National Emission Standards for Hazardous Air Pollutants: Oil and Natural Gas Production Facilities Supplemental Proposed Rule EPA Docket Number OAR 2004 0238 Final Approved Copy by The Office of Management and Budget June 30, 2005 2 6560 50 P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 63 [ OAR 2004 0238; FRL ]

[ RIN A2060 AM16]

National Emission Standards for Hazardous Air Pollutants: Oil and Natural Gas Production Facilities AGENCY: Environmental Protection Agency ( EPA).

ACTION: Supplemental proposed rule.

SUMMARY: This action is a supplemental notice of proposed rulemaking to our February 6, 1998 ( 63 FR 6288) proposed national emissions standards for hazardous air pollutants ( NESHAP) to limit emissions of hazardous air pollutants ( HAP) from oil and natural gas production facilities that are area sources. The final NESHAP for major sources was promulgated on June 17, 1999 ( 64 FR 32610), but final action with respect to area sources was deferred. This action proposes changes to the 1998 proposed rule for area sources,

proposes alternative applicability criteria and reopens the public comment period to solicit comment on the changes proposed today. The proposal also includes the addition of ASTM D6420 99 as an alternative test method to EPA Method 18. Oil and natural gas production is included as an area source category for regulation under the Urban Air Toxics 3 Strategy ( Strategy)( 64 FR 38706, July 19, 1999). As explained below, we included oil and natural gas production facilities in the Strategy because of benzene emissions from triethylene glycol ( TEG) dehydration units located at such facilities.

DATES: Comments must be received on or before [ INSERT DATE 60 DAYS AFTER PUBLICATION OF THE PROPOSED RULE IN THE FEDERAL REGISTER].

ADDRESSES: Comments. Submit your comments, identified by Docket ID No. OAR 2004 0238, by one of the following methods:

° Federal eRulemaking Portal:

http:// www. regulations. gov. Follow the on line instructions for submitting comments.

° Agency Website: http:// www. epa. gov/ edocket. EDOCKET,

EPA's electronic public docket and comment system, is EPA's preferred method for receiving comments. Follow the on line instructions for submitting comments.

° E mail: a and r docket@ epa. gov.

° Fax: ( 202) 566 1741.

° Mail: Air and Radiation Docket, U. S. Environmental Protection Agency, Mailcode 6102T, 1200 Pennsylvania Ave.,

N. W., Washington, DC, 20460. Please include a total of two copies. In addition, please mail a copy of your comments on 4 the information collection provisions to the Office of Information and Regulatory Affairs, Office of Management and Budget ( OMB), Attn: Desk Officer for EPA, 725 17th St.

N. W., Washington, DC, 20503.

° Hand Delivery: U. S. Environmental Protection Agency,

1301 Constitution Ave., N. W., Room: B102, Washington, DC,

20460. Such deliveries are only accepted during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information.

We request that a separate copy also be sent to the contact person listed below ( see FOR FURTHER INFORMATION CONTACT).

Instructions. Direct your comments to Docket ID No. OAR

2004 0238. The EPA's policy is that all comments received will be included in the public docket without change and may be made available online at http:// www. epa. gov/ edocket,

including any personal information provided, unless the comment includes information claimed to be Confidential Business Information ( CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through EDOCKET, regulations. gov, or e mail. The EPA EDOCKET and the federal regulations. gov websites are " anonymous access" systems, which means EPA will not know 5 your identity or contact information unless you provide it in the body of your comment. If you send an e mail comment directly to EPA without going through EDOCKET or regulations. gov, your e mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption,

and be free of any defects or viruses. For additional information about EPA's public docket, visit EDOCKET on line or see the Federal Register of May 31, 2002 ( 67 FR 38102).

Docket. All documents in the docket are listed in the EDOCKET index at http:// www. epa. gov/ edocket. Although listed in the index, some information is not publicly available, i. e., CBI or other information whose disclosure is restricted by statute. Certain other information, such as copyrighted materials, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either 6 electronically in EDOCKET or in hard copy form at the Air and Radiation Docket, EPA/ DC, EPA West, Room B102, 1301 Constitution Ave., N. W., Washington, DC. The Public Reading Room is open from 8: 30 a. m. to 4: 30 p. m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is ( 202) 566 1744, and the telephone number for the Air and Radiation Docket is ( 202) 566 1742.

FOR FURTHER INFORMATION CONTACT: Mr. Greg Nizich, Office of Air Quality Planning and Standards, Emission Standards Division ( C439 03), EPA, Research Triangle Park, NC 27711;

telephone number: 919 541 3078; fax number: 919 541 3207;

electronic mail address: nizich. greg@ epa. gov.

SUPPLEMENTARY INFORMATION: Entities Table. Entities potentially affected by this proposed action include, but are not limited to, the following:

Category NAICS Code1 Examples of Regulated Entities Industry 211111, 211112 Condensate tank batteries, glycol dehydration units, and natural gas processing plants. 1 North American Industry Classification System.

This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. To determine whether your facility would be regulated by this action, you should 7 examine the applicability criteria in 40 CFR part 63,

subpart HH National Emissions Standards for Hazardous Air Pollutants: Oil and Natural Gas Production Facilities. If you have any questions regarding the applicability of this action to a particular entity, consult the person listed in the preceding FOR FURTHER INFORMATION CONTACT section.

