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How the New Subpart Ja Regulations will Affect Your Refinery

Jess McAngus, P.E. – Spirit Environmental, LLC

Joseph F. Guida ‐ Guida, Slavich & Flores P.C.

The New Source Performance Standards ("NSPS") for Petroleum Refineries, Subpart J, 40 C.F.R.

60.100 were recently revised and new NSPS standards for Petroleum Refineries, Subpart Ja, 40

C.F.R. 60.100a, for which construction, reconstruction, or modification commenced after May

14, 2007 were promulgated on June 24, 20081.

Background and Legal Status

The background for the development of the regulations is as follows:

1. EPA was required to perform a review of NSPS Subpart J rules pursuant to a consent

decree: Our Children’s Earth Foundation v. EPA, No. C 05‐00094 CW (N.D. Cal. decree entered

October 31, 2005).

EPA was required by the Consent Decree to finalize NSPS Subpart J revisions by April 30,

2008

EPA proposed amendments to NSPS Subpart J and proposed new Subpart Ja on May 14, 2007 (72 Fed. Reg. 27278); extended public comment period.

2. Revisions to Subpart J and promulgation of new NSPS Subpart Ja were signed by the EPA

Administrator on April 30, 2008.

3. On June 9, 2008 EPA Administrator issued a memorandum on “Inadvertent Errors in the

Final Amendments to the New Source Performance Standards for Petroleum Refineries (NSPS

Subpart J) and the Newly Promulgated New Source Performance Standards for Petroleum

Refineries (NSPS Subpart Ja)”, (Attachment #1).

1 Federal Register, 73 FR 35838, June 24, 2008.

EPA acknowledges an error in establishing applicability date for flare gas minimization

requirements that were not included in the original proposed rule.

Because of EPA’s error, flares that would not have been affected sources under the

proposed rule would be subject to the new Subpart Ja requirements as of the date of

the proposal, (May 14, 2007). EPA chose to fix this problem by altering the final rule to

provide that only flares commencing construction, reconstruction, or modification after

the date of promulgation of the final rule would be subject to the new Subpart Ja

requirements.

To avoid a “gap” in coverage, EPA, however, elected to change the amended Subpart J

requirements (after issuance) so that flares that were new, modified, or reconstructed

between the proposal date and the final date would be subject to fuel gas combustion

unit standards in Subpart J rather than no requirements at all.

EPA also acknowledged a second error:

Under the final NSPS Subpart Ja requirements, venting additional streams of

combustible gases into an existing flare system for safety reasons or physically altering

flare to increase flow capacity would make the existing flare system a “modified”

source. (This is a particularly controversial change for industry because EPA has not

predicated the definition a flare modification on an increase in emission rate as is

generally necessary for applicability of NSPSs. See 40 C.F.R. §60.14(a), (Attachment #2).

There also are statutory issues with this definition. See 42 U.S.C. §7411(a)(4),

(Attachment #3).

Therefore, such existing flare system would be immediately subject to the Subpart Ja

flare requirements at startup. EPA acknowledges that delaying such venting to allow

time for compliance with the new flare gas minimization requirements could result in

unsafe operating conditions.

In addition, for cost‐effectiveness reasons, immediate upgrades to meet the new flare

gas minimization requirements would not be Best Demonstrated Technology (“BDT”).

Consequently, EPA chose to alter the final rule (after issuance) to allow for sequencing

compliance for modified flares after June 24, 2008.

New and reconstructed flares after June 24, 2008, however, are required to comply

upon start‐up.

Affected flares must comply with the final hydrogen sulfide (“H2S”) limitations

immediately upon startup with all other flare minimization requirements within one (1)

year of startup.

With the June 9, 2008 memorandum, EPA also included redline text of the rule to show

the post‐issuance revisions, (Attachment #4).

4. EPA subsequently published a 60‐day stay for implementation of Subpart Ja on the

grounds that the effective date published in the June 24, 2008 Federal Register was

“incorrect”.

Subpart Ja is a “major rule” under the Congressional Review Act (“CRA”) meaning that it

will or will likely result in: 1) an annual effect on the economy of $100,000,000 or more;

2) a major increase in costs or prices for consumers, individual industries, Federal, State,

or local government agencies, or geographic regions; or 3) significant adverse effects on

competition, employment, investment, productivity, innovation, or on the ability of

United States‐based enterprises to compete with foreign‐based enterprises in domestic

and export markets. (5 USC 804(2)).

Section 801 of the CRA precludes a “major rule” from taking effect until the later of 60

days after the date of publication in the Federal Register or 60 days after each House of

Congress and the Comptroller General receive a copy of a rule report.

EPA published the stay in the July 28, 2008 Federal Register2, (Attachment #5).

Effective Date of Subpart Ja stayed until September 26, 2008.

The stay does not affect the amendments to Subpart J.

2 Federal Register, 73 FR 43626, July 28, 2008.

In a Petition for Reconsideration, NPRA and API requested an additional 90‐day stay

after the conclusion of EPA’s 60‐day stay.

5. Industry Response

NPRA Petition for Reconsideration: According to NPRA, the API/NPRA NSPS Workgroup has commenced meetings with EPA staff during July 2008 in an effort to resolve the major issues (namely the flaring modification and process heater NOx limits) within the time period defined by the stays.

Petitions for Review—Various parties may file petitions for review in the D.C. Circuit. We will update this topic at the NPRA presentation.

Affected Facilities for Refineries

The NSPS Subpart J and Subpart Ja Regulations apply only to “affected facilities” as defined in

the regulations. The definition of an affected facility is important and one must review each

process unit to determine if a unit is grandfathered (not subject to NSPS subpart J or Ja), subject

to Subpart J or subject to Subpart Ja.

The Subpart J affected facilities and effective dates include:

1. Fluid Catalytic Cracking Unit Catalyst Regenerator – January 17, 1984 to May 13, 2007;

2. Fuel Gas Combustion Devices (except flares) – June 11, 1973 to May 13, 2007;

3. Flares – June 11, 1973 to June 23, 2008; and

4. Claus Sulfur Recovery Plants (Design Capacity >20 long tons per day) – October 4, 1976

to May 13, 2007.

The Subpart Ja affected facilities include:

1. Fluid Catalytic Cracking Units – after May 14, 2007;

2. Fluid Coking Units – after May 14, 2007;

3. Delayed Coking Units – after May 14, 2007;

4. Fuel Gas Combustion Devices (except flares) – after May 14, 2007;

5. Flares – after June 24, 2008; and

6. Sulfur Recovery Plants (any size) – after May 14, 2007.

The significant changes between the Subpart J and Subpart Ja affected facilities include two

new process units: Fluid Coking Units (“FCU”); and Delayed Coking Units (“DCU”). In addition,

instead of just Claus‐Sulfur Recovery Units (“SRU”); the Subpart Ja affected facilities include any

type of SRU (whether Claus‐type or not) and any design capacity of SRU.

Subpart J Revisions

EPA made only a limited number of significant changes to the existing Subpart J regulations.

First, EPA modified the definition of “fuel gas” to exclude vapors that are collected and

combusted in an air pollution control device installed to comply with a wastewater3 or marine

vessel loading4 emission standard.

Second, EPA finalized exemptions for certain fuel gas streams from all continuous monitoring

requirements, including process upset gases, flaring of relief valve leakage, emergency

malfunctions, and inherently low sulfur fuel gas streams, (pilot gas , commercial grade product

{>30 ppm sulfur}, gases produced by: Hydrogen Plant; Catalytic Reforming Unit; Isomerization

Unit; and HF Alkylation). A refiner can exempt other inherently low sulfur fuel gas streams by

submitting an application to EPA. The effected date of the exemption is the date of submission

of the application to EPA5.

EPA had proposed to amend the definition of “Claus sulfur recovery plant” to clarify that the

SRP may consist of multiple units and that the primary sulfur pits are considered part of the

Claus SRP. EPA decided not to include this change in the Subpart J revisions but expressed in

the preamble that this change in definition is and has been EPA’s interpretation.

Refiners should be aware that future EPA inspections may look to see if smaller SRPs (<20 LTD)

use a common source of sour gas. EPA explains in the new Subpart Ja regulations that if a

multiple SRUs are fed from a common source of sour gas they are to be considered as one SRU.

3 40 C.F.R. 60.692; 40 C.F.R. 61.343 through 61.348; or 40 C.F.R. 63.647. 4 40 C.F.R. 63.651; or 40 C.F.R. 63.652. 5 40 C.F.R. 60.105(b)(2).

Third, EPA makes several (16) technical corrections (spelling, references, units, etc.) to the

Subpart J regulations.

Also, note that the revised Subpart J regulations are not included in the 60‐day stay and were

effective on date of proposal, May 14, 2007.

Subpart Ja Regulations

As referenced earlier, the NSPS regulations for refineries were required to be reviewed because

of a lawsuit settlement. Because of the extensive changes in the regulations and changes in

definitions, EPA was required to develop a new set of regulations that apply to new refineries

and modified or reconstructed refineries. EPA proposed the new regulations on May 14, 2007.

The public was invited to comment on the regulations and a total of 46 comments were

submitted. A complete list of comments submitted and materials EPA used in the preparation

of the regulations can be found in the Docket ID EPA‐HQ‐OAR‐2007‐00116. A table of contents

of the Docket is included as Attachment #6 to this paper.

The next section of this paper will summarize the new Subpart Ja regulations, 40 C.F.R. 60.100a

– 109a. Please note that NSPS regulations are effective on the date of proposal (May 14, 2007)

not on the date of promulgation (June 24, 2008). Where EPA has made revisions since the

proposal date, the effective date is generally the date of promulgation. These differences will

be highlighted in the paper.

Affected Facilities

As described earlier, the new Subpart Ja regulations include additional units as affected

facilities. The list of Subpart Ja affected facilities includes:

1. Fluid Catalytic Cracking Units – after May 14, 2007;

2. Fluid Coking Units – after May 14, 2007;

3. Delayed Coking Units – after May 14, 2007;

6 http://www.regulations.gov/fdmspublic/component/main?main=DocketDetail&d=EPA‐HQ‐OAR‐2007‐0011

4. Fuel Gas Combustion Devices (except flares) – after May 14, 2007;

5. Flares – after June 24, 2008; and

6. Sulfur Recovery Plants – after May 14, 2007.

The new affected facilities include the Fluid Coking Unit, the Delayed Coking Unit, and Sulfur

Recovery Plants less than 20 LTD. Note, there are also slight differences in the definition of

units that may have a significant bearing on your refinery. For Fluid Catalytic Cracking Units

(“FCCU”), EPA has added that if 2 FCCU share a common exhaust treatment (e.g., CO Boiler or

wet scrubber) the FCCU is a single affected facility.

EPA changed the definition of “Petroleum Refinery” in Subpart Ja to include producing asphalt

(bitumen). This change is not expected to have a significant impact on the number of affected

Petroleum Refineries.

EPA deleted the definition of Claus Sulfur Recovery Plant and substituted Sulfur Recovery Plant

(“SRP”). The definition of SRP now includes all types of SRPs and also includes in the definition

the primary sulfur pits. EPA also makes the clarification that SRPs that receive sour gas from

the same source are a single affected facility. EPA claims in the preamble that this has been

EPA’s interpretation all along; however, I suspect many refiners share a different opinion.

Flare Modification

A very significant change in the definition of modification for flares is included as a new section

40 C.F.R. 60.100a (c)(1) and (c)(2). EPA defines that a modification of a flare occurs if:

1. Any new piping from a refinery process unit or fuel gas system is physically connected to

the flare (e.g., for direct emergency relief or some form of continuous or intermittent

venting); or

2. A flare is physically altered to increase the flow capacity of the flare.

This change suggests that any change that a refiner makes to a flare system (note: that a flare is

now defined to include the piping and header system) will cause the flare to become subject to

the Subpart Ja regulations. EPA does grant a 1‐year delay of the affected date for flares if they

become modified.

EPA has also recently issued an applicability determination7 that determines that “Combusting

gas streams not previously combusted in the flare is a change in how the flare operates,

whether these streams are routed on a routine basis or on an intermittent basis”, (Attachment

#7). The determination suggests that any new stream added to a flare is a change in operation

that would result in an increase in emissions.

Reconstruction Cost

Under the Subpart J regulations, the reconstruction cost analysis was based on the capital cost

following January 17, 1984. For the Subpart Ja regulations, the reconstruction cost analysis

(required by 40 C.F.R. 60.15) is now based upon any two‐year period following May 14, 2007.

Definitions

EPA has made a few critical changes or additions to the definition of several terms including:

Fuel Gas;

Flare; and

Process Upset Gas.

First, as with the Subpart J revisions, EPA modified the definition of “fuel gas” to exclude

vapors that are collected and combusted in an air pollution control device installed to comply

with a wastewater or marine vessel loading emission standard. Fuel gas also does not include

gases from FCCU or FCU but does include gases from Flexicoking Unit Gasifiers.

Second, EPA has added the definition of a flare and defines a flare as:

“an open‐flame fuel gas combustion device for burning off unwanted gas or flammable gas and

liquids. The flare includes the foundations, flare tip, structural support, burner, igniter, flare

controls including air injection or steam injections systems, flame arrestors, knockout pots,

piping and header systems.”

Note, that the flare definition includes “piping and header systems”. This important addition

will cause flares to become modified more easily as was described earlier regarding flare

modifications.

7 Gigliello, Ken, EPA letter to Domike, Julie, Wallace, King, Domike, & Branson, April 10, 2008.

Third, the definition of process upset gas has been modified. The Subpart J definition of

process upset gas included “gas generated by a petroleum refinery process unit as a result of

start‐up, shut‐down, upset or malfunction”. The new Subpart Ja definition of process upset gas

is: “any gas generated by a petroleum refinery process unit as a result of upset or malfunction”.

Note that the gases generated by start‐ups or shut‐downs are no longer included. This is

especially important for flares as the flaring of process upset gases are exempt from the SO2

emission limits8.

Emission Limits

Shown on Table 1 is a summary of the Subpart Ja emission limits for new affected facilities.

Shown on Table 2 is the summary of Subpart Ja emission limits for modified or reconstructed

facilities. Rather that discuss each emission limit separately, we will discuss the new

requirements that either differ from Subpart J regulations or are new requirements.

Fuel Gas Combustion Units

The Subpart Ja regulation keep the same short‐term (3‐hour rolling average) SO2 limits (20 ppm

SO2 or 162 ppm H2S). The new regulations however add a long‐term (365‐day rolling average)

of 8 ppm SO2 or 60 ppm H2S. Note that these requirements apply to heaters, boilers, and

flares. The Subpart Ja regulations add short‐term NOX limits for process heaters only. The new

short‐term (24‐hour rolling average) NOX limit is 40 ppm and applies to only process heaters

with a rated capacity of 40 million BTU per hour (“MMBTU/hr”) or higher.

