TECHNICAL SUPPORT DOCUMENT 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and Standard Permit 

Applicability 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

Revisions submitted on September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; 

February 1, 2006; and March 11, 2011 

December 3, 2013 

FOR FURTHER INFORMATION CONTACT: Ms. Ashley Mohr, United States Environmental 

Protection Agency Region 6, Air Permits Section (6PD-R), 1445 Ross Avenue, Suite 1200, 

Dallas, Texas, 75202-2733, (214) 665-7289 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

1 

Discussion of Revisions to 30 TAC 116.610(a) and (b), 116.617(3), and 116.620 – Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities (Oil and Gas Standard 

Permit) and Standard Permit Applicability Provisions 

I. Introduction.

A. Overview. This Technical Support Document (TSD) is a technical evaluation of 

submitted revisions to the Texas Minor New Source Review (NSR) State 

Implementation Plan (SIP) that relate to the Oil and Gas Standard Permit and the 

Standard Permit applicability provisions. Specifically, this is an evaluation of SIP 

revisions to the Title 30 of the Texas Administrative Code (30 TAC), Chapter 

116, Section 610, Paragraphs a and b, Section 617, Paragraph 3, and Section 620. 

B. What are we addressing in this action? EPA is addressing portions of the SIP 

revisions identified below that relate to the Oil and Gas Standard Permit 

provisions and the Standard Permit applicability provisions. Additional 

information regarding the revisions addressed in this action is included in Tables 

1 and 2 in Section II, and in Appendix B. 

 Submitted September 20, 1995: Standard Permits. Establishes Standard 

Permit for Oil and Gas Facilities at 30 TAC 116, Section 617, Paragraph 3. 

 Submitted April 19, 1996: MSW Standard Permits. Moves Standard Permit 

for Oil and Gas Facilities to newly established 30 TAC Chapter 116, Section 

620 and revises the Standard Permit. 

 Submitted July 22, 1998: NSR Rule Revisions; §112(g). Revises Standard 

Permit for Oil and Gas Facilities in Section 620. (Rule Log Number 98001-

116-AI) 

 Submitted September 11, 2000: Air Permits (SB 766). Revises Standard 

Permit for Oil and Gas Facilities in Section 620. (Rule Log Number 1999-

29B-116-AI) 

 Submitted February 1, 2006: Chapter 116 NSR Rule Revisions. Revised 

Paragraphs a and b of the Standard Permit applicability provisions in Section 

610. (Rule Log Number 2005-01 0-1 16-PR) 

 Submitted March 11, 2011: Chapter 116 NSR Rule Revisions. Resubmittal

of the changes to the Standard Permit applicability provisions in Section 610 

adopted in 2006. (Rule Log Number 2010-008-116-PR)
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

2 

C. What are we not addressing in this action? As part of this action, EPA is 

reviewing only those portions of the aforementioned submittals that are applicable 

to the Oil and Gas Standard Permit and the Standard Permit applicability 

provisions. The SIP submittals addressed in this action also include additional 

unrelated, severable, revisions to 30 TAC Chapters 101 and 116, which are not 

addressed as part of this action. 

II. Overview of the Submitted Revisions to Chapter 116, Section 610, Paragraphs a and 

b, Section 617, Paragraph 3, and Section 620.

A. Are any of the rules and regulations which are evaluated in this action currently 

SIP-approved? The rules and regulations which relate to the Oil and Gas Standard 

Permit are not currently SIP-approved. The Standard Permit applicability 

provisions contained in Section 610(a) and (b) are currently SIP-approved. 

B. What are we reviewing in this action? The pending SIP revisions are summarized 

in Tables 1 and 2 below. See the Appendix for further details on the specific 

changes that were submitted. 

Table 1. Summary of Pending SIP Submittals Addressed in this Action 

Title of SIP submittal Date 

submitted 

to EPA 

Date of 

State 

adoption 

Affected Regulations Related to Oil and Gas Standard 

Permit 

Standard Permits 09/20/1995 07/26/1995 Addition of New Paragraph 30 TAC 116.617(3) – 

Installation and/or Modification of Oil and Gas Facilities 

 Established a Standard Permit for Oil and Gas 

Facilities 

MSW Standard Permits 04/19/1996 03/26/1996 Deletion of 30 TAC 116.617(3) – Installation and/or 

Modification of Oil and Gas Facilities 

Addition of New Section 30 TAC 116.620 – Installation 

and/or Modification of Oil and Gas Facilities. 

 Deletion of 30 TAC 116.617(3) – Installation and/or 

Modification of Oil and Gas Facilities 

 The Oil and Gas Standard Permit was moved and 

renumbered from 116.617(3) to 116.620 and 

sections renumbered to conform these sections to 

Texas Register style conventions 

NSR Rule Revisions; 

§112(g) 

07/22/1998 06/17/1998 Revision to 30 TAC 116.620 – Installation and/or 

Modification of Oil and Gas Facilities 

Air Permits (SB 766) 09/11/2000 04/07/2000 Revision to 30 TAC 116.620 – Installation and/or 

Modification of Oil and Gas Facilities 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

3 

Title of SIP submittal Date 

submitted 

to EPA 

Date of 

State 

adoption 

Affected Regulations Related to Oil and Gas Standard 

Permit 

Chapter 116 NSR Rule 

Revisions 

02/01/2006 01/11/2006 Revision to 30 TAC 116.610 – Standard Permits 

Applicability 

Chapter 116 NSR Rule 

Revisions 

03/11/2011 01/11/2006 Resubmittal of January 11, 2006 revisions to 30 TAC 

116.610 

Table 2. Summary of the Individual Revisions to Each Section Evaluated 

Section Title Date 

submitted 

to EPA 

Adopted 

by State 

Comments 

Chapter 116 – Control of Air Pollution by Permits New Construction or Modification 

Subchapter F – Standard Permits 

Section 

116.610 

Applicability 02/01/06 01/11/06  Non-substantive revisions to 

§116.620(a) and (b) 

03/11/11 01/11/06  Resubmittal of 2006 adopted changes to 

§116.620(a) and (b)

Section 

116.617(3) 

Installation and/or 

Modification of Oil 

and Gas Facilities 

09/20/95 07/26/95  Initial adoption of §116.617(3) 

Section 

116.620 

Installation and/or 

Modification of Oil 

and Gas Facilities 

04/19/96 03/27/96  Deleted §116.617(3) and moved 

Standard Permit to newly adopted 

§116.620 

o Moving the Standard Permit from a 

paragraph to a section required 

renumbering to conform to Texas 

Register style conventions 

7/22/98 06/17/98  Revisions to §116.620(a)(4) 

 Revisions to §116.620(a)(13) 

 §116.620(a)(14) was subdivided into 

sections 116.620(a)(14) – (15) 

 Added §116.620(a)(16) 

 Renumbered §116.620(a)(15) – (16) to 

§116.620(a)(17) and (18) 

 Revisions to §116.620(b)(1) added 

reference to PBR 106.476 

 Revisions to §116.620(c)(1)(A) 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

4 

Section Title Date 

submitted 

to EPA 

Adopted 

by State 

Comments 

 Revisions to §116.620(c)(1)(J) 

 Revisions to §116.620(c)(2)(J) 

 Revisions to §116.620(d)(3) 

 Revisions to §116.620(e)(1) 

09/11/00 04/07/00  Revisions to §116.620(a)(4) 

 Revisions to §116.620(a)(11) 

 Revisions to §116.620(b)(1) 

 Revisions to §116.620(b)(E) 

 Revisions to §116.620(c)(1)(J) 

III. Proposed Revisions to the Standard Permit Applicability Provisions

On February 1, 2006, and March 11, 2011, the State of Texas submitted revisions to the 

Standard Permit SIP rules, which included non-substantive revisions to the applicability 

provisions in 30 TAC 116.610(a) and (b). The revisions to these paragraphs included 

changes such as defining previously undefined acronyms, changing capitalization, 

rephrasing of rule language, and updating or deleting cross-references as appropriate due 

to revisions to other Sections of the state regulations. Based on our review of the 

proposed changes, we propose to find these changes to 30 TAC 116.610(a) and (b) to be 

approvable because they are ministerial and non-substantive in nature. 

IV. Summary of the Oil and Gas Standard Permit

A. General Description of the Texas Standard Permits Program

EPA approved Texas’ general regulations for Standard Permits in 30 TAC 

Subchapter F of 30 TAC Chapter 116 on November 14, 2003 (68 FR 64543) as 

meeting the federal requirements for Minor NSR.1

 The November 14, 2003 action 

describes how those rules meet EPA’s requirements for new minor sources and minor 

modifications. A Standard Permit is a Minor NSR permit that is adopted under 

Chapter 116, Subchapter F. Subchapter F provides an alternative process for 

approving the construction of certain categories of new and modified sources for 

which TCEQ has adopted a Standard Permit. These provisions provide for a 

streamlined Minor NSR mechanism for authorizing the construction of certain 

sources within source categories for which TCEQ has adopted a Standard Permit. A 

 

1

 EPA did not approve the Standard Permit for Installation and/or Modification of Oil and Gas Facilities in the 

November 14, 2003, action as part of the Texas SIP (68 FR 64543, at 64547). 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

5 

Standard Permit is not available to a facility or group of facilities that undergo a 

change that constitutes a new major source or major modification under Title I of the 

Act, part C (Prevention of Significant Deterioration of Air Quality) or part D 

(Nonattainment Review). Such major source or major modification must comply with 

the applicable permitting requirements under Chapter 116, Subchapter B, which meet 

the NSR requirements in Title I, part C or part D of the Act. A facility that qualifies 

for a Minor NSR Standard Permit must also comply with all applicable provisions of 

Section 111 of the Act (NSPS) and Section 112 of the Act (NESHAP). Furthermore, a 

facility that qualifies for a Minor NSR Standard Permit must comply with all rules 

and regulations of TCEQ. 

A Standard Permit is not a case-by-case Minor NSR SIP permit, but rather it is a 

streamlined mechanism with all permitting requirements for construction and 

operation of a certain source category. Therefore, each Standard Permit approved in a 

SIP must contain all terms and conditions on the face of it (combined with the SIP 

general requirements), and it cannot be used to address site-specific determinations. 

B. Description of the Oil and Gas Permit

The Oil and Gas Standard Permit was developed to provide a streamlined permitting 

process for oil and gas facilities. The Standard Permit contained in 30 TAC 116.620 

simplifies the permit review process for these facilities by establishing standardized 

conditions applicable to the oil and gas industry, which help to streamline the agency 

review process and allow more rapid approval than would be possible under case-bycase Minor NSR review permitting. 

The standardized conditions contained in the Oil and Gas Standard Permit include 

emission specifications, control requirements, inspection requirements, approved test 

methods provisions, and monitoring and recordkeeping requirements. In addition, a 

source applying for authorization under 30 TAC 116.620 must also meet the 

applicable requirements contained in the other Sections under 30 TAC Chapter 116, 

Subchapter F – Standard Permits, which include registration and fee requirements and 

general permit conditions for Standard Permits. In accordance with 30 TAC 

116.610(b), the Oil and Gas Standard Permit is limited to Minor NSR and cannot be 

used to authorize a project that constitutes a new major stationary source or major 

modification. Therefore, as discussed in this document, the Oil and Gas Standard 

Permit provisions are evaluated with respect to the applicable Minor NSR 

requirements. 

As previously mentioned, the Oil and Gas Standard Permit includes standardized 

conditions for the emission units located at oil and gas facilities that may be 

authorized by the Standard Permit. The types of emission units that may be 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

6 

authorized by the Standard Permit are the following: 

 Internal combustion engines (ICEs), 

 Natural gas turbines (NG turbines), 

 Flares, 

 Other combustion units (design heat input > 40 million Btu per hour), 

 Natural gas glycol dehydration units, 

 Storage tanks, 

 Separators, 

 Condensers, 

 Vapor recovery units, 

 Process vents, and 

 Process fugitives (including process pipelines, flanges, pumps, and 

compressors). 

This list of emission units reflects the named units found in the Oil and Gas Standard 

Permit. As stated in the previous Section, the Oil and Gas Standard Permit cannot be 

used to address site-specific determinations or to authorize those emission units that 

are not specifically named, and therefore, not covered by the Standard Permit. As 

discussed below, emission units that are not contained on this list may not be 

authorized by the Oil and Gas Standard Permit. Instead, the permit applicant would 

need to obtain authorization for those emission units via a separate SIP-approved 

Minor NSR permitting mechanism. 

In order for one of the previously-listed emission units to be authorized by the 

Standard Permit, that unit must meet the applicable unit-specific standardized 

conditions, and, the oil and gas facility as a whole must meet any applicable site-wide 

standardized conditions contained in the Standard Permit. If a proposed project at an 

oil and gas facility includes any emission units that are not explicitly covered by the 

Oil and Gas Standard Permit, the permit applicant would turn to another type of 

Standard Permit authorization or a permit-by-rule (PBR) or, if necessary, case-bycase NSR permitting for authorization. For example, the Oil and Gas Standard Permit 

does not provide authorization for cooling towers. Therefore, an oil and gas facility 

with a cooling tower on-site would not be able to use the Oil and Gas Standard Permit 

to authorize the emissions from that emission unit, but could rely upon the separate 

cooling tower Standard Permit or PBR.2

 Any other emission units not specifically 

authorized under the Oil and Gas Standard Permit also could obtain authorization 

 

2

 For example, cooling towers, including those located at oil and gas facilities, that meet all of the applicable PBR 

requirements may be authorized under the SIP-approved Cooling-Water Unit PBR found at 30 TAC 106.371. 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

7 

through either a Standard Permit or PBR that explicitly addresses it or obtain a caseby-case Minor NSR permit. In addition to cooling towers, other examples of emission 

units that may be found at oil and gas facilities that are not covered by the Oil and 

Gas Standard Permit include, but are not limited to, truck loading emissions, heat 

exchangers, amine sweetening units, and sulfur recovery units.3,4 

If the TCEQ were found to be misapplying the Oil and Gas Standard Permit or a 

permittee obtained authorization under this Standard Permit for emission units that 

are outside the scope of 116.620, then EPA would interpret such action as a violation 

of the Minor NSR program in the Texas SIP. EPA or the public could address this 

implementation failure on a permit specific basis or other CAA remedy mechanism, 

such as a finding of failure to implement. 

V. General Discussion of EPA’s Evaluation of the Oil and Gas Standard Permit 

Regulations 

The SIP revisions related to the Oil and Gas Standard Permit are reviewed for compliance 

with the requirements of the CAA and 40 CFR part 51 – Requirements for Preparation, 

Adoption, and Submittal of Implementation Plans. 

 

3

 Sources may utilize SIP-approved Standard Permits or PBRs for these sources if they meet all of the applicable 

requirements (e.g., Organic and Inorganic Liquid Loading and Unloading PBR found at 30 TAC 116.372 or Organic 

Liquid Loading and Unloading PBR found at 30 TAC 116.373 to authorize truck loading and/or sulfur recovery 

units). Sources may also obtain a case-by-case Minor NSR permit for these, and other sources, not covered by the 

Oil and Gas Standard Permit. 

