION FACTOR,

LB/MMBTU Acetylene 158 Ethanol 151 (includes CH4, N2O) Coal Tar Oil 260 Coke Oven Gas 103 (includes CH4, N2O) Methanol 142 Municipal Solid Waste (MSW) 203 (includes CH4, N2O) Phenol Residue 162 Propane 136 Refuse Derived Fuel (RDF) 231 Toluene 179 Wood 211 (includes CH4, N2O) (Note: CO2e from emissions of CH4 and N2O during combustion are included above as noted where provided in the EPA Mandatory Reporting Rule).

SELECTED BTU CONTENT FUEL BTU/UNIT

Coal Tar Oil 145,000 /gal Coke Oven Tar 34.68 MM / ton Phenol Residue 160,000 /gal


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APPENDIX D - 2013 ENERGY EFFICIENCY AND GREENHOUSE GAS EMISSIONS SURVEY – 4 parts

AMERICAN CHEMISTRY COUNCIL ENERGY EFFICIENCY AND GREENHOUSE GAS EMISSIONS SURVEY RESPONSE FORM

Report Data for Calendar Year 2013 and for NAICS 325 production facilities and facilities which primarily support NAICS 325 production facilities. If submitting data for years other than 2013, insert the correct year in the cell followed by "Calendar Year" at the top of each sheet.

CALENDAR YEAR: 2013 I. ALL RESPONDENTS Please provide the company contact person to whom questions about the survey response can be directed.

NAME:

TITLE:

COMPANY:

PHONE:

E-MAIL:

II. REQUIREMENT FOR ENERGY EFFICIENCY AWARD PROGRAM

Any company wishing to participate in the Energy Efficiency Award Program must complete Sheets 1 & 2 of this Survey and return it to the American Chemistry Council no later than C.O.B. May 31, 2014. In general, "to complete" the survey requires filling out this page and providing the data requested on Sheets 1-3 of the survey. The only exception to this rule is that Small Energy Users as defined above may "complete" the survey simply by filling out and returning this page.

III. Enter your responses online by MAY 31, 2014 at HTTP://METRICS.RESPONSIBLECARETOOLKIT.COM


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Part 2 Enter Your Data in the Yellow Cells. Data will be Automatically Calculated in the Blue Cells.

AMERICAN CHEMISTRY COUNCIL

ENERGY EFFICIENCY & GREENHOUSE GAS EMISSIONS SURVEY

SHEET 1: SALES; PRODUCTION; PURCHASED ELECTRICITY & FUELS PLUS ON-SITE GENERATED FUELS

CALENDAR YEAR: 2013

1a. Total Company US Sales: Dollars, Millions 1b. Total Company US Production: Pounds, Millions

Include exports and intra-company sales & transfers within and out of NAICS 325. Include exports and intra-company transfers.

STANDARD STANDARD

COUNCIL OR COUNCIL

OR

QUANTITY ALTERNATE ALTERNATE CO2

PURCHASED ENERGY ENERGY CO2 EMISSION

AS FUEL/ CONVERSION CONSUMED EMISSION RATE, SHORT

ELECTRICITY UNITSa FACTORS(3)(4) UNITSa MM BTU FACTORS(4) UNITSa TONS/YEAR 2. Nonfeedstock Energy & Feedstock Electricity Purchased 2a. Electricity(feedstock and non feedstock) MMKWH(2) 10,000 BTU/KWH - 115.39 LB/MMBTU

-

2b. Natural Gas MCF

1.026 MMBTU/MCF - 117.1 LB/MMBTU

-

2c. LPG BBL(1)

3.86 MMBTU/BBL - 136.2 LB/MMBTU

-

2d. Distillate Fuel Oil(5) BBL(1) 5.8 MMBTU/BBL - 163.6 LB/MMBTU

-

2e. Residual Fuel Oil(5) BBL(1) 6.3 MMBTU/BBL - 166.1 LB/MMBTU

-

2f. Coal TONS

24.93 MMBTU/TON - 207.3 LB/MMBTU

-

2g. Coke TONS

30.00 MMBTU/TON - 227.4 LB/MMBTU

-

2h. Purchased Steam

MMLB(2) 1,200 BTU/LB -

-

2i. Other Purchased (specify type)

______________

______________

______________

______________

3. Total Purchased Nonfeedstock Energy + Total Electricity -

-

4. Fuel Produced On-site(6)

4a. Subtotal - Gases

4b. Subtotal - Liquids

4c. Subtotal - Solids

5. Total On-site Produced Fuel (gases+liquids+solids) -

-

6. Total Nonfeedstock Energy + Total Electricity (3+5) -

-

(Sum of Purchased and On-site. CO2 total carries forward to Sheet 2, Item 9.)


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Part 3 Enter Your Data in the Yellow Cells. Data will be Automatically Calculated in the Blue Cells.