Fluid Catalytic Cracking Units

The FCCU Subpart J regulation for short‐term SO2 was for one of three options:

1. 50 ppm, 7‐day or 90% reduction;

2. Pretreat FCCU feed to 0.3 weight % sulfur; or

3. 9.8 lb‐SO2 per 1,000 pounds of coke burned (lb‐SO2/M‐lb coke burn).

8 40 C.F.R. 60.140(a)(1).

Table 1 Summary of Refinery NSPS Subpart Ja Regulations – New Sources

Issue New Sources

Existing J Standard Proposed Ja Standard Final Ja Standard

Fuel Gas Combustion Device (Heater/Boiler/Flare)

Sulfur Fuel ‐ annual No Standard 8 ppm ‐ SO2 8 ppm SO2 or 60 ppm H2S

Sulfur Fuel ‐ 3‐hour 160 ppm H2S 20 ppm ‐ SO2 20 ppm SO2 or 162 ppm H2S

NOX ‐ 7‐day (Process Heater) No Standard 80 ppm, >20 MMBTU/hr 40 ppm, >40 MMBTU/hr

SO2 Releases No Standard No Standard RCA (>500 lb‐SO2/day)

FCCU

SO2 ‐ 365‐day No Standard 25 ppm 25 ppm

SO2 ‐ short term, 7‐day 1. 50 ppm, 7‐day avg or 90% reduction; 50 ppm, 7‐day 50 ppm, 7‐day

2. Pretreat feed to 0.3 wt.% S

3. Limit emissions to 9.8 lb‐SO2/M‐lb coke burn

NOX ‐ annual No Standard No Standard No Standard

NOX ‐ short term ‐ 7‐day No Standard 80 ppm 80 ppm

CO ‐ 1‐hour 500 ppm 500 ppm 500 ppm

PM 1.0 lb‐PM/ M‐lb coke burn 0.5 lb‐PM(M5)/ M‐lb coke burn 0.5 lb‐PM(M5B or 5F)/ M‐lb coke burn

Opacity 30% No Limit No Limit

Fluid Coking Unit

SO2 No Standard Same as FCCU Same as FCCU


CO ‐ 1‐hour No Standard 500 ppm 500 ppm

PM No Standard 0.5 lb‐PM(M5)/ M‐lb coke 1.0 lb‐PM(M5B)/ M‐lb coke

Opacity No Standard No Standard No Standard

Sulfur Recovery Plant

SRP ‐ SO2 Release No Standard No Standard RCA (>500 lb‐SO2/day)

Large SRP (>20LTD), with oxidation >20 LTPD, 99.9%, 250 ppm SO2 >20 LTPD, 99.9%, 250 ppm SO2 >20 LTPD, 99.9%, 250 ppm SO2

Large SRP (>20LTD), with reduction >20 LTPD, 99.9%, 300 ppm TRS, 10 ppm H2S >20 LTPD, 99.9%, 300 ppm TRS, 10 ppm H2S >20 LTPD, 99.9%, 300 ppm TRS, 10 ppm H2S

Small SRP (<20LTD), with oxidation No Standard < 20 LTPD 99.0%, 2,500 ppm SO2 < 20 LTPD 99.0%, 2,500 ppm SO2

Small SRP (<20LTD), with reduction No Standard < 20 LTPD 99.0%, 3,000 ppm TRS, 100 ppm H2S < 20 LTPD 99.0%, 3,000 ppm TRS, 100 ppm H2S

Delayed Coking Unit

SO2 and VOC No Standard Depressure to 5 psig to fuel gas system Depressure to 5 psig

Flare Gas Minimization

Flow No Standard No routine flaring Flow < 250,000 SCFD, 30‐day, minimize startup shutdown emissions

SO2, NOX, VOC No Standard No routine flaring, SSM plan and RCA (>500 lb/day)

Flare minimization plan, RCA (>500 lb/day)

Table 2 Summary of Refinery NSPS Subpart Ja Regulations – Modified and Reconstructed Sources

Issue Modified and Reconstructed Sources

Existing Standard Proposed Standard Final Standard

Fuel Gas Combustion Device (Heater/Boiler/Flare)

Sulfur Fuel ‐ annual N/A 8 ppm ‐ SO2 8 ppm SO2 or 60 ppm H2S

Sulfur Fuel ‐ 3‐hour 160 ppm H2S 20 ppm ‐ SO2 20 ppm SO2 162 ppm H2S

NOX ‐ 7‐day (Process Heater) No Standard 80 ppm, >20 MMBTU/hr 40 ppm, >40 MMBTU/hr

SO2 Releases No Standard No Standard RCA (>500 lb‐SO2/day)

FCCU

SO2 ‐ annual No Standard 25 ppm 25 ppm

SO2 ‐ short term ‐ 7‐day 1. 50 ppm, 7‐day avg or 90% reduction; 50 ppm, 7‐day 50 ppm, 7‐day

2. Pretreat feed to 0.3 wt.% S

3. Limit emissions to 9.8 lb‐SO2/M‐lb coke burn

NOX ‐ annual No Standard No Standard No Standard


CO ‐ 1‐hour 500 ppm 500 ppm 500 ppm

PM 1.0 lb‐PM/ M‐lb coke 0.5 lb‐PM(M5)/ M‐lb coke 1.0 lb‐PM (M5B or F)/ M‐lb coke burn

Opacity 30% No Limit No Limit

Fluid Coking Unit

SO2 No Standard Same as FCCU Same as FCCU


CO ‐ 1‐hour No Standard 500 ppm 500 ppm

PM No Standard 0.5 lb‐PM(M5)/ M‐lb coke 1.0 lb‐PM(M5B)/ M‐lb coke

Opacity No Standard No Standard No Standard


SRP ‐ SO2 Release No Standard No Standard RCA (>500 lb‐SO2/day)

Large SRP (>20LTD), with oxidation >20 LTPD, 99.9%, 250 ppm SO2 >20 LTPD, 99.9%, 250 ppm SO2 >20 LTPD, 99.9%, 250 ppm SO2

Large SRP (>20LTD), with reduction >20 LTPD, 99.9%, 300 ppm TRS, 10 ppm H2S >20 LTPD, 99.9%, 300 ppm TRS, 10 ppm H2S >20 LTPD, 99.9%, 300 ppm TRS, 10 ppm H2S

Small SRP (<20LTD), with oxidation No Standard < 20 LTPD 99.0%, 2,500 ppm SO2 < 20 LTPD 99.0%, 2,500 ppm SO2

Small SRP (<20LTD), with reduction No Standard < 20 LTPD 99.0%, 3,000 ppm TRS, 100 ppm H2S < 20 LTPD 99.0%, 3,000 ppm TRS, 100 ppm H2S

Delayed Coking Unit

SO2 and VOC No Standard Depressure to 5 psig to fuel gas system Depressure to 5 psig

Flare Gas Minimization

Flow No Standard No routine flaring Flow < 250,000 SCFD, 30‐day, minimize startup shutdown emissions

SO2, NOX, VOC No Standard No routine flaring, SSM plan and RCA (>500 lb/day)

Flare minimization plan, RCA (>500 lb/day)

The new short‐term SO2 limit is only the 50 ppm9 (7‐day rolling average). The new regulations

have added a long‐term SO2 limit of 25 ppm (365‐day rolling average). The regulations have

also added a short‐term NOX limit of 80 ppm (7‐day rolling average). The short‐term CO limit of

500 ppm (1‐hour rolling average) remains the same. The short‐term particulate limit for new

sources has been lowered to 0.5 lb‐PM/M‐lb coke burn (0.020 grains per dry standard cubic

foot [“gr/dscf”] if using a CEMs). The limit for modified or reconstructed sources remains at 1.0

lb‐PM/M‐lb coke burn, (0.040 gr/dscf if using a CEMs).

Both of the Subpart Ja PM limits allow the use of either Method 5B or Method 5F. These

methods do not included the condensable PM fraction that is measured in Method 5. EPA had

originally proposed requiring the use of Method 5, however after numerous adverse comments

about the use of Method 5, EPA changed the requirement to either Method 5B or 5F. EPA has

indicated that it intends to perform more work to analyze Method 5 and also Method 202. The

suggestion is that in the future EPA will revise the PM standard to include the condensable

fraction.

One change in the method of calculating the PM emissions is the coke burn equation. EPA has

added a term to account for any oxygen enrichment used in the FCCU. EPA had previously not

accounted for the added enrichment oxygen in the coke burn equation. The coke burn

equations in Subpart J and Subpart Ja are now equivalent to the equations used in the Refinery

MACT regulations.

Fluid Coking Unit

EPA has added a new process unit emission limit for Fluid Coking Units (“FCU”). The emission

limits are similar to the FCCU limits. The SO2 emission limits are identical (i.e., 25 ppm 365‐day

rolling average and 50 ppm 7‐day rolling average). The NOX emissions limit, (80 ppm 7‐day

rolling average) and CO limit (500 ppm 1‐hour rolling average) are also identical to the FCCU

limits. The PM emission limit for new and for modified or reconstructed FCU is 1.0 lb‐PM/M‐lb

coke burn. There are no FCU standards for opacity.

9 All SO2, NOX, CO, H2S, and reduced sulfur emission limits are each corrected to a dry, 0% excess air (by volume). PM is corrected to 0% excess air.


As mentioned previously, EPA has modified the definition of SRP to include non‐Claus SRP and

to include all capacities of SRP. In addition, all SRPs that share the same source of sour gas are

accumulated to determine whether the greater than 20 long ton per day (“>20 LTD”)

regulations apply or the less than 20 LTD (“<20 LTD”) apply. For each size of SRP, EPA requires

tail gas treatment using either an oxidation system or a reducing system. For >20 LTD SRPs, the

regulations are the same as they were for Subpart J. Oxidation systems are limited to 250 ppm

SO2 (~99.9% sulfur removal). Reducing systems are limited to 300 ppm reduced sulfur

compounds and 10 ppm H2S.

The <20 LTD SRP emission limits were not required in the Subpart J regulations. The new

Subpart Ja emission limits for oxidation systems are 2,500 ppm SO2 (~99.0% sulfur removal).

The reducing system limits are 3,000 ppm reduced sulfur compounds and 100 ppm H2S.

The SRP emission limits now contain a factor to include the effect of oxygen enrichment. This

factor was not used in the previous Subpart J regulations.

Work Practice Standards

EPA has added three work practice standards to reduce VOC, NOX, and SO2 emissions from

delayed coker units, flares, and sulfur recovery units. Note that VOCs are now regulated by

Subpart Ja and therefore must be considered when determining whether a modification has

occurred.

Delayed Coker Unit

EPA has added a work practice standard for delayed coker units (“DCU”) to depressure to 5

pounds per square inch gauge (“psig”) during reactor vessel depressuring. The exhaust gases

are to be vented to the fuel gas system or to a flare.

Flare Management Plan

The flare minimization work practice standard requires each flare that is subject to Subpart Ja

to prepare a Flare Management Plan (“FMP”). New and reconstructed flares are required to be

in compliance upon startup. Modified flares are subject 1 year after the flare becomes subject

to the Subpart Ja regulations.

The FMP requires the following items:

1. Diagram showing all connections to the flare;

2. Methods for monitoring flow rate to the flare;

3. Procedures to minimize discharges to the flare during start‐up and shut‐down;

4. Procedures to conduct a root cause analysis (“RCA”) of any process upset or malfunction

that causes a discharge of more than 500,000 SCFD to the flare;

5. Procedures to reduce flaring in cases of excess fuel gas; and

6. Explanation of the procedures to follow during times the flare exceeds the 250,000 SCFD

limit.

Emission Limit Exceedance

The new regulations require that any time a fuel gas combustion device or a SRP, subject to

Subpart Ja, causes a release of more than 500 lb‐SO2/day, a RCA must be performed. Of special

note, many Refinery Consent Decrees require the refinery to perform a similar RCA for either a

Flaring Incident or a Hydrocarbon Flaring Incident. Each of the Consent Decree incidents must

occur at a flare for a RCA to be performed. For the new Subpart Ja regulations, the

requirement is expanded to also include fuel gas combustion devices (process heaters and

boilers are added) and SRPs. The RCA is to include:

1. Identification of the affected facility;

2. Date and duration of the discharge;

3. Results of the RCA; and

4. Corrective Action taken because of the RCA.

As EPA has expressed in many of the Refinery Consent Decree negotiations, the Corrective

Action taken because of performing a RCA is expected to eliminate the cause of the release

from occurring in the future. If the cause of the release occurs again, one can expect EPA to

become involved and enter into a negotiated settlement incurring penalties and injunctive

relief.

Performance Tests

Regulation 40 C.F.R. 60.104a details the performance tests required to satisfy the initial

compliance with each applicable emission limit and subsequent performance tests. The

affected facility must provide EPA with a 30‐day notice prior to the performance test as

detailed in 40 C.F.R. 60.8(d). The FCCU and FCU PM performance tests must be performed

once every 12 months.

Monitoring of Emissions

Regulations 40 C.F.R. 105a, 106a, and 107a provide detailed requirements for the monitoring of

emissions to demonstrate continuous compliance with the emission limits. These regulations

are very prescriptive and must be followed exactly to maintain compliance. The regulations

require either parametric monitoring of specified operating parameters or direct continuous

emission monitoring. In general, the continued expansion in the use of continuous emission

systems (“CEMs”) will occur. Of note, process heaters with a rated design of less than 100

MMBTU/hr can use parametric monitoring rather than CEMs to satisfy the NOX monitoring

requirements. Also of note is that affected flares will need to be monitored for SO2 or H2S and

for flow.

Greenhouse Gases

Several of the commenters stated that the NSPS regulations for refiners needed to include

limits to greenhouse gases (“GHG”) such as carbon dioxide (“CO2”) and methane (“CH4”). While

there is now an argument to be made that GHG are to be regulated because of the

Massachusetts v. EPA Supreme Court decision, EPA states that it is not reasonable to regulate

refinery GHG at this time. EPA states that the GHG regulation strategy must be determined first

for the nation before individual source categories can be regulated. As the Subpart Ja

regulations are to be reviewed in eight years (2016), look for GHG regulations specific to

refineries in the next review.

Summary

The new Subpart Ja regulations have immediately been the source of much discussion and

expected litigation. We expect that these regulations will be litigated and probably revised as a

result of this litigation. This regulation and subsequent revisions will be followed by the writers.

If you have any questions about this regulation or Subpart J regulations, please feel free to

contact the writers directly. Our contact information is included below.

Joseph F. Guida Guida, Slavich & Flores, P.C. 750 N. St. Paul Street Suite 200 Dallas, Texas 75201 [email protected] (214) 692‐0014 Jess A. McAngus Spirit Environmental, LLC 17350 State Highway 249 Suite 249 Houston, Texas 77379 [email protected] (281) 664‐2810

Mr. Guida would like to gratefully acknowledge the assistance of his associate, Erika S. Erikson, in the

preparation of this paper.