4 While, as discussed in our proposed rulemaking, EPA finds that the provisions in 30 TAC 116.620 are approvable 

for authorizing certain emission units at oil and gas facilities in Texas, EPA recognizes that Texas also has a nonrule Standard Permit for oil and gas facilities in its SIP for facilities located in the Barnett Shale region. 

Beginning March 2010, TCEQ began the process of developing a new Standard Permit for oil and gas facilities. 

The new Standard Permit was initially going to replace the Standard Permit in the SIP submittal being addressed in 

this action. TCEQ adopted the new standard permit for oil and gas facilities on January 26, 2011 with applicability 

limited to the Barnett Shale region. When it was adopted, it was adopted as a non-rule standard permit. Upon 

adoption, the non-rule standard permit for Oil and Gas Facilities automatically became a part of the approved Texas 

SIP [30 TAC §116.601(a)(2) approved at 68 FR 64543]. We note that the non-rule Oil and Gas Standard Permit 

may be utilized in lieu of 30 TAC 116.620 by facilities located outside the Barnett Shale, and it provides control 

technology requirements (e.g., emission limits, operational limits, design capacity, or State BACT) for additional 

emission units not covered by the Standard Permit under review in this action. 

EPA finds that this non-rule Standard Permit is more robust and more reflective of the current oil and gas 

industry, as compared to the Standard Permit under review in this action. Therefore, we believe that the non-rule 

Standard Permit’s applicability should be expanded to apply statewide as the oil and gas industry continues to 

evolve and experience significant growth in geographic areas in Texas located outside the Barnett Shale. The nonrule standard permit is a more detailed permit, with improved control requirements, monitoring, testing, and 

recordkeeping. It clearly identifies the emission units that can be covered, including those not covered in the 30 

TAC 116.620 Standard Permit, and requires all sources to use standardized methodologies to establish emission 

limits. 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

8 

The Act at Section 110(a)(2)(C) requires states to develop and submit to EPA for 

approval into the state SIP, preconstruction review and permitting programs applicable to 

certain new and modified stationary sources of air pollutants for attainment and 

nonattainment areas that cover both major and minor new sources and modifications, 

collectively referred to as the NSR SIP. The CAA NSR SIP program is composed of 

three separate programs: Prevention of Significant Deterioration (PSD), Nonattainment 

New Source Review (NNSR), and Minor NSR. 

The Minor NSR SIP program addresses construction or modification activities that do not 

emit, or have the potential to emit, beyond certain major source/major modification 

thresholds and thus do not qualify as “major” and applies regardless of the designation of 

the area in which a source is located. Any submitted SIP revision, including revisions to a 

Minor NSR program, must meet the applicable requirements for SIP elements in Section 

110 of the Act, and be consistent with all applicable statutory and regulatory 

requirements. 

EPA regulations governing the criteria that states must satisfy for EPA approval of the 

NSR programs as part of the SIP are contained in 40 CFR Sections 51.160-51.166. 

Regulations specific to Minor NSR programs are contained in 40 CFR Section 51.160-

51.164. The TCEQ has developed the Oil and Gas Standard Permit as a component of the 

Texas Minor NSR program; therefore we will evaluate the Standard Permit as submitted 

on September 20, 1995; April 19, 1996; July 22, 1998; and September 11, 2000, against 

the federal requirements for Minor NSR programs. 

40 CFR Section 51.160 establishes the requirements that all Minor NSR programs must 

meet. We will address these specific requirements in Section VI.A of this TSD. 40 CFR 

Section 51.161 establishes the public notice requirements for Minor NSR programs. We 

will address the public notice requirements more fully in Section VI.B of this TSD. 

Section 51.160-51.164 requires that a SIP revision demonstrate that the adopted rules will 

not interfere with any applicable requirement concerning attainment and reasonable 

further progress, or any other applicable requirement of the CAA. We will address the 

specific requirements for permitting activities that ensure attainment more fully in 

Section VI.C of this TSD. 

VI. Do the State’s Submittals for the Oil and Gas Standard Permit Meet the Applicable 

Federal Requirements for Minor NSR? 

A. Evaluation of Minor NSR Requirements

EPA’s regulations addressing a Minor NSR program as part of a state’s SIP are 

included at 40 CFR 51.160, which applies to all programs under Title I of the 

CAA. The provisions of a Minor NSR program must provide that the permitting 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

9 

authority will not permit the construction of a facility or modification that will 

cause a violation of applicable portions of the control strategy or interfere with 

attainment or maintenance of a NAAQS. To accomplish this goal, the state’s 

Minor NSR program must include the means by which the state agency will 

review and take final action on proposed new construction or modification to be 

protective of the control strategy and NAAQS. As stated in 40 CFR 51.160, all 

NSR programs, including the Minor NSR program, must include legally 

enforceable5

 procedures that meet the following requirements: 

 Provide for the submission, by the owner or operator of the building, 

facility, structure or installation to be constructed or modified of such 

information on the nature and amounts of emissions to be emitted by it or 

emitted by associated mobile sources; and the design, construction and 

operation of such facility, building, structure, or installation as may be 

necessary to allow the permitting authority to make a determination on 

approvability. 40 CFR 51.160(c). 

 The Minor NSR program must provide that approval of any construction 

or modification must not affect the responsibility of the owner or operator 

to comply with applicable portions of the control strategy. 40 CFR 

51.160(d). 

 The Minor NSR program must include procedures to identify the types 

and sizes of facilities, buildings, structures, or installations which will be 

subject to review. The Minor NSR program must also discuss the basis for 

determining which facilities will be subject to review. 40 CFR 51.160(e). 

 The Minor NSR program must also discuss the air quality data and the 

dispersion or other air quality modeling used to meet the NSR 

requirements. 40 CFR 51.160(f). 

In the September 23, 1987, Memorandum from J. Craig Potter, Assistant 

Administrator for Air and Radiation, and Thomas L. Adams Jr., Assistant 

Administrator for Enforcement and Compliance Monitoring, entitled “Review of 

State Implementation Plans and Revisions for Enforceability and Legal 

Sufficiency” is EPA's additional guidance for interpreting the enforceability 

requirements found in Section 110(a)(2)(C) of the Act and 40 CFR 51.160.6,7 In 

 

5

 A requirement is ‘‘legally enforceable’’ if some authority has the right to enforce the restriction. 67 FR 80186, at 

80190. 

6

 Other relevant guidance includes: “Approaches to creating Federally-Enforceable Emissions Limits,” John S. 

Seitz, November 3, 1993; January 25, 1995 Memorandum entitled “Guidance on Enforceability Requirements for 

Limiting Potential to Emit through SIP and section 112 rules and General Permits” from Kathie A. Stein, Office of 

Enforcement and Compliance Assurance; and “Potential to Emit (PTE) Guidance for Specific Source Categories” 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

10 

the 1987 memorandum we explain that submitted rules that are clearly worded, 

clear as to who must comply, and explicit in their applicability to regulated 

sources are appropriate means for achieving the statutory enforcement 

requirement. Appropriate testing, recordkeeping, reporting, and monitoring 

provisions are necessary to establish how compliance will be determined and be 

sufficient to ensure that the NAAQS and PSD increments are protected. 

The SIP submittals being evaluated as part of this action are for a Standard Permit 

that is submitted as part of Texas’s Minor NSR program; therefore, the provisions 

from the Oil and Gas Standard Permit are evaluated against the federal 

requirements for Minor NSR and in conjunction with the existing SIP-approved 

provisions of the Standard Permitting Program found in 30 TAC Chapter 116, 

Subchapter F – Standard Permits that provides the basic requirements that a 

facility must meet to qualify for a Standard Permit. 

Based on our evaluation, we propose to find that the Oil and Gas Standard Permit 

provisions found in 30 TAC 116.620 provide for the necessary procedures and 

applicable requirements that are required for Minor permitting programs. 

In accordance with 30 TAC 116.611, sources seeking authorization via the Oil 

and Gas Standard Permit are required to submit a Standard Permit registration to 

TCEQ, which is to include information regarding the proposed project to be 

authorized (e.g., emission estimates, description of project and related process, 

description of equipment being installed). 30 TAC 116.615 includes general 

conditions that must be met by sources authorized via a Standard Permit, 

including the Oil and Gas Standard Permit. These general conditions specifically 

require that sources authorized under a Standard Permit comply with all “rules, 

regulations, and orders of the commission issued in conformity with the [Texas 

Clean Air Act].” In the case where more than one state or federal rule of 

 Memorandum from John S. Seitz, OAQPS, and Eric Schaffer, OECA, April 14, 1998. 

7

 Practical enforceability for a source-specific permit will be achieved if the permit’s provisions specify: (1) A 

technically-accurate limitation and the portions of the source subject to the limitation; (2) the time period for the 

limitation (hourly, daily, monthly, and annual limits such as rolling annual limits); and (3) the method to determine 

compliance, including appropriate monitoring, recordkeeping, and reporting. For rules and general permits that 

apply to categories of sources, practicable enforceability additionally requires that the provisions: (1) Identify the 

types or categories of sources that are covered by the rule; (2) where coverage is optional, provide for notice to the 

permitting authority of the source’s election to be covered by the rule; and (3) specify the enforcement consequences 

relevant to the rule. (See See memorandum, “Release of Interim Policy on Federal Enforceability of Limitations on 

Potential to Emit,” signed by John Seitz and Robert Van Heuvelen, Jan. 22, 1996 at 5–6 and Attachment 4.) The 

Agency has frequently used the term “practicably enforceable” and “practical enforceability,” interchangeably. 

There is no difference in the meaning of these terms. ‘‘Enforceable as a practical matter’’ will be achieved if a 

requirement is both legally and practically enforceable. 67 FR 80186, at 80190-91. 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

11 

regulation or permit condition are applicable, the source must comply with the 

most stringent requirement or limit. See 30 TAC 116.615(10). Therefore, the 

conditions of the Standard Permit in no way supersede or relax other applicable 

state or federal requirements. In addition, the provisions found in the Oil and Gas 

Standard Permit under 30 TAC 116.620 also require that sources authorized under 

the Standard Permit submit appropriate documentation to demonstrate compliance 

with state and federal provisions, including PSD, NNSR, NSPS, and NESHAP. 

The Standard Permit also requires that new or increased emissions authorized 

under the permit shall not cause or contribute to a violation of any NAAQS and 

references that engineering judgment and/or air dispersion modeling may be used 

to demonstrate NAAQS compliance for the specific minor construction project. 

See 30 TAC 116.620(a)(13)-(17). Regarding testing, recordkeeping, reporting and 

monitoring provisions, the Oil and Gas Standard Permit contains provisions that 

include these requirements for the emission units that can be authorized under the 

Standard Permit. See 30 TAC 116.620(c)-(e). 

As discussed in this TSD, the Oil and Gas Standard Permit may be used to 

authorize only those emission units that are specifically covered by the Standard 

Permit provisions. Our proposed approval of the Oil and Gas Standard Permit 

reflects this limitation in the scope regarding the emission units that may be 

authorized under the Standard Permit. EPA would interpret the use of the Oil and 

Gas Standard Permit to authorize additional emission units beyond the scope of 

the rule as circumvention of the Minor NSR program in the Texas SIP. EPA or 

the public could address this implementation failure on a permit specific basis or 

other CAA remedy mechanism, such as a finding of failure to implement. The 

following paragraph further explains our basis for limiting the approval of the Oil 

and Gas Standard Permit to the specific covered emission units, which are listed 

in Section IV.B of this TSD. 

If the Oil and Gas Standard Permit is used to authorize emission units other than 

the ones specifically covered by the Standard Permit provisions, the Standard 

Permit would not meet the requirement that all permits must be enforceable. Clear 

limits on operation and/or emissions for all sources seeking coverage are 

necessary to meet the requirement of enforceability under 40 CFR 51.160(a). 

Section 110(a)(2)(A) states that plans shall include enforceable emission 

limitations and other control measures, means, or techniques. For those emission 

units not specifically covered by the provisions of the Oil and Gas Standard 

Permit, the Standard Permit does not provide necessary operation and/or emission 

limits. As discussed previously, the types of uncovered emission units that may be 

found at an oil and gas facility include cooling towers, truck loading emissions, 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

12 

heat exchangers, amine sweetening units, and sulfur recovery units. For these 

emission units, the Standard Permit fails to provide clearly identifiable 

operational limits or emission limits. Therefore, these emission units are not 

included in the scope of the emission units that may be authorized under the Oil 

and Gas Standard Permit. Our proposed approval specifically excludes these 

emission units, as well as, any other emission units not included in the covered 

units list included in Section IV.B of this TSD. If one of these emission units is 

located at an oil and gas facility seeking NSR authorization under the Oil and Gas 

Standard Permit, the applicant would need to seek separate authorization for the 

uncovered emission units through a separate Minor NSR permitting mechanism 

(e.g., a PBR, a different Standard Permit, or a case-by-case Minor NSR permit). 

Also note that the definition of Oil and Gas facility at §116.14(2) (SIP approved) 

states “For the purposes of Subchapter F of this chapter only, shall be defined as 

facilities which handle gases and liquids associated with the production, 

conditioning, processing, and pipeline transfer of fluids found in geologic 

formations beneath the earth's surface. These oil and gas facilities include, but are 

not limited to: oil or gas production facilities; water injection facilities; carbon 

dioxide separation facilities; or oil or gas pipeline facilities consisting of one or 

more tanks, separators, dehydration units, free water knock-outs, gunbarrels, 

heater treaters, vapor recovery units, flares, pumps, internal combustion engines, 

gas turbines, compressors, natural gas liquid recovery units, or gas sweetening 

and other gas conditioning facilities. This definition does not include sulfur 

recovery units.” The definition does not encompass all the emission units that can 

be found at an oil and gas facility, and the definition does not necessarily prohibit 

any emission unit other than sulfur recovery units. The definition may allow a 

source to make its own determination of what may be permitted by allowing the 

statement “but are not limited to” in the definition. The definition also includes 

“gas sweetening and other gas conditioning facilities.” Gas sweetening and gas 

conditioning facilities can cover a variety of processes including solid bed 

absorption, amine treaters, usage of chemical solvents and physical solvents, 

molecular sieves and other treatment processes.8

 The provisions in 30 TAC 

116.620 do not provide requirements for all of these types of units. Therefore, as 

discussed previously, the Oil and Gas Standard Permit is not adequate to 

authorize these units and some other type of SIP-approved permitting mechanism 

should be obtained. 

Keeping in mind that our proposed approval of the Oil and Gas Standard Permit is 

 

8 Kruse, C. F. 1974; Plant Processing of Natural Gas. Austin: The University of Texas, 1974. 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

13 

narrowed to include the authorization of emissions from only the named covered 

emission units, based on our evaluation of the proposed provisions found in the 

Standard Permit, in conjunction with the underlying SIP-approved provisions of 

the Texas Standard Permitting Program found in Chapter 116, Subchapter F, we 

propose to find that the Oil and Gas Standard Permit meets the Minor NSR 

requirements for the units for which it is applicable. 