AMERICAN CHEMISTRY COUNCIL

ENERGY EFFICIENCY AND GREENHOUSE GAS EMISSIONS SURVEY

SHEET 2: NET EMISSIONS OF GREENHOUSE GASES

CALENDAR YEAR: 2013

IPCC/EPA

7.Emissions of greenhouse gases QUANTITY CONVERSION QUANTITY EMITTED/

other than CO2 produced from EMITTED, FACTOR, TONS

CO2 (REMOVED),

combustion of fuels: TONS OF GAS(1) PER TON OF

GAS(2) EQUIVALENT TONS CO2(1)

7.a. Process CO2 1 -

7.b. Methane (CH4) 25 -

7.c. Nitrous Oxide (N2O) 298 -

7.d. HFCs

HFC-23 14,800 -

HFC-32 675 -

HFC-125 3,500 -

HFC-134a 1,430 -

HFC-143a 4,470 -

HFC-152a 124 -

HFC-227ea 3,220 -

HFC-236fa 9,810 -

HFC-4310mee 1,640 -

Other HFCs (3) -

7.e. PFCs (3)

Perfluoromethane (CF4) 7,390 -

Perfluoroethane (C2F6) 12,200 -

C4F10 8,860 -

C6F14 9,300 -

Other PFCs

7.f. Sulfur Hexafluoride (SF6) 22,800 -

8. Total emissions of greenhouse gases other than CO2

produced from combustion of fuels, expressed as tons of

CO2 equivalent: (Sum of items 7.a.- 7.f., inclusive) -

9. Emissions of combustion CO2 from total nonfeedstock

energy: (Carried forward from Sheet 1, Item 6.) -

10. Grand total, emissions of greenhouse gases expressed as

tons of CO2 equivalent: -

11. Net annual removals of greenhouse gas emissions by sinks

resulting from direct human-induced land use change and

forestry activities instituted since 1990: the sum of afforestation

(negative value), reforestation (negative value) and

deforestation (positive value).

12. Net total, emissions of greenhouse gases expressed as tons

of CO2 equivalent, less removals by sinks (Sum of items 10 an 11).

-


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Part 4 American Chemistry Council

ENERGY EFFICIENCY AND GREENHOUSE GAS EMISSIONS SURVEY

SHEET 3: OPTIONAL, SUPPLEMENTARY INFORMATION

CALENDAR YEAR: 2013

I. MAJOR CHANGES THAT MAY HAVE IMPACTED ENERGY & EMISSIONS DATA.

Please check below those major facility or operational changes which occurred since last year's survey and which had a significant effect on your company's energy consumption, energy efficiency and/or greenhouse gas emissions, and which could help to explain large differences in reported energy and emission figures year-to-year. As appropriate, please indicate the number of instances of each item checked i.e., one acquisition, two major expansions, etc. As appropriate, please comment on reported major changes.

TYPE OF MAJOR CHANGE OCCURRED? NUMBER OF

CHECK IF "YES". OCCURRENCES

Facility acquisition

Facility divestiture

Facility major expansion

Facility temporary shutdown

Facility permanent shutdown

Restart of existing facility

Startup of new facility

Cogeneration facility started operation

Initiated steam purchase

Major energy efficiency improvement program

Process change

Other (Please Explain in Comments)

Comments on Major Changes:

II. COMPANY'S VOLUNTARY ACTIVITIES.

Please check below those activities voluntarily undertaken by your company. As appropriate, please comment on reported activities.

TYPE OF VOLUNTARY ACTIVITY UNDERTAKEN?

CHECK IF "YES".

Corporate energy policy?

Goals for energy efficiency improvement?

Plans to meet energy efficiency goals?

Non-energy efficiency measures to reduce combustion CO2 emissions (e.g. fuel switching)?

Inventory and examine greenhouse gas emissions?

Take appropriate and economic measures to reduce ghg emissions?

Participate in DOE or EPA "green programs"?

Additional Activities


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Comments on Voluntary Activities:

SHEET 4: FOOTNOTES PART 2- SHEET 1 (1) 42 US gallons per barrel. (2) Note the specific units - millions of kWh and millions of LB of steam are requested. Note also that the corresponding energy conversion factors are per kWh and per LB of steam. (3) Use higher heating value for all fuels. (4) For typical purchased fuels, use the Council's standard energy and CO2e emission factors. For each atypical purchased fuel, provide the alternate energy conversion and CO2 emission factors. All default CO2e emission factors provided are a composite of CO2, CH4, and N2O combustion related emissions on a CO2 equivalent basis. Any specific alternative factors used should be on a similar basis if factors are available. (5) Distillate fuel oil includes #1 and #2. Residual fuel oil includes crude, #4, #5 and #6. (6) Provide data for the cumulative total Btu and CO2 emissions by type (gases, liquids, solids). A list of approximate factors for some alternate energy sources is included in the instructions. (7) (7) Report total electricity purchases on Sheet 1 with non-feedstock and feedstock electricity on line 2a PART 3- SHEET 2 (1) If one of your individual plant site's estimated emissions of any greenhouse gas listed under question 7 are less than 5,000 tons of CO2 equivalent, you may ignore emissions of that gas for that site for the purposes of this survey. Company total emissions of each gas are to be reported as a single figure. (2) Source: Environmental Protection Agency, 78 Fed. Reg. 71904, November, 29, 2013. Access this publication here: http://www.gpo.gov/fdsys/search/getfrtoc.action?selectedDate=2013-11-29 (3) Conversion factors for some additional greenhouse gases are also given in the publication cited in Note (2). GENERAL (a) M = 1,000; MM = 1,000,000. (b) Provide Btu and CO2e data for all fuel uses including production of heat and power, generation of electricity, incineration, flares and any other combustion sources which emit CO2 to the atmosphere.