Disclaimer: The information provided in this presentation is intended solely as an educational resource, does not

constitute legal advice, and should not be used as a substitute for careful review of the rulemaking action itself

and consultation with competent legal and technical professionals as to site‐specific circumstances.

Copyright 2008. Joseph F. Guida and Jess A. McAngus. All rights reserved.

Attachment #1

Attachment #2

76

40 CFR Ch. I (7–1–07 Edition) § 60.14

the source emissions are approaching the level. The criterion for reviewing the waiver is the collection of CEMS data showing that emissions have ex-ceeded 70 percent of the applicable standard for seven, consecutive, aver-aging periods as specified by the appli-cable regulation(s). For sources subject to standards expressed as control effi-ciency levels, the criterion for review-ing the waiver is the collection of CEMS data showing that exhaust emis-sions have exceeded 70 percent of the level needed to meet the control effi-ciency requirement for seven, consecu-tive, averaging periods as specified by the applicable regulation(s) [e.g., § 60.45(g) (2) and (3), § 60.73(e), and § 60.84(e)]. It is the responsibility of the source operator to maintain records and determine the level of emissions relative to the criterion on the waiver of RA testing. If this criterion is ex-ceeded, the owner or operator must no-tify the Administrator within 10 days of such occurrence and include a de-scription of the nature and cause of the increasing emissions. The Adminis-trator will review the notification and may rescind the waiver and require the owner or operator to conduct a RA test of the CEMS as specified in Section 8.4 of Performance Specification 2.

[40 FR 46255, Oct. 6, 1975; 40 FR 59205, Dec. 22, 1975, as amended at 41 FR 35185, Aug. 20, 1976; 48 FR 13326, Mar. 30, 1983; 48 FR 23610, May 25, 1983; 48 FR 32986, July 20, 1983; 52 FR 9782, Mar. 26, 1987; 52 FR 17555, May 11, 1987; 52 FR 21007, June 4, 1987; 64 FR 7463, Feb. 12, 1999; 65 FR 48920, Aug. 10, 2000; 65 FR 61749, Oct. 17, 2000; 66 FR 44980, Aug. 27, 2001; 71 FR 31102, June 1, 2006; 72 FR 32714, June 13, 2007]

EDITORIAL NOTE: At 65 FR 61749, Oct. 17, 2000, § 60.13 was amended by revising the words ‘‘ng/J of pollutant’’ to read ‘‘ng of pol-lutant per J of heat input’’ in the sixth sen-tence of paragraph (h). However, the amend-ment could not be incorporated because the words ‘‘ng/J of pollutant’’ do not exist in the sixth sentence of paragraph (h).

§ 60.14 Modification. (a) Except as provided under para-

graphs (e) and (f) of this section, any physical or operational change to an existing facility which results in an in-crease in the emission rate to the at-mosphere of any pollutant to which a standard applies shall be considered a modification within the meaning of

section 111 of the Act. Upon modifica-tion, an existing facility shall become an affected facility for each pollutant to which a standard applies and for which there is an increase in the emis-sion rate to the atmosphere.

(b) Emission rate shall be expressed as kg/hr of any pollutant discharged into the atmosphere for which a stand-ard is applicable. The Administrator shall use the following to determine emission rate:

(1) Emission factors as specified in the latest issue of ‘‘Compilation of Air Pollutant Emission Factors,’’ EPA Publication No. AP–42, or other emis-sion factors determined by the Admin-istrator to be superior to AP–42 emis-sion factors, in cases where utilization of emission factors demonstrates that the emission level resulting from the physical or operational change will ei-ther clearly increase or clearly not in-crease.

(2) Material balances, continuous monitor data, or manual emission tests in cases where utilization of emission factors as referenced in paragraph (b)(1) of this section does not dem-onstrate to the Administrator’s satis-faction whether the emission level re-sulting from the physical or oper-ational change will either clearly in-crease or clearly not increase, or where an owner or operator demonstrates to the Administrator’s satisfaction that there are reasonable grounds to dispute the result obtained by the Adminis-trator utilizing emission factors as ref-erenced in paragraph (b)(1) of this sec-tion. When the emission rate is based on results from manual emission tests or continuous monitoring systems, the procedures specified in appendix C of this part shall be used to determine whether an increase in emission rate has occurred. Tests shall be conducted under such conditions as the Adminis-trator shall specify to the owner or op-erator based on representative per-formance of the facility. At least three valid test runs must be conducted be-fore and at least three after the phys-ical or operational change. All oper-ating parameters which may affect emissions must be held constant to the maximum feasible degree for all test runs.

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Environmental Protection Agency § 60.14

(c) The addition of an affected facil-ity to a stationary source as an expan-sion to that source or as a replacement for an existing facility shall not by itself bring within the applicability of this part any other facility within that source.

(d) [Reserved] (e) The following shall not, by them-

selves, be considered modifications under this part:

(1) Maintenance, repair, and replace-ment which the Administrator deter-mines to be routine for a source cat-egory, subject to the provisions of paragraph (c) of this section and § 60.15.

(2) An increase in production rate of an existing facility, if that increase can be accomplished without a capital expenditure on that facility.

(3) An increase in the hours of oper-ation.

(4) Use of an alternative fuel or raw material if, prior to the date any standard under this part becomes ap-plicable to that source type, as pro-vided by § 60.1, the existing facility was designed to accommodate that alter-native use. A facility shall be consid-ered to be designed to accommodate an alternative fuel or raw material if that use could be accomplished under the facility’s construction specifications as amended prior to the change. Conver-sion to coal required for energy consid-erations, as specified in section 111(a)(8) of the Act, shall not be consid-ered a modification.

(5) The addition or use of any system or device whose primary function is the reduction of air pollutants, except when an emission control system is re-moved or is replaced by a system which the Administrator determines to be less environmentally beneficial.

(6) The relocation or change in own-ership of an existing facility.

(f) Special provisions set forth under an applicable subpart of this part shall supersede any conflicting provisions of this section.

(g) Within 180 days of the completion of any physical or operational change subject to the control measures speci-fied in paragraph (a) of this section, compliance with all applicable stand-ards must be achieved.

(h) No physical change, or change in the method of operation, at an existing

electric utility steam generating unit shall be treated as a modification for the purposes of this section provided that such change does not increase the maximum hourly emissions of any pol-lutant regulated under this section above the maximum hourly emissions achievable at that unit during the 5 years prior to the change.

(i) Repowering projects that are awarded funding from the Department of Energy as permanent clean coal technology demonstration projects (or similar projects funded by EPA) are ex-empt from the requirements of this section provided that such change does not increase the maximum hourly emissions of any pollutant regulated under this section above the maximum hourly emissions achievable at that unit during the five years prior to the change.

(j)(1) Repowering projects that qual-ify for an extension under section 409(b) of the Clean Air Act are exempt from the requirements of this section, provided that such change does not in-crease the actual hourly emissions of any pollutant regulated under this sec-tion above the actual hourly emissions achievable at that unit during the 5 years prior to the change.

(2) This exemption shall not apply to any new unit that:

(i) Is designated as a replacement for an existing unit;

(ii) Qualifies under section 409(b) of the Clean Air Act for an extension of an emission limitation compliance date under section 405 of the Clean Air Act; and

(iii) Is located at a different site than the existing unit.

(k) The installation, operation, ces-sation, or removal of a temporary clean coal technology demonstration project is exempt from the require-ments of this section. A temporary clean coal control technology demonstration project, for the purposes of this section is a clean coal technology demonstra-tion project that is operated for a pe-riod of 5 years or less, and which com-plies with the State implementation plan for the State in which the project is located and other requirements nec-essary to attain and maintain the na-tional ambient air quality standards


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40 CFR Ch. I (7–1–07 Edition) § 60.15

during the project and after it is termi-nated.

(l) The reactivation of a very clean coal-fired electric utility steam gener-ating unit is exempt from the require-ments of this section.

[40 FR 58419, Dec. 16, 1975, as amended at 43 FR 34347, Aug. 3, 1978; 45 FR 5617, Jan. 23, 1980; 57 FR 32339, July 21, 1992; 65 FR 61750, Oct. 17, 2000]

§ 60.15 Reconstruction.

(a) An existing facility, upon recon-struction, becomes an affected facility, irrespective of any change in emission rate.

(b) ‘‘Reconstruction’’ means the re-placement of components of an exist-ing facility to such an extent that:

(1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be re-quired to construct a comparable en-tirely new facility, and

(2) It is technologically and economi-cally feasible to meet the applicable standards set forth in this part.

(c) ‘‘Fixed capital cost’’ means the capital needed to provide all the depre-ciable components.

(d) If an owner or operator of an ex-isting facility proposes to replace com-ponents, and the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable en-tirely new facility, he shall notify the Administrator of the proposed replace-ments. The notice must be postmarked 60 days (or as soon as practicable) be-fore construction of the replacements is commenced and must include the following information:

(1) Name and address of the owner or operator.

(2) The location of the existing facil-ity.

(3) A brief description of the existing facility and the components which are to be replaced.

(4) A description of the existing air pollution control equipment and the proposed air pollution control equip-ment.

(5) An estimate of the fixed capital cost of the replacements and of con-structing a comparable entirely new fa-cility.

(6) The estimated life of the existing facility after the replacements.

(7) A discussion of any economic or technical limitations the facility may have in complying with the applicable standards of performance after the pro-posed replacements.

(e) The Administrator will deter-mine, within 30 days of the receipt of the notice required by paragraph (d) of this section and any additional infor-mation he may reasonably require, whether the proposed replacement con-stitutes reconstruction.

(f) The Administrator’s determina-tion under paragraph (e) shall be based on:

(1) The fixed capital cost of the re-placements in comparison to the fixed capital cost that would be required to construct a comparable entirely new facility;

(2) The estimated life of the facility after the replacements compared to the life of a comparable entirely new facil-ity;

(3) The extent to which the compo-nents being replaced cause or con-tribute to the emissions from the facil-ity; and

(4) Any economic or technical limita-tions on compliance with applicable standards of performance which are in-herent in the proposed replacements.

(g) Individual subparts of this part may include specific provisions which refine and delimit the concept of recon-struction set forth in this section.

[40 FR 58420, Dec. 16, 1975]

§ 60.16 Priority list.

PRIORITIZED MAJOR SOURCE CATEGORIES

Pri-ority Num-ber 1

Source Category

1. Synthetic Organic Chemical Manufacturing Industry (SOCMI) and Volatile Organic Liquid Storage Ves-sels and Handling Equipment

(a) SOCMI unit processes (b) Volatile organic liquid (VOL) storage vessels and

handling equipment (c) SOCMI fugitive sources (d) SOCMI secondary sources

2. Industrial Surface Coating: Cans 3. Petroleum Refineries: Fugitive Sources 4. Industrial Surface Coating: Paper 5. Dry Cleaning

(a) Perchloroethylene (b) Petroleum solvent

6. Graphic Arts 7. Polymers and Resins: Acrylic Resins


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Attachment #3

From the U.S. Code Online via GPO Access [wais.access.gpo.gov] [Laws in effect as of January 3, 2006] [CITE: 42USC7411] TITLE 42--THE PUBLIC HEALTH AND WELFARE CHAPTER 85--AIR POLLUTION PREVENTION AND CONTROL SUBCHAPTER I--PROGRAMS AND ACTIVITIES Part A--Air Quality and Emission Limitations Sec. 7411. Standards of performance for new stationary sources (a) Definitions For purposes of this section: (1) The term ``standard of performance'' means a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. (2) The term ``new source'' means any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source. (3) The term ``stationary source'' means any building, structure, facility, or installation which emits or may emit any air pollutant. Nothing in subchapter II of this chapter relating to nonroad engines shall be construed to apply to stationary internal combustion engines. (4) The term ``modification'' means any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted. (5) The term ``owner or operator'' means any person who owns, leases, operates, controls, or supervises a stationary source. (6) The term ``existing source'' means any stationary source other than a new source. (7) The term ``technological system of continuous emission reduction'' means-- (A) a technological process for production or operation by any source which is inherently low-polluting or nonpolluting, or (B) a technological system for continuous reduction of the pollution generated by a source before such pollution is emitted into the ambient air, including precombustion cleaning or treatment of fuels. (8) A conversion to coal (A) by reason of an order under section 2(a) of the Energy Supply and Environmental Coordination Act of 1974 [15 U.S.C. 792(a)] or any amendment thereto, or any subsequent enactment which supersedes such Act [15 U.S.C. 791 et seq.], or (B) which qualifies under section 7413(d)(5)(A)(ii) \1\ of this title,

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the final amendments for subpart J and will continue to address

individual applicability issues under our applicability

determination procedures. Similarly, we proposed revisions to

the subpart J definitions of “oxidation control system” and

“reduction control system” in 40 CFR 60.101(j) and 40 CFR

60.101(k), respectively, to clarify that these systems were

intended to recycle the sulfur back to the Claus SRP. The

proposed amendments needlessly limit the types of tail gas

treatment systems that can be used; therefore, we are not

amending these definitions in the final amendments for

subpart J.

The final amendments also include technical corrections to

fix references and other miscellaneous errors in 40 CFR part 60,

subpart J. Table 1 of this preamble describes the miscellaneous

technical corrections not previously described in this preamble

that are included in the amendments to subpart J.

Table 1. Technical Corrections to 40 CFR Part 60, Subpart J. Section Technical Correction and Reason

60.100 Replace instances of “construction or modification” with “construction, reconstruction, or modification.”

60.100(a) Replace “except Claus plants of 20 long tons per day (LTD) or less” with “except Claus plants with a design capacity for sulfur feed of 20 long tons per day (LTD) or less” to clarify that the size cutoff is based upon design capacity and sulfur content in the inlet stream rather than the amount of sulfur produced.

Deleted: b)

13

60.100(b) Insert ending date for applicability of 40 CFR part 60, subpart J (one date for flares and another date for all other affected facilities); sources beginning construction, reconstruction, or modification after this date will be subject to 40 CFR part 60, subpart Ja.

60.102(b) Replace “g/MJ” with “grams per Gigajoule (g/GJ)” to correct units.

60.104(b)(1) Replace “sulfur dioxide” with “SO2” and replace “50 ppm by volume (vppm)” with “50 ppm by volume (ppmv)” for consistency in unit and acronym definition.

60.104(b)(2) Add “to reduce SO2 emissions” to the end of the phrase “Without the use of an add-on control device” at the beginning of the paragraph to clarify the type of control device to which this paragraph refers; replace “sulfur dioxide” with “SO2” for consistency in acronym definition.

60.105(a)(3) Add “either” before “an instrument for continuously monitoring” and replace “except where an H2S monitor is installed under paragraph (a)(4)” with “or monitoring as provided in paragraph (a)(4)” to more accurately refer to the requirements of §60.105(a)(4) and clarify that there is a choice of monitoring requirements.