B. Evaluation of Public Availability of Information Requirements for Minor NSR

Federal requirements for public notice of Minor NSR programs are found at 40 

CFR 51.160 and 51.161. The procedures for a Minor NSR program in 40 CFR 

51.160 require an opportunity for public comment on information submitted by 

the permit applicant and on the permitting authority’s analysis of the application, 

submitted materials and proposed approval or disapproval of the permit 

application. EPA further explains at 40 CFR 51.161(b) that opportunity for public 

comment is, at a minimum, the availability for public inspection in at least one 

location in the area affected of the information submitted by the owner/operator 

and of the permitting authority’s analysis of the effect on air quality; a 30-day 

period for submittal of public comment; and a notice by prominent advertisement 

in the area affected of the location where the public can see the submitted 

materials and analysis. The SIP submittals being evaluated as part of this action 

are for a Standard Permit; therefore, the provisions from the Oil and Gas Standard 

Permit are evaluated against the federal requirements regarding public notice in 

conjunction with the existing SIP-approved provisions of the Standard Permits 

Program found in 30 TAC Chapter 116, Subchapter F – Standard Permits that 

provide the basic requirements that a facility must meet to qualify for a Standard 

Permit, including public participation requirements. See 30 TAC 116.603. 

Based on our evaluation, we propose to find that the SIP’s general provisions for 

all Standard Permits found at 30 TAC 116.603 apply to the Oil and Gas Standard 

Permit. These general provisions were found to meet EPA’s requirements for 

public participation for Minor NSR permits and in some cases are more stringent. 

(73 FR 53716, September 17, 2008) As required by 30 TAC 116.603, a Standard 

Permit must comply with the following public notice requirements: 

 Notice of a proposed Standard Permit is required to be published in the 

Texas Register, the commission’s publicly accessible electronic media, 

and in a daily or weekly newspaper of general circulation in the area 

affected by the activity that is subject to the proposed permit. If the 

proposed Standard Permit will have statewide applicability, notice will be 

published in the daily newspaper of largest general circulation within each 
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

14 

of the following metropolitan areas: Austin, Dallas, and Houston and any 

other regional newspapers designated by the executive director on a caseby-case basis. Additionally, the commission will publish notice in the 

Texas Register and issue a press release; 

 The notice must provide for a public comment period on the proposed 

Standard Permit of at least 30 days; 

 A public meeting is required to be held to provide an additional 

opportunity for public comment; 

 Written responses must be prepared to all public comments received from 

the public related to the issuance of a Standard Permit, which will be made 

available to the public; 

 Notice of the final action on the proposed Standard Permit is required to 

be published in the Texas Register, including the text of the response to 

comments; and 

 Copies of the final issued Standard Permit along with the response to 

public comments received on the draft permit are required to be made 

available at the TCEQ Austin office and appropriate TCEQ regional 

offices. 

Subsequent amendments or revocation of an issued Standard Permit must also 

meet the public notice procedures contained in Section 603, as required by 30 

TAC 116.605. 

Based on our evaluation of the proposed provisions found in the Oil and Gas 

Standard Permit, as well as the underlying SIP-approved provisions of the Texas 

Standard Permitting Program found in Chapter 116, Subchapter F, we propose to 

find that the Oil and Gas Standard Permit meets the federal public notice 

requirements that are applicable to Minor NSR for those emission units that are 

specifically covered by the Standard Permit provisions. In addition, Texas has 

provided documentation within their SIP revision submittals to document that the 

SIP-approved public notice process was followed consistent with the 30 TAC 

116.603 requirements when the Oil and Gas Standard Permit was initially issued 

and subsequently amended. The SIP submittals are available in the docket 

accompanying this action. 

C. Evaluation of SIP Revisions with Respect to Attainment, Reasonable Further 

Progress, and Other Applicable Requirements of the Act
Technical Support Document 

Revisions to Texas New Source Review State Implementation Plan Related to the Standard 

Permit for Installation and/or Modification of Oil and Gas Facilities and to the Standard 

Permit Applicability Provisions 

30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, Section 617, 

Paragraph 3, and Section 620 

(30 TAC 116.610(a) and (b), 116.617(3), and 116.620) 

15 

Section 110(l) of the CAA states: 

Each revision to an implementation plan submitted by a State 

under this Act shall be adopted by such State after reasonable 

notice and public hearing. The Administrator shall not approve a 

revision of a plan if the revision would interfere with any 

applicable requirement concerning attainment and reasonable 

further progress (as defined in Section 171), or any other 

applicable requirement of this Act. 

Thus, under Section 110(l), the regulations submitted as SIP revisions establishing 

the Oil and Gas Standard Permit must meet the procedural requirements of 

Section 110(l) by demonstrating that the State followed all necessary procedural 

requirements such as providing reasonable notice and public hearing of the SIP 

revision. Additionally, the SIP revision must demonstrate that the adopted rules 

will not interfere with any applicable requirement concerning attainment and 

reasonable further progress, or any other applicable requirement of the CAA. We 

propose to find that the TCEQ satisfied all procedural requirements pursuant to 

Section 110(l). 

A Minor NSR program is a requirement of the CAA and EPA’s regulations at 40 

CFR 51.160-1.164. As discussed in this TSD, EPA proposes that the Oil and Gas 

Standard Permit as submitted on September 20, 1995, and revised through SIP 

submittals dated April 19, 1996; July 22, 1998; and September 11, 2000, satisfies 

the minimum requirements for a Minor NSR program, including adequate 

provisions for legal enforceability and public participation to ensure protection of 

the control strategy and any applicable NAAQS. The Oil and Gas Standard Permit 

also contains sufficient safeguards to prevent circumvention of Major NSR 

permitting requirements. Therefore, we propose to find that the Oil and Gas 

Standard Permit is protective of the NAAQS and applicable control strategy 

requirements and satisfies the requirements of 110(l) of the Act. 

D. Summary of EPA’s Evaluation

As discussed above, EPA proposed to find that the Oil and Gas Standard Permit, 

as submitted on September 20, 1995, and revisions submitted on April 19, 1996; 

July 22, 1998; and September 11, 2000, is limited to Minor NSR. EPA proposes 

to find that the program satisfies the federal requirements for Minor NSR and 

contains sufficient enforceable safeguards to ensure that the NAAQS and 

applicable control strategies are protected. 
Technical Support Document 

Appendix A 

Part 51, Appendix V Evaluation 

Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; 

February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V 

i 

Part 51, Appendix V Completeness Checklist 

The criteria for completeness determination are found in Appendix V to Part 51 – Criteria for 

determining the completeness of plan submissions and are outlined below: 

1.0 Purpose: This appendix V sets forth the minimum criteria for determining whether a state 

implementation plan submitted for consideration by EPA is an official submission for 

purposes of review under § 51.103. 

1.1 The EPA shall return to the submitting official any plan or revision thereof which fails to 

meet the criteria set forth in this appendix V, and request corrective action, identifying 

the component(s) absent or insufficient to perform a review of the submitted plan. 

1.2 The EPA shall inform the submitting official whether or not a plan submission meets the 

requirements of this appendix V within 60 days of EPA’s receipt of the submittal, but no 

later than 6 months after the date which the State was required to submit the plan or 

revision. If a completeness determination is not made by 6 months from receipt of a 

submittal, the submittal shall be deemed complete by operation of law on the date 6 

months from receipt. A determination of completeness under this paragraph means that 

the submission is an official submission for purposes of § 51.103. 

The attached checklist outlines the basic criteria included under 2.1, 2.2, and 2.3 of Appendix V.

 
Technical Support Document 

Appendix A 

Part 51, Appendix V Evaluation 

Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; 

February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V 

ii 

Administrative Materials (2.1) 

1. The package is sent with a formal submittal letter from the Governor or his or her 

designee requesting EPA’s approval of the revision. 

The SIP revisions addressed in this action were submitted via letters from Governor 

George W. Bush, TCEQ Chairman Kathleen Harnett White, and TCEQ Chairman Bryan 

Shaw, dated September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; 

February 1, 2006; and March 11, 2011. 

2. Evidence is included that the State has adopted the revision in the State code or body of 

regulations, or that the State has issued the permit, order, consent agreement (hereafter 

document) in final form. This evidence would include the date of adoption or final 

issuance and the effective date of revision, if different from the adoption/issuance date. 

The SIP revisions addressed in this action were adopted by the state as follows: 

 September 20, 1995 Submittal – Adopted July 26, 1995, effective September 1, 

1995; 

 April 19, 1996 Submittal – Adopted March 27, 1996, effective April 19, 1996; 

 July 22, 1998 Submittal – Adopted June 17, 1998, effective July 8, 1998; 

 September 11, 2000 Submittal – Adopted August 9, 2000, effective September 4, 

2000; 

 February 1, 2006 Submittal – Adopted January 11, 2006, effective February 1, 

2006; and 

 March 11, 2011 Submittal – Adopted January 11, 2006, effective February 1, 

2006. 

3. Evidence is included that the State has necessary legal authority under State law to adopt 

and implement the revision, e.g., a citation of the appropriate State authority. 

The authority for promulgating changes to the Texas State Implementation is found in the 

Texas Clean Air Act, Chapter 382 of the Texas Health and Safety Code. 

4. A copy is included of the actual regulation or document submitted for approval and 

incorporation by reference into the SIP including an indication of the changes made to the 

existing approved place where applicable. The submittal shall be a copy of the official 

State regulation document signed, stamped, and dated by the appropriate State official 
Technical Support Document 

Appendix A 

Part 51, Appendix V Evaluation 

Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; 

February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V 

iii 

indicating that it is fully enforceable by the State. The effective date of the regulation 

document shall, whenever possible, be indicated in the document itself. 

Each of the SIP submittals included a copy of the official State regulation document. 

5. Evidence is included that the State followed all of the procedural requirements of its laws 

and/or its constitution in the conducting and completing the adoption/issuance of the 

plan. 

The SIP submittal packages include a certification demonstrating the SIP submittal was 

developed pursuant to 40 CFR 51.104. 

6. Evidence is included that public notice was given of the proposed changes consistent 

with the procedures approved by EPA, including the date of publication of such notice 

(e.g., notarized or certified copies of any public notices published in newspapers). (The 

notice should be at least 30 days prior to the public hearing(s). 

The SIP submittals addressed in this action included a summary of the Public Notices 

published for the rule revisions, as well as, copies showing evidence of the published 

notices. These public notices included information regarding the public comment period 

and upcoming public hearings. 

7. A certification is included indicating that public hearing(s) was/were held in accordance 

with the information provided in the public notice(s) and the State’s laws and 

constitution, if applicable. 

See reporter’s certification at the end of the public hearing transcripts in each of the SIP 

submittals addressed in this action. 

8. A compilation of public comments and the State’s response is included. 

The SIP submittals addressed in this action included copies of comments received from 

the public on the State regulation, as well as, as the State’s responses to the comments 

received. 
Technical Support Document 

Appendix A 

Part 51, Appendix V Evaluation 

Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; 

February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V 

iv 

Technical Support (2.2) 

9. Identification of all regulated pollutants affected by the revision included. 

The SIP submittals address revisions to the provisions related to the Minor NSR 

construction permitting program; therefore, the SIP submittals have the potential to 

address all regulated pollutants. 

10. Identification of the locations of affected sources including the EPA 

attainment/nonattainment designation of the locations and the status of the attainment 

plan for the affected area(s) is included. 

The provisions contained in 30 TAC 116.610 can be applied statewide to facilities 

seeking authorization under a Standard Permit. 

The provisions contained in 30 TAC 116.620 can be applied statewide to oil and gas 

facilities seeking authorization under a Standard Permit. The only exception would be 

those facilities located in the Barnett Shale region, which would seek authorization 

through the non-rule Standard Permit that was adopted by Texas in 2011. The 

provisions related to the non-rule Standard Permit are addressed in separate provisions 

of the state’s rules. 

11. Quantifications of the changes in SIP allowable emissions from the affected sources is 

included. (Examples include estimates of changes in current actual emissions from 

affected sources and/or, where appropriate, quantification of changes in actual emissions 

from affected sources through calculations of the differences between certain baseline 

levels and allowable emissions anticipated if the revisions were approved.) 

The provisions for the Standard Permit applicability provisions do not need to include 

quantification of the changes in SIP allowable emissions from the affected sources. 

These are non-substantive changes. In addition, the underlying standard permitting 

process addresses the permitting emissions for a given facility. 

The provisions for the Oil and Gas Standard Permit do not need to include quantification 

of the changes in SIP allowable emissions from the affected sources. The mechanics of 

the standard permitting process ensure appropriate amounts of permitted emissions are 

approved. 
Technical Support Document 

Appendix A 

Part 51, Appendix V Evaluation 

Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; 

February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V 

v 

12. Demonstration is included that the NAAQS/PSD increments/RFP demonstration and 

visibility as applicable would be protected if the revision were approved and 

implemented. 

The proposed revisions to the Standard Permit applicability provisions are nonsubstantive in nature and; therefore, will not interfere with the attainment or reasonable 

further progress or any other applicable requirement of the Act. 

See Section VI.C of this document for more information regarding the Oil and Gas 

Standard Permit SIP revisions and how they meets the Section 110(l) requirements that 

require the revisions not interfere with attainment or reasonable further progress or any 

other applicable requirement of the Act. 

13. FOR REDESIGNATIONS: 

a. Is there a fully approved maintenance plan for the primary ambient air quality 

standards for at least 10 years as required by § 175A of the Clean Air Act? 

Not applicable. 

b. Are contingency measures included? 

Not applicable. 

14. Modeling information, if applicable, is required to support the proposed revision. 

Modeling information is not necessary to support this SIP revision. 

15. Evidence is included where necessary, that emission limitations are based on continuous 

emission reduction technology (e.g., add-on controls, industrial/process equipment 

designs, reformulated materials, etc.). 

Not applicable to the non-substantive changes to the Standard Permit applicability 

provisions. 

The provisions contained in the Oil and Gas Standard Permit include both emission 

limitations and control requirements that must be met by any facility that is authorized 

under the Standard Permit. 
Technical Support Document 

Appendix A 

Part 51, Appendix V Evaluation 

Evaluation of the September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; 

February 1, 2006; and March 11, 2011 SIP Submittals with respect to Part 51, Appendix V 

vi 

16. Evidence is included indicating that a SIP revision contains emission limitations, work 

practice standards and recordkeeping/reporting requirements to ensure stated emission 

levels. 

Not applicable to the non-substantive changes to the Standard Permit applicability 

provisions. 

The provisions contained in 30 TAC 116.620 include emission specifications, control 

requirements, inspection requirements, and monitoring and recordkeeping requirements 

for the emission sources covered by the Oil and Gas Standard Permit. These limitations 

and requirements become effective for a source when they register for authorization 

under the Standard Permit. 

17. Compliance/enforcement strategies including how compliance will be determined in 

practice (including at what frequency). 

Not applicable to the non-substantive changes to the Standard Permit applicability 

provisions. 

30 TAC 116.620 does not need to include compliance/enforcement strategies. 

Compliance/enforcement of the Oil and Gas Standard Permit will be determined on a 

permit-by-permit basis. 

18. As appropriate, special economic and technological justifications are included per 

applicable EPA policies or an explanation why such justifications are not necessary 

should be included. For example, requests for alternative RACT may require such 

justification. 