Worldwide Web. In addition to being available in the docket, an electronic copy of the proposed rule is also available on the Worldwide Web ( WWW) through the Technology Transfer Network ( TTN). Following the Administrator's signature, a copy of the proposed rule will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at http:// www. epa. gov/ ttn/ oarpg. The TTN provides information and technology exchange in various areas of air pollution control.

Public Hearing. If anyone contacts EPA requesting to speak at a public hearing by [ INSERT DATE 20 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER], a public hearing will be held on [ INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. If a public hearing is requested, it will be held at 10: 00 a. m. at the EPA Facility Complex in Research Triangle Park, North Carolina or at an alternate site nearby. Contact Mr. Greg Nizich at 919 541 3078 to request a hearing, to request to speak at a public hearing, 8 to determine if a hearing will be held, or to determine the hearing location.

Outline. The information presented in this preamble is organized as follows:

I. Background II. Summary of Proposed Rule for Area Sources III. Rationale for Selecting the Proposed Standards A. How did we select the source category? B. How did we select the affected sources and emission points? C. What changes to the applicability requirements for area sources are part of this supplemental notice? D. What changes are we proposing to the startup, shutdown, and malfunction plan requirements? IV. Summary of Environmental, Energy, Cost, and Economic Impacts A. What are the air quality impacts? B. What are the cost impacts? C. What are the economic impacts? D. What are the non air environmental and energy impacts? V. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act I. Background We proposed NESHAP for the Oil and Natural Gas Production source category on February 6, 1998 ( 63 FR 6288) 9 1 The proposed finding evaluated HAP from TEG units, but the only HAP identified in the Strategy that is emitted from TEG units is benzene. that addressed both major and area sources of oil and natural gas production facilities. Area sources of HAP are those stationary sources that emit or have the potential to emit, considering controls, less than 10 tons per year of any one HAP and less than 25 tons per year of any combination of HAP. The 1998 proposed area source rule was based on a proposed finding of adverse human health effects from benzene emissions from triethylene glycol ( TEG)

dehydration units at area source oil and natural gas production facilities1. Based on this finding, referred to as an area source finding, we proposed to amend the source category list to add oil and natural gas production to the list of area source categories established under section 112( c)( 1) of the Clean Air Act ( CAA). In June 1999, we took final action on the major source standards but deferred action on the TEG dehydration units at oil and natural production area source facilities and on listing the area source category pending issuance of the Strategy.

The Strategy was issued on July 19, 1999 ( 64 FR 38706)

and addressed section 112( c)( 3) and 112( k)( 3)( B)( ii) of the CAA that instruct us to identify not less than 30 HAP which, 10 as the result of emissions from area sources, present the greatest threat to public health in the largest number of urban areas, and to list sufficient area source categories or subcategories to ensure that emissions representing 90 percent of the 30 listed HAP are subject to regulation. The Strategy included a list of 33 HAP judged to pose the greatest potential threat to public health in the largest number of urban areas ( the urban HAP) and a list of area source categories emitting 30 of the listed HAP ( area source HAP). Once listed, these area source categories shall be subject to standards under section 112( d) of the CAA. The proposed standards that are the subject of today's action are based on generally available control technology ( GACT)

pursuant to section 112( d)( 5) of the CAA.

Benzene was one of the HAP listed under the Strategy.

Oil and natural gas production facilities were listed in the Strategy solely because the TEG dehydration units located at these facilities contributed approximately 47 percent of the national urban emissions of benzene from stationary sources at area sources. As the result of the emission standards development process, we recognize that our description of the source category in the Strategy is overbroad. The listing should read TEG dehydration units at oil and natural gas production facilities. This clarification to the scope 11 of the source category is consistent with the Agency's proposed 1998 finding and the record supporting both the 1998 finding and the 1999 listing in the Strategy.

Today, we are proposing the addition of regulatory language to 40 CFR part 63, subpart HH, to address area sources and fulfill a portion of our obligation under section 112( c)( 3) to regulate stationary sources of benzene.

Even though we had previously included area source requirements as part of the 1998 subpart HH proposal, at this time, we are proposing some changes to the previously proposed standards in response to the comments we received on the 1998 proposal. In addition, we are proposing another geographical applicability option as an alternative to the previously proposed criteria. We are seeking comment on these proposed changes. Most importantly, we are seeking comments on both applicability options that are under consideration.