60.105(a)(3)(iv) Replace “accurately represents the S2 emissions” with “accurately represents the SO2 emissions” to correct a typographical error.

60.105(a)(4) Replace “In place” with “Instead” at the beginning of this paragraph and add “for fuel gas combustion devices subject to §60.104(a)(1)” after “paragraph (a)(3) of this section” to clarify that there is a choice of monitoring requirements.

60.105(a)(8) Replace “seeks to comply with §60.104(b)(1)” with “seeks to comply specifically with the 90-percent reduction option under §60.104(b)(1)” to clearly identify the emission limit option to which the monitoring requirement in this paragraph refers.

22

In the subpart Ja proposal, we divided fuel gas combustion

devices into two separate affected sources: “process heaters”

and “other fuel gas combustion devices.” In response to

comments, we have eliminated the proposed definition of “other

fuel gas combustion devices” and revised the standards to either

refer to fuel gas combustion devices, which include process

heaters, or to refer specifically to process heaters. This

revision makes the definition of “fuel gas combustion devices”

consistent with subpart J. Based on public comments, we have

also added a definition of “flare” as a subcategory of fuel gas

combustion devices. The owner or operator of an affected flare

must comply with the fuel gas combustion device requirements as

well as specific provisions for flares as described in section

III.E of this preamble.

We proposed a primary sulfur dioxide emission limit for

fuel gas combustion devices of 20 ppmv or less SO2 (dry at 0

percent excess air) on a 3-hour rolling average basis and 8 ppmv

or less on a 365-day rolling average basis. We also proposed an

alternative limit of 160 ppmv H2S or, in the case of coker-

derived fuel gas, 160 ppmv total reduced sulfur (TRS), on a 3-

hour rolling average basis and 60 ppmv or less on a 365-day

rolling average basis. We are promulgating the 20 ppmv and 8

ppmv limits for SO2 as proposed. We are also promulgating the

alternative limit except that the limits are expressed and

Deleted: .”

26

subject to the provisions of subpart Ja that exceeds 500 pounds

per day (lb/day) of SO2. Recordkeeping and reporting

requirements apply in the event of such a discharge. Newly

constructed and reconstructed flares must comply with these

requirements immediately upon startup. Modified flares must

comply no later than the first discharge that occurs after that

flare has been an affected flare for 1 year.

In response to comments regarding the work practice

standards for fuel gas producing units and associated

difficulties with no routine flaring, we re-evaluated the work

practice standards and have decided not to promulgate a work

practice standard for fuel gas producing units. Rather, we have

decided to define a flare as an affected facility and adopt

regulations applicable to it. Therefore, we are not

promulgating the proposed definition of “fuel gas producing

unit” and the proposed requirement for “no routine flaring.”

Instead, we are promulgating the following requirements for

flares that become affected facilities after [INSERT DATE OF

PUBLICATION IN THE FEDERAL REGISTER]: (1) flare fuel gas flow

rate monitoring; (2) a flare fuel gas flow rate limit; and (3) a

flare management plan. Affected flares cannot exceed a flow

rate of 250,000 standard cubic feet per day (scfd) on a 30-day

rolling average basis. In cases where the flow would exceed

this value, the owner or operator would install a flare gas

Deleted: flares and

Deleted: to define a flare as the affected source rather than a

27

recovery system or implement other methods to reduce flaring

from the affected flare. To demonstrate compliance with the

flow rate limitations, flow rate monitors must be installed and

operated. Newly constructed and reconstructed flares must

comply with the flow rate limitations and the monitoring


comply with the flow rate limitations and the associated

monitoring provisions no later than 1 year after the flare

becomes an affected facility. A provision is provided for an

exclusion from the flow limitation for times when the refinery

can demonstrate that the refinery produces more fuel gas than it

needs to fuel the refinery combustion devices (i.e., it is fuel

gas rich) or that the flow is due to an upset or malfunction,

provided the refinery follows procedures outlined in the flare

management plan. The flare management plan should address

potential causes of fuel gas imbalances (i.e., excess fuel gas)

and records to be maintained to document these periods. As

described in 40 CFR 60.103a(a), the flare management plan must

include a diagram illustrating all connections to each affected

flare, identification of the flow rate monitoring device and a

detailed description of the manufacturer’s specifications

regarding quality assurance procedures, procedures to minimize

flaring during planned start-up and shut down events, and

procedures for implementing root cause analysis when daily flow

Deleted: To demonstrate compliance with the flow limitations, flow rate monitors must be installed and operated.

Deleted: maintain to

28

to the flare exceeds 500,000 scfd. The root cause analysis

procedures should address the evaluation of potential causes of

upsets or malfunctions and records to be maintained to document

the cause of the upset or malfunction. Newly constructed and

reconstructed flares must comply with the flare management plan


comply with the flare management plan requirements no later than

1 year after the flare becomes an affected facility.

Additionally, as described above, the owner or operator of a

modified flare must conduct the first root cause analysis no

later than the first discharge that occurs after that flare has

been an affected flare for 1 year. Excess emission events for

the flow rate limit of 250,000 scfd and the result of root cause

analysis must be reported in the semi-annual compliance reports.

Because affected flares are also affected fuel gas

combustion devices, the root cause analysis for SO2 emissions

exceeding 500 lbs/day also applies to all affected flares.

However, compliance with the 500 lb/day root cause analysis will

also require continuous monitoring of total reduced sulfur of

all gases flared. Although all fuel gas combustion devices are

required to comply with continuous H2S monitoring of fuel gas,

flares routinely accept gases from upsets, malfunctions and

startup and shutdown events, and H2S or sulfur monitoring is not

specifically required for these gases. In subpart Ja, we

29

explicitly require TRS monitoring for flares that become

affected facilities after [INSERT DATE OF PUBLICATION IN THE

FEDERAL REGISTER] to ensure that the 500 lb/day SO2 trigger is

accurately measured. The owner or operator of a modified flare

must install and operate the TRS monitoring instrument no later

than 1 year after the flare becomes an affected facility. The

owner or operator of a newly constructed or reconstructed flare

must install and operate the TRS monitoring instrument no later

than start-up of the flare.

F. What are the modification and reconstruction provisions?

Existing affected facilities that commence modification or

reconstruction after May 14, 2007, are subject to the final

standards in 40 CFR part 60, subpart Ja. A modification is any

physical or operational change to an existing affected facility

which results in an increase in the emission rate to the

atmosphere of any pollutant to which a standard applies (see 40

CFR 60.14). Changes to an existing affected facility that do

not result in an increase in the emission rate, as well as

certain changes that have been exempted under the General

Provisions (see 40 CFR 60.14(e)), are not considered

modifications.

The intermittent operation of a flare makes it difficult to

use the criteria of 40 CFR 60.14 to determine when a flare is

modified; therefore, we have specified in the final rule the

85

includes a flare management plan. Finally, fuel gas flow to the

flare is limited to 250,000 scfd. To support implementation of

these requirements, monitoring and reporting of the flow rate

and sulfur content is required. For new flaring devices, this

option achieves SO2 emission reductions of 16 tons/yr from a

baseline of 32 tons/yr, NOX emission reductions of 1 tons/yr from

a baseline of 2 tons/yr, and VOC emission reductions of 41

tons/yr from a baseline of 67 tons/yr with a net fuel savings of

$23,000 per ton of combined SO2, NOX, and VOC. For modified and

reconstructed flaring devices, this option achieves SO2 emission

reductions of 64 tons/yr from a baseline of 129 tons/yr, NOX

emission reductions of 4 tons/yr from a baseline of 7 tons/yr,

and VOC emission reductions of 165 tons/yr from a baseline of

266 tons/yr with a net fuel savings of $23,000 per ton of

combined SO2, NOX, and VOC.

The flare gas minimization requirements included in the

final standards are important to reduce criteria pollutant

emissions and conserve energy. However, we recognize that

owners and operators also need to be able to make quick changes

to existing process units or flare systems to avoid unsafe

conditions. It could take an owner or operator more time to

implement the flare requirements, especially flow monitoring and

any physical changes needed to comply with the limit on flow to

the flare, than it took to implement the change to the flare

86

that caused it to be an affected facility. There is the

potential for serious safety concerns if the owner or operator

must wait until compliance has been achieved with all of the

flare gas minimization requirements prior to venting explosive

vapors to the flare or modifying the flare system, such as

adding a knockout pot for safety reasons. Moreover, avoiding

unsafe conditions by requiring immediate shutdown of all process

units connected to the potentially affected flare while the

owner or operator takes steps to comply with the final

provisions specific to flare gas minimization results in

additional emissions, significant costs, and large lost

production of refined products. By providing 1 year for

modified flares to comply with these flare gas minimization

provisions, refinery owners and operators have sufficient time

to coordinate the installation of the flow rate and sulfur

content monitors, to take whatever steps necessary to meet the

flow limitations, to develop and implement the flare management

plan, and to make other modifications, if needed, regarding

safety and maintenance considerations for other process

equipment tied to the flare.

Considering the cost and the energy penalty from the

reduction in refined products (e.g., the need to shut down the

refinery until the flare gas minimization requirements can be

met) and emissions associated with the immediate application of

87

these requirements of the rule to modified flares, we determined

that BDT was to phase in the requirements. The owner or

operator of a modified flare would have to comply with the

applicable H2S limit immediately and would have 1 year to

implement the flare gas minimization requirements. Therefore,

the final standards specify that for modified flares, the H2S

limits for fuel gas combustion units apply immediately and the

flare gas minimization requirements apply no later than 1 year

after the flare becomes an affected facility. For newly

constructed and reconstructed flares, the H2S limits and all of

the flare gas minimization requirements apply immediately upon

start-up of the affected flare.

Comment: Several commenters requested clarification of how

one would assess a flare “modification.” Questions included:

(1) how the emission basis of a flare should be calculated;

(2) if the modification determination would be based on flare

capacity or increase in discharge capability of units connected

to the flare; (3) whether the modification determination would

include all possible flaring events or just non-emergency

flaring; (4) whether adding a new line to a flare is considered

to increase the capacity of the flare and cause a modification;

(5) whether flare tip replacements are considered routine

maintenance instead of a modification of the flare, even if the

new flare tip has a different geometry (e.g., a larger diameter

89

sent to the flare, consequently increasing emissions from the

flare. Second, a flare is considered to be modified if that

flare is physically altered to increase flow capacity.

While in most cases an affected facility must comply with

the final standard if it commences construction, reconstruction

or modification after the proposal date, section 111(a)(2) of

the CAA also provides that in certain circumstances such a

source only need comply with the standard if it commences

construction after the final date. Given the number of changes

between proposal and final, we have concluded that this is one

of the rare cases in which the final, rather than proposal, date

applies.

In this case, we are promulgating a newly defined affected

facility, adding a new provision specifically defining what

constitutes a modification of a flare, adding several new

requirements, and adding a definition of a flare. All of these

changes significantly alter what would be an affected facility

and the obligations of the affected facility for purposes of

reducing flaring. Furthermore, while some of the requirements

that were proposed for the fuel gas producing unit were

transferred to the flare as an affected source, the scope of

these requirements changed significantly when they were applied

to a flare rather than a fuel gas producing unit. Specifically,

under the proposal, only the gas stream from the modified fuel

90

gas producing unit was barred from routine flaring. Under the

final rule, however all of the units connected to the flare are

now addressed, not just the fuel gas producing unit that was

new, modified, or reconstructed.

Accordingly, we are providing in the final standards that

only those flares commencing construction, reconstruction, or

modification after [INSERT DATE OF PUBLICATION IN THE FEDERAL

REGISTER] must meet the requirements in subpart Ja. Flares

commencing construction, reconstruction, or modification after

June 11, 1973, and on or before [INSERT DATE OF PUBLICATION IN

THE FEDERAL REGISTER] must meet the requirements in subpart J

regarding fuel gas combustion devices (i.e., the H2S fuel gas

limit).

J. Delayed Coking Units

Comment: Several commenters supported the proposal that

requires delayed coking units to depressure the coke drums to

the fuel gas system down to 5 psig. One commenter supported

venting the delayed coker gas to a flare or to the atmosphere at

pressures less than 5 psig; at pressures greater than 5 psig,

the commenter suggested that the rule should only prohibit gases

from being sent to a flare and allow any other disposition.

That is, the commenter stated that EPA should not restrict the

disposition of the coker depressurization gas to only the fuel

gas system.

129

The EPA has also decided to use EPA methods 1, 2, 3, 3A,

3B, 5, 5B, 5F, 5I, 6, 6A, 6C, 7, 7A, 7C, 7D, 7E, 10, 10A, 10B,

11, 15, 15A, 16, and 17 (40 CFR part 60, Appendices A-1 through

A6); Performance Specifications 1, 2, 3, 4, 4A, 5, 7, and 11 (40

CFR part 60, Appendix B); quality assurance procedures in 40 CFR

part 60, Appendix F; and the Gas Processors Association Standard

2377-86, “Test for Hydrogen Sulfide and Carbon Dioxide in

Natural Gas Using Length of Stain Tubes,” 1986 Revision. While

the Agency has identified 22 VCS as being potentially applicable

to this rule, we have decided not to use these VCS in this

rulemaking. The use of these VCS would have been impractical

because they do not meet the objectives of the standards cited

in this rule. See the docket for this rule for the reasons for

these determinations.

Under 40 CFR 60.13(i) of the NSPS General Provisions, a

source may apply to EPA for permission to use alternative test

methods or alternative monitoring requirements in place of any

required testing methods, performance specifications, or

procedures in the final rule and amendments.

J. Executive Order 12898: Federal Actions to Address

Environmental Justice in Minority Populations and Low-Income

Populations

Executive Order 12898 (59 FR 7629, February 16, 1994)

establishes Federal executive policy on environmental justice.

Deleted: Method

Deleted: .”

135

(b) Any fluid catalytic cracking unit catalyst regenerator

or fuel gas combustion device under paragraph (a) of this

section other than a flare as defined in §60.101a which

commences construction, reconstruction, or modification after

June 11, 1973, and on or before May 14, 2007, or any fuel gas

combustion device under paragraph (a) of this section that meets

the definition of a flare as defined in §60.101a which commences

construction, reconstruction, or modification after June 11,

1973, and on or before [INSERT DATE OF PUBLICATION IN THE

FEDERAL REGISTER], or any Claus sulfur recovery plant under

paragraph (a) of this section which commences construction,

reconstruction, or modification after October 4, 1976, and on or

before May 14, 2007, is subject to the requirements of this

subpart except as provided under paragraphs (c) and (d) of this

section.

(c) Any fluid catalytic cracking unit catalyst regenerator

under paragraph (b) of this section which commences

construction, reconstruction, or modification on or before

January 17, 1984, is exempted from §60.104(b).