These justifications are not necessary for this SIP revision. 

The September 20, 1995; April 19, 1996; July 22, 1998; September 11, 2000; February 1, 

2006; and March 11, 2011 SIP submittals meet the completeness criteria established in 40 

CFR part 51, Appendix V. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

i 

I. General Discussion

This Appendix contains the annotation and evaluation of SIP revisions that Texas 

submitted to EPA on September 20, 1995; April 19, 1996; July 22, 1998; and September 

11, 2000. These SIP revisions consist of revisions to 30 Texas Administrative Code 

(TAC) Chapter 116 – Control of Air Pollution by Permits for New Construction and 

Modification. 

II. Annotation Procedure

The annotation and evaluation consists of a table for each section that is submitted. 

Below is a description of how each table is organized. 

A. Section Title and indication of SIP Approval Status and Pending SIP Revisions

1. Above each table is the title of each section. 

2. Below the title are notes which indicate the following: 

3. Indication whether EPA has approved a prior version of the section. If the 

prior version is currently SIP approved, we identify the following: 

i. The Federal Register page number and date of the latest SIP 

approval, the version of the State rule that is approved, and the 

effective date of the SIP approval action; and 

ii. The version of the State rule that is approved by the date of 

adoption by the State and the date the rule was effective as a State 

rule. 

4. Identification of all pending SIP revisions considered in this action, which 

include: 

i. The date submitted; 

ii. The date adopted by the State; and 

iii. The date the rule was effective as a State rule. 

B. Evaluation Matrix

1. Organization of Each Table: 

Each row is the annotation of each subsection, paragraph, subparagraph, 

etc. or each section. Each row is divided into two or more columns which 

show a separate annotation of each individual SIP revision that is 

reviewed in this evaluation. Above each column is the date of the SIP 

revisions for which the changes are shown. The column at the far right of 

each row provides comments that summarize the proposed SIP revisions. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

ii 

2. Annotation style: 

(i) The far left column contains the text of the initial SIP revision, 

which included the initial adoption of the rule. 

(ii) To the right of the initial SIP submitted rule is the revised rule. If 

there is more than one revision to the rule, each revision is 

identified in a separate column and the revisions are placed in 

chronological order with the first revision placed to the immediate 

right of the initial submitted SIP and subsequent revisions are 

placed on order from left to right. If there is no existing SIP 

provision, the entire text is underlined to indicate that it is new 

text. If the submittal revised a previous provision, new text is 

underlined and text that is removed is struck-out. In the case of 

multiple SIP revisions, each revision is annotated to compare the 

revised rule to the revision that immediately preceded that 

particular change. 

(iii) The right-most column includes a summary of the proposed 

revisions of the particular provision, as well as, any additional 

comments. 

C. Proposed Action

This Section of the Appendix indicates our proposed action on the revisions 

included in the evaluation matrix, as well as, provides additional information 

regarding the basis of our proposed action. 

 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

iii 

30 TAC 116.610. Applicability

I. Background of 30 TAC 116.610. 

A. Current SIP: The current SIP-approved version of 116.610 was adopted by TNRCC 

March 7, 2001 (effective March 29, 2001). EPA approved this version of 116.610 into 

the Texas SIP on September 6, 2006 (effective October 6, 2006; 71 FR 52664). The 

current SIP contains paragraphs a, b, and c of Section 160. 116.610(d) is not approved 

into the SIP. 

B. Pending SIP Revisions Reviewed in this Action:

1. February 1, 2006: Texas revised §116.610, adopted January 11, 2006; effective 

February 1, 2006. 

2. March 11, 2011: Resubmittal of revisions to §116.610, January 11, 2006; effective 

February 1, 2006. 

II. Evaluation matrix. 

Annotation and Evaluation of §116.610 Comments 

Current SIP 

a) Under the TCAA, §382.051, a project which meets 

the requirements for a standard permit listed in this 

subchapter or issued by the commission is hereby 

entitled to the standard permit, provided the 

following conditions listed in this section are met. 

 For the purposes of this subchapter, project means 

the construction or modification of a facility or a 

group of facilities submitted under the same 

registration:

Rev submitted 02/01/2006 (Resubmitted on 03/11/2011) 

a) Under the Texas Clean Air Act TCAA, §382.051, a 

project that which meets the requirements for a standard 

permit listed in this subchapter or issued by the 

commission is hereby entitled to the standard permit, 

provided the following conditions listed in this section 

are met. For the purposes of this subchapter, project 

means the construction or modification of a facility or a 

group of facilities submitted under the same registration:

Revision 02/01/06 

 Revisions are nonsubstantive to 

update formatting 

requirements 

Current SIP 

1) any project which results in a net increase in 

emissions of air contaminants from the project 

other than carbon dioxide, water, nitrogen, 

methane, ethane, hydrogen, oxygen, or those for 

which a National Ambient Air Quality Standard 

has been established must meet the emission 

limitations of §106.261(3) or (4) or §106.262(3) 

of this title (relating to Facilities (Emission 

Limitations), and Facilities (Emission and 

Distance Limitations)), unless otherwise 

specified by a particular standard permit; 

Rev submitted 02/01/2006 (Resubmitted on 03/11/2011) 

1)Any any project that which results in a net increase in 

emissions of air contaminants from the project other 

than carbon dioxide, water, nitrogen, methane, 

ethane, hydrogen, oxygen, or those for which a 

National Ambient Air Quality Standard has been 

established must meet the emission limitations of 

§106.261 §106.261(3) or (4) or §106.262(3) of this 

title (relating to Facilities (Emission Limitations), and 

Facilities (Emission and Distance Limitations)), 

unless otherwise specified by a particular standard 

permit.;

Revision 02/01/06 

 Revisions are nonsubstantive to 

update formatting 

requirements and 

to update internal 

cross references 

Current SIP 

2) construction or operation of the project must be 

commenced prior to the effective date of a 

revision to this subchapter under which the 

project would no longer meet the requirements 

for a standard permit; 

Rev submitted 02/01/2006 (Resubmitted on 03/11/2011) 

2) Construction construction or operation of the project 

must be commenced prior to the effective date of a 

revision to this subchapter under which the project 

would no longer meet the requirements for a standard 

permit.;

Revision 02/01/06 

 Revisions are nonsubstantive to 

update formatting 

requirements 

Current SIP 

3) the proposed project must comply with the 

applicable provisions of the FCAA, §111 

(concerning New Source Performance 

Standards) as listed under Title 40 Code of 

Federal Regulations (CFR) Part 60, promulgated 

by the EPA; 

Rev submitted 02/01/2006 (Resubmitted on 03/11/2011) 

3) The the proposed project must comply with the 

applicable provisions of the Federal Clean Air Act 

(FCAA), §111 (concerning New Source Performance 

Standards) as listed under Title 40 Code of Federal 

Regulations (CFR) Part 60, promulgated by the 

United States Environmental Protection Agency 

(EPA).;

Revision 02/01/06 

 Revisions are nonsubstantive to 

update formatting 

requirements 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

iv 

Annotation and Evaluation of §116.610 Comments 

Current SIP 

4) the proposed project must comply with the 

applicable provisions of FCAA, §112 

(concerning Hazardous Air Pollutants) as listed 

under 40 CFR 61, promulgated by the EPA; 

Rev submitted 02/01/2006 (Resubmitted on 03/11/2011) 

4)The the proposed project must comply with the 

applicable provisions of FCAA, §112 (concerning 

Hazardous Air Pollutants) as listed under 40 CFR 

Part 61, promulgated by the EPA.;

Revision 02/01/06 

 Revisions are nonsubstantive to 

update formatting 

requirements 

Current SIP 

5) the proposed project must comply with the 

applicable maximum achievable control 

technology standards as listed under 40 CFR 

Part 63, promulgated by the EPA under FCAA, 

§112 or as listed under Chapter 113, Subchapter 

C of this title (relating to National Emissions 

Standards for Hazardous Air Pollutants for 

Source Categories (FCAA, §112, 40 CFR 63)); 

and 

Rev submitted 02/01/2006 (Resubmitted on 03/11/2011) 

5) The the proposed project must comply with the 

applicable maximum achievable control technology 

standards as listed under 40 CFR Part 63, 

promulgated by the EPA under FCAA, §112 or as 

listed under Chapter 113, Subchapter C of this title 

(relating to National Emissions Standards for 

Hazardous Air Pollutants for Source Categories 

(FCAA, §112, 40 CFR Part 63)).; and

Revision 02/01/06 

 Revisions are nonsubstantive to 

update formatting 

requirements 

Current SIP 

6) If subject to Chapter 101, Subchapter H, 

Division 3 of this title (relating to Mass 

Emissions Cap and Trade Program) the 

proposed facility, group of facilities, or account 

must obtain allocations to operate. 

Rev submitted 02/01/2006 (Resubmitted on 03/11/2011) 

No changes submitted. 

Revision 02/01/06 

No changes 

Current SIP 

b) Any project, except those authorized under 

§116.617 of this title (relating to Standard Permits 

for Pollution Control Projects), which constitutes a 

new major source, or major modification under the 

new source review requirements of the FCAA, Part 

C (Prevention of Significant Deterioration Review) 

or Part D (Nonattainment Review) and regulations 

promulgated thereunder is subject to the 

requirements of §116.110 of this title (relating to 

Applicability) rather than this subchapter. 

Rev submitted 02/01/2006 (Resubmitted on 03/11/2011) 

b) Any project that constitutes a new major stationary 

source or major modification as defined in §116.12 of 

this title (relating to Nonattainment and Prevention of 

Significant Deterioration Review Definitions) is subject 

to the requirements of § 116.110 of this title (relating to 

Applicability) rather than this subchapter. , except those 

authorized under §116.617 of this title (relating to 

Standard Permits for Pollution Control Projects), which 

constitutes a new major source, or major modification 

under the new source review requirements of the FCAA, 

Part C (Prevention of Significant Deterioration Review) 

or Part D (Nonattainment Review) and regulations 

promulgated thereunder is subject to the requirements of 

§116.110 of this title (relating to Applicability) rather 

than this subchapter.

Revision 02/01/06 

 Revisions are nonsubstantive to 

update internal 

cross references 

Current SIP 

c) Persons may not circumvent by artificial 

limitations the requirements of §116.110 of this 

title. 

Rev submitted 02/01/2006 (Resubmitted on 03/11/2011) 

No changes submitted. 

Revision 02/01/06 

 No changes 

Current SIP 

d) NOT in SIP 

Rev submitted 02/01/2006 (Resubmitted on 03/11/2011) 

Not submitted to SIP 

Revision 02/01/06 

 Not submitted to 

SIP 

III. Proposed Action. 

Approval of the non-substantive revisions to 30 TAC 116.610 February 1, 2006, and 

March 11, 2011. Based on our review of the proposed changes, we propose to find these 

changes to 30 TAC 116.610(a) and (b) to be approvable because they are ministerial and 

non-substantive in nature. 

 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

v 

30 TAC 116.620. Installation and/or Modification of Oil and Gas Facilities. (Initially 

adopted at 30 TAC 116.617(3)) 

I. Background of 30 TAC 116.620. 

A. Current SIP: §116.620 is not currently approved as part of the Texas SIP. 

B. Pending SIP Revisions Reviewed in this Action:

1. September 20. 1995: Texas submitted new §116.617(3), adopted July 26, 1995; 

effective September 1, 1995. 

2. April 19, 1996: Texas deleted §116.617(3) and moved Standard Permit to§116.620 

with revisions, adopted March 27, 1996; effective April 19, 1996. 

3. July 22, 1998: Texas revised §116.620, adopted June 17, 1998; effective July 8, 

1998. 

4. September 11, 2000: Texas revised §116.620, adopted August 9, 2000; effective 

September 4, 2000. 

II. Evaluation matrix. 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95 

§116.617(3). Installation and/or Modification of 

Oil and Gas Facilities.

Rev submitted 04/19/1996 

§116.620. Installation and/or Modification of Oil and 

Gas Facilities. 

Revision 04/19/96 

 116.617(3) deleted 

and section moved 

to new section 

116.620 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Submitted 09/20/95 

(A) Emission Specifications

Rev submitted 04/19/1996 

(a) Emission Specifications 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Submitted 09/20/95

(i) Venting or flaring more than 0.3 long tons per 

day of total sulfur shall not be allowed.

(ii) No Facility shall be allowed to emit total 

uncontrolled emissions of sulfur compounds, 

except sulfur dioxide (SO2), from all vents 

(excluding process fugitives emissions) equal to 

or greater than four pounds per hour unless 

vapors are collected and routed to a flare.

(iii) Any vent, excluding any safety relief valves that 

discharge to the atmosphere only as a result of 

fire or failure of utilities, emitting sulfur 

compounds other than sulfur dioxide shall be at 

least 20 feet above ground level.

Rev submitted 04/19/1996 

(1) Venting or flaring more than 0.3 long tons per day of 

total sulfur shall not be allowed. 

(2) No Facility shall be allowed to emit total 

uncontrolled emissions of sulfur compounds, except 

sulfur dioxide (SO2), from all vents (excluding 

process fugitives emissions) equal to or greater than 

four pounds per hour unless vapors are collected and 

routed to a flare. 

(3) Any vent, excluding any safety relief valves that 

discharge to the atmosphere only as a result of fire or 

failure of utilities, emitting sulfur compounds other 

than sulfur dioxide SO2 shall be at least 20 feet above 

ground level. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

vi 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(iv)New or modified 

internal combustion 

reciprocating 

engines or gas 

turbines permitted 

under this standard 

permit shall satisfy 

all the requirements 

of Standard 

Exemption Number 

6, except that 

registration using 

form PI-7 or PI-8 

shall not be required. 

Emissions from 

engines or turbines 

shall be limited to 

the amounts found 

in §116.211(a)(1) of 

this title (relating to 

Standard Exemption 

List).

Rev submitted 

04/19/1996

(4) New or modified 

internal combustion 

reciprocating engines 

or gas turbines 

permitted under this 

standard permit shall 

satisfy all the 

requirements of 

Standard Exemption 

Number 6, except 

that registration using 

form PI-7 or PI-8 

shall not be required. 

Emissions from 

engines or turbines 

shall be limited to the 

amounts found in 

§116.211(a)(1) of this 

title (relating to 

Standard Exemption 

List). 

Rev submitted 

07/22/1998 

(4) New or modified 

internal 

combustion 

reciprocating 

engines or gas 

turbines permitted 

under this standard 

permit shall satisfy 

all of the 

requirements of 

Standard 

Exemption 

Number 6

§106.512 of this 

title (relating to 

Stationary Engines 

and Turbines 

(Previously SE 

6)), except that 

registration using 

the Form PI-7 or 

PI-8 shall not be 

required. 

Emissions from 

engines or turbines 

shall be limited to 

the amounts found 

in §116.211

106.4(a)(1) of this 

title (relating to 

Standard 

Exemption List 

Requirements for 

Exemption from 

Permitting).