An applicability option under consideration was first described in the 1998 proposed rule. Specifically, we proposed that the area source standards would apply only to TEG dehydration units at area source oil and natural gas production facilities located in an urban county rather than 12 2 Urban 1 and Urban 2 are defined based on the U. S. Census Bureau's most current decennial census data. Urban 1 counties consist of counties with metropolitan statistical areas ( MSA) with a population greater than 250,000. Urban 2 counties are defined as all other counties where more than 50 percent of the population is designated urban by the U. S. Census Bureau. For purposes of this preamble, we refer to those counties that qualify as Urban 1 and Urban 2 as " urban" counties. Rural counties are those counties that do not meet the criteria of Urban 1 or Urban 2. A list of the urban and rural counties based on the 1990 census classifications can be found online at http:// www. epa. gov/ ttnatw01/ urban/ 112kfac. html. A list of the urban and rural counties based on the 1990 and 2000 census classifications can be found online at http:// www. epa. gov/ ttn/ atw/ oilgas/ oilgaspg. html and in the Docket. a rural county using Urban 1 and Urban 22 classifications that we defined based on information from the U. S. Census Bureau ( 64 FR 6293). ( Note: Urban 2 counties in the 1998 proposed rule were incorrectly defined. In that notice, we incorrectly stated that Urban 2 counties were defined by criteria used by the U. S. Census Bureau to define urbanized areas, which are not county based areas. The actual parameters for Urban 2 that we used for determining urban HAP under the Strategy, as well as for the 1998 and today's proposed standards for TEG units at area source oil and natural gas production facilities, are provided in footnote 2 of today's notice.) Under this proposed geographical applicability criterion described in footnote 2, those area source TEG dehydration units located in counties classified as urban areas would be subject to the rule. 13 In today's notice, we are proposing a second,

alternative applicability approach for purposes of the proposed rule. Under that alternative option, the final rule would apply to all TEG dehydrators at area source oil and natural gas production facilities.

We are seeking comment on both of these proposed applicability options. We are not requesting comment on any aspect of subpart HH as it applies to major sources. We issued the final rule for major sources in 1999, and that rule is not part of today's proposal. We are today,

however, proposing to add ASTM D6420 99( 2004) as an alternative to EPA Method 18 for both major and area sources, and we seek comment on this particular proposed regulatory change, as it affects both major and area sources.

II. Summary of Proposed Rule for Area Sources The 1998 proposal described the area source requirements as largely identical to the major source requirements, except for the addition of geographic applicability criteria, the fact that only the TEG dehydration unit would be an affected source covered by the emission reduction standards at area sources, and some reduced reporting requirements. Except as described below,

we have not changed these requirements with today's 14 supplemental notice.

As in the 1998 proposed rule ( 63 FR 6290), the standards proposed today are based on GACT which would require owners or operators of TEG dehydration units at area sources to connect, through a closed vent system, each process vent on the TEG dehydration unit to an emission control system. The control system must reduce emissions either: ( 1) by 95.0 percent or more of HAP ( generally a condenser with a flash tank), or ( 2) to an outlet concentration of 20 parts per million by volume ( ppmv) or less ( for combustion devices), or ( 3) to a benzene emission level of less than 0.90 Megagrams per year ( Mg/ yr) ( 1.0 tons per year( tpy)). Sources whose actual annual average flowrate of natural gas to the TEG dehydration unit is less than 85 thousand standard cubic meters per day ( thousand m3/ day) ( 3 million standard cubic feet per day ( MMSCFD)), or sources whose actual average emissions of benzene from the TEG dehydration unit process vent to the atmosphere are less than 0.90 Mg/ yr ( 1 tpy), as determined by the procedures specified in 40 CFR 63.772( b)( 1) and ( 2), would not have any control requirements.

We believe these cutoffs are appropriate due to similarities between TEG units at area sources and those at major sources. Based on the available data for TEG units at 15 major sources in 1998, we were not able to determine any level of emission control below the 85 thousand m3/ day and 0.90 Mg/ yr cutoff levels at major sources. Because our assessment of the cutoff levels for TEG units at major sources has not changed since 1998, and because we have no information suggesting any difference between major and area sources in the basis for controlling TEG units, we do not believe that we would be able to determine any level of emission control for TEG units below the cutoff levels at area sources either. In addition, we compared the cost of control per unit of HAP removed when controlling all units,

against such cost when controlling only units with benzene emissions of 1 tpy or greater. We also evaluated the projected impacts and costs associated with four different levels of natural gas throughput ( see 63 FR 6288 and 6299).

Based on these assessments, we believe that the cost burden to the affected sources below these cutoff levels would be too high for the amount of emission reduction these sources would achieve with the proposed controls.

We note that for the reasons described above, we are proposing in this action to subcategorize those TEG dehydration units that are subject to the final rule based on whether the unit has an annual average flowrate of natural gas less than 85 thousand m3/ day ( 3 MMSCFD), or 16 actual annual average benzene emissions from the TEG dehydration unit process vent to the atmosphere less than 0.90 MG/ yr ( 1 tpy). We are further proposing that GACT for sources that meet the cutoffs described above is no control.

We specifically seek comment on our proposed subcategorization approach ( including the specific values for the cutoffs) and whether to proceed with subcategorization in this rule. Pursuant to section 112( d),

EPA also has authority to " distinguish among classes, types,

and sizes of sources within a category or subcategory in establishing . . . ( emission) standards." CAA section 112( d)( 1).

As an alternative to complying with the control requirements mentioned above, pollution prevention measures,

such as process modifications or combinations of process modifications and one or more control device that reduce the amount of HAP emissions generated, are allowed provided they achieve the required emissions reductions.