(d) Any fluid catalytic cracking unit in which a contact

material reacts with petroleum derivatives to improve feedstock

quality and in which the contact material is regenerated by

burning off coke and/or other deposits and that commences

142

minimum, 2 weeks of daily monitoring (14 grab samples) for

frequently operated fuel gas streams/systems; for infrequently

operated fuel gas streams/systems, seven grab samples must be

collected unless other additional information would support

reduced sampling. The owner or operator shall use detector

tubes (“length-of-stain tube” type measurement) following the

“Gas Processors Association Standard 2377-86, Test for Hydrogen

Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain

Tubes,” 1986 Revision (incorporated by reference-see §60.17),

with ranges 0-10/0-100 ppm (N =10/1) to test the applicant fuel

gas stream for H2S; and

(v) A description of how the 2 weeks (or seven samples for

infrequently operated fuel gas streams/systems) of monitoring

results compares to the typical range of H2S concentration (fuel

quality) expected for the fuel gas stream/system going to the

affected fuel gas combustion device (e.g., the 2 weeks of daily

detector tube results for a frequently operated loading rack

included the entire range of products loaded out, and,

therefore, should be representative of typical operating

conditions affecting H2S content in the fuel gas stream going to

the loading rack flare).

(2) The effective date of the exemption is the date of

submission of the information required in paragraph (b)(1) of

this section).

Deleted: Processor Association’s

148

60.108a Recordkeeping and reporting requirements.

60.109a Delegation of authority.

Subpart Ja--Standards of Performance for Petroleum Refineries

for which Construction, Reconstruction, or Modification

Commenced After May 14, 2007

§60.100a Applicability, designation of affected facility, and

reconstruction.

(a) The provisions of this subpart apply to the following

affected facilities in petroleum refineries: fluid catalytic

cracking units (FCCU), fluid coking units (FCU), delayed coking

units, fuel gas combustion devices, including flares and process

heaters, and sulfur recovery plants. The sulfur recovery plant

need not be physically located within the boundaries of a

petroleum refinery to be an affected facility, provided it

processes gases produced within a petroleum refinery.

(b) Except for flares, the provisions of this subpart

apply only to affected facilities under paragraph (a) of this

section which commence construction, modification, or

reconstruction after May 14, 2007. For flares, the provisions

of this subpart apply only to flares which commence

construction, modification, or reconstruction, after [INSERT

DATE OF PUBLICATION IN THE FEDERAL REGISTER].

(c) For the purposes of this subpart, under §60.14, a

modification to a flare occurs if:

Deleted: The

162

allow flow to each affected flare during normal operations of

more than 7,080 standard cubic meters per day (m3/day) (250,000

standard cubic feet per day (scfd)) on a 30-day rolling average.

The owner or operator of a newly constructed or reconstructed

flare shall comply with the emission limit in this paragraph by

no later than the date that flare becomes an affected flare

subject to this subpart. The owner or operator of a modified

flare shall comply with the emission limit in this paragraph by

no later than 1 year after that flare becomes an affected flare

subject to this subpart.

(h) The combustion in a flare of process upset gases or

fuel gas that is released to the flare as a result of relief

valve leakage or other emergency malfunctions is exempt from

paragraph (g) of this section.

(i) In periods of fuel gas imbalance that are described in

the flare management plan required in section 60.103a(a),

compliance with the emission limit in paragraph (g)(3) of this

section is demonstrated by following the procedures and

maintaining records described in the flare management plan to

document the periods of excess fuel gas.

§60.103a Work practice standards.

(a) Each owner or operator that operates a flare that is

subject to this subpart shall develop and implement a written

flare management plan. The owner or operator of a newly

163

constructed or reconstructed flare must develop and implement

the flare management plan by no later than the date that flare

becomes an affected flare subject to this subpart. The owner or

operator of a modified flare must develop and implement the

flare management plan by no later than 1 year after the flare

becomes an affected flare subject to this subpart. The plan

must include:

(1) A diagram illustrating all connections to the flare;

(2) Methods for monitoring flow rate to the flare,

including a detailed description of the manufacturer’s

specifications, including but not limited to, make, model, type,

range, precision, accuracy, calibration, maintenance, and

quality assurance procedures for flare gas monitoring devices;

(3) Procedures to minimize discharges to the flare gas

system during the planned start-up and shutdown of the refinery

process units that are connected to the affected flare;

(4) Procedures to conduct a root cause analysis of any

process upset or malfunction that causes a discharge to the

flare in excess of 14,160 m3/day (500,000 scfd);

(5) Procedures to reduce flaring in cases of fuel gas

imbalance (i.e., excess fuel gas for the refinery’s energy

needs); and

(6) Explanation of procedures to follow during times that

the flare must exceed the limit in §60.102a(g)(3) (e.g., keep

164

records of natural gas purchases to support assertion that the

refinery is producing more fuel gas than needed to operate the

processes).

(b) Each owner or operator that operates a fuel gas

combustion device or sulfur recovery plant subject to this

subpart shall conduct a root cause analysis of any emission

limit exceedance or process start-up, shutdown, upset, or

malfunction that causes a discharge to the atmosphere in excess

of 227 kilograms per day (kg/day) (500 lb per day (lb/day)) of

SO2. For any root cause analysis performed, the owner or

operator shall record the identification of the affected

facility, the date and duration of the discharge, the results of

the root cause analysis, and the action taken as a result of the

root cause analysis. The first root cause analysis for a

modified flare must be conducted no later than the first

discharge that occurs after the flare has been an affected flare

subject to this subpart for 1 year.

(c) Each owner or operator of a delayed coking unit shall

depressure to 5 lb per square inch gauge (psig) during reactor

vessel depressuring and vent the exhaust gases to the fuel gas

system for combustion in a fuel gas combustion device.

§60.104a Performance tests.

(a) The owner or operator shall conduct a performance test

for each FCCU, FCU, sulfur recovery plant, and fuel gas

189

Exhaust Gas Analyses,” (incorporated by reference-see §60.17) is

an acceptable alternative to EPA Method 7 or 7C of Appendix A-4

to part 60.

(3) The owner or operator shall install, operate, and

maintain each O2 monitor according to Performance Specification 3

of Appendix B to part 60. The span value of this O2 monitor must

be selected between 10 and 25 percent, inclusive.

(4) The owner or operator shall conduct performance

evaluations of each O2 monitor according to the requirements in

§60.13(c) and Performance Specification 3 of Appendix B to part

60. Method 3, 3A, or 3B of Appendix A-2 to part 60 shall be

used for conducting the relative accuracy evaluations. The

method ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,”

(incorporated by reference-see §60.17) is an acceptable

alternative to EPA Method 3B of Appendix A-2 to part 60.

(5) The owner or operator shall comply with the quality

assurance requirements of Procedure 1 of Appendix F to part 60

for each NOX and O2 monitor, including quarterly accuracy

determinations for NOX monitors, annual accuracy determinations

for O2 monitors, and daily calibration drift tests.

(g) FCCU and FCU subject to SO2 limit. The owner or

operator subject to the SO2 emissions limit in §60.102a(b)(3) for

an FCCU or an FCU shall install, operate, calibrate, and

maintain an instrument for continuously monitoring and recording

Deleted: Apppendix

201

(b) Excess emissions. For the purpose of reports required

by §60.7(c), periods of excess emissions for sulfur recovery

plants subject to the emissions limitations in §60.102a(f) are

defined as specified in paragraphs (b)(1) through (3) of this

section. Note: Determine all averages as the arithmetic

average of the applicable 1-hour averages, e.g., determine the

rolling 12-hour average as the arithmetic average of 12

contiguous 1-hour averages.

(1) All 12-hour periods during which the average

concentration of SO2 as measured by the SO2 continuous monitoring

system required under paragraph (a)(1) of this section exceeds

the applicable emission limit (dry basis, zero percent excess

air); or

(2) All 12 hour periods during which the average

concentration of reduced sulfur (as SO2) as measured by the

reduced sulfur continuous monitoring system required under

paragraph (a)(2) of this section exceeds the applicable emission

limit; or

(3) All 12-hour periods during which the average

concentration of H2S as measured by the H2S continuous monitoring

system required under paragraph (a)(2) of this section exceeds

the applicable emission limit (dry basis, 0 percent excess air).

§60.107a Monitoring of emissions and operations for fuel gas

combustion devices.

Deleted: e

207

(i) A description of the fuel gas stream/system to be

considered, including submission of a portion of the appropriate

piping diagrams indicating the boundaries of the fuel gas

stream/system, and the affected fuel gas combustion device(s) to

be considered;

(ii) A statement that there are no crossover or entry

points for sour gas (high H2S content) to be introduced into the

fuel gas stream/system (this should be shown in the piping

diagrams);

(iii) An explanation of the conditions that ensure low

amounts of sulfur in the fuel gas stream (i.e., control

equipment or product specifications) at all times;

(iv) The supporting test results from sampling the

requested fuel gas stream/system demonstrating that the sulfur

content is less than 5 ppm H2S. Sampling data must include, at

minimum, 2 weeks of daily monitoring (14 grab samples) for

frequently operated fuel gas streams/systems; for infrequently

operated fuel gas streams/systems, seven grab samples must be

collected unless other additional information would support

reduced sampling. The owner or operator shall use detector

tubes (“length-of-stain tube” type measurement) following the

“Gas Processors Association Standard 2377-86, Test for Hydrogen

Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain

Tubes,” 1986 Revision (incorporated by reference-see §60.17),

Deleted: Processor Association’s

211

§60.13(c) and Performance Specification 3 of Appendix B to part

60. Method 3, 3A, or 3B of Appendix A-2 to part 60 shall be

used for conducting the relative accuracy evaluations. The

method ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,”

(incorporated by reference-see §60.17) is an acceptable

alternative to EPA Method 3B of Appendix A-2 to part 60.

(5) The owner or operator shall comply with the quality

assurance requirements in Procedure 1 of Appendix F to part 60

for each NOX and O2 monitor, including quarterly accuracy

determinations for NOX monitors, annual accuracy determinations

for O2 monitors, and daily calibration drift tests.

(6) The owner or operator of a process heater that has a

rated heating capacity of less than 100 MMBtu and is equipped

with low-NOX burners (LNB) or ultra low-NOX burners (ULNB) is not

subject to the monitoring requirements in paragraphs (c)(1)

through (5) of this section. The owner or operator of such a

process heater must conduct biennial performance tests to

demonstrate compliance.

(d) Sulfur monitoring for affected flares. The owner or

operator of an affected flare subject to §60.103a(b) shall

install, operate, calibrate, and maintain an instrument for

continuously monitoring and recording the concentration of

reduced sulfur in flare gas. The owner or operator of a

modified flare shall install this instrument by no later than 1

212

year after the flare becomes an affected flare subject to this

subpart.

(1) The owner or operator shall install, operate, and

maintain each reduced sulfur CEMS according to Performance

Specification 5 of Appendix B to part 60.

(2) The owner or operator shall conduct performance

evaluations of each reduced sulfur monitor according to the

requirements in §60.13(c) and Performance Specification 5 of

Appendix B to part 60. The owner or operator shall use Methods

15 or 15A of Appendix A-5 to part 60 for conducting the relative

accuracy evaluations. The method ASME PTC 19.10-1981, “Flue and

Exhaust Gas Analyses,” (incorporated by reference-see §60.17) is

an acceptable alternative to EPA Method 15A of Appendix A-5 to

part 60.

(3) The owner or operator shall comply with the applicable

quality assurance procedures in Appendix F to part 60 for each

reduced sulfur monitor.

(e) Flow monitoring for flares. The owner or operator of

an affected flare subject to §60.102a(g)(3) shall install,

operate, calibrate, and maintain CPMS to measure and record the

exhaust gas flow rate. The owner or operator of a modified

flare shall install this instrument by no later than 1 year

after the flare becomes an affected flare subject to this

subpart.

Attachment #5

43626 Federal Register / Vol. 73, No. 145 / Monday, July 28, 2008 / Rules and Regulations

finishing South at position 42° 50′27″ N, 078°51′35″ W (NAD 83).

(b) Effective period. This regulation is effective from 6:30 a.m. to 2:30 p.m. on August 16, 2008.

(c) Regulations. (1) In accordance with the general regulations in section 165.23 of this part, entry into, transiting, or anchoring within this safety zone is prohibited unless authorized by the Captain of the Port Buffalo or his on- scene representative.

(2) This safety zone is closed to all vessel traffic, except as may be permitted by the Captain of the Port Buffalo or his on-scene representative.

(3) The ‘‘on-scene representative’’ of the Captain of the Port is any Coast Guard commissioned, warrant or petty officer who has been designated by the Captain of the Port to act on his behalf. The on-scene representative of the Captain of the Port will be aboard either a Coast Guard or Coast Guard Auxiliary vessel.

(4) Vessel operators desiring to enter or operate within the safety zone shall contact the Captain of the Port Buffalo or his on-scene representative to obtain permission to do so. The Captain of the Port or his on-scene representative may be contacted via VHF Channel 16. Vessel operators given permission to enter or operate in the safety zone must comply with all directions given to them by the Captain of the Port Buffalo or his on-scene representative.

Dated: July 17, 2008. Robert S. Burchell, Captain, U.S. Coast Guard, Captain of the Port Buffalo. [FR Doc. E8–17181 Filed 7–25–08; 8:45 am] BILLING CODE 4910–15–P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA–HQ–OAR–2007–0011; FRL–8698–3]

RIN 2060–AN72

Standards of Performance for Petroleum Refineries

AGENCY: Environmental Protection Agency (EPA). ACTION: Final rule; stay of effective date.

SUMMARY: On June 24, 2008, EPA published in the Federal Register final amendments to the current standards of performance for petroleum refineries and separate standards of performance for new, modified, or reconstructed process units at petroleum refineries. Both of these final rules had an effective date of June 24, 2008. This document

stays the effective date of the rule for the newly promulgated standards of performance for new, modified, or reconstructed process units at petroleum refineries to September 26, 2008 to be consistent with sections 801 and 808 of the Congressional Review Act, enacted as part of the Small Business Regulatory Enforcement Fairness Act, 5 U.S.C. 801, 808. The effective date for the final rule promulgating amendments to the current standards of performance for petroleum refineries is not changing and remains June 24, 2008. DATES: The effective date of this rule is July 28, 2008. Title 40 CFR part 60, subpart Ja, consisting of §§ 60.100a through 60.109a, is stayed until September 26, 2008. FOR FURTHER INFORMATION CONTACT: Mr. Robert B. Lucas, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, Coatings and Chemicals Group (E143–01), Environmental Protection Agency, Research Triangle Park, NC 27711, telephone number: (919) 541–0884; fax number: (919) 541–0246; e-mail address: [email protected]. SUPPLEMENTARY INFORMATION:

I. Background The Environmental Protection Agency

published a final rule on June 24, 2008 that contained the following: (1) Final amendments to the existing refineries New Source Performance Standards (NSPS) in 40 CFR part 60, subpart J; and (2) a new refineries NSPS in 40 CFR part 60, subpart Ja (73 FR 35838). The preamble to that rule contained an incorrect effective date and contained an error in the Congressional Review Act (CRA) statement in the Statutory and Executive Order Reviews section. The preamble incorrectly classified all amendments to the CFR in that rule document as ‘‘non-major’’ rules and provided for an effective date of June 24, 2008. The amendments to existing NSPS subpart J in that document are properly classified as a ‘‘non-major rule;’’ however, the amendment that added the new NSPS subpart Ja is a ‘‘major’’ rule under the CRA. Section 801 of the CRA precludes a major rule from taking effect until the later of 60 days after the date of publication of the rule in the Federal Register or 60 days after each House of Congress and the Comptroller General of the Government Accountability Office receive a copy of a rule report. While EPA did submit the above rule as required, because NSPS subpart Ja is a ‘‘major’’ rule, the effective date of June 24, 2008 does not comply with sections 801 and 808 of the CRA. Today’s rule

stays the effective date of NSPS subpart Ja consistent with the provisions of the CRA; the effective date of NSPS subpart Ja is September 26, 2008. The amendments in NSPS subpart J are not affected by today’s action and remain effective from June 24, 2008.