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APPENDIX E – Greenhouse Gases and Energy Efficiency FAQ’s

ACC Energy Efficiency and GHG Emissions Survey- Frequently Asked Questions

1. What is the global warming potential (GWP) for Dichlorofluoroethane?

Answer

Dichlorofluoroethane is also known as HCFC-141b. HCFCs are ozone depleting substances and are being phased out under the Montreal Protocol. As such, they are not included under reporting requirements for Global Climate Change purposes. Therefore, emissions of that substance and any other HCFCs (such as HCFC-123) are not to be reported in the ACC survey.

2. What is the global warming potential of R-22, Chlorodifluoromethane?

Answer

R-22 is a HCFC and not reportable on the survey. HCFC-22 is covered by the Copenhagen Amendments to the Montreal Protocol, with a complete phase-out by 2030. Ozone depleting gases (including HCFC-22) covered under the Montreal Protocol and its Amendments are not covered by the FCCC (Framework Convention on Climate Change), not covered by the EPA GHG Mandatory Reporting Rule, and not reportable in the ACC survey.

3. For the energy metric, should we include gasoline and diesel fuel used for plant vehicles? Should the emissions of these vehicles be included in the Green House Gas metric? We also manufacture a biodiesel product which depending on the price of natural gas, we burn in our boilers. Since technically we don't purchase the material, do we need to include it in our Btu count ?

Answer

We have excluded transportation fuels in both the energy and greenhouse gas reporting. Our plans are to continue that exclusion. However, some government programs such as Climate Leaders and the EIA MECS (Manufacturing Energy Consumption Survey) include that data, so if the company/plant site is participating/reporting in those programs, they will need to have that data available for that purpose. MECS excludes highway use for diesel and motor gasoline. The MECS wording for diesel fuel and motor gasoline is: "Include fuel consumed by vehicles intended primarily for use onsite, e.g., forklifts, intra-plant shuttles, loaders and other materials-handling equipment operated solely within the boundaries of the establishment site." There is no problem if submitters want to include in-plant transport fuel use, however, year to year consistency is key. See also Question 20. Biodiesel burned in the plant's boilers would need to be included as on-site generated fuel, including both energy and associated CO2 emissions (see Question 4).


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4. I have a question regarding the biodiesel and greenhouse gas emissions. One of the drivers for Biodiesel is the fact that since it is made from naturally grown crops the net greenhouse gas emissions are 80% less when you count the credit for the soybeans that are grown. What factor should I use for the Biodiesel that we burned in our boilers? The emissions for Fuel oil or fuel oil x 20% (Factor)?

Answer

The EPA GHG Mandatory Reporting Rule requires reporting of biogenic/biomass combustion related GHG emissions. The ACC survey has been modified to accommodate inputs on the quantity, energy input, and GHG emissions from combustion of biogenic/biomass fuels. GHG emissions from biogenic fuel sources will be kept separate from fossil fuel emissions in the member submissions and ACC aggregation of GHG emissions will also maintain separate accounting of fossil fuel emissions vs biogenic/biomass combustion related emissions.

5. Company X burns comparable (non-commercial) fuel in our boilers for energy recovery. Therefore, we need to calculate emission factors for our variable fuel mixture. As an example, in the energy survey instructions, ACC lists an emission factor of 142 lbs CO2 per million Btu for methanol. Our DIPPR data base indicates the heat of combustion for methanol is 8575 Btu per lb or 0.008575 MMBtu/lb. The stoichiometric ratio of CO2 to methanol is 1.375. Why then isn't the methanol emission factor equal to 1.375/0.008575 or 160.35 lb CO2 per MMBtu?

Answer

Data source for methanol was the North American Combustion Handbook, 2nd Edition, Table 2.1b, p.17. That reference gives Gross Heating Value for methanol of 9700 Btu/lb and weight of combustion products of 1.38 lb CO2/lb fuel.

1.38/(9700/1E6)=142 lb CO2/MMBtu We are using Gross or Higher Heating Value (HHV) for all inputs to the survey. It appears the DIPPR results are on a lower heating value basis. For reference, the North American Handbook gives a LHV for methanol of 8400 Btu/lb.

6. From a process a company gets hydrogen as a byproduct. Some of this byproduct they sell to another company (ACC member) which uses it to produce steam. How does the first company report it?


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Answer

a) Report any of the hydrogen consumed on the generating site for energy purposes as a fuel produced on site (Part 2 (Sheet 1), line 4a. Subtotal - Gases).

b) Report the quantity sold as a negative value on Sheet 1, line 2i. (Other Purchased). Do not report it under fuel produced on site since it is not consumed on site. List it as a negative quantity under other purchased, noting it as hydrogen with a zero CO2 emission rate. The hydrogen purchaser should report it on their Sheet 1, line 2.i, Other Purchased, with a zero CO2 emission rate.

7. If we purchase toluene for use as a product solvent, how should that use be reported?

Answer

It depends what happens to the toluene. Options for the questioner to consider: If the toluene becomes a part of the final product stream, it would be considered as a

feedstock (not reportable). If the toluene after being used as a solvent becomes a byproduct/waste/dirty stream that is

sent back to the supplier or someone else for reclamation and subsequent reuse and essentially none is consumed, it would not be reported.