Similarly, area sources would be subject to the same initial and continuing compliance requirements as major sources except that area sources would be required to submit periodic reports annually, instead of semiannually as is required for major sources. That is, affected sources must submit Notification of Compliance Status Reports annually, 17 inspect/ test the closed vent system and control device( s),

and establish monitoring parameter values. Continuing compliance requirements include submitting Periodic Reports,

conducting annual inspections of closed vent systems,

repairing leaks and defects, conducting the required monitoring, and maintaining required records.

As the result of comments received on the 1998 proposal on the level of the standards and how it is to be demonstrated, the final major source rule addressed the need for an averaging period to accommodate fluctuations in condenser efficiency due to changes in ambient temperature.

We also clarified in that final rule that owners or operators could be allowed to achieve a 95 percent emission reduction using process modifications or combinations of process modifications and one or more control device. These changes are not dependent on the amount of emissions at the facility, but rather address practical considerations in complying with the control standards, which are the same for both major and area sources. Therefore, as indicated in today's proposal, we propose that these provisions also apply to area sources.

Today's supplemental notice presents compliance dates for existing area sources and new or reconstructed area sources for the two proposed applicability options noted 18 above and described in greater detail below. For purposes of establishing compliance dates, it should be noted that the 1998 proposal applied only to TEG dehydrators located in urban areas, which are counties designated as Urban 1 and Urban 2 ( see supra note 2). The tables that follow present compliance dates for the two alternative geographic applicability options that we are proposing. Under Option 1 all TEG dehydration units at area source oil and natural gas production facilities would be subject to the final rule.

Under Option 2, the option we proposed in 1998, only those TEG units located in counties that satisfy the Urban 1 or Urban 2 county criteria, as described herein, would be subject to the requirements of the final rule.

Table 1 of this preamble presents compliance dates for Option 1.

Table 1  Compliance Dates for Existing and New Sources for Applicability Option 1 For an affected area source located in a county we classified as... Where the source was constructed/ reconstructed ... then the source is... And the compliance date for that source would be...

( a) urban based on 2000 census data before February 6, 1998 existing 3 years after the effective date of the area source standards. 19 ( b) urban based on 2000 census data on or after February 6, 1998 new the effective date of the area source standards or startup, whichever is later.

( c) rural based on 2000 census data before today's supplemental proposal existing 3 years after the effective date of the area source standards.

( d) rural based on 2000 census data on or after today's supplemental proposal new the effective date of the area source standards or startup, whichever is later.

With respect to item ( b) in Table 1 above, we solicit comment on the proposed compliance date for those sources located in counties that were rural in 1990 and became urban as a result of the 2000 decennial census. Specifically, we solicit comment on whether the sources affected under item ( b) should be considered new or existing, and what the appropriate trigger date should be for defining new source status. We further solicit comment on the compliance deadlines for these sources.

The list of urban ( i. e., Urban 1 and Urban 2) and rural counties based on 1990 U. S. Census Bureau data can be found at http:// www. epa. gov/ ttnatw01/ urban/ 112kfac. html). This list can also be found in the docket, along with the list of urban counties based on 2000 U. S. Census Bureau data ( Docket No. OAR 2004 0238). These two lists can also be found at 20 the following url as well:

http:// www. epa. gov/ ttn/ atw/ oilgas/ oilgaspg. html.

For Option 2, existing sources ( i. e., affected sources constructed before the 1998 proposal) must achieve compliance within 3 years after the effective date of the final rule, and new sources ( affected sources constructed on or after the 1998 proposal) must comply on the effective date of the final rule, or startup, whichever date is later.

Sources that are located in a county that meets the definition of rural are not subject to the requirements of the rule under Option 2.

We recognize that where a source is constructed in a county that is initially classified as rural and subsequently reclassified as urban, the reclassification may occur after the source's startup date or the effective date of the final rule, such that it is impossible for the source to meet the relevant compliance deadline described above.

To account for changes in urban/ rural status that will likely occur with each decennial census, EPA intends, after the issuance of the decennial census data, to publish in the Federal Register an updated list of counties that qualify as urban based on the most recent decennial data.

For any new source ( i. e., affected sources constructed on or after the 1998 proposal) located in a county where the classification of that county changes from rural to urban 21 based on 2010 or a later decennial census, we are proposing that the compliance deadline for such source be the date EPA publishes the updated list of urban counties in the Federal Register. We request comment on whether this compliance deadline is appropriate. For existing sources ( i. e.,

affected sources constructed before the 1998 proposal)

located in a county that is redesignated as urban based on 2010 or later census data, we propose that the compliance date for such sources be three years after the publication of the updated list of counties in the Federal Register.

As noted above, we also solicit comment on how to treat new sources that were rural in 1990 and became urban based on the 2000 decennial census data and what the compliance date for such sources should be.

In the 1998 proposal, we proposed that area sources would be exempt from title V permitting requirements ( 63 FR 6307). We do not believe that the proposed applicability approaches described in today's notice alter the basis for the proposed title V permit exemption. Neither the scope of geographical applicability nor the number of sources impacted by the options change the degree to which the standards are implementable outside of a permit, and we,

therefore, maintain our belief that the permit would provide minimal additional benefit. Therefore, we propose to 22 maintain the exemption.