Section 553 of the Administrative Procedure Act, 5 U.S.C. 553(b)(B), provides that when an agency for good cause finds that notice and public procedure are impracticable, unnecessary or contrary to the public interest, an agency may issue a rule without providing notice and an opportunity for public comment. EPA has determined that there is good cause for making today’s rule final without prior proposal and opportunity for comment because EPA is merely correcting the effective date of the promulgated rule to be consistent with the congressional review requirements of the CRA as a matter of law and has no discretion in this matter. Thus, notice and public procedure are unnecessary. The Agency finds that this constitutes good cause under 5 U.S.C. 553(b)(B).

II. Statutory and Executive Order Reviews

A. General Requirements Under Executive Order 12866 (58 FR

51735, October 4, 1993), this action is not a ‘‘significant regulatory action’’ and, therefore, is not subject to review by the Office of Management and Budget. For this reason, this action is also not subject to Executive Order 13211, ‘‘Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use’’ (66 FR 28355, May 22, 2001). In addition, this action does not impose any enforceable duty or contain any unfunded mandate as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104–4), or require prior consultation with State officials as specified by Executive Order 12875 (58 FR 58093, October 28, 1993), or involve special consideration of environmental justice related issues as required by Executive Order 12898 (59 FR 7629, February 16, 1994). Because this action is not subject to notice-and- comment requirements under the Administrative Procedure Act or any other statute, it is not subject to the regulatory flexibility provisions of the Regulatory Flexibility Act (5 U.S.C. 601, et seq.). This rule also does not have tribal implications because it will not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal government and Indian tribes, or on the distribution of power and responsibilities between the

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43627 Federal Register / Vol. 73, No. 145 / Monday, July 28, 2008 / Rules and Regulations

Federal government and Indian tribes, as specified by Executive Order 13175 (65 FR 67249, November 9, 2000). This action also does not have Federalism implications because it does not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132 (64 FR 43255, August 10, 1999). This rule also is not subject to Executive Order 13045 ‘‘Protection of Children from Environmental Health Risks and Safety Risks’’ (62 FR 19885, April 23, 1997). The requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) do not apply. This rule does not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501, et seq.). EPA’s compliance with these statutes and Executive Orders for the underlying rule is discussed in the June 24, 2008 Federal Register document.

B. Submission to Congress and the Comptroller General

The Congressional Review Act, 5 U.S.C. 801, et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this rule and other required information to the United States Senate, the United States House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the Federal Register. This rule is not a ‘‘major rule’’ as defined by 5 U.S.C. 804(2).

List of Subjects in 40 CFR Part 60 Environmental protection,

Administrative practice and procedure, Air pollution control, Incorporations by reference, Intergovernmental relations, Reporting and recordkeeping requirements.

Dated: July 22, 2008. Stephen L. Johnson, Administrator.

■ For the reasons stated in the preamble, title 40, chapter I of the Code of Federal Regulations is amended as follows:

PART 60—[AMENDED]

■ 1. The authority citation for part 60 continues to read as follows:

Authority: 42 U.S.C. 7401, et seq.

Subpart Ja—[Stayed]

■ 2. Subpart Ja, consisting of §§ 60.100a through 60.109a, is stayed until September 26, 2008.

[FR Doc. E8–17220 Filed 7–25–08; 8:45 am] BILLING CODE 6560–50–P

GENERAL SERVICES ADMINISTRATION

41 CFR Chapter 301–10

[FTR Amendment 2008–05; FTR Case 2008– 304; Docket 2008–0002, Sequence 3]

RIN 3090–AI65

Federal Travel Regulation; Privately Owned Vehicle Mileage Reimbursement

AGENCY: Office of Governmentwide Policy, General Services Administration (GSA). ACTION: Final rule.

SUMMARY: This final rule amends the mileage reimbursement rate for use of a privately owned vehicle (POV) when that mode of transportation is authorized or approved as more advantageous to the Government. The governing regulation is revised to increase the cost of operating a privately owned airplane from $1.07 to $1.26 per mile, a privately owned automobile (POA) from $0.505 to $0.585 cents per mile, and a privately owned motorcycle from $0.305 to $0.585 cents per mile. DATES: Effective Date: This final rule is effective July 28, 2008.

Applicability Date: This final rule applies to travel performed on or after August 1, 2008. FOR FURTHER INFORMATION CONTACT The Regulatory Secretariat (VPR), Room 4041, GS Building, Washington, DC, 20405, (202) 501–4755, for information pertaining to status or publication schedules. For clarification of content, contact Patrick McConnell, Office of Governmentwide Policy, Travel Management Policy, at (202) 501–2362. Please cite FTR Amendment 2008–05; FTR case 2008–304. SUPPLEMENTARY INFORMATION:

A. Background

Pursuant to 5 U.S.C. 5707(b), the Administrator of General Services has the responsibility to establish the POV mileage reimbursement rates. The Acting Administrator of General Services has determined that the per- mile operating cost of each POV is as follows:

Airplane—Costs presented in the 1995 initial investigation of operating costs of privately owned aircraft are updated through GSA’s consultation with the Aircraft Owners and Pilots Association. The general methodology, in part, included information and items such as average U.S. retail price for aviation fuel, maintenance labor and parts, engine and propeller overhaul, and all items associated with determining a composite single engine piston aircraft reimbursement rate for Federal employees using their own aircraft while on official travel. The per- mile operating cost of a privately owned airplane is $1.26.

Automobile—A recent investigation revealed that the per-mile operating cost of a privately owned automobile is $0.585 cents. As provided in 5 U.S.C. 5704(a)(1), the automobile reimbursement rate cannot exceed the single standard mileage rate established by the Internal Revenue Service (IRS). On June 23, 2008, IRS announced a new single standard mileage rate for automobiles of $0.585 cents per mile effective July 1, 2008 to December 31, 2008.

Motorcycle—A report on the motorcycle mileage reimbursement rate prepared for GSA provides that the costs of operating a privately owned motorcycle for official travel now equals the mileage reimbursement rate set for official use of a privately owned automobile. The per-mile operating cost of a privately owned motorcycle is $0.585.

B. Executive Order 12866

This is not a significant regulatory action and, therefore, was not subject to review under Section 6(b) of Executive Order 12866, Regulatory Planning and Review, dated September 30, 1993. This final rule is not a major rule under 5 U.S.C. 804.

C. Regulatory Flexibility Act

This final rule is not required to be published in the Federal Register for notice and comment; therefore, the Regulatory Flexibility Act, 5 U.S.C. 601, et seq., does not apply.

D. Paperwork Reduction Act

The Paperwork Reduction Act does not apply because the changes to the Federal Travel Regulation do not impose recordkeeping or information collection requirements, or the collection of information from offerors, contractors, or members of the public that require the approval of the Office of Management and Budget under 44 U.S.C. 3501, et seq.

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Attachment #6

Document ID Title Date Posted Type Views

EPA‐HQ‐OAR‐2007‐0011‐0001 Standards of Performance for Petroleum Refineries 05/14/2007 Proposed Rules

EPA‐HQ‐OAR‐2007‐0011‐0002 NSPS Subpart J ‐ Impacts Table 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0003 Office of Management and Budget (OMB) Comments 23APR2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0004 Office of Management and Budget (OMB) Comments April 25, 2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0004.1 Office of Management and Budget (OMB) Comments April 26, 2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0004.2 Office of Management and Budget (OMB)Comments April 27, 2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0004.3 Office of Management and Budget (OMB) Comments April 27, 2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0005 Incidence of Federal and State Gasoline Taxes 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0006 Inventories and Market Power in the World Crude Oil Market 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0007 Gasoline demand revisited: an international meta‐analysis of elasticities 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0008 Tax Incidence 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0009 The Demand for Automobile Fuel: A Survey of Elasticities 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0010 Oil and Gas Journal. 2006. Worldwide Construction Update 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0011 Assessing the Employment Impacts of Environmental and Natural Resource Policy 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0012 Proposed Rule for Petroleum Refinery New Source Performance Standards (NSPS) Subpart J 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0013 Office of Management and Budget (OMB) Comments 30 April 2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0014 Record of Office of Management and Budget (OMB) Interagency Conference Call 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0015 Impacts on PM and SO2 from FCCU 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0016 FCCU Impacts Memo Appendices 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0017 Fuel Gas Impacts 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0018 Documentation of NOx Control Cost Estimates 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0019 Standards Support and Environmental Impact Statement Volume 1: Proposed Standards of Performance for Petroleum Refinery Sulfur Recovery Plants

05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0020 Alternative Flow Schemes to Reduce Capital and Operating Costs of Amine Sweetening Units 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0021 Sulfur Oxides Emissions from Fluid Catalytic Cracking Unit Regenerators ‐ Background Information for Proposed Standards 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0022 Bay Area Air Quality Management District Regulation 9: Inorganic Gaseous Pollutants, Rule 1: Sulfur Dioxide 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0023 Antelope Valley Air Quality Management District Rule 431.1: Sulfur Content Of Gaseous Fuels 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0024 Texas Natural Resource Conservation Commission Chapter 112 ‐ Control of Air Pollution From Sulfur Compounds 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0025 The Cost of Controlling Air Emissions Generated By FCCU's 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0026 Environmental Fluid Catalytic Cracking Technology 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0027 South Coast Air Quality Management District Rule 1146 ‐ Emissions of Oxides of Nitrogen from Industrial, Institutional, and Commercial Boilers, Steam Generators, and Process Heaters


EPA‐HQ‐OAR‐2007‐0011‐0028 Petroleum Refinery Tier 2 BACT Analysis Report 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0029 Low Temperature Oxidation System Demonstration at RSR Quemetco, Inc. 05/14/2007 Supporting & Related Materials


EPA‐HQ‐OAR‐2007‐0011‐0030 Bay Area Air Quality Management District Regulation 9: Inorganic Gaseous Pollutants ‐ Rule 10: Nitrogen Oxides and Carbon Monoxide from Boilers, Steam Generators and Process Heaters in Petroleum Refineries


EPA‐HQ‐OAR‐2007‐0011‐0031 South Coast Air Quality Management District Rule 1105.1 ‐ Reduction of PM10 and Ammonia Emissions from Fluid Catalytic Cracking Units. Rule and Supporting Documentation


EPA‐HQ‐OAR‐2007‐0011‐0032 Selective H2S Removal: ExxonMobil Research 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0033 Benefits of a Tail Gas Clean Up (TGCU) Amine Solvent Changeover: ExxonMobil Research 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0034 Emission Test Report for Compliance Testing of one Fluidized Catalytic Cracking Unit (FCCU) 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0035 Brochure and Case Studies for LO‐CAT: Knock Out Hydrogen Sulfide With LO‐CAT 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0036 Best Available Retrofit Technology (BART) Engineering Analysis 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0037 Bay Area Air Quality Management District (BAAQD) Staff Report Proposed Regulation 12 ‐ Flares at Petroleum Refineries 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0038 Electric Power Annual 2004 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0039 South Coast Air Quality Management District (SCAQMD) Rule 1118: Control of Emissions from Refinery Flares 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0040 Small Business Innovation Research (SBIR) Success Stories 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0041 Memorandum to Bob Lucas, EPA/ESD; NOx emissions, December 14, 2005 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0042 Memo to Bob Lucas, EPA/ESD; PM Emissions, December 20, 2005 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0043 Memo to Bob Lucas, EPA/ESD: VOC Emissions, December 14, 2005 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0044 Memorandum to Bob Lucas, USEPA, December 22, 2005 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0045 Memorandum to Bob Lucas, USEPA, January 17, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0046 Email to Bob Lucas, USEPA, February 23, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0047 Proposed Regulation ‐ Regulation 12, Miscellaneous Standards of Performance ‐ Rule 12, Flares at Petroleum Refineries 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0048 Refinery Capacity Report 2006; Energy Information Administration 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0049 Letter to Milind Bhatte, Environmental Lead, ConocoPhillips Trainer Refinery, July 13, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0050 Letter to Sean D. Horne, Valero Paulsboro confirming site visit, July 13, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0051 Letter to Andrew Kenner, Valero Delaware City 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0052 Letter to James A. Keeler, Sunoco Westvillle, July 14, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0053 Letter to Michael Drager, CITGO‐Paulsboro, July 13, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0054 Email to Dan Hunter and Milind Bhatte, ConocoPhillips 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0055 Email to Paul Johnston, Sunoco from Kristin Parrish, August 10, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0056 Email to Renae Schmidt and Janet Ferris, CITGO from Kristin Parrish, August 10, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0057 Letter to Robert Lucas, USEPA, August 31, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0058 Email to Jeff Coburn, RTI, September 6, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0059 Letter to Bob Lucas from Mike Drager, Plant Manager, Citgo, September 19, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0060 Part 2‐ Letter to Bob Lucas from Mike Drager, Citgo; Data., September 19, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0061 Part 3 Letter to Bob Lucas, USEPA from Mike Drager, Plant Manager, Citgo; Data., September 19, 2006 05/14/2007 Supporting & Related Materials