If some of the used solvent is recycled and some consumed, only the consumed portion would be considered as feedstock (not reportable).

If the toluene after use is burned as onsite fuel with heat recovery, it would be reported on Part 2 (Sheet 1) as onsite fuel.

If the toluene after use is sent off site for disposal by combustion as a fuel with heat recovery, it should be reported by the combusting entity (assuming it is an ACC member) on their Part 2 (Sheet 1), line 2.i as Other Purchased energy with appropriate energy content and CO2e emissions. It would not be appropriate for the initial user to report a negative quantity on Part 2 (Sheet 1) since the total incoming toluene quantity is not reported. If the combusting entity is not an ACC member, there is no reporting of that stream.

If the toluene after use is sent off site for disposal by combustion in an incinerator without heat recovery, it would be considered as a feedstock (not reportable) by the initial user and not reported on Part 2 (Sheet 1). If the combusting entity is an ACC member, they would not report the energy use, but would report the CO2 emissions on Sheet 2, 7.a. as Process CO2 emissions. If the combusting entity is not an ACC member, there is no reporting of those emissions.

The purpose is to capture that quantity that is passed on to a downstream use or used/partly used as onsite fuel and not recycled. These approaches would be applicable to any similarly handled fossil energy based stream.

8. In reporting energy sources as feedstock (not reportable), we deduct that portion of the ethane that goes to ethylene, propylene etc. that is sold as an olefin. Do we also deduct the portion of the ethane need that is converted to on-site produced fuel? If not, why? We count this fuel in our energy balance.


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Answer

The methodology used is somewhat aimed at simplicity, not necessarily accuracy.

Energy inputs used to calculate the Btu/$ or Btu/lb trends include that used as fuel or power, specifically, purchased fuels, purchased electricity, and on-site generated fuels. The on-site generated fuels in almost all cases are derived from feedstocks and are byproduct streams otherwise considered as waste. On-site generated and consumed electricity is not added in since that would be double counting energy used to fire the boilers or turbines to generate that power. On-site electricity that is sold should be subtracted from the purchased electricity amount to determine net purchased electricity. Similar approach for on-site generated steam whose energy source is the purchased or onsite generated fuel. However, steam generated from process coolers is not included in the net energy reporting. So basically, in the Btu/lb or Btu/$ calculation, the feedstock energy does not enter the picture except for the byproduct (waste) stream that is used as on-site fuel. This data and calculation is used to determine energy efficiency trends- that is, the long term variation in energy use per unit of production.

Feedstock use data is only used to determine the relative importance of the various input streams and to determine total inputs. This is of value when discussing the relative importance of feedstocks vs energy for heat and power (roughly 50/50 for the chemical industry). The total feedstock inputs figure and ratio to total is also of use whenever energy or carbon taxes are discussed, in that a feedstock exemption is a top priority, and it helps to know what is used and the relative impact of such a tax or fee. Any portion of the feedstock that happens to not be included with the final product but rather happens to wind up as on-site fuel is not important in that analysis. The key point is to just get an exemption for the total quantity entering the process as feedstock, regardless of the yield or ultimate disposition. While it would be more accurate to only count the molecules ending up in the final product, that exercise would require a lot of effort that we do not want to get into, so just keeping total inputs to the process as feedstocks is simpler and easier to use for advocacy.

A portion of ethane that is converted to ethylene or propylene and sold to another company as that intermediate should theoretically be reported as feedstock by that other company (under prior reporting requirements and assuming that all chemical companies reported to ACC). So if that ethane as initial feedstock and the ethylene as another company's feedstock were both reported, that would double count the feedstock. Therefore, the convention is to only report those feedstocks taken in and converted to some product not listed so that there is no double counting. There is an inherent problem with this method when not all companies report, in that some of that feedstock is not accounted for at all. This method is left over from the old CE-189 reporting, when all companies were required to report. But there is no way to determine who is reporting year to year, so we just keep that method in place.

It would probably be more accurate to account for the yield of feedstock energy through the process, but again, that is a level of effort that we should stay away from. In addition, that figure will vary depending on the product, process used, operating rate, etc. Overall it is too detailed and the overall average results would be meaningless or counter-productive anyway.

9. What is the density of coke oven tar?

Answer

204 gallons per ton, or 9.8 lb/gallon.


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10. How would you report "uncombusted methane" which is emitted along with the combustion products? Should this be reported at all? If so, where?

Answer

That sounds like methane VOCs, and as such would be a deminimis quantity and not typically reportable. A large methane quantity above the deminimis quantity (>5,000 tons of CO2 equivalent per plant site) would be reported on Sheet 2, line 7.b. Trace CH4 combustion related emissions are included in the CO2e emission factor where those factors are provided in the EPA GHG Mandatory Reporting Rule.

11. One contact person said their electrolysis process produces hydrogen. They sell it to another company. Where should that be reported?

Answer

Sheet 1, 2i, Other Purchased, as a negative quantity with zero CO2 emissions.

12. A company flares or incinerates low Btu content off gases from processes. How should flares (and incinerators without heat recovery) be accounted for?