III. Rationale for Selecting the Proposed Standards A. How did we select the source category?

We listed area source oil and natural gas production facilities in July 1999 pursuant to 112( c)( 3) and 112( k)( 3)( B) of the CAA to ensure that area sources representing 90 percent of the area source emissions of the 30 HAP that present the greatest threat to public health in the largest number of urban areas are subject to regulation under section 112. This listing was based on information showing that benzene emissions from the TEG dehydration units at area sources of oil and natural gas production facilities contribute at least 47 percent of the national urban emissions of benzene, one of the 30 listed area source HAP, from stationary sources that are area sources. Based on emission estimates ranking the area source categories,

TEG dehydration units at area sources contributed the highest quantity of benzene of all the source categories analyzed ( see Docket No. A 97 44).

B. How did we select the affected sources and emission points?

The 1999 area source listing in the Strategy was based on emissions information showing that TEG dehydration units emit benzene in levels that contribute significantly to 23 nationwide emissions of benzene from area sources in urban areas. Furthermore, TEG dehydration units account for approximately 90 percent of the HAP emissions at an oil and natural gas production facility. Therefore, in listing this area source category in the Strategy in 1999, EPA focused on regulating benzene emissions from TEG dehydration units.

For the same reasons, our 1998 proposal ( and proposed area source finding) did not include for regulation other types of dehydration units or other emission points at area source oil and natural gas production facilities. Consistent with the 1998 proposed area source finding that benzene emissions from TEG dehydration units are the emission points of concern for this area source category, we are maintaining the 1998 proposed definition of the affected source as each TEG dehydration unit located at a facility that is an area source and that processes, upgrades, or stores hydrocarbon liquids prior to the point of custody transfer or that processes, upgrades, or stores natural gas prior to the point at which natural gas enters the natural gas transmission and storage source category or is delivered to the final end user.

We are seeking comment on the proposed applicability approaches described above as they relate directly to the scope of TEG dehydration units at oil and natural gas 24 production facilities that would be subject to the final rule.

C. What changes to the applicability requirements for area sources are part of this supplemental notice?

The 1998 area source proposal contained geographical applicability criteria for area source TEG dehydration units that would have limited the application of area source standards to those selected area source TEG dehydration units located in counties we classified as Urban 1 or Urban

2, referred to herein as " urban."

As stated earlier, today, we are proposing an alternative to the geographical applicability criteria proposed in 1998. If finalized, the 1998 criteria would require all TEG dehydration units at area source oil and natural gas production facilities in areas that meet the urban requirements to comply with the final rule. See supra fn. 2. The alternative option we are proposing for the first time today, if finalized, would require TEG dehydration units at area source oil and natural gas production facilities in urban and rural counties to comply with the requirements of the final rule. In sum, we are proposing two options for defining geographically the scope of the area source standards. The standards would apply:

( 1) in urban and rural counties; or ( 2) in urban counties 25 only ( the 1998 proposal).

In the 1998 proposal, we estimated that there were 37,000 area source glycol dehydrators in the U. S., and that TEG dehydrators comprised most of that figure. Based on more recent information from the Department of Energy ( DOE)

regarding the number of oil and gas wells and the amount of natural gas produced in the U. S., we have updated this figure to approximately 38,000 dehydrators.

Although we believe our estimate of TEG dehydrator population is reasonable, we lack information indicating the locations of most of these units. Therefore, in assessing the impacts of the different applicability options being considered, we made several assumptions. Using DOE data from 2003, we identified 13 States where 95 percent of the natural gas in the U. S. is produced ( Texas, New Mexico,

Oklahoma, Wyoming, Louisiana, Colorado, Alaska, Kansas,

California, Utah, Michigan, Alabama and Mississippi).

First, although Outer Continental Shelf ( OCS) sources contribute over 20 percent of the 2003 natural gas production total, we assumed that none of the sources on the OCS are uncontrolled area sources that would be impacted by the final rule. This assumption is based on a belief that these sources are generally controlled through flares for safety purposes. Next, we assumed a uniform distribution of 26 sources by assigning 95 percent of the estimated number of sources in the 13 States in proportion to their percentage of natural gas production. Finally, we assumed a linear distribution within each of the 13 States that is proportional to the amount of geographical area encompassed by a given option ( i. e., for an option encompassing areas covering 20 percent of the 13 State landmass would contain 20 percent of the area source glycol dehydrators). We realize this approach does not yield precise results for determining affected facility populations for individual options, and it assumes a uniform distribution of sources between rural and urban areas, but we believe it is useful for comparing different options and estimating the number of potentially affected units.

The urban/ rural classification status of some counties may change every 10 years as the population is reassessed by the U. S. Census Bureau. These changes occur with increases in U. S. population and also with population relocation.

These changes may cause land area classifications to change from one where the rule would not apply to a classification where it would apply. The reverse case is also a possibility although we would expect such a scenario to be infrequent.

For the urban county option, sources would be required 27 3 We do not believe that the GACT analysis and subcategorization of TEG dehydration units described above would change based on the applicability option selected in the final rule. to determine the final rule's applicability based on data from the latest decennial census. Based on the latest decennial data, sources in urban counties would be required to comply with the requirements of the final rule. We would recommend that those sources not subject to requirements of the final rule document their status and retain a record of their finding. We further recommend that all sources in rural counties reconfirm their status related to geographical location within 6 months after the release of the latest decennial census results.