EPA‐HQ‐OAR‐2007‐0011‐0062 Part 4 ‐ Letter to Bob Lucas, USEPA from Mike Drager, Plant Manager, Citgo; Data , September 19, 2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0063 U.S. Geological Survey Minerals Yearbook 2005: Sulfur 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0064 Email to Jim Eddinger, USEPA et al. from Timothy J. Dougan, Davison Catalysts 11/06/2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0065 Email to Bob Lucas, USEPA from Matt Hodges, Valero Energy Corporation, 11/22/06 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0066 Design of Refinery Flares, Valero, 11/22/06 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0067 Texas Administrator Code, Part 1, Chapter 115 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0068 Natural Gas Navigator; Industrial Price 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0069 Email to Kristen Parrish, RTI International from Paul K. Johnson, Sunoco 1/22/07 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0070 Email to K. Parrish RTI International from Matthew Hodges, Valero 1/30/07 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0071 Email to Bob Lucas, USEPA from P. Foley, USEPA dated February 2, 2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0072 Email to Bob Lucas, USEPA from Ron Chittim, API, dated February 8, 2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0073 Email to Bob Lucas, USEPA from Ron Chittim, API ‐ priority issues dated February 27, 2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0074 Email to B. Lucas dated February 27, 2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0075 State of Louisiana Title 33, Part III, Chapt. 17 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0076 Facsimile to K.C. Hustvedt from Office of Management and Budget (OMB) 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0077 Sulfuric Acid Plant Tail Gas Cleanup with CANSOLV System SO2 Scrubbing Technology 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0078 The CANSOLV System Process: A New Paradigm for SO2 Recovery and Recycle 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0079 LoTOx NOx Reduction ‐ Installation List 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0080 Background Information ‐ Petroleum Refineries 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0081 BID for Petroleum Refineries ‐ Volume 2 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0082 Background Information for Petroleum Refineries ‐ Volume 3 [EPA‐450/2‐74‐003] 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0083 Enforcement Alert ‐ Routine Flaring [EPA‐300‐N‐00‐014] Revised 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0084 Memorandum to Jeff Coburn from Dan Roper, ERG, April 30, 2007 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0085 Review of Fluid Coking and Flexicoking 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0086 Memorandum to Bob Lucas ‐ FCCU Analysis 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0087 Memorandum to Bob Lucas, USEPA ‐ Fuel Gas Combustion SO2 Impacts Data 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0088 Memorandum to Bob Lucas, USEPA ‐ Sulfur Recovery Plants 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0089 Memorandum to Bob Lucas, USEPA ‐ Nitrogen Oxides 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0090 Reducing Flare Emissions from Chemical Plants and Refineries 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0091 Flare Gas Recovery Systems ‐ John Zink Company, LLC 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0092 Driving the Future of Clean Combustion ‐ John Zink Company LLC 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0093 Review of CANSOLV® SO2 Scrubbing System's First Commercial Operations and Application in the Oil and Gas Industry 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0094 LoTOx Technology Demonstration at Marathon Ashland Petroleum LLC's Refinery in Texas City, Texas 05/14/2007 Supporting & Related Materials


EPA‐HQ‐OAR‐2007‐0011‐0095 Email to Bob Lucas, USEPA 5/9/2006 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0096 Report on the LABSORB Regenerative SO2 Scrubbing System application at the Eni S.p.A. refinery FCCU in Sannazzaro, Italy 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0097 Re‐evaluate Recycling Options for the Claus Unit 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0098 Standards Support and Environmental Impact Statement Volume II: Promulgated Standards of Performance For Petroleum Refinery Sulfur Recovery Plants [EPA‐450/2‐76‐016‐b]


EPA‐HQ‐OAR‐2007‐0011‐0099 Sulfur Oxides Emissions from Fluid Catalytic Cracking Unit Regenerators [EPA‐450/3‐82‐013b] 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0100 TCEQ Chemical Sources: Current Best Available Control Technology (BACT) Requirements 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0101 Air Permit Technical Guidance for Chemical Sources: Sulfur Recovery Units 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0102 An Update of Wet Scrubbing Control Technology for FCCUS‐Multiple Pollutant Control [AM‐03‐120] 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0103 Assessing the Employment Impacts of Environmental and Natural Resource Policy 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0104 Incidence of Federal and State Gasoline Taxes 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0105 Inventories and Market Power in the World Crude Oil Market 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0106 Tax Incidence 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0107 The Demand for Automobile Fuel: A Survey of Elasticities 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0108 Oil and Gas Journal; Worldwide Construction Update 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0109 Regulatory Impact Analysis for the Proposed Petroleum Refinery NSPS [EPA‐452/R‐07‐006] 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0110 Master Report Table from Flaring Events 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0111 Gasoline Demand Revisited: an international meta‐analysis of elasticities 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0112 EPA Enforcement: National Petroleum Refinery Initiative 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0113 Meeting Minutes for various conference calls between the USEPA and representatives of the Petroleum Refining Industry 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0114 Meeting Minutes for October 26, 2006 Meeting with USEPA and representatives of the Petroleum Refining Industry 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0115 Location of Coking Tutorial 05/14/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0116 Comment submitted by Patrick M. Kariuki, International Division, Texas Refinery Corporation 05/14/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0117 OMB (Office of Management and Budget) Proposal Package for Subparts J and Ja: Standards of Performance for Petroleum Refineries


EPA‐HQ‐OAR‐2007‐0011‐0118 Form for Compliance with E.O. 12866 Docket Requirements 05/21/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0119 Source Test Data 06/12/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0120 Standards of Performance for Petroleum Refineries; Extension of Public Comment Period 06/28/2007 Proposed Rules

EPA‐HQ‐OAR‐2007‐0011‐0121 Comment submitted by Glenn Shankle, Executive Director, Texas Commission on Environmental Quality (TCEQ) 08/04/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0121.1 Comment attachment submitted by Glenn Shankle, Executive Director, Texas Commission on Environmental Quality (TCEQ) 08/04/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0122 Anonymous Public Comment 08/23/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0123 Comment submitted by Richard T. Metcalf, Health, Safety and Environmental Affairs Coordinator, Louisiana Mid‐Continent Oil and Gas Association

08/23/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0123.1 Comment attachment submitted by Richard T. Metcalf, Health, Safety and Environmental Affairs Coordinator, Louisiana Mid‐Continent Oil and Gas Association



EPA‐HQ‐OAR‐2007‐0011‐0124 Comment submitted by Larry Zink, President, Montana Sulphur & Chemical Co. (MSCC) 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0124.1 Comment attachment submitted by Larry Zink, President, Montana Sulphur & Chemical Co. (MSCC) 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0125 Comment submitted by Robert Hermanson, Senior Environmental Consultant, US Refining & Marketing, Environmental Performance, BP America, Inc.


EPA‐HQ‐OAR‐2007‐0011‐0125.1 Comment attachment submitted by Robert Hermanson, Senior Environmental Consultant, US Refining & Marketing, Environmental Performance, BP America, Inc.


EPA‐HQ‐OAR‐2007‐0011‐0126 Comment submitted by Lucy Ann Randel, Research Director, on behalf of Industry Professionals for Clean Air (IPCA), Galveston‐Houston Association for Smog Prevention, and Mothers for Clean Air


EPA‐HQ‐OAR‐2007‐0011‐0126.1 Comment attachment submitted by Lucy Ann Randel, Research Director, on behalf of Industry Professionals for Clean Air (IPCA), Galveston‐Houston Association for Smog Prevention, and Mothers for Clean Air


EPA‐HQ‐OAR‐2007‐0011‐0126.2 Comment attachment submitted by Lucy Ann Randel, Research Director, on behalf of Industry Professionals for Clean Air (IPCA), Galveston‐Houston Association for Smog Prevention, and Mothers for Clean Air


EPA‐HQ‐OAR‐2007‐0011‐0127 Comment submitted by Brian Bunger for Jack P. Broadbent, Executive Officer/APCO, Bay Area Air Quality Management District


EPA‐HQ‐OAR‐2007‐0011‐0127.1 Comment attachment submitted by Brian Bunger for Jack P. Broadbent, Executive Officer/APCO, Bay Area Air Quality Management District


EPA‐HQ‐OAR‐2007‐0011‐0128 Comment submitted by Tim Ballo, Earthjustice on behalf of Environmental Integrity Project (EIP) and Sierra Club 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0128.1 Comment attachment submitted by Tim Ballo, Earthjustice on behalf of Environmental Integrity Project (EIP) and Sierra Club


EPA‐HQ‐OAR‐2007‐0011‐0129 Comment submitted by Sally V. Allen, Gary‐Williams Energy Corporation, on behalf of the Ad Hoc Coalition of Small Refiners


EPA‐HQ‐OAR‐2007‐0011‐0129.1 Comment attachment submitted by Sally V. Allen, Gary‐Williams Energy Corporation, on behalf of the Ad Hoc Coalition of Small Refiners






EPA‐HQ‐OAR‐2007‐0011‐0130 Comment submitted by Benjamin J. Wakefield, Counsel on behalf of Environmental Integrity Project and Sierra Club 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0130.1 Comment attachment submitted by Benjamin J. Wakefield, Counsel on behalf of Environmental Integrity Project and Sierra Club


EPA‐HQ‐OAR‐2007‐0011‐0131 Comment submitted by George Garten, Lion Oil Company 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0131.1 Comment attachment submitted by George Garten, Lion Oil Company 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0132 Comment submitted by Richard Smullen, Vice President, Environmental Health and Safety, HOVENSA, LLC 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0132.1 Comment attachment submitted by Richard Smullen, Vice President, Environmental Health and Safety, HOVENSA, LLC 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0133 Comment submitted by Sally V. Allen, Vice President, Administration & Governmental Affairs, Gary‐Williams Energy Corporation on behalf of AD HOC Coalition of Small Business Refiners


EPA‐HQ‐OAR‐2007‐0011‐0133.1 Comment attachment submitted by Sally V. Allen, Vice President, Administration & Governmental Affairs, Gary‐Williams Energy Corporation on behalf of AD HOC Coalition of Small Business Refiners


EPA‐HQ‐OAR‐2007‐0011‐0134 Comment submitted by Timothy Ballo, Associate Attorney, on behalf of Environmental Integrity Project and Sierra Club 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0134.1 Comment attachment submitted by Timothy Ballo, Associate Attorney, on behalf of Environmental Integrity Project and 08/28/2007 Public Submissions


Sierra Club

EPA‐HQ‐OAR‐2007‐0011‐0135 Comment submitted by Peter Haid, Environmental Manager, Hess Corporation 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0135.1 Comment attachment submitted by Peter Haid, Environmental Manager, Hess Corporation 08/28/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0136 Comment submitted by Terry Fleming, Executive Director, Ohio Petroleum Council 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0136.1 Comment attachment submitted by Terry Fleming, Executive Director, Ohio Petroleum Council 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0137 Comment submitted by Erin T. Roth, Executive Director, Wisconsin Petroleum Council (WPC) 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0137.1 Comment attachment submitted by Erin T. Roth, Executive Director, Wisconsin Petroleum Council (WPC) 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0138 Comment submitted by Deepak Garg, Executive Director, Environmental Services, Valero Energy Corporation 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0138.1 Comment attachment submitted by Deepak Garg, Executive Director Environmental Services, Valero Energy Corporation 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0139 Comment submitted by Lisa B. Barry, Vice President and General Manager, Chevron Governmental Affairs, Chevron Corporation


EPA‐HQ‐OAR‐2007‐0011‐0139.1 Comment attachment submitted by Lisa B. Barry, Vice President and General Manager, Chevron Governmental Affairs, Chevron Corporation


EPA‐HQ‐OAR‐2007‐0011‐0140 Comment submitted by John A. Maxwell, Associate Director, New Jersey Petroleum Council 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0141 Comment submitted by John M. Griffin, Executive Director, Associated Petroleum Industries of Michigan (APIM) 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0142 Comment submitted by Steve Smith, Environmental Issues Manager, Lyondell Chemical Company 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0143 Comment submitted by Maggie McShane, Executive Director, Indiana Petroleum Council (IPC) 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0144 Comment submitted by Ron Ness, President, North Dakota Petroleum Council 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0145 Comment submitted by Gary B. Patterson, Executive Director, Delaware Petroleum Council 08/29/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0146 Comment submitted by Ali Mirzakhalili, P. E., Administrator, Delaware Department of Natural Resources & Environmental Control (DNREC)


EPA‐HQ‐OAR‐2007‐0011‐0147 Comment submitted by Brian Bunger on behalf of Jack P. Broadbent, Executive Officer/Air Pollution Control Officer (APCO), Bay Area Air Quality Management District (BAAQMD)


EPA‐HQ‐OAR‐2007‐0011‐0148 Comment submitted by Chuck Feerick, New Source Review (NSR) CD Program Coordinator, Downstream & Chemicals SH&E, ExxonMobil Refining and Supply Company


EPA‐HQ‐OAR‐2007‐0011‐0149 Comment submitted by Bob Hodanbosi, Co‐Chair(Ohio) and Ursula Kramer, Co‐Chair (Tucson, Arizona), National Association of Clean Air Agencies (NACAA) Permitting Committee


EPA‐HQ‐OAR‐2007‐0011‐0150 Comment submitted by Dan F. Hunter, Manager, Regulatory Issues, ConocoPhillips 09/04/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0151 Comment submitted by Joseph K. Sims, President, US Oil and Gas Association (USOGA) 09/04/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0152 Comment submitted by Mohsen Nazemi, P.E., Assistant Deputy Executive Officer, Engineering and Compliance, South Coast Air Quality Management District (SCAQMD)


EPA‐HQ‐OAR‐2007‐0011‐0153 Comment submitted by Jack R. Pounds, President, Ohio Chemistry Technology Council (OCTC) 09/04/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0154 Comment submitted by American Petroleum Institute (API), National Petrochemical and Petroleum Refiners Association (NPRA), and Western States Petroleum Association (WSPA)


EPA‐HQ‐OAR‐2007‐0011‐0154.1 Comment attachment submitted by American Petroleum Institute (API), National Petrochemical and Petroleum Refiners Association (NPRA), and Western States Petroleum Association (WSPA)


EPA‐HQ‐OAR‐2007‐0011‐0155 Comment submitted by Mark Asmundson, Director,Northwest Clean Air Agency (NWCAA) 09/05/2007 Public Submissions


EPA‐HQ‐OAR‐2007‐0011‐0156 Comment submitted by Allen Greene, Manager of Environmental Protection, CITGO Petroleum Corporation 09/05/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0157 Comment submitted by Tom Parker, Executive Director, Arkansas Petroleum Council (APC) 09/06/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0158 Comment submitted by Debbie M. Hastings, Vice‐President fof Environmental Affairs,Texas Oil and Gas Association (TXOGA)


EPA‐HQ‐OAR‐2007‐0011‐0159 Comment submitted by Marathon Petroleum Company LLC 09/06/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0160 Comment submitted by Mark Asmundson, Director, Northwest Clean Air Agency (NWCAA) 09/13/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0161 Comment submitted by Theodore Metrose, Environmental Manager, Tesoro Hawaii Corporation 10/04/2007 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0162 Bay Area Air Quality Management District (BAAQMD) Flare Rule 10/18/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0163 SO2 (Sulfur Dioxide) Compliance Flint Hills Resources, LP (FHR) 10/18/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0164 John Zinc Flare gas recovery (Minimize flaring with flare gas recovery) 10/20/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0165 Meeting Minutes for March 28, 2006 10/20/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0166 RTR Docket Data Files Index 10/20/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0167 Handbook Control Technologies for Hazardous Air Pollutants [EPA/625/6‐91/014] 10/20/2007 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0168 Standards of Performance for Petroleum Refineries 12/07/2007 Notices