Rev submitted 09/11/2000

(4) New or modified internal 

combustion reciprocating 

engines or gas turbines 

permitted under this 

standard permit shall satisfy 

all of the requirements of 

§106.512 of this title 

(relating to Stationary 

Engines and Turbines 

(Previously SE 6)), except 

that registration using the 

Form PI-7 or PI-8 shall not 

be required. Emissions 

from engines or turbines 

shall be limited to the 

amounts found in § 

106.4(a)(1) of this title 

(relating to Requirements 

for Exemption from

Permitting by Rule). 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revisions 07/22/98 

and 09/11/00 

 Revisions updated 

the reference from 

standard 

exemption to 

permit by rule. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

vii 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(v) Total Volatile Organic Compound (VOC) 

emissions from a natural gas glycol dehydration 

unit shall not exceed ten tons per year (tpy) 

unless the vapors are collected and controlled in 

accordance with subparagraph (B)(ii) of this 

paragraph.

(vi) Any combustion unit (excluding flares, internal 

combustion engines, or natural gas turbines), 

with a design maximum heat input greater than 

40 million British thermal units (Btu) per hour 

(using lower heating values) shall not emit more 

than 0.06 pounds of nitrogen oxides (NOx) per 

million Btu.

(vii) No facility which is less than 500 feet from the 

nearest off-plant receptor shall be allowed to 

emit uncontrolled VOC process fugitive 

emissions equal to or greater than ten tpy, but 

less than 25 tpy, unless the equipment is 

inspected and repaired according to 

subparagraph (C)(i) of this paragraph.

(viii) No facility which is 500 feet or more from the 

nearest off-plant receptor shall be allowed to 

emit uncontrolled VOC process fugitive 

emissions equal to or greater than 25 tpy unless 

the equipment is inspected and repaired 

according to subparagraph (C)(i) of this 

paragraph.

(ix) No facility which is less than 500 feet from the 

nearest off-plant receptor shall be allowed to 

emit uncontrolled VOC process fugitive 

emissions equal to or greater than 25 tpy unless 

the equipment is inspected and repaired 

according to subparagraph (C)(ii) of this 

paragraph.

(x) No facility shall be allowed to emit uncontrolled 

VOC process fugitive emissions equal to or 

greater than 40 tpy unless the equipment is 

inspected and repaired according to 

subparagraph (C)(ii) of this paragraph.

Rev submitted 04/19/1996

(5) Total Volatile Organic Compound (VOC) emissions 

from a natural gas glycol dehydration unit shall not 

exceed ten tons per year (tpy) unless the vapors are 

collected and controlled in accordance with 

subparagraph subsection (B b)(ii 2) of this paragraph

section. 

(6) Any combustion unit (excluding flares, internal 

combustion engines, or natural gas turbines), with a 

design maximum heat input greater than 40 million 

British thermal units (Btu) per hour (using lower 

heating values) shall not emit more than 0.06 pounds 

of nitrogen oxides (NOx) per million Btu. 

(7) No facility which is less than 500 feet from the 

nearest off-plant receptor shall be allowed to emit 

uncontrolled VOC process fugitive emissions equal 

to or greater than ten tpy, but less than 25 tpy, unless 

the equipment is inspected and repaired according to 

subparagraph subsection (C c)(i 1) of this paragraph

section. 

(8) No facility which is 500 feet or more from the nearest 

off-plant receptor shall be allowed to emit 

uncontrolled VOC process fugitive emissions equal 

to or greater than 25 tpy unless the equipment is 

inspected and repaired according to subparagraph

subsection (C c)(i 1) of this paragraph section. 

(9) No facility which is less than 500 feet from the 

nearest off-plant receptor shall be allowed to emit 

uncontrolled VOC process fugitive emissions equal 

to or greater than 25 tpy unless the equipment is 

inspected and repaired according to subparagraph

subsection (C c)(ii 2) of this paragraph section. 

(10) No facility shall be allowed to emit uncontrolled 

VOC process fugitive emissions equal to or greater 

than 40 tpy unless the equipment is inspected and 

repaired according to subparagraph subsection (C

c)(ii 2) of this paragraph section. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

viii 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(xi) No facility which is 

located less than one 

quarter of a mile from the 

nearest off-plant receptor 

shall be allowed to emit 

hydrogen sulfide (H2S) or 

SO2 process fugitive 

emissions unless the 

equipment is inspected and 

repaired according to 

subsection (C)(iii) of this 

paragraph. No facility 

which is located at least 

one quarter of a mile from 

the nearest off-plant 

receptor shall be allowed 

to emit H2S or SO2 process 

fugitive emissions unless 

the equipment is inspected 

and repaired according to 

subparagraph (C)(iii) of 

this paragraph or unless the 

H2S or SO2 emissions are 

monitored with ambient 

property line monitors 

according to subparagraph 

(E)(i) of this paragraph. 

Components in sweet 

crude oil or gas service as 

defined by Chapter 101 of 

this title (relating to 

General Rules) are exempt 

from these limitations. 

Rev submitted 04/19/1996

(11) No facility which is located 

less than one quarter of a 1⁄4

mile from the nearest offplant receptor shall be 

allowed to emit hydrogen 

sulfide (H2S) or SO2 process 

fugitive emissions unless 

the equipment is inspected 

and repaired according to 

subparagraph subsection (C

c)(iii 3) of this paragraph

section. No facility which 

is located at least one 

quarter of a 1⁄4 mile from 

the nearest off-plant 

receptor shall be allowed to 

emit H2S or SO2 process 

fugitive emissions unless 

the equipment is inspected 

and repaired according to 

subparagraph subsection (C

c)(iii 3) of this paragraph or

section unless the H2S or 

SO2 emissions are 

monitored with ambient 

property line monitors 

according to subparagraph

subsection (E e)(i 1) of this 

paragraph section. 

Components in sweet crude 

oil or gas service as defined 

by Chapter 101 of this title 

(relating to General Rules) 

are exempt from these 

limitations. 

Rev submitted 09/11/2000

(11) No facility which is located less than 

1⁄4 mile from the nearest off-plant 

receptor shall be allowed to emit 

hydrogen sulfide (H2S) or SO2

process fugitive emissions unless the 

equipment is inspected and repaired 

according to subsection (c)(3) of this 

section. No facility which is located 

at least 1⁄4 mile from the nearest offplant receptor shall be allowed to 

emit H2S or SO2 process fugitive 

emissions unless the equipment is 

inspected and repaired according to 

subsection (c)(3) of this section 

unless the H2S or SO2 emissions are 

monitored with ambient property 

line monitors according to 

subsection (e)(1) of this section. 

Components in sweet crude oil or 

gas service as defined by Chapter 

101 of this title (relating to General 

Rules) are exempt from these 

limitations. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 09/11/00 

 Revision 

eliminated 

parenthesis around 

H2S in the first 

sentence. 

Submitted 09/20/95

(xii) Flares shall be designed and operated in 

accordance with 40 Code of Federal 

Regulations (CFR), Part 60.18 or equivalent 

standard approved by the commission, 

including specifications of minimum heating 

values of waste gas, maximum tip velocity, and 

pilot flame monitoring. If necessary to ensure 

adequate combustion, sufficient gas shall be 

added to make the gases combustible. An 

infrared monitor is considered equivalent to a 

thermocouple for flame monitoring purposes. 

An automatic ignition system may be used in 

lieu of a continuous pilot.

Rev submitted 04/19/1996

(12) Flares shall be designed and operated in accordance 

with 40 Code of Federal Regulations (CFR), Part 

60.18 or equivalent standard approved by the 

commission, including specifications of minimum 

heating values of waste gas, maximum tip velocity, 

and pilot flame monitoring. If necessary to ensure 

adequate combustion, sufficient gas shall be added to 

make the gases combustible. An infrared monitor is 

considered equivalent to a thermocouple for flame 

monitoring purposes. An automatic ignition system 

may be used in lieu of a continuous pilot.

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

ix 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(xiii) Appropriate documentation 

shall be submitted to 

demonstrate that compliance 

with the Prevention of 

Significant Deterioration 

(PSD) and nonattainment 

new source review (NSR) 

provisions of the FCAA, 

Parts C and D, and 

regulations promulgated 

thereunder, are being met. 

The oil and gas facility shall 

be required to meet the 

requirements of Subchapter 

B of the chapter (relating to 

New Source Review 

Permits) instead of this 

subchapter if a PSD or 

nonattainment permit is 

required.

(xiv) Documentation shall be 

submitted to demonstrate 

compliance with applicable 

New Source Performance 

Standards (NSPS, 40 CFR 

60) and National Emission 

Standards for Hazardous Air 

Pollution (NESHAP, 40 

CFR 61).

Rev submitted 04/19/1996

(13) Appropriate 

documentation shall be 

submitted to demonstrate 

that compliance with the 

Prevention of Significant 

Deterioration (PSD) and 

nonattainment new source 

review (NSR) provisions 

of the FCAA Federal 

Clean Air Act, Parts C and 

D, and regulations 

promulgated thereunder, 

are being met. The oil and 

gas facility shall be 

required to meet the 

requirements of 

Subchapter B of the this 

chapter (relating to New 

Source Review Permits) 

instead of this subchapter 

if a PSD or nonattainment 

permit is required.

(14) Documentation shall be 

submitted to demonstrate 

compliance with 

applicable New Source 

Performance Standards 

(NSPS, 40 CFR 60) and 

National Emission 

Standards for Hazardous 

Air Pollution (NESHAP, 

40 CFR 61).

Rev submitted 07/22/1998 

(13) Appropriate documentation shall be 

submitted to demonstrate that 

compliance with the Prevention of 

Significant Deterioration (PSD) and 

nonattainment new source review 

provisions of the Federal Clean Air 

Act FCAA, Parts C and D, and 

regulations promulgated thereunder, 

and with Subchapter C of this 

chapter (relating to Hazardous Air 

Pollutants: Regulations Governing 

Constructed or Reconstructed Major 

Sources (FCAA, §112(g), 40 CFR 

Part 63)) are being met. The oil and 

gas facility shall be required to meet 

the requirements of Subchapter B of 

this chapter (relating to New Source 

Review Permits) instead of this 

subchapter if a PSD or 

nonattainment permit or a review 

under Subchapter C of this chapter is 

required.

(14) Documentation shall be submitted to 

demonstrate compliance with 

applicable New Source Performance 

Standards (NSPS, 40 CFR Part 60). 

and National Emission Standards for 

Hazardous Air Pollution (NESHAP, 

40 CFR 61).

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 07/22/98 

 Revision to (13): 

Added reference to 

Subchapter C and 

40 CFR Part 63 for 

compliance and 

review under 

Subchapter C for 

major sources. 

 Revision to (14): 

Separated NSPS 

and NESHAP 

requirements into 

separate sections. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

x 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95 

(xv) New and increased 

emissions shall not cause or 

contribute to a violation of 

any National Ambient Air 

Quality Standard (NAAQS) 

or regulation property line 

standards as specified in 

Chapters 111, 112, and 113 

of this title (relating to 

Control of Air Pollution 

From Visible Emissions and 

Particulate Matter; Control 

of Air Pollution From Sulfur 

Compounds; and Control of 

Air Pollution From Toxic 

Materials). Engineering 

judgment and/or 

computerized air dispersion 

modeling may be used in 

this demonstration. To 

show compliance with § 

116.610(a)(1) of this title 

(relating to Applicability) 

for H2S emissions from 

process vents, ten 

milligrams per cubic meter 

shall be used as the “L” 

value instead of the value 

represented by 

§116.610(a)(1) of this title.

Rev submitted 04/19/1996

(15) New and increased 

emissions shall not cause 

or contribute to a violation 

of any National Ambient 

Air Quality Standard 

(NAAQS) or regulation 

property line standards as 

specified in Chapters 111, 

112, and 113 of this title 

(relating to Control of Air 

Pollution From Visible 

Emissions and Particulate 

Matter; Control of Air 

Pollution From Sulfur 

Compounds; and Control 

of Air Pollution From 

Toxic Materials). 

Engineering judgment 

and/or computerized air 

dispersion modeling may 

be used in this 

demonstration. To show 

compliance with § 

116.610(a)(1) of this title 

(relating to Applicability) 

for H2S emissions from 

process vents, ten 

milligrams per cubic meter 

shall be used as the “L” 

value instead of the value 

represented by 

§116.610(a)(1) of this title.

Rev submitted 07/22/1998 

(15) Documentation shall be submitted to 

demonstrate compliance with 

applicable National Emission 

Standards for Hazardous Air 

Pollution (NESHAP, 40 CFR Part 

61).

(16) Documentation shall be submitted to 

demonstrate compliance with 

applicable maximum achievable 

control technology standards as 

listed under 40 CFR Part 63, 

promulgated by the EPA under 

FCAA, §112 or as listed in Chapter 

113, Subchapter C of this title 

(relating to National Emissions 

Standards for Hazardous Air 

Pollutants for Source Categories 

(FCAA §112, 40 CFR Part 63)).

(17) (15) New and increased emissions 

shall not cause or contribute to a 

violation of any National Ambient 

Air Quality Standard or regulation 

property line standards as specified 

in Chapters 111, 112, and 113 of this 

title (relating to Control of Air 

Pollution From Visible Emissions 

and Particulate Matter; Control of 

Air Pollution From Sulfur 

Compounds; and Control of Air 

Pollution From Toxic Materials). 

Engineering judgment and/or 

computerized air dispersion 

modeling may be used in this 

demonstration. To show compliance 

with §116.610(a)(1) of this title 

(relating to Applicability) for H2S 

emissions from process vents, ten 

milligrams per cubic meter shall be 

used as the “L” value instead of the 

value represented by §116.610(a)(1) 

of this title.

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 07/22/98 

 Revised (15): 

Created a new 

section for 

NESHAP 

compliance 

 Revised (16): 

Created a new 

section for MACT 

requirements 

 Revised (17):Was 

originally (15), no 

changes made to 

the language 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xi 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(xvi) Fuel for all combustion 

units and flare pilots shall 

be sweet natural gas or 

liquid petroleum gas, fuel 

gas containing no more 

than ten grains of total 

sulfur per 100 dry standard 

cubic feet (scdf), or field 

gas. If field gas contains 

more than 1.5 grains of H2S 

or 30 grains total sulfur 

compounds per 100 scdf, 

the operator shall maintain 

records, including at least 

quarterly measurements of 

fuel H2S and total sulfur 

content, which demonstrate 

that the annual SO2

emissions from the facility 

do not exceed the 

limitations listed in the 

standard permit 

registration. If a flare is the 

only combustion unit on a 

property, the operator shall 

not be required to maintain 

such records on flare pilot 

gas. 

Rev submitted 04/19/1996

(16) Fuel for all combustion 

units and flare pilots shall 

be sweet natural gas or 

liquid petroleum gas, fuel 

gas containing no more 

than ten grains of total 

sulfur per 100 dry standard 

cubic feet (scdf), or field 

gas. If field gas contains 

more than 1.5 grains of H2S 

or 30 grains total sulfur 

compounds per 100 scdf, 

the operator shall maintain 

records, including at least 

quarterly measurements of 

fuel H2S and total sulfur 

content, which demonstrate 

that the annual SO2

emissions from the facility 

do not exceed the 

limitations listed in the 

standard permit 

registration. If a flare is the 

only combustion unit on a 

property, the operator shall 

not be required to maintain 

such records on flare pilot 

gas. 