Answer

Refer to Footnote 8 for Part 2 (Sheet 1). The following are recommended for flares and incinerators

without heat recovery:

a) Include the fossil fuel used for the flare and incinerator pilot fuel and supplemental fuel on Sheet 1, line 2, including quantity, Btu, and CO2 emissions.

b) Include only the CO2 emissions from the off gas or waste feeds to the flare or incinerator without heat recovery on Sheet 2, line 7.a- Process CO2. Since the waste streams are not used as fuel, they are not included in the energy efficiency metrics, but since there are CO2 emissions, they need to be accounted for as Process CO2.

c) If an incinerator is equipped with heat recovery (e.g., waste heat boiler), the energy from all feed streams (including waste feeds) is utilized and reportable. Report all onsite generated feed streams as fuels on Part 2 (Sheet 1), line 5, including both Btu and CO2 emissions.

13. One member company reports on Sheet 3 (Voluntary Activities) under the 8th item (“green programs”) as follows:

Yes, EPA Landfill Methane Outreach Program at the XXX location. Using landfill gas, according to the EPA "...substantially reduces emissions of methane (a potent greenhouse gas) that would otherwise be released to the atmosphere..." (see Sheet 1, Line 2i). Is this correct?


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Answer

es, that is a legitimate green program and net GHG emissions should be accounted for in Part 2 (Sheet 1), under 2.i for other purchased fuels including CO2 emissions. In addition, if the landfill gas was released directly to the atmosphere prior to use as a fuel, a reduction in methane emissions (negative value) can be entered on Sheet 2, line 7.b.. If the LFG was flared prior to use as fuel, then the methane reduction would not be appropriate. Since the use of LFG would reduce the quantity of natural gas consumed, the quantity of natural gas will decrease, along with the CO2e associated with that natural gas. See below for other options.

14. To account for landfill gas, the company entered on Sheet 1, 2.i, under "other purchased,” "Landfill gas" positive values for MCF, MMBtu and CO2 (at 206 lb/MMBtu). Is this correct?

Answer

The data entries in that location are correct, but the correct CO2 emission rate for landfill gas per the EPA GHG Mandatory Reporting Rule revisions of November 29, 2013 is 114.8 lb/MMBtu. The prior use of natural gas would have decreased from prior years.

15. Following the previous question, the company also listed directly under the positive LFG values, "displaced natural gas" with negative values for MMBtu (same amount as the landfill gas value) and CO2 (at 117.1 lb/MMBtu). Is this correct?

Answer

The response depends on the prior disposition of the LFG in that particular case. The following are legitimate options:

a) Per Question 13 above, if the LFG had been released directly to the atmosphere, a negative value should be applied on Part 3 (Sheet 2), line 7.a for reduced methane emissions and positive Btu and CO2e emission values entered on Part 2 (Sheet 1), line 2.i. In that case, it is not appropriate to also take a negative credit for displaced natural gas that would have otherwise been burned. The quantity of natural gas still burned (if any) would be reported on Part 2 (Sheet 1), line 2.b.

b) However, if the LFG had been flared or otherwise burned without energy recovery, then there is a net reduction in total CO2e emissions from the prior case (natural gas in the boiler CO2e plus LFG CO2e) to the current case (only LFG in the boiler CO2e). The cleanest way to account for the reduction in CO2e is to use a negative value on Part 3 (Sheet 2), line 7.a for CO2e reduced- applying the LFG quantity (as total annual Btu) times 115 lb/MMBtu. The LFG burned in the boiler would still be reported as positive values on Part 2 (Sheet 1), line 2.i for energy and CO2e emissions. The quantity of natural gas still burned (if any) would be reported on Part 2 (Sheet 1), line 2.b.

c) Third option- if the LFG was previously burned for energy recovery, such as in an IC engine for electricity generation, then removing that gas from that service would result in increased electric utility CO2e emissions depending on the energy source used to make up the lost power; so there would essentially be no reduction in CO2e emissions globally overall,


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assuming natural gas as the electric utility incremental generation energy source. In that case, the LFG burned in the boiler would still be reported as positive values on Part 2 (Sheet 1), line 2.i for energy and CO2 emissions. The quantity of natural gas still burned (if any) would be reported on Part 2 (Sheet 1), line 2.b. There would be no negative values.

16. Is there some reason the conversion factor for purchased steam doesn't also include the thermal efficiency of the source boiler and possible line losses?

Answer

Refer to the instructions, #1-8. Boiler efficiency is already included in the 1200 Btu/lb figure. Typical steam generation enthalpy rise from feedwater to steam output can be taken as about 1000 Btu/lb. Using 1200 Btu/lb allows for average boiler efficiency of 83%. Heat loss from a steam transfer line from a third party is unknown, so that is not included in the 1200 number. If a particular site knows their heat loss and specific enthalpy rise as well as boiler efficiency, it is recommended that they use their own conversion factor.