Proposed Applicability Options3 Option 1:

Under option 1, all TEG dehydrators at area source oil and natural gas production facilities would be subject to the final rule. This applicability option provides a HAP reduction of approximately 14,700 Mg/ yr ( 16,400 tpy) and requires an estimated 2,200 TEG dehydrators to reduce emissions.

Option 1 would ensure that units effecting every urban area would be subject to regulation. It would also ensure that benzene is reduced in non densely populated areas which 28 can provide additional benefits since benzene is a carcinogen and a national risk driver based on our National Air Toxics Assessment ( NATA). ( NATA is our program for evaluating air toxics in the U. S. and involves: expanding air toxics monitoring, improving/ updating emission inventories, improving small and large scale modeling, as well as improving our knowledge of health effects and assessment tools ( see http:// www. epa. gov/ ttn/ atw/ nata/ for additional information about NATA)). Moreover, reduction in benzene emissions from affected sources in urban and rural counties brings us closer to one goal of the Strategy ( i. e.,

to achieve a 75 percent reduction in cancer incidence).

With this option, there is no issue of change in geographical applicability with decennial census updates ( i. e., neither the regulators nor the sources need to be concerned with keeping track of changes in the applicability of this rule due to future changes in population density).

We do, however, believe that option 1 raises an issue because it requires emission reductions for sources located in remote areas many miles from densely populated areas. As noted above, GACT for lower emitting sources ( i. e., sources with either a natural gas throughput below 3 MMSCFD or emitting less than 1 tpy of benzene) is no control. We estimate the annual compliance cost for this option to be 29 $ 39.2 million.

Option 2:

This option, which was in the 1998 proposal, would provide HAP emission reductions of approximately 6,900 Mg/ yr ( 7,700 tpy) in counties with MSA populations exceeding 250,000 people and in counties where the majority of people are classified by the U. S. Census Bureau to live in urban areas based on 2000 census data. This applicability option would require an estimated 1,050 facilities to control emissions. Since this applicability option is a countybased scope, and since the Urban 2 county classification is based on percentage of people in urban areas within a county, we believe changes in county status from rural to urban from one decennial census to the next could occur as densely settled areas grow. For determining initial applicability, sources would know immediately which facilities would be subject to the emission reduction requirements simply based on county designation. However,

the urban/ rural designation provides an imperfect measure of population density in the immediate vicinity of TEG dehydrators. Thus, under this option emission reductions may be required from sources in remote areas of counties meeting the urban criteria and, at the same time, TEG dehydrators may be located in densely populated areas in 30 unregulated rural counties. Thus, units located in similarly populated areas would be regulated differently based on county designation. We estimate the annual compliance cost for this applicability option to be $ 18.5 million.

We specifically request comment on both applicability options and on possible alternative approaches that might better reflect population density and exposure. We also request information related to the locations of TEG dehydration units at area source oil and natural gas production facilities.

D. What changes are we proposing to the startup, shutdown,

and malfunction plan requirements?

In the 1998 proposal, we proposed that owners and operators of TEG dehydration units subject to the area source standards would not be subject to the requirements of 40 CFR 63.6( e) of the General Provisions for developing and maintaining a startup, shutdown, and malfunction ( SSM) plan,

or the requirements of 40 CFR 63.10( d) of the General Provisions for reporting actions not consistent with the plan. Rather than developing a SSM plan and submitting reports in accordance with that plan, we proposed an alternative to the General Provisions where owners and operators of affected area sources should only submit 31 reports of any malfunctions that are not corrected within 2 calendar days of the malfunction within 7 days of the subject malfunction( s). It was our intent that the 1998 proposal would require only the submittal of malfunction reports, and not the development and implementation of a SSM plan, and that such an approach would reduce burden.

Commenters on the 1998 proposal stated that submittal of malfunction reports would be burdensome and impractical,

particularly in remote locations that do not have full time operators onsite. They recommended that area sources be allowed to develop a simplified contingency plan, adopt and update the plan using their notification of compliance status reports, and allow for compilation of all events in which special action was taken that is inconsistent with the plan to be submitted in monthly letter reports. Commenters also suggested that sources be allowed more time to correct malfunctions and report them, given the nature of their operations and staffing.

Based on these comments, we have decided to follow the requirements of the General Provisions regarding SSM events.

We believe that the unique nature of unmanned or remote area source oil and natural gas production facilities can best be addressed by having owners or operators prepare an SSM plan that would provide needed flexibility of dealing with SSM 32 events at these sites. The SSM plan could be tailored to identify SSM events posing concerns for them and establish appropriate procedures for minimizing emissions and making necessary repairs in the manner suitable for each situation.