Rev submitted 07/22/1998

(18) (16) Fuel for all combustion units 

and flare pilots shall be sweet natural 

gas or liquid petroleum gas, fuel gas 

containing no more than ten grains 

of total sulfur per 100 dry standard 

cubic feet (scdf dscf), or field gas. If 

field gas contains more than 1.5 

grains of H2S or 30 grains total 

sulfur compounds per 100 scdf dscf, 

the operator shall maintain records 

including at least quarterly 

measurements of fuel H2S and total 

sulfur content, which demonstrate 

that the annual SO2 emissions from 

the facility do not exceed the 

limitations listed in the standard 

permit registration. If a flare is the 

only combustion unit on a property, 

the operator shall not be required to 

maintain such records on flare pilot 

gas. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 07/22/98 

 Revision corrected 

the acronym for 

dry standard cubic 

feet from scdf to 

dscf. 

 Section 

renumbered from 

addition of 

addition sections 

above. 

Submitted 09/20/95

(B) Control requirements 

Rev submitted 04/19/1996

 (B) (b) Control requirements 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xii 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(1) (i) Floating roofs 

or equivalent 

controls shall be 

required on all 

new or modified 

storage tanks, 

other than 

pressurized tanks 

which meet 

Standard 

Exemption 83, 

unless the tank is 

less than 25,000 

gallons in nominal 

size or the vapor 

pressure of the 

compound to be 

stored in the tank 

is less than 0.5 

pounds per square 

inch absolute 

(psia) at maximum 

short-term storage 

temperature. 

Rev submitted 

04/19/1996

(1) Floating roofs or 

equivalent controls 

shall be required 

on all new or 

modified storage 

tanks, other than 

pressurized tanks 

which meet 

Standard 

Exemption 83, 

unless the tank is 

less than 25,000 

gallons in nominal 

size or the vapor 

pressure of the 

compound to be 

stored in the tank is 

less than 0.5 

pounds per square 

inch absolute (psia) 

at maximum shortterm storage 

temperature. 

Rev submitted 

07/22/1998 

(1) Floating roofs or 

equivalent controls 

shall be required on 

all new or modified 

storage tanks, other 

than pressurized 

tanks which meet 

Standard Exemption 

83 §106.476 of this 

title (relating to 

Pressurized Tanks 

or Tanks Vented to 

Control (Previously 

SE 83)), unless the 

tank is less than 

25,000 gallons in 

nominal size or the 

vapor pressure of 

the compound to be 

stored in the tank is 

less than 0.5 pounds 

per square inch 

absolute (psia) at 

maximum shortterm storage 

temperature. 

Rev submitted 09/11/2000

 (1) Floating roofs or equivalent 

controls shall be required on 

all new or modified storage 

tanks, other than pressurized 

tanks which meet §106.476 

of this title (relating to 

Pressurized Tanks or Tanks 

Vented to Control 

(Previously SE 83)), unless 

the tank is less than 25,000 

gallons in nominal size or the 

vapor pressure of the 

compound to be stored in the 

tank is less than 0.5 pounds 

per square inch absolute 

(psia) at maximum shortterm storage temperature. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 07/22/98 and 

09/11/00 

 Revisions changed 

reference from 

Standard 

Exemptions to 

Permits by Rule 

Submitted 09/20/95

(I) For internal floating roofs, mechanical shoe 

primary seal or liquid-mounted primary seal or 

a vapor-mounted primary with rim-mounted 

secondary seal shall be used. 

(II) Mechanical shoe or liquid-mounted primary 

seals shall include a rim-mounted secondary 

seal on all external floating roofs tanks. Vapormounted primary seals will not be accepted. 

(III) All floating roof tanks shall comply with the 

requirements under §115.112(a)(2)(A)-(F) of 

this title (relating to Control Requirements). 

(IV) In lieu of a floating roof, tank emissions may be 

routed to: 

(-a-) A destruction device such that a 

minimum VOC destruction efficiency of 

95% is achieved; or 

(-b-) A vapor recovery system such that a 

minimum VOC recovery efficiency of 

95% is achieved. 

Rev submitted 04/19/1996

(A) For internal floating roofs, mechanical shoe primary 

seal or liquid-mounted primary seal or a vapormounted primary with rim-mounted secondary seal 

shall be used. 

(B) Mechanical shoe or liquid-mounted primary seals shall 

include a rim-mounted secondary seal on all external 

floating roofs tanks. Vapor-mounted primary seals 

will not be accepted. 

(C) All floating roof tanks shall comply with the 

requirements under §115.112(a)(2)(A)-(F) of this title 

(relating to Control Requirements). 

(D) In lieu of a floating roof, tank emissions may be 

routed to: 

(i) A destruction device such that a minimum VOC 

destruction efficiency of 95% is achieved; or 

(ii) A vapor recovery system such that a minimum 

VOC recovery efficiency of 95% is achieved. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xiii 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(I) Independent of the 

exemptions listed in the 

paragraph, if the emissions 

from any fixed roof tank 

exceeded ten tpy of VOC 

or ten tpy of sulfur 

compounds, the tank 

emissions shall be routed 

to a destruction device, 

vapor recovery unit, or 

equivalent method of 

control that meets the 

requirements listed in 

subclause (VI) of this 

clause. 

Rev submitted 04/19/1996

(E) Independent of the 

exemptions listed in the 

paragraph, if the emissions 

from any fixed roof tank 

exceeded ten tpy of VOC or 

ten tpy of sulfur 

compounds, the tank 

emissions shall be routed to 

a destruction device, vapor 

recovery unit, or equivalent 

method of control that 

meets the requirements 

listed in subclause (VI) 

subparagraph (D) of this 

clause paragraph. 

Rev submitted 09/11/2000

(E) Independent of the exemptions

permits by rule listed in the this

paragraph, if the emissions from any 

fixed roof tank exceeded ten tpy of 

VOC or ten tpy of sulfur 

compounds, the tank emissions shall 

be routed to a destruction device, 

vapor recovery unit, or equivalent 

method of control that meets the 

requirements listed in subparagraph 

(D) of this paragraph. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 09/11/00 

 Revision changed 

reference from 

standard 

exemption to 

permit by rule. 

Submitted 09/20/95

(ii) The VOC emissions from a natural gas glycol 

dehydration unit shall be controlled as follows. 

(I) If total uncontrolled VOC emissions are 

equal to or greater than ten tpy, but less 

than 50 tpy, a minimum of 80% by 

weight minimum control efficiency shall 

be achieved by either operating a 

condenser and a separator (or flash tank), 

vapor recovery unit, destruction device, 

or equivalent control device. 

(II) If total uncontrolled VOC emissions are 

equal to or greater than 50 tpy, a 

minimum of: 

(-a-) 98% by weight minimum 

destruction efficiency shall be 

achieved by a destruction device or 

equivalent; or 

(-b-) 95% by weight minimum control 

efficiency shall be achieved by a 

vapor recovery system or 

equivalent. 

 

Rev submitted 04/19/1996

(2) The VOC emissions from a natural gas glycol 

dehydration unit shall be controlled as follows. 

(A) If total uncontrolled VOC emissions are equal to 

or greater than ten tpy, but less than 50 tpy, a 

minimum of 80% by weight minimum control 

efficiency shall be achieved by either operating a 

condenser and a separator (or flash tank), vapor 

recovery unit, destruction device, or equivalent 

control device. 

(B) If total uncontrolled VOC emissions are equal to 

or greater than 50 tpy, a minimum of: 

(i) 98% by weight minimum destruction 

efficiency shall be achieved by a destruction 

device or equivalent; or 

(ii) 95% by weight minimum control efficiency 

shall be achieved by a vapor recovery 

system or equivalent. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Submitted 09/20/95

(C) Inspection requirements. 

Rev submitted 04/19/1996 

(C) (c) Inspection requirements. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xiv 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(i) Owners or operators who are 

subject to subparagraph (A)(vii) 

or (viii) of this paragraph shall 

comply with the following 

requirements. 

(I) No component shall be 

allowed to have a VOC leak 

for more than 15 days after 

the leak is detected to 

exceed a VOC concentration 

greater than 10,000 parts per 

million by volume (ppmv) 

above background as 

methane, propane, or 

hexane, or the dripping or 

exuding of process fluid 

based on sight, smell, or 

sound for all components. 

The VOC fugitive emission 

components which contact 

process fluids where the 

VOCs have an aggregate 

partial pressure or vapor 

pressure of less than 0.5 psia 

at 100 degrees Fahrenheit 

are exempt from this 

requirement. If VOC 

fugitive emission 

components are in service 

where the operating pressure 

is at least 0.725 pounds per 

square inch (psi) (five 

kilopascals (Kpa)) below 

ambient pressure, then these 

components are also exempt 

from this requirement as 

long as the equipment is 

identified in a list that is 

made available upon request 

by Texas Natural Resource 

Conservation Commission 

(TNRCC) representatives, 

the EPA, or any other air 

pollution agency having 

jurisdiction. All piping and 

valves two inches nominal 

size and smaller, unless 

subject to federal New 

Source Performance 

Standards requiring a 

fugitive VOC emissions leak 

detection and repair program 

or Chapter 115 of this title 

(relating to Control of Air 

Pollution from Volatile 

Organic Compounds), are 

also exempt from this 

requirement. 

Rev submitted 04/19/1996 

(1) Owners or operators who are 

subject to subparagraph

subsection (A a)(vii 7) or (viii 8) 

of this paragraph section shall 

comply with the following 

requirements. 

(A) No component shall be 

allowed to have a VOC leak 

for more than 15 days after 

the leak is detected to exceed 

a VOC concentration greater 

than 10,000 parts per million 

by volume (ppmv) above 

background as methane, 

propane, or hexane, or the 

dripping or exuding of 

process fluid based on sight, 

smell, or sound for all 

components. The VOC 

fugitive emission components 

which contact process fluids 

where the VOCs have an 

aggregate partial pressure or 

vapor pressure of less than 0.5 

psia at 100 degrees Fahrenheit 

are exempt from this 

requirement. If VOC fugitive 

emission components are in 

service where the operating 

pressure is at least 0.725 

pounds per square inch (psi) 

(five kilopascals (Kpa)) 

below ambient pressure, then 

these components are also 

exempt from this requirement 

as long as the equipment is 

identified in a list that is made 

available upon request by 

Texas Natural Resource 

Conservation Commission 

(TNRCC) representatives the 

agency representatives, the 

United States Environmental 

Protection Agency (EPA), or 

any other air pollution agency 

having jurisdiction. All piping 

and valves two inches 

nominal size and smaller, 

unless subject to federal New 

Source Performance 

Standards NSPS requiring a 

fugitive VOC emissions leak 

detection and repair program 

or Chapter 115 of this title 

(relating to Control of Air 

Pollution from Volatile 

Organic Compounds), are 

also exempt from this 

requirement. 

Rev submitted 07/22/1998 

 (1) Owners or operators who are 

subject to subsection (a)(7) or 

(8) of this section shall comply 

with the following requirements. 

(A) No component shall be 

allowed to have a VOC leak 

for more than 15 days after 

the leak is detected to 

exceed a VOC concentration 

greater than 10,000 parts per 

million by volume (ppmv) 

above background as 

methane, propane, or 

hexane, or the dripping or 

exuding of process fluid 

based on sight, smell, or 

sound for all components. 

The VOC fugitive emission 

components which contact 

process fluids where the 

VOCs have an aggregate 

partial pressure or vapor 

pressure of less than 0.5 psia 

at 100 degrees Fahrenheit 

are exempt from this 

requirement. If VOC 

fugitive emission 

components are in service 

where the operating pressure 

is at least 0.725 pounds per 

square inch (psi) (five 

kilopascals (Kpa)) below 

ambient pressure, then these 

components are also exempt 

from this requirement as 

long as the equipment is 

identified in a list that is 

made available upon request 

by the agency 

representatives, the United 

States Environmental 

Protection Agency (EPA), 

or any other air pollution 

agency having jurisdiction. 

All piping and valves two 

inches nominal size and 

smaller, unless subject to 

federal NSPS requiring a 

fugitive VOC emissions leak 

detection and repair program 

or Chapter 115 of this title 

(relating to Control of Air 

Pollution from Volatile 

Organic Compounds), are 

also exempt from this 

requirement. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 07/22/98 

 Revision removed 

the formal name 

for EPA, leaving 

just the acronym. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xv 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(II) All technically feasible repairs shall be made to 

repair a VOC leaking process fugitive component 

within 15 days after the leak is detected. If the repair 

of a component would require a unit shutdown, the 

repair may be delayed until the next scheduled 

shutdown. All leaking components which cannot be 

repaired until a scheduled shutdown shall be 

identified for such repair by tagging. The TNRCC 

executive director, at his or her discretion, may 

require early unit shutdown or other appropriate 

action based on the number and severity of tagged 

leaks awaiting shutdown. 

(III) New and reworked underground process pipelines 

containing VOCs shall contain no buried valves such 

that process fugitive emission inspection and repair is 

rendered impractical. 

(IV) To the extent that good engineering practice will 

permit, new and reworked valves and piping 

connections in VOC service shall be so located to be 

reasonably accessible for leak-checking during plant 

operation. Valves elevated more than two meters 

above a support surface will be considered nonaccessible and shall be identified in a list to be made 

available upon request. 

(V) New and reworked piping connections in VOC 

service shall be welded or flanged. Screwed 

connections are permissible only on piping smaller 

than two-inch diameter. No later than the next 

scheduled quarterly monitoring after initial 

installation or replacement, all new or reworked 

connections shall be gas-tested or hydraulically-tested 

at no less than normal operating pressure and 

adjustments made as necessary to obtain leak-free 

performance. Flanges in VOC service shall be 

inspected by visual, audible, and/or olfactory means 

at least weekly by operating personnel walk-through. 

(VI) Each open-ended valve or line in VOC service, 

other than a valve or line used for safety relief, shall 

be equipped with a cap, blind flange, plug, or a 

second valve. Except during sampling, the second 

valve shall be closed. 

(VII) Accessible valves in VOC service shall be 

monitored by leak-checking for fugitive emissions at 

least quarterly using an approved gas analyzer. For 

valves equipped with rupture discs, a pressure gauge 

shall be installed between the relief valve and rupture 

disc to monitor disc integrity. All leaking discs shall 

be replaced at the earliest opportunity, but no later 

than the next process shutdown. Sealless/leakless 

valves (including, but not limited to, welded bonnet 

bellows and diaphragm valves) and relief valves 

equipped with a rupture disc or venting to a control 

device are exempt from monitoring. 

(VIII) Dual pump seals with barrier fluid at higher 

pressure than process pressure, seals degassing to vent 

control systems kept in good working order, or seals 

equipped with an automatic seal failure detection and 

alarm system, submerged pumps, or sealless pumps 

(including, but not limited to, diaphragm, canned, or 

magnetic driven pumps) are exempt from monitoring. 