17. A company used an alternate CO2 emission factor for purchased steam of 39.68 (which dropped from 116 in the prior year) with the following logic:

The purchased steam is supplied from an adjacent non-(respondent) co-gen facility. This facility came on line in mid 1997, so the 1997 data contained a blend of (respondent's) use of coal, No. 6 oil, natural gas, and co-gen supplied steam. In 1998, all site steam was supplied by the co-gen plant. The carbon emissions were calculated based on their load factors and on the gas they used in their aux boilers to supply us during off-line periods, and on the aux duct burners which were required to attain the steam production we required when they were on line. When they aren't on line, carbon emissions are totally due to the quantity of natural gas they burn to supply us. When they are on line, most of the BTU's we require can be supplied by their waste heat, with the balance supplied by duct burners. This is why the carbon emissions attributable to steam load have dropped drastically.

Does this seem all right? Should the 39.68 lb factor be used?

Answer

Sounds like they are not following the Instruction #1-8 in the survey. Steam is calculated at full energy input value to the steam considering boiler efficiency, with cogen efficiency benefit calculated for the electricity portion. So the 116 value is likely closer to right for gas fuel in that case. However, if the submitter has another method of allocating energy and CO2 emissions for the cogen facility, they can use that and the resulting factors as long as they are consistent in methodology year-to-year.

18. How would energy and CO2 emissions for potassium carbonate production be done, where a portion of the CO2 is used for the process?


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Answer

If understood correctly, natural gas (assumed purchased) is burned to provide heat for the process, and a portion of the resulting CO2 is injected into the process with the remainder being rejected to atmosphere. Assuming this is correct, the natural gas burned as fuel would be reported on Part 2 (Sheet 1) since it is purchased energy and combusted for process heat. The CO2e emission rate for that gas should be factored down to account for the CO2 injected into the process. For example, if about 40% of the CO2 is used in the process and the rest discharged to atmosphere, then the CO2 emission factor would be 117.1*0.6=70 lb/MMBtu for the gas used in that process.

19. Does the survey mean to include CO2e generated from internal combustion engines that are operated at production facilities? We have stationary IC engines as well as a fleet of vehicles that are refueled at gasoline and diesel fuel pumps located at each facility.

Answer

Fuel used for transportation internal to a plant site or external is excluded from being reported. If there are significant internal combustion engine drives (e.g., stationary engines) in use at a facility for process purposes (e.g., electrical generation, process gas compressors, etc.), the fuel used in those should be reported in the survey. If a common fuel supply is used for both transportation and stationary engine use and only a total quantity utilized is known, there are three choices:

a) Ignore the energy use if it is a small total quantity and do not report it. b) If the stationary use is a significant quantity relative to total site energy use (say >10%?),

then include an educated estimate of the quantity used for stationary sources. c) Report the total quantity without differentiation between end uses if that is easier.

The key is to be consistent in methodology year-to-year.

20. A member company has asked for help ascertaining CO2 and other GHG factors for specific energy sources used to generate electricity: coal, natural gas, hydro, nuclear. The company’s electricity provider has both nuclear and hydro sources and would like to calculate a weighted average CO2 factor for its electricity, which they think would be lower than the default ACC factor. Is there a source of such data available?

Answer

The latest version of the EIA Annual Energy Review gives net generation data and emissions from energy consumption for electricity generation on a national basis. For example, the 2007 AER gives generation data through 2007 and energy consumption data through 2006. Using the 2006 data for both and dividing CO2 emissions for each fuel by net generation gives:


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Coal- 2.147 lb CO2/kwh Petroleum- 2.017 Natural gas- 1.014 These figures appear reasonable. There are zero CO2 emissions associated with hydro and nuclear generated power. The reporter may also be able to get the actual average CO2 emission factor from the electricity supplier or obtain data from the EPA eGRID web site.

21. How should production, energy, and GHG emissions be reported for tolling operations?

Answer

There are at least two ways to approach tolling operation data:

a. If the tolling companies are ACC members, if they report the associated energy and GHG emissions to ACC for the tolled production, they should also report the associated tolled production figures.

b. If the tolling company did not report the energy and GHG emissions to ACC, then the contracting company should get the energy, GHG, and production data from the tollers and report all of that to ACC in aggregate, if it exceeds the deminimis quantities on an individual site basis.

c. If it is likely that the energy use and GHG emissions are less than deminimis, neither the contracting nor tolling companies report since they are each deminimis.

22. Question on Process CO2- CO2 is not produced from a process, but there is a scrubbing system that pulls air across certain tanks that have chlorine emissions. The CO2 from the air would pass through the scrubbing system and be released through one of the permitted emission points. Would this be reportable?

Answer

That is a deminimis stream and does not need to be accounted for. 23. We do not actually produce anything since all of our products are toll manufactured and

we only have an office and laboratory. What production would need to be reported?

Answer

There are probably several ways to approach it:

If the ACC dues basis for the reporting company includes production tolled by the third party, then the production and energy use, GHG emissions, etc., for the reporting entity as well as that of the tolling company associated with the company activities would need to be reported.


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If the contracted company doing the tolling is an ACC member itself and reports its data for activities associated with the questioner’s company, then that would be double reporting, so only one of them should report. This method appears to follow the reporting for the Process Safety Incidents metric on p.7-2 of the RCMDMS Users Guide- where the company that operates the unit where the incident initiated would report.

Most logical option might be to have the company doing the production work under contract (tolling) report. In that case, the questioner would report his energy use and GHG emissions since they are associated with NAICS 325 production, and they would report zero production. The data for the tolling company should also be obtained and reported either separately or combined with the parent contracting company if possible so that more representative overall industry data is obtained.