The purposes of a SSM plan are to: ensure that the owner or operator operates and maintains each affected source in such a way that minimizes emissions in a manner consistent with safety and good air pollution control practices, ensure that owners or operators are prepared to correct malfunctions as soon as practicable after their occurrence to minimize excess emissions, and reduce the reporting burden associated with SSM events. The submittal of separate SSM reports are only required if actions taken during these events are not consistent with the plan. Events handled in accordance with the SSM plan are documented and included with the periodic reports. For the reasons stated above, we have revised the SSM provisions for area sources in the 1998 proposal to require the development and implementation of SSM plans, as opposed to malfunction reports as proposed in 1998. We are proposing the same SSM requirements that we have for major sources, except the timing of periodic SSM reports. Because we are proposing that area sources submit annual rather than semiannual periodic reports, which may include periodic SSM reports, area sources may submit such reports annually. 33 IV. Summary of Environmental, Energy, Cost, and Economic Impacts The environmental and cost impacts for the proposed options are presented in Table 3 of this preamble:

Table 3. Summary of National Impacts for the Geographical Options for the Oil and Natural Gas Production NESHAP Emissions Reductions ( Mg/ yr)

No. of Controlled Sources VOC HAP Benzene Total Annual Compliance Cost ( million $/ yr)

Option 1 2,200 28,600 14,700 4,400 39.2 Option 2 1,050 13,700 6,900 2,070 18.5 A. What are the air quality impacts?

For existing area source TEG dehydration units in the oil and natural gas production source category, we estimate that nationwide baseline area sources HAP emissions are 45,100 Mg/ yr ( 49,600 tpy). The standards being proposed with today's supplemental notice require that TEG dehydration units with a natural gas throughput greater than 85 thousand standard cubic meters per day and benzene emissions greater than 0.90 Mg/ yr ( 1.0 tpy) achieve a 95 percent emission reduction either through pollution prevention process changes or by installing a control device ( e. g., condenser).

We anticipate that no new area source TEG dehydration units will be constructed over the next 5 years based on an 34 assumption that any new sources constructed during this period will be major sources. We specifically request comment on this assumption. Emission reduction requirements for new sources are the same as for existing sources.

Secondary environmental impacts are considered to be any air, water, or solid waste impacts, positive or negative, associated with the implementation of the final standards. These impacts are exclusive of the direct organic HAP air emissions reductions discussed in the previous section.

The capture and control of benzene that is presently emitted from area source TEG dehydration units will result in a decrease in volatile organic compound ( VOC) emissions as well. The estimated total VOC emissions reductions shown above are from a nationwide baseline of 86,500 Mg/ yr ( 95,200 tpy).

Emissions of VOC have been associated with a variety of health and welfare impacts. VOC emissions, together with nitrogen oxides, are precursors to the formation of groundlevel ozone, or smog. Exposure to ambient ozone is responsible for a series of public health impacts, such as alterations in lung capacity and aggravation of existing respiratory disease. Ozone exposure can also damage forests and crops. 35 Other secondary environmental impacts are those associated with the operation of certain air emission control devices ( i. e., flares). The adverse secondary air impacts would be minimal in comparison to the primary HAP reduction benefits from implementing the proposed control options for area sources. We estimate that national annual increase of secondary air pollutant emissions that would result from the use of a flare to comply with the proposed standards is less than 1 Mg/ yr ( 0.24 tpy) for sulfur oxides,

2.2 Mg/ yr ( 2.4 tpy) for carbon monoxide, and 11 Mg/ yr ( 12 tpy) for nitrogen oxides based on option 1, which affects the largest number of sources.

B. What are the cost impacts?

Since several compliance options are available to owners/ operators of affected sources, we are not sure what control method will be employed. Sources can control emissions by routing emissions to a condenser, a flare, a process heater, or back to the process or by implementing pollution prevention process changes. Some of these options have very low capital costs, however, for the purpose of determining costs, we have assumed that 90 percent of the affected sources utilize condensers and 10 percent use flares. For the cost estimates developed for condenser systems, we looked at systems with and without the use of a 36 gas condensate glycol separator ( GCG separator or flash tank) in TEG dehydration system design.

The estimated annual costs shown in Table 3 of this preamble include the capital cost; operating and maintenance costs; the cost of monitoring, inspection, recordkeeping,

and reporting ( MIRR); and any associated product recovery credits.

C. What are the economic impacts?

For the 1998 proposal, we prepared an economic impact analysis evaluating the impacts of the rule on affected producers, consumers, and society. The economic analysis focuses on the regulatory effects on the U. S. natural gas market that is modeled as a national, perfectly competitive market for a homogenous commodity.

The results of the analysis show that the imposition of regulatory costs on the natural gas market would result in negligible changes in natural gas prices, output,

employment, foreign trade, and business closures. The price and output changes as a result of the 1998 proposed regulation were estimated to be less than 0.01 percent,

significantly less than observed market trends. Because we believe that these assumptions are relevant for both applicability options described in today's proposal and that the result of the 1998 economic impact analysis resulted in 37 a very low percent increase in price and output changes, we believe that imposition of regulatory costs associated with the proposed applicability options will result in negligible changes in natural gas prices, output, employment, foreign trade, and business closures.

D. What are the non air environmental and energy impacts?

The water impacts associated with the installation of a condenser system for the TEG dehydration unit reboiler vent would be minimal. This is because the condensed water collected with the hydrocarbon condensate can be directed back into the system for reprocessing with the hydrocarbon condensate or, if separated, combined with produced water for disposal by reinjection.

Similarly, the water impacts associated with installation of a vapor control system would be minimal.