Rev submitted 04/19/1996 

(B) All technically feasible repairs shall be made to 

repair a VOC leaking process fugitive component 

within 15 days after the leak is detected. If the repair 

of a component would require a unit shutdown, the 

repair may be delayed until the next scheduled 

shutdown. All leaking components which cannot be 

repaired until a scheduled shutdown shall be 

identified for such repair by tagging. The TNRCC

executive director, at his or her discretion, may 

require early unit shutdown or other appropriate 

action based on the number and severity of tagged 

leaks awaiting shutdown. 

(C) New and reworked underground process pipelines 

containing VOCs shall contain no buried valves such 

that process fugitive emission inspection and repair is 

rendered impractical. 

(D) To the extent that good engineering practice will 

permit, new and reworked valves and piping 

connections in VOC service shall be so located to be 

reasonably accessible for leak-checking during plant 

operation. Valves elevated more than two meters 

above a support surface will be considered nonaccessible and shall be identified in a list to be made 

available upon request. 

(E) New and reworked piping connections in VOC 

service shall be welded or flanged. Screwed 

connections are permissible only on piping smaller 

than two-inch diameter. No later than the next 

scheduled quarterly monitoring after initial 

installation or replacement, all new or reworked 

connections shall be gas-tested or hydraulicallytested at no less than normal operating pressure and 

adjustments made as necessary to obtain leak-free 

performance. Flanges in VOC service shall be 

inspected by visual, audible, and/or olfactory means 

at least weekly by operating personnel walk-through. 

(F) Each open-ended valve or line in VOC service, other 

than a valve or line used for safety relief, shall be 

equipped with a cap, blind flange, plug, or a second 

valve. Except during sampling, the second valve shall 

be closed. 

(G) Accessible valves in VOC service shall be 

monitored by leak-checking for fugitive emissions at 

least quarterly using an approved gas analyzer. For 

valves equipped with rupture discs, a pressure gauge 

shall be installed between the relief valve and rupture 

disc to monitor disc integrity. All leaking discs shall 

be replaced at the earliest opportunity, but no later 

than the next process shutdown. Sealless/leakless 

valves (including, but not limited to, welded bonnet 

bellows and diaphragm valves) and relief valves 

equipped with a rupture disc or venting to a control 

device are exempt from monitoring. 

(H) Dual pump seals with barrier fluid at higher pressure 

than process pressure, seals degassing to vent control 

systems kept in good working order, or seals 

equipped with an automatic seal failure detection and 

alarm system, submerged pumps, or sealless pumps 

(including, but not limited to, diaphragm, canned, or 

magnetic driven pumps) are exempt from monitoring. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xvi 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(IX) All other pump and 

compressor seals 

emitting VOC shall 

be monitored with an 

approved gas 

analyzer at least 

quarterly. 

(X) After completion of 

the required quarterly 

inspections for a 

period of at least two 

years, the operator of 

the oil and gas 

facility may request 

in writing to the 

TNRCC, Office of 

Air Quality, New 

Source Review 

Division that the 

monitoring schedule 

be revised based on 

the percent of valves 

leaking. The percent 

of valves leaking 

shall be determined 

by dividing the sum 

of valves leaking 

during current 

monitoring and 

valves for which 

repair has been 

delayed by the total 

number of valves 

subject to the 

requirements. This 

request shall include 

all data that has been 

developed to justify 

the following 

modifications in the 

monitoring schedule. 

Rev submitted 04/19/1996 

 (I) All other pump and 

compressor seals emitting 

VOC shall be monitored 

with an approved gas 

analyzer at least 

quarterly. 

(J) After completion of the 

required quarterly 

inspections for a period of 

at least two years, the 

operator of the oil and gas 

facility may request in 

writing to the TNRCC,

Office of Air Quality, 

New Source Review 

Division that the 

monitoring schedule be 

revised based on the 

percent of valves leaking. 

The percent of valves 

leaking shall be 

determined by dividing 

the sum of valves leaking 

during current monitoring 

and valves for which 

repair has been delayed 

by the total number of 

valves subject to the 

requirements. This 

request shall include all 

data that has been 

developed to justify the 

following modifications 

in the monitoring 

schedule. 

Rev submitted 

07/22/1998 

(I) All other pump and 

compressor seals 

emitting VOC shall 

be monitored with 

an approved gas 

analyzer at least 

quarterly. 

(J) After completion of 

the required 

quarterly 

inspections for a 

period of at least 

two years, the 

operator of the oil 

and gas facility may 

request in writing to 

the Office of Air 

Quality, New 

Source Review 

Permits Division 

that the monitoring 

schedule be revised 

based on the percent 

of valves leaking. 

The percent of 

valves leaking shall 

be determined by 

dividing the sum of 

valves leaking 

during current 

monitoring and 

valves for which 

repair has been 

delayed by the total 

number of valves 

subject to the 

requirements. This 

request shall include 

all data that has 

been developed to 

justify the following 

modifications in the 

monitoring 

schedule. 

Rev submitted 09/11/2000 

(I) All other pump and 

compressor seals 

emitting VOC shall be 

monitored with an 

approved gas analyzer at 

least quarterly. 

(J) After completion of the 

required quarterly 

inspections for a period 

of at least two years, the 

operator of the oil and 

gas facility may request 

in writing to the Office 

of Air Quality, New 

Source Review Permits 

Division Permitting, 

Remediation, and 

Registration that the 

monitoring schedule be 

revised based on the 

percent of valves 

leaking. The percent of 

valves leaking shall be 

determined by dividing 

the sum of valves 

leaking during current 

monitoring and valves 

for which repair has 

been delayed by the 

total number of valves 

subject to the 

requirements. This 

request shall include all 

data that has been 

developed to justify the 

following modifications 

in the monitoring 

schedule. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 07/22/98 and 

09/11/00 

 Revisions changed 

the office name 

reference. 

 No change made 

to (I) 

Submitted 09/20/95

(-a-) After two consecutive quarterly leak detection 

periods with the percent of valves leaking equal to 

or less than 2.0%, an owner or operator may begin 

to skip one of the quarterly leak detection periods 

for the valves in gas/vapor and light liquid service. 

(-b-) After five consecutive quarterly leak detection 

periods with the percent of valves leaking equal 

to or less than 2.0%, an owner or operator may 

begin to skip three of the quarterly leak detection 

periods for the valves in gas/vapor and light liquid 

service. 

Rev submitted 04/19/1996 

 (i) After two consecutive quarterly leak detection 

periods with the percent of valves leaking equal to 

or less than 2.0%, an owner or operator may begin 

to skip one of the quarterly leak detection periods 

for the valves in gas/vapor and light liquid service. 

(ii) After five consecutive quarterly leak detection 

periods with the percent of valves leaking equal 

to or less than 2.0%, an owner or operator may 

begin to skip three of the quarterly leak detection 

periods for the valves in gas/vapor and light liquid 

service. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xvii 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(ii) Owners or operators who are subject to subsection 

(A)(ix) or (x) of this section shall comply with the 

following requirements. 

(I) No component shall be allowed to have a 

VOC leak for more than 15 days after the 

leak is found which exceeds a VOC 

concentration greater than 500 ppmv for all 

components except pumps and compressors 

and greater than 2,000 ppmv for pumps and 

compressors above background as methane, 

propane, or hexane, or the dripping or 

exuding of process fluid based on sight, 

smell, or sound. The VOC fugitive emission 

components which contact process fluids 

where the VOCs have an aggregate partial 

pressure or vapor pressure of less than 0.044 

psia at 100 degrees Fahrenheit are exempt 

from this requirement. If VOC fugitive 

emission components are in service where the 

operating pressure is at least 0.725 psi (five 

Kpa) below ambient pressure, these 

components are also exempt from this 

requirement as long as the equipment is 

identified in a list that is made available upon 

request by TNRCC representatives, the EPA, 

or any air pollution control agency having 

jurisdiction. All piping and valves two inches 

nominal size and smaller are also exempt 

from this requirement. 

(II) All technically feasible repairs shall be made 

to repair a VOC leaking process fugitive 

component within 15 days after the leak is 

detected. If the repair of a component would 

require a unit shutdown, the repair may be 

delayed until the next scheduled shutdown. 

All leaking components which cannot be 

repaired until a scheduled shutdown shall be 

identified for such repair by tagging. The 

executive director, at his or her discretion, 

may require early unit shutdown or other 

appropriate action based on the number and 

severity of tagged leaks awaiting shutdown. 

(III) New and reworked underground process 

pipelines containing VOCs shall contain no 

buried valves such that process fugitive 

emission inspection and repair is rendered 

impractical. 

(IV) To the extent that good engineering practice 

will permit, new and reworked valves and 

piping connections in VOC service shall be 

so located to be reasonably accessible for 

leak-checking during plant operation. Valves 

elevated more than two meters above a 

support surface will be considered nonaccessible and shall be identified in a list to 

be made available upon request. 

Rev submitted 04/19/1996 

(2) Owners or operators who are subject to subsection 

(A a)(ix 9) or (x 10) of this section shall comply 

with the following requirements. 

(A) No component shall be allowed to have a 

VOC leak for more than 15 days after the 

leak is found which exceeds a VOC 

concentration greater than 500 ppmv for all 

components except pumps and compressors 

and greater than 2,000 ppmv for pumps and 

compressors above background as methane, 

propane, or hexane, or the dripping or 

exuding of process fluid based on sight, 

smell, or sound. The VOC fugitive emission 

components which contact process fluids 

where the VOCs have an aggregate partial 

pressure or vapor pressure of less than 0.044 

psia at 100 degrees Fahrenheit are exempt 

from this requirement. If VOC fugitive 

emission components are in service where the 

operating pressure is at least 0.725 psi (five 

Kpa) below ambient pressure, these 

components are also exempt from this 

requirement as long as the equipment is 

identified in a list that is made available upon 

request by TNRCC agency representatives, 

the EPA, or any air pollution control agency 

having jurisdiction. All piping and valves two 

inches nominal size and smaller are also 

exempt from this requirement. 

(B) All technically feasible repairs shall be made 

to repair a VOC leaking process fugitive 

component within 15 days after the leak is 

detected. If the repair of a component would 

require a unit shutdown, the repair may be 

delayed until the next scheduled shutdown. 

All leaking components which cannot be 

repaired until a scheduled shutdown shall be 

identified for such repair by tagging. The 

executive director, at his or her discretion, 

may require early unit shutdown or other 

appropriate action based on the number and 

severity of tagged leaks awaiting shutdown. 

(C) New and reworked underground process 

pipelines containing VOCs shall contain no 

buried valves such that process fugitive 

emission inspection and repair is rendered 

impractical. 

(D) To the extent that good engineering practice 

will permit, new and reworked valves and 

piping connections in VOC service shall be 

so located to be reasonably accessible for 

leak-checking during plant operation. Valves 

elevated more than two meters above a 

support surface will be considered nonaccessible and shall be identified in a list to 

be made available upon request. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xviii 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(V) New and reworked piping connections in VOC 

service shall be welded or flanged. Screwed 

connections are permissible only on piping smaller 

than two-inch diameter. No later than the next 

scheduled quarterly monitoring after initial 

installation or replacement, all new or reworked 

connections shall be gas-tested or hydraulicallytested at no less than normal operating pressure 

and adjustments made as necessary to obtain leakfree performance. Flanges in VOC service shall be 

inspected by visual, audible, and/or olfactory 

means at least weekly by operating personnel 

walk-through. 

(VI) Each open-ended valve or line in VOC service, 

other than a valve or line used for safety relief, 

shall be equipped with a cap, blind flange, plug, or 

a second valve. Except during sampling, the 

second valve shall be closed. 

(VII) Accessible valves in VOC service shall be 

monitored by leak-checking for fugitive emissions 

at least quarterly using an approved gas analyzer. 

For valves equipped with rupture discs, a pressure 

gauge shall be installed between the relief valve 

and rupture disc to monitor disc integrity. All 

leaking discs shall be replaced at the earliest 

opportunity, but no later than the next process 

shutdown. Sealless/leakless valves (including, but 

not limited to, welded bonnet bellows and 

diaphragm valves) and relief valves equipped with 

a rupture disc or venting to a control device are 

exempt from monitoring. 

(VIII) Dual pump seals with barrier fluid at higher 

pressure than process pressure, seals degassing to 

vent control systems kept in good working order or 

seals equipped with an automatic seal failure 

detection and alarm system, submerged pumps, or 

sealless pumps (including, but not limited to, 

diaphragm, canned, or magnetic driven pumps) are 

exempt from monitoring. 

(IX) All other pump and compressor seals emitting 

VOC shall be monitored with an approved gas 

analyzer at least quarterly. 

Rev submitted 04/19/1996 

(E) New and reworked piping connections in VOC 

service shall be welded or flanged. Screwed 

connections are permissible only on piping smaller 

than two-inch diameter. No later than the next 

scheduled quarterly monitoring after initial 

installation or replacement, all new or reworked 

connections shall be gas-tested or hydraulicallytested at no less than normal operating pressure 

and adjustments made as necessary to obtain leakfree performance. Flanges in VOC service shall be 

inspected by visual, audible, and/or olfactory 

means at least weekly by operating personnel 

walk-through. 

(F) Each open-ended valve or line in VOC service, 

other than a valve or line used for safety relief, 

shall be equipped with a cap, blind flange, plug, or 

a second valve. Except during sampling, the 

second valve shall be closed. 

(G) Accessible valves in VOC service shall be 

monitored by leak-checking for fugitive emissions 

at least quarterly using an approved gas analyzer. 

For valves equipped with rupture discs, a pressure 

gauge shall be installed between the relief valve 

and rupture disc to monitor disc integrity. All 

leaking discs shall be replaced at the earliest 

opportunity, but no later than the next process 

shutdown. Sealless/leakless valves (including, but 

not limited to, welded bonnet bellows and 

diaphragm valves) and relief valves equipped with 

a rupture disc or venting to a control device are 

exempt from monitoring. 

(H) Dual pump seals with barrier fluid at higher 

pressure than process pressure, seals degassing to 

vent control systems kept in good working order or 

seals equipped with an automatic seal failure 

detection and alarm system, submerged pumps, or 

sealless pumps (including, but not limited to, 

diaphragm, canned, or magnetic driven pumps) are 

exempt from monitoring. 

(I) All other pump and compressor seals emitting 

VOC shall be monitored with an approved gas 

analyzer at least quarterly. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xix 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(X) After completion of the 

required quarterly 

inspections for a period of 

at least two years, the 

operator of the oil and gas 

facility may request in 

writing to the TNRCC, 

Office of Air Quality, New 

Source Review Division 

that the monitoring 

schedule be revised based 

on the percent of valves. 

Leaking. The percent of 

valves leaking shall be 

determined by dividing the 

sum of valves leaking 

during current monitoring 

and valves for which repair 

has been delayed by the 

total number of valves 

subject to the requirements. 

This request shall include 

all data that has been 

developed to justify the 

following modifications in 

the monitoring schedule. 

Rev submitted 04/19/1996 

(J) After completion of the 

required quarterly 

inspections for a period of at 

least two years, the operator 

of the oil and gas facility 

may request in writing to 

the TNRCC, Office of Air 

Quality, New Source 

Review Division that the 

monitoring schedule be 

revised based on the percent 

of valves. Leaking. The 

percent of valves leaking 

shall be determined by 

dividing the sum of valves 

leaking during current 

monitoring and valves for 

which repair has been 

delayed by the total number 

of valves subject to the 

requirements. This request 

shall include all data that 

has been developed to 

justify the following 

modifications in the 

monitoring schedule. 