24. The energy conversion factor for electricity seems extremely high (10,000 Btu/kwh).

How was this figure obtained?

Answer The 10,000 Btu/kwh conversion factor is a standard heat rate that includes the inefficiency of electric utility generation and transmission. When one kwh is used to drive equipment or provide heat, it releases 3413 Btu/kwh. The purpose of using the 10,000 Btu/kwh figure is to account for the mother earth energy use required to provide that kwh. This is also explained in the Instructions, item 13 in the Performance Metrics Guidance Document.

25. Do potential CO2 emissions as a byproduct of aerobic wastewater treatment need to be

included as direct process CO2 emissions?

Answer That is considered deminimis and does not need to be estimated and reported. That source of emissions is not required to be reported under the EPA GHG Mandatory Reporting Rule for facilities in the NAICS 325 sector.

26. If a company has all facilities that are smaller than the deminimis level, do they need to

report anything?

Answer They only need to check the deminimis box and provide respondent information Part 2 (Sheet 1).

27. Should we include nitrous oxide emissions produced from combustion of coal and

natural gas during offsite electricity generation?

Answer Yes. While N2O emissions from fuel combustion are very low, they are required to be reported under the EPA GHG Mandatory Reporting Rule, and the default CO2e emission factors provided in this survey include the equivalent CO2e emission rates for CO2 and both N2O and CH4 based on EPA Subpart C, Table C-2 factors.


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28. One of our plants is a “tenant” of another company and the “host” pays all of the gas

and electricity bills. How do we handle this situation on the survey form?

Answer The tenant is likely paying for their utilities in some manner, even if not for gas and electricity directly. If they are buying steam, for example, they should report purchased steam on Part 2 (Sheet 1), line 2h in MMLbs along with appropriate conversion factors. It is possible that the entity is not buying utilities per se, but they are included with the property or facility lease payments. In that case, if the quantities used are known or can be estimated, they should be reported. If the quantities are simply not available, they can be ignored. The facility should be sure to compare against the small user exemption to be sure they need to be reporting in the first place.

29. A process uses coal as a raw material, with a portion converted to final product and the

balance combusted in-process to generate heat and eventually evolves as CO2. How should the consumed portion be reported?

Answer The portion of coal combusted with energy recovery and the associated CO2e emissions should be listed under the appropriate line on Part 2 (Sheet 1), line 4a, 4b, or 4c if gaseous, liquid, or solid form as combusted. The key to the line to use is the physical form of the stream as it is combusted (likely gaseous as syngas in this case). If some of the coal is fed as coal directly into a combustion unit like a boiler with some fed into a process, the portion fed to the boiler would be listed on Part 2 (Sheet 1), line 2g.

30. How are facility and product boundaries handled, especially under pounds of

production? For example, does production include ethylene produced at a site even if all of the ethylene is converted to polyethylene and then shipped as product?

Answer In general, intermediates should be included as production as well as the final plant product. That way, if in the future any of the intermediate (ethylene in this case) is sold outside the company, then the total production figure is consistent. If there is no way to quantify the intermediate steam and there is no way to sell any of it, reporting final production only is acceptable. Consistency year-to-year is the critical issue.

31. What is the density of diesel fuel used in lieu of natural gas?

Answer Use 7.1 lb/gal. Diesel fuel or distillate fuel oil is routinely used as backup fuel to natural gas during times when natural gas is not available. Diesel and distillate fuels are very similar in density with the main difference being lower sulfur in diesel fuel.


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32. Is there any guidance for calculating “sinks” for agricultural crops or trees?

Answer ACC does not have guidance available at this time for estimating sequestration impact. Refer to the IPCC web site, the EPA website, or EIA 1605(b) for further guidance.

33. Our company reports annually through other entities that use slightly different CO2 conversion factors. Must we use the ACC default conversion factors?

Answer No, the reporter can use more representative conversion factors and input those in the spreadsheet or online form in place of the ACC default conversion factors. ACC started internal reporting of greenhouse gases in the late 1980s, with initial focus on CO2 from combustion. This pre-dated DOE and 1605(b) reporting and other reporting systems. At that time, CO2 emissions were calculated from typical pipeline natural gas and other typical fuels and those values were used, e.g., 116 lb/MMBtu for natural gas. Since that time, other conventions have come into play.. The survey default factor for natural gas is 117.1 lb/MMBtu based on the EPA GHG Mandatory Reporting Rule factors, including the CO2e emission rates for N2O and CH4 from combustion of those fuels where applicable.

34. Our company uses large quantities of electricity to compress air which is the basic material in our process. Should this electricity be considered feedstock electricity?

Answer No. The only electricity use considered “feedstock” is direct use in electrolysis processes.

35. We have waste heat boilers where hot gas streams heat water in the boilers to produce steam. Should that be accounted for as an onsite fuel?

Answer No. Refer to instructions 1-6 and 1-7. Steam produced in waste heat boilers (process stream coolers) that is used on site is not reported in the survey. Only if that steam is sold to another company is that quantity reported as a negative energy quantity with no CO2 emissions. The source of the energy recovered in that waste heat boiler/steam is typically derived from feedstock energy, data which was included in the survey in past years but no longer required. Increased waste heat recovery would be reflected as decreased fossil fuel input for fuel, so it is indirectly reflected in the industry/company performance. Increased waste heat might also be indicative of lower yields, so that as the production goes down, energy efficiency performance (Btu/lb) suffers. For clarity, fuel produced on site refers to gaseous, liquid, or solid fuels that are combusted on site for heat and power (they are typically derived from feedstock energy).