EPA‐HQ‐OAR‐2007‐0011‐0169 Comment submitted by K. Comey 01/07/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0170 Comment submitted by Ruth A. Cade, Environmental Coordinator, Refining, Marathon Petroleum Company 01/08/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0170.1 Comment attachment submitted by Ruth A. Cade, Environmental Coordinator, Refining, Marathon Petroleum Company 01/08/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0171 Comment submitted by B. Lane 01/08/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0172 Comment submitted by Ron Chittim, American Petroleum Institute (API) and the National Petrochemical and Refiners Association (NPRA)


EPA‐HQ‐OAR‐2007‐0011‐0172.1 Comment attachment submitted by Ron Chittim, American Petroleum Institute (API) and the National Petrochemical and Refiners Association (NPRA)


EPA‐HQ‐OAR‐2007‐0011‐0173 Comment submitted by Christopher G. Swanberg, Vice President, Environmental, Health and Safety, CVR Energy 01/09/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0173.1 Comment attachment submitted by Christopher G. Swanberg, Vice President, Environmental, Health and Safety, CVR Energy


EPA‐HQ‐OAR‐2007‐0011‐0174 Comment submitted by Ron Chittim, American Petroleum Institute (API), the National Petrochemical , Refiners Association (NPRA), and Western States Petroleum Association (WSPA)


EPA‐HQ‐OAR‐2007‐0011‐0174.1 Comment attachment submitted by Ron Chittim, American Petroleum Institute (API), the National Petrochemical , Refiners Association (NPRA), and Western States Petroleum Association (WSPA)


EPA‐HQ‐OAR‐2007‐0011‐0175 Comment submitted by Ruth Cade, Environmental Coordiator, Refining, Marathon Petroleum Company 02/07/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0175.1 Comment attachment submitted by Ruth Cade, Environmental Coordiator, Refining, Marathon Petroleum Company 02/07/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0175.2 Comment attachment submitted by Ruth Cade, Environmental Coordiator, Refining, Marathon Petroleum Company 02/07/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0176 Comment submitted by Kathleen C. Antoine, Environmental Director, HOVENSA LLC 02/12/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0176.1 Comment attachment submitted by Kathleen C. Antoine, Environmental Director, HOVENSA LLC 02/12/2008 Public Submissions





EPA‐HQ‐OAR‐2007‐0011‐0177 Comment submitted by John Sawyer, Pall Corporation 03/19/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0177.1 Comment attachment submitted by John Sawyer, Pall Corporation 03/19/2008 Public Submissions

EPA‐HQ‐OAR‐2007‐0011‐0178 Comment submitted by Ruth A. Cade, Environmental Coordinator, Refining, Marathon Petroleum Company, LLC (Marathon)


EPA‐HQ‐OAR‐2007‐0011‐0178.1 Comment submitted by Ruth A. Cade, Environmental Coordinator, Refining, Marathon Petroleum Company, LLC (Marathon)


EPA‐HQ‐OAR‐2007‐0011‐0178.2 Comment attachment submitted by Ruth A. Cade, Environmental Coordinator, Refining, Marathon Petroleum Company, LLC (Marathon)


EPA‐HQ‐OAR‐2007‐0011‐0178.3 Comment attachment submitted by Ruth A. Cade, Environmental Coordinator, Refining, Marathon Petroleum Company, LLC (Marathon)


EPA‐HQ‐OAR‐2007‐0011‐0179 Standards of Performance for Petroleum Refineries 06/24/2008 Rules

EPA‐HQ‐OAR‐2007‐0011‐0180 Evaluation of the Particulate Test Method for FCCU Regenerator Emissions 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0181 Method 5.2: Determination of Particulate Matter Emissions from Stationary Sources Using Heated Probe and Filter 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0182 National Air Pollution Control Techniques Advisory Committee: Minutes of Meeting ‐ November 29 and 30, 1983 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0183 Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0184 Summary of Comments and Responses for Methods 5B and 5F (EPA‐450/3‐86‐008) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0185 Development and Evaluation of Method 5B ‐‐ Background Information for Proposed Reference Method (EPA‐450/3‐84‐16) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0186 Source Test Report conducted at Conoco‐Phillips Refinery, Carson, California ‐‐ Volatile Organic Compound (VOC), Speciated Hydrocarbons, Aromatic Hydrocarbons, Carbon Monoxide (CO), and Particulate Matter (PM) Emissions from a Coke Drum Steam Vent


EPA‐HQ‐OAR‐2007‐0011‐0187 Source Test Report conducted at Chevron / Texaco Refinery, El Segundo, California ‐‐ Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions from a Coke Drum Steam Vent


EPA‐HQ‐OAR‐2007‐0011‐0188 Source Test Report conducted at Exxon Mobil Refinery, Torrance, California ‐‐ Volatile Organic Compound (VOC), Speciated Hydrocarbons, Aromatic Hydrocarbons, Carbon Monoxide (CO), and Particulate Matter (PM) Emissions from a Coke Drum Steam Vent


EPA‐HQ‐OAR‐2007‐0011‐0189 Source Test Report conducted at Shell Oil Refinery, Wilmington, California ‐‐ Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions from a Coke Drum Steam Vent


EPA‐HQ‐OAR‐2007‐0011‐0190 Minimize facility flaring: Flares are safety devices that prevent the release of unburned gases to atmosphere 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0191 FCC Flue Gas Blowback Filter: Particulate Emission Control 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0192 Valero: Houston Refinery Uses Plant‐Wide Assessment to Develop an Energy Optimization and Management System [DOE/GO‐102005‐2121]


EPA‐HQ‐OAR‐2007‐0011‐0193 UOP MeroxTM Process for Gas Extraction 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0194 Integrated View to Understanding the FCC NOx Puzzle 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0195 Sulfur Recovery Feasibility Study for Rompetrol Refining S.A. 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0196 High Efficiency, Ultra‐Low Emission, Integrated Process Heater System: Final Technical Report 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0197 BP Australia Installs & Commissions Pall GSS 3rd Stage Blowback Filter System to Reduce RCCU Flue Gas Emissions 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0198 Envirocomb Limited ‐ Zero Flaring by Flare Gas Recovery 06/24/2008 Supporting & Related Materials


EPA‐HQ‐OAR‐2007‐0011‐0199 John Zink: Flare Gas Recovery (FGR) to Reduce Plant Flaring Operations 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0200 Natural Gas Navigator: Natural Gas Prices 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0201 May 2006 National Industry‐Specific Occupational Employment and Wage Estimates: NAICS 324000 ‐ Petroleum and Coal Products Manufacturing


EPA‐HQ‐OAR‐2007‐0011‐0202 Status of Data Request and SO2 Limits for Fluid Catalytic Cracking Units (FCCU) (February 5, 2008) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0203 Natural Gas Annual 2006 [DOE/EIA‐0131(06)] 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0204 Electric Power Annual 2006 [DOE/EIA‐0348(2006)] 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0205 Mineral Commodity Summaries 2007 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0206 2005 Worldwide Refining Survey 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0207 Industry Information on Heater NOx, Flare Management Plans, & Sulfur Pit Vent Controls (March 28, 2008) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0208 Industry Information on TRS Monitoring (March 20, 2008) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0209 Test reports for Marathon Petroleum Company, LLC, Catlettsburg, Kentucky (February 22, 2008) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0210 Industry Information on Fluid Cat Cracking Units (FCCU) NOx (March 21, 2008) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0211 Implementation Status Report for 2006 for Rule 1118 – Control of Emissions from Refinery Flares 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0212 Applicability Determination for Shell Oil Products US (Shell), Deer Park Refining Limited Partnership (Deer Park) and Motiva Enterprises LLC (Motiva) Flares (April 10, 2008)


EPA‐HQ‐OAR‐2007‐0011‐0213 Refinery New Source Performance Standards (NSPS) – List of Confidential Business Information Documents 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0214 New Source Performance Standard (NSPS) Subparts J/Ja ‐Meeting Minutes for June 4, 2007 ‐ Meeting Between the USEPA and Representatives of the Petroleum Refining Industry (March 20, 2008)


EPA‐HQ‐OAR‐2007‐0011‐0215 New Source Performance Standard (NSPS) Subparts J/Ja ‐Meeting Minutes for August 6, 2007 ‐ Meeting Between the USEPA and Representatives of the Petroleum Refining Industry (April 28, 2008)


EPA‐HQ‐OAR‐2007‐0011‐0216 New Source Performance Standard (NSPS) Subparts J/Ja: Meeting Minutes for August 10, 2007 Conference Call Between the USEPA and Representatives of the Petroleum Refining Industry (March 20, 2008)


EPA‐HQ‐OAR‐2007‐0011‐0217 New Source Performance Standard (NSPS) Subparts J/Ja ‐Meeting Minutes for September 19, 2007 ‐ Meeting Between the USEPA and Representatives of Valero Energy Corporation


EPA‐HQ‐OAR‐2007‐0011‐0218 New Source Performance Standard (NSPS) Subpart J Review ‐Meeting Minutes for December 12, 2007, Meeting Between the USEPA and Representatives of the Petroleum Refining Industry


EPA‐HQ‐OAR‐2007‐0011‐0219 New Source Performance Standard (NSPS) Subparts J/Ja: Meeting Minutes for February 27, 2008; Meeting between the USEPA and Representatives of the Petroleum Refining Industry


EPA‐HQ‐OAR‐2007‐0011‐0220 Industry Meeting with Robert Meyers on 4/4/2008 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0221 New Source Performance Standard (NSPS) Subparts J/Ja ‐Meeting Minutes for April 10, 2008 ‐ Meeting between the USEPA and Representatives of the Petroleum Refining Industry


EPA‐HQ‐OAR‐2007‐0011‐0222 Documentation of Final NOx Control Cost Estimates ‐ 4/28/2008 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0222.1 Calculation Spreadsheet for NOx Emissions from FCCU 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0222.2 Calculation spreadsheet for NOx emissions from FCU 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0222.3 Calculation spreadsheet for NOx emissions from Process Heaters 06/24/2008 Supporting & Related Materials


EPA‐HQ‐OAR‐2007‐0011‐0223 Documentation of Flare Recovery Impact Estimates 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0223.1 Calculation spreadsheet for emissions from Flares 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0224 Memorandum to Bob Lucas, USEPA/SPPD Re: Final Impacts Analysis for SO2 Emissions from Sulfur Recovery Plants. March 17, 2008


EPA‐HQ‐OAR‐2007‐0011‐0225 Final Impacts Analysis for SO2 Emissions from Fuel Gas Combustion Devices. April 24, 2008 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0226 Final Impacts Analysis for Delayed Coker Depressurization Emissions. April 28, 2008 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0226.1 Calculation spreadsheet for delayed coker depressurization 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0227 Final Impacts Analysis for PM and SO2 Emissions from Fluid Catalytic Cracking Units (FCCU) and Fluid Coking Units (FCU) ‐4/28/2008


EPA‐HQ‐OAR‐2007‐0011‐0227.1 Calculation spreadsheet for PM and SO2 emissions from Fluid Catalytic Cracking Units (FCCU) and Fluid Coking Units (FCU) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0228 Standards of Performance for Petroleum Refineries: Background Information for Final Standards ‐ Summary of Public Comments and Responses


EPA‐HQ‐OAR‐2007‐0011‐0229 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990‐2005. Executive Summary (EPA 430‐R‐07‐002) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0230 SAN 5036 ‐ New Source Performance Standards (NSPS) Review for Petroleum Refineries – subpart J/Ja 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0231 Materials used in meetings with Cortney Higgins and Art Fraas of Office of Management and Budget (OMB) on 3/27/08 and 4/15/08


EPA‐HQ‐OAR‐2007‐0011‐0232 Email transmitting Industry Information on Heater NOx, Flare Management Plans & Sulfur Pit Vent Controls (April 25, 2008)


EPA‐HQ‐OAR‐2007‐0011‐0233 Courtesy copy of Standards of Performance for Petroleum Refineries for Office of Management and Budget (OMB) ‐4/23/2008


EPA‐HQ‐OAR‐2007‐0011‐0234 Copy of Standards of Performance for Petroleum Refineries for Office of Management and Budget (OMB) ‐ 4/30/2008 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0235 Summary of Office of Management and Budget (OMB) Meetings ‐‐ Petroleum Refinery New Source Performance Standards (NSPS) Subpart J/Ja ‐ 4/30/2008


EPA‐HQ‐OAR‐2007‐0011‐0236 Draft Regulatory Impact Analysis (RIA) ‐Petroleum Refineries New Source Performance Standard (NSPS) ‐ for submittal to Offiice of Management and Budget (OMB) (April 23, 2008)


EPA‐HQ‐OAR‐2007‐0011‐0236.1 Draft Regulatory Impact Analysis (RIA) Section 1 ‐ Executive Summary 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0236.2 Draft Regulatory Impact Analysis (RIA) Section 2 ‐ Introduction 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0236.3 Draft Regulatory Impact Analysis (RIA) Section 3 ‐ Industry Profile 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0236.4 Draft Regulatory Impact Analysis (RIA) Section 4 ‐ New Source Performance Standards (NSPS) Regulatory Options, Costs and Emission Reductions from Complying with the NSPS


EPA‐HQ‐OAR‐2007‐0011‐0236.5 Draft Regulatory Impact Analysis (RIA) Section 5 ‐ Economic Impact Analysis: Methods and Results 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0236.6 Draft Regulatory Impact Analysis (RIA) Section 6 ‐ Small Business Analysis 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0236.7 Draft Regulatory Impact Analysis (RIA) Section 7 ‐ Human Health Benefits of Emissions Reductions 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0236.8 Draft Regulatory Impact Analysis (RIA) Appendix B: Summary of Significant Comments and Responses, and Rationales for New Source Performance Standards (NSPS) Emission Limits



EPA‐HQ‐OAR‐2007‐0011‐0236.9 Draft Regulatory Impact Analysis (RIA) Appendix C: Overview of Economic Model Equations 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0237 Revised benefits chapter ‐ refineries NSPS final Regulatory Impact Analysis (RIA) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0238 Table 1: Summary of Intermediate‐Run Economic Impacts by Petroleum Product: 2012 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0239 Regulatory Impact Analysis (RIA) of the Petroleum Refinery New Source Performance Standards (NSPS) 06/24/2008 Supporting & Related Materials

EPA‐HQ‐OAR‐2007‐0011‐0240 Supporting Statement: Environmental Protection Agency NSPS Subpart Ja ‐ Standards of Performance for Petroleum Refineries


EPA‐HQ‐OAR‐2007‐0011‐0241 Voluntary Consensus Standard Results for Amendments to Standards of Performance for Petroleum Refineries (Subpart J) and Standards of Performance for Petroleum Refineries for which Construction, Reconstruction, or Modification Commenced After May 14, 2007 (Subpart Ja) (April 30, 2008)


Attachment #7