Rev submitted 07/22/1998 

(J) After completion of the required 

quarterly inspections for a period of 

at least two years, the operator of the 

oil and gas facility may request in 

writing to the Office of Air Quality, 

New Source Review Permits

Division that the monitoring 

schedule be revised based on the 

percent of valves. Leaking. The 

percent of valves leaking shall be 

determined by dividing the sum of 

valves leaking during current 

monitoring and valves for which 

repair has been delayed by the total 

number of valves subject to the 

requirements. This request shall 

include all data that has been 

developed to justify the following 

modifications in the monitoring 

schedule. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 07/22/98 

 Revision added 

Permits to the 

office name 

Submitted 09/20/95

(-a-) After two consecutive quarterly leak detection 

periods with the percent of valves leaking equal 

to or less than 2.0%, an owner or operator may 

begin to skip one of the quarterly leak detection 

periods for the valves in gas/vapor and light 

liquid service. 

(-b-) After five consecutive quarterly leak detection 

periods with the percent of valves leaking equal 

to or less than 2.0%, an owner or operator may 

begin to skip three of the quarterly leak 

detection periods for the valves in gas/vapor and 

light liquid service. 

Rev submitted 04/19/1996 

(i) After two consecutive quarterly leak detection 

periods with the percent of valves leaking equal to or 

less than 2.0%, an owner or operator may begin to 

skip one of the quarterly leak detection periods for 

the valves in gas/vapor and light liquid service. 

(ii) After five consecutive quarterly leak detection 

periods with the percent of valves leaking equal to or 

less than 2.0%, an owner or operator may begin to 

skip three of the quarterly leak detection periods for 

the valves in gas/vapor and light liquid service. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Submitted 09/20/95

(XI) A directed maintenance program shall be used 

and consist of the repair and maintenance of 

VOC fugitive emission components assisted 

simultaneously by the use of an approved gas 

analyzer such that a minimum concentration of 

leaking VOC is obtained for each component 

being maintained. Replaced components shall 

be remonitored within 30 days of being placed 

back into VOC service. 

Rev submitted 04/19/1996 

(K) A directed maintenance program shall be used and 

consist of the repair and maintenance of VOC fugitive 

emission components assisted simultaneously by the 

use of an approved gas analyzer such that a minimum 

concentration of leaking VOC is obtained for each 

component being maintained. Replaced components 

shall be remonitored within 30 days of being placed 

back into VOC service. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xx 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(iii) For owners and operators who are subject to the 

applicable parts of subparagraph (A)(xi) of this 

paragraph, auditory and visual checks for SO2

and H2S leaks within the operating area shall be 

made every day. Immediately, but no later than 

eight hours upon detection of a leak, operating 

personnel shall take the following actions: 

(I) isolate the leak; and 

(II) commence repair or replacement of the 

leaking component; or 

(III) use a leak collection/containment system to 

prevent the leak until repair or replacement 

can be made if immediate repair is not 

possible. 

Rev submitted 04/19/1996 

(3) For owners and operators who are subject to the 

applicable parts of subparagraph subsection (A a)(xi

11) of this paragraph section, auditory and visual 

checks for SO2 and H2S leaks within the operating area 

shall be made every day. Immediately, but no later 

than eight hours upon detection of a leak, operating 

personnel shall take the following actions: 

(A) isolate the leak; and 

(B) commence repair or replacement of the leaking 

component; or 

(C) use a leak collection/containment system to 

prevent the leak until repair or replacement can 

be made if immediate repair is not possible. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Submitted 09/20/95

(D) Approved test methods. 

Rev submitted 04/19/1996 

 (D) (d) Approved test methods. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Submitted 09/20/95

(i) An approved gas analyzer used for the VOC 

fugitive inspection and repair requirement in 

subparagraph (C) of this paragraph, shall 

conform to requirements listed in 40 CFR 

§60.485(a) and (b). 

(ii) Tutweiler analysis or equivalent shall be used to 

determine the H2S content as required under 

subparagraph (A) and (E) of this paragraph 

Rev submitted 04/19/1996 

(1) An approved gas analyzer used for the VOC fugitive 

inspection and repair requirement in subparagraph

subsection (C c) of this paragraph section, shall 

conform to requirements listed in 40 CFR §60.485(a) 

and (b). 

(2) Tutweiler analysis or equivalent shall be used to 

determine the H2S content as required under 

subparagraph subsection (A a) and (E e) of this 

section. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xxi 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(iii) Proper operation of any 

condenser used as a VOC 

emissions control device 

to comply with 

subparagraph (A)(v) of 

this paragraph shall be 

tested to demonstrate 

compliance with the 

minimum control 

efficiency. Sampling shall 

occur within 60 days after 

start-up of new or 

modified facilities. The 

permittee shall contact the 

Engineering Services 

Section, Air Quality 

Enforcement Division 45 

days prior to sampling for 

approval of sampling 

protocol. The appropriate 

regional office in the 

region where the source is 

located shall also be 

contacted 45 days prior to 

sampling to provide them 

the opportunity to view 

the sampling. Neither the 

regional office nor the 

Engineering Services 

Section, Air Quality 

Enforcement Division 

personnel are required to 

view the testing. 

Sampling reports which 

comply with the 

provisions of the 

"TNRCC Sampling 

Procedures Manual," 

Chapter 14 ("Contents of 

Sampling Reports," dated 

January 1983 and revised 

July 1985), shall be 

distributed to the 

appropriate regional 

office, any local 

programs, and the 

Engineering Services 

Section, Air Quality 

Enforcement Division. 

Rev submitted 04/19/1996 

(3) Proper operation of any 

condenser used as a VOC 

emissions control device to 

comply with subparagraph

subsection (A a)(v 5) of this 

paragraph section shall be 

tested to demonstrate 

compliance with the 

minimum control efficiency. 

Sampling shall occur within 

60 days after start-up of new 

or modified facilities. The 

permittee shall contact the 

Engineering Services Section, 

Air Quality Enforcement 

Division 45 days prior to 

sampling for approval of 

sampling protocol. The 

appropriate regional office in 

the region where the source is 

located shall also be contacted 

45 days prior to sampling to 

provide them the opportunity 

to view the sampling. Neither 

the regional office nor the 

Engineering Services Section, 

Air Quality Enforcement 

Division personnel are 

required to view the testing. 

Sampling reports which 

comply with the provisions of 

the "TNRCC Sampling 

Procedures Manual," Chapter 

14 ("Contents of Sampling 

Reports," dated January 1983 

and revised July 1985), shall 

be distributed to the 

appropriate regional office, 

any local programs, and the 

Engineering Services Section, 

Air Quality Enforcement 

Division. 

Rev submitted 07/22/1998 

(3) Proper operation of any condenser used 

as a VOC emissions control device to 

comply with subsection (a)(5) of this 

section shall be tested to demonstrate 

compliance with the minimum control 

efficiency. Sampling shall occur within 

60 days after start-up of new or 

modified facilities. The permittee shall 

contact the Engineering Services 

Section, Air Quality Office of 

Compliance and Enforcement Division

45 days prior to sampling for approval 

of sampling protocol. The appropriate 

regional office in the region where the 

source is located shall also be contacted 

45 days prior to sampling to provide 

them the opportunity to view the 

sampling. Neither the regional office 

nor the Engineering Services Section, 

Air Quality Office of Compliance and 

Enforcement Division personnel are 

required to view the testing. Sampling 

reports which comply with the 

provisions of the "TNRCC Sampling 

Procedures Manual," Chapter 14 

("Contents of Sampling Reports," dated 

January 1983 and revised July 1985), 

shall be distributed to the appropriate 

regional office, any local programs, and 

the Engineering Services Section, Air 

Quality Office of Compliance and

Enforcement Division. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 07/22/98 

 Revision changed 

the office name 

referenced 

Submitted 09/20/95

(E) Monitoring and recordkeeping requirements. 

Rev submitted 04/19/1996 

 (E) (e) Monitoring and recordkeeping requirements. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xxii 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(i) If the operator elects to 

install and maintain ambient 

H2S property line monitors 

to comply with 

subparagraph (A)(xi) of this 

paragraph, the monitors 

shall be approved by the 

TNRCC Engineering 

Services Section, Air 

Quality Enforcement 

Division office in Austin, 

and shall be capable of 

detecting and alarming at 

H2S concentrations of ten 

ppmv. Operations personnel 

shall perform an initial onsite inspection of the facility 

within 24 hours of initial 

alarm and take corrective 

actions as listed in 

subparagraph (C)(iii)(I) - 

(III) of this paragraph within 

eight hours of detection of a 

leak. 

(ii) The results of the VOC leak 

detection and repair 

requirements shall be made 

available to the executive 

director, his or her 

designated representative, or 

any air pollution control 

agency having jurisdiction 

upon request. Records, for 

all components, shall 

include: 

Rev submitted 04/19/1996 

 (1) If the operator elects to 

install and maintain ambient 

H2S property line monitors 

to comply with 

subparagraph subsection (A 

a)(xi 11) of this paragraph 

section, the monitors shall 

be approved by the TNRCC

Engineering Services 

Section, Air Quality 

Enforcement Division office 

in Austin, and shall be 

capable of detecting and 

alarming at H2S 

concentrations of ten ppmv. 

Operations personnel shall 

perform an initial on-site 

inspection of the facility 

within 24 hours of initial 

alarm and take corrective 

actions as listed in 

subparagraph subsection (C

c)(iii 3)(I A) - (III C) of this 

paragraph section within 

eight hours of detection of a 

leak. 

(2) The results of the VOC leak 

detection and repair 

requirements shall be made 

available to the executive 

director, his or her 

designated representative, or 

any air pollution control 

agency having jurisdiction 

upon request. Records, for 

all components, shall 

include: 

Rev submitted 07/22/1998 

(1) If the operator elects to install and 

maintain ambient H2S property line 

monitors to comply with subsection 

(a)(11) of this section, the monitors 

shall be approved by the Engineering 

Services Section, Air Quality 

Enforcement Division Office of 

Compliance and Enforcement in 

Austin, and shall be capable of 

detecting and alarming at H2S 

concentrations of ten ppmv. 

Operations personnel shall perform an 

initial on-site inspection of the facility 

within 24 hours of initial alarm and 

take corrective actions as listed in 

subsection (c)(3)(A) - (C) of this 

section within eight hours of detection 

of a leak. 

(2) The results of the VOC leak detection 

and repair requirements shall be made 

available to the executive director, his 

or her designated representative, or 

any air pollution control agency 

having jurisdiction upon request. 

Records, for all components, shall 

include: 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

Revision 07/22/98 

 Revision changed 

the office name 

referenced 
Technical Support Document 

Appendix B 

Annotation of 30 TAC Chapter 116, Subchapter F, Section 610, Paragraphs a and b, 

Section 617, Paragraph 3 and Section 620 (30 TAC 116.617(3) and 116.620) 

xxiii 

Annotation and Evaluation of §116.620 Comments 

Submitted 09/20/95

(I) appropriate dates; 

(II) test methods; 

(III) instrument readings; 

(IV) repair results; and 

(V) corrective actions. Records of flange 

inspections are not required unless a leak 

is detected. 

(iii) Records for repairs and replacements made due 

to inspections of H2S and SO2 components 

shall be maintained. 

(iv) Records shall be kept for each production, 

processing, and pipeline tank battery or for 

each storage tank if not located at a tank 

battery, on a monthly basis, as follows: 

(I) Tank battery identification or storage tank 

identification, if not located at a tank 

battery; 

(II) Compound stored; 

(III) Monthly throughput in barrels/month; and 

(IV) Cumulative annual throughput, 

barrels/year. 

(v) A plan shall be submitted to show how ongoing 

compliance will be demonstrated for the 

efficiency requirements listed in subparagraph 

(B)(i)(IV) of this paragraph. The demonstration 

may include, but is not limited to, monitoring 

flowrates, temperatures, or other operating 

parameters. 

(vi) Records shall be kept on at least a monthly 

basis of all production facility flow rates (in 

standard cubic feet per day) and total sulfur 

content of process vents or flares or gas 

processing streams. Total sulfur shall be 

calculated in long tons per day. 

(vii) Records shall be kept of all ambient property 

line monitor alarms and shall include the date, 

time, duration, and cause of alarm, date and 

time of initial on-site inspection, and date and 

time of corrective actions taken. 

(viii) All required records shall be made available to 

representatives of the TNRCC, EPA, or local 

air pollution control agencies upon request and 

be kept for at least two years. All required 

records shall be kept at the plant site, unless the 

plant site is unmanned during business hours. 

For plant sites ordinarily unmanned during 

business hours, the records shall be maintained 

at the nearest office in the state having day-today operations control of the plant site. 

Rev submitted 04/19/1996 

(A) appropriate dates; 

(B) test methods; 

(C) instrument readings; 

(D) repair results; and 

(E) corrective actions. Records of flange inspections 

are not required unless a leak is detected. 

(3) Records for repairs and replacements made due to 

inspections of H2S and SO2 components shall be 

maintained. 

(4) Records shall be kept for each production, processing, 

and pipeline tank battery or for each storage tank if not 

located at a tank battery, on a monthly basis, as 

follows: 

(A) Tank battery identification or storage tank 

identification, if not located at a tank battery; 

(B) Compound stored; 

(C) Monthly throughput in barrels/month; and 

(D) Cumulative annual throughput, barrels/year. 

(5) A plan shall be submitted to show how ongoing 

compliance will be demonstrated for the efficiency 

requirements listed in subparagraph subsection (B b)(I

1)(IV D) of this paragraph section. The demonstration 

may include, but is not limited to, monitoring 

flowrates, temperatures, or other operating parameters. 

(6) Records shall be kept on at least a monthly basis of all 

production facility flow rates (in standard cubic feet per 

day) and total sulfur content of process vents or flares 

or gas processing streams. Total sulfur shall be 

calculated in long tons per day. 

(7) Records shall be kept of all ambient property line 

monitor alarms and shall include the date, time, 

duration, and cause of alarm, date and time of initial 

on-site inspection, and date and time of corrective 

actions taken. 

(8) All required records shall be made available to 

representatives of the TNRCC agency, the EPA, or 

local air pollution control agencies upon request and be 

kept for at least two years. All required records shall be 

kept at the plant site, unless the plant site is unmanned 

during business hours. For plant sites ordinarily 

unmanned during business hours, the records shall be 

maintained at the nearest office in the state having dayto-day operations control of the plant site. 

Revision 04/19/96 

 Changed section 

designations when 

moved to comply 

with section 

numbering. 

III. Proposed Action. 

Approval of the adoption of 30 TAC 116.617(3) and subsequent revisions to 30 TAC 

116.620 submitted September 20, 1995, April 19, 1996, July 22, 1998, and September 11, 

2000. See discussion regarding basis for approval in Sections V and VI of this TSD and in 

Section III of the Federal Register.