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36. Electricity at the plant is used for chlor-alkali production, so it would be considered “feedstock” electricity. The electricity is provided with a gas fired cogeneration unit on site. How would electricity sold to another entity be listed- negative feedstock electricity?

Answer • Chlor alkali processes typically do use electrolysis, so purchased electricity for that use would be

considered feedstock electricity. • If natural gas is burned in a cogen unit to generate power that is then used in that chlor-alkali

process, technically that gas use could be considered at least partially feedstock. But since some portion of electricity is sold and the gas is really used first as fuel, then reporting the gas as fuel and power and not as feedstock is appropriate.

• The portion of electricity that is sold is not used for electrolysis (feedstock) purposes, but it is a negative quantity relative to reporting.

• Since we do not any longer gather feedstock energy other than for electricity and we would want to include both the gas use and associated CO2 emissions, include the cogen gas use as non-feedstock energy on Part 2 (Sheet 1), item 2b.

• Electricity generated with the cogen unit and used for chlor-alkali production would be feedstock electricity but would not be separately reported since that would be double counting with the gas.

• Excess electricity sold should be reported as a negative non-feedstock electricity value on Part 2 (Sheet 1), item 2a-1, since its ultimate use is not for feedstock use. So as far as the reporting entity is concerned, there is no feedstock energy reportable in this case; but since all electricity is treated equally anyway, that is okay.

37. How is production reported when multiple facilities in a company sequentially use intermediate products from the other facilities?

Answer Refer to instruction 1-2. When intermediate products are manufactured at a plant site and then shipped to another site for further processing, it is typically easier to simply add the production from each site even though there is double counting instead of trying to account for the production process impact on the pounds. This methodology also makes it more consistent when some of the product from an upstream site may be sold to another entity and not be used at an internal company downstream facility, and that sales portion can vary year to year. This approach is explained somewhat in the survey instruction 1-2. The key point is consistency year to year so that trends are available on a consistent basis.

38. How should Joint Venture (JV) arrangements and associated data be reported? Answer Reporting for the Energy Efficiency and GHG Emissions Survey is on the same basis as ACC dues determination for individual companies. That basis covers only wholly owned entities/facilities associated with NAICS 325 production. JV facilities and their data are not to be reported. If ownership changes from one year to the next, simply report data for the wholly owned facilities starting with the first full year of ownership for a newly owned facility, and drop data in the year the facility became a part of a JV.


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APPENDIX F – FORM 5800 REGULATORY DEFINITION Sec. 171.16 Detailed hazardous materials incident reports.

TITLE 49 - TRANSPORTATION SUBTITLE B - OTHER REGULATIONS RELATING TO TRANSPORTATION CHAPTER I - PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION, DEPARTMENT OF TRANSPORTATION SUBCHAPTER C - HAZARDOUS MATERIALS REGULATIONS PART 171 - GENERAL INFORMATION, REGULATIONS, AND DEFINITIONS

(A) General. Each person in physical possession of a hazardous material at the time that any of the following incidents occurs during transportation (including loading, unloading, and temporary storage) must submit a Hazardous Materials Incident Report on DOT Form F 5800.1 (01/2004) within 30 days of discovery of the incident:

(1) Any of the circumstances set forth in 171.15(b);

171.15(b) (b) Reportable incident. A telephone report is required whenever any of the following occurs

during the course of transportation in commerce (including loading, unloading, and temporary storage): (1) As a direct result of a hazardous material (i) A person is killed; (ii) A person receives an injury requiring admittance to a hospital; (iii) The general public is evacuated for one hour or more; (iv) A major transportation artery or facility is closed or shut down for one hour or more; or (v) The operational flight pattern or routine of an aircraft is altered; (2) Fire, breakage, spillage, or suspected radioactive contamination occurs involving a radioactive material (see also 176.48 of this subchapter); (3) Fire, breakage, spillage, or suspected contamination occurs involving an infectious substance other than a diagnostic specimen or regulated medical waste; (4) A release of a marine pollutant occurs in a quantity exceeding 450 L (119 gallons) for a liquid or 400 kg (882 pounds) for a solid; or (5) A situation exists of such a nature (e.g., a continuing danger to life exists at the scene of the incident) that, in the judgment of the person in possession of the hazardous material, it should be reported to the NRC even though it does not meet the criteria of paragraph (b) (1), (2), (3) or (4) of this section.

(2) An unintentional release of a hazardous material or the discharge of any quantity of hazardous waste;

(3) A specification cargo tank with a capacity of 1,000 gallons or greater containing any hazardous material suffers structural damage to the lading retention system or damage that requires repair to a system intended to protect the lading retention system, even if there is no release of hazardous material; or

(4) An undeclared hazardous material is discovered.

Documents

Performance Metrics Guidance Document 2014 · Guidance Background In 2002, the American Chemistry Council (ACC) enhanced the Responsible Care program by requiring the public reporting