This is because the water vapor collected along with the hydrocarbon vapors in the vapor collection and redirect system can be directed back into the system for reprocessing with the hydrocarbon condensate or, if separated, combined with the produced water for disposal for reinjection.

Therefore, we expect the adverse water impacts from the implementation of control options for either option considered for proposed area source standards to be minimal.

We do not anticipate any adverse solid waste impacts 38 from the implementation of the area source standards.

Energy impacts are those energy requirements associated with the operation of emission control devices. There would be no national energy demand increase from the operation of any of the control options analyzed under the proposed oil and natural gas production standards for area sources. The proposed area source standards encourage the use of emission controls that recover hydrocarbon products, such as methane and condensate, that can be used on site as fuel or reprocessed, within the production process, for sale. Thus,

both options considered for proposed standards have a positive impact associated with the recovery of nonrenewable energy resources.

V. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review Under Executive Order 12866 ( 58 FR 51735, October 4,

1993), we must determine whether a regulatory action is " significant" and therefore subject to Office of Management and Budget ( OMB) review and the requirements of the Executive Order. The Order defines a " significant regulatory action" as one that is likely to result in a rule that may:

1. Have an annual effect on the economy of $ 100 million or more, adversely affecting in a material way the 39 economy, a sector of the economy, productivity, competition,

jobs, the environment, public health or safety in State,

local, or tribal governments or communities;

2. create a serious inconsistency or otherwise interfere with an action taken or planned by another agency;

3. materially alter the budgetary impact of entitlement, grants, user fees, or loan programs of the rights and obligations of recipients thereof; or 4. raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order.

Pursuant to the terms of Executive Order 12866, OMB has notified EPA that it considers this a " significant regulatory action" within the meaning of the Executive Order. The EPA submitted this action to OMB for review.

Changes made in response to OMB suggestions or recommendations will be documented in the public record.

B. Paperwork Reduction Act The OMB has previously approved the information collection requirements in the existing major source rule ( 40 CFR part 63, subpart HH). The information collection requirements in the proposed rule have been submitted for approval to OMB under the Paperwork Reduction Act, 44 U. S. C.

3501 et seq. The Information Collection Request ( ICR) 40 document prepared by EPA has been assigned EPA ICR number 1788.07.

The information to be collected for the area source provisions of the Oil and Natural Gas Production NESHAP are based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions in 40 CFR part 63, subpart A, which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA ( 42 U. S. C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to EPA policies set forth in 40 CFR part 2, subpart B.

The proposed rule would require maintenance inspections of the control devices but would not require any notifications or reports beyond those required by the General Provisions in subpart A to 40 CFR part 63. The recordkeeping requirements require only the specific information needed to determine compliance.

The oil and natural gas production NESHAP require that facility owners or operators retain records for a period of 5 years, which exceeds the 3 year retention period contained in the guidelines in 5 CFR 1320.6. The 5 year retention 41 period is consistent with the General Provisions of 40 CFR part 63, and with the 5 year records retention requirement in the operating permit program under title V of the CAA.

All subsequent guidelines have been followed and do not violate any of the Paperwork Reduction Act guidelines contained in 5 CFR 1320.6.

The burden and associated costs discussed here are based on option 1 since it would affect the greatest number of sources among the two proposed applicability options.

The annual projected burden for this information collection to owners and operators of affected sources subject to the final rule ( averaged over the first 3 years after the effective date of the promulgated rule) is estimated to be 209,322 labor hours per year, with a total annual cost of $ 17.1 million per year. These estimates include a one time performance test and report ( with repeat tests where needed): preparation of a startup, shutdown, and malfunction plan; immediate reports for any event when the procedures in the plan were not followed; annual compliance reports; maintenance inspections; notifications; and recordkeeping.

Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain,

or disclose or provide information to or for a Federal 42 agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting,

validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information.

An Agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number.

The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.

To comment on the Agency's need for this information,

the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden,

including through the use of automated collection techniques, EPA has established a public docket for the proposed rule, which includes this ICR, under Docket ID number OAR 2004 0238. Submit any comments related to the ICR for the proposed rule to EPA and OMB. See ADDRESSES 43 section at the beginning of this notice for where to submit comments to EPA. Send comments to OMB at the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th St., N. W., Washington, DC 20503, Attention:

Desk Office for EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after [ INSERT DATE OF PUBLICATION OF THE PROPOSED RULE IN THE FEDERAL REGISTER], a comment to OMB is best assured of having its full effect if OMB receives it by [ INSERT DATE 30 DAYS AFTER PUBLICATION OF THE PROPOSED RULE IN THE FEDERAL REGISTER]. The final rule will respond to any OMB or public comments on the information collection requirements contained in this proposal.

C. Regulatory Flexibility Act The Regulatory Flexibility Act ( RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.

For purposes of assessing the impacts of the proposed 44 rule on small entities, small entity is defined as: ( 1) a small business based on Small Business Administration size standards of 1,500 employees and a mass throughput of 75,000 barrels/ day or less, and 4 million kilowatt hours of production or less, respectively; ( 2) a small governmental jurisdiction that is a government of a city, county, town,

school district or special district with a population of less than 50,000; and ( 3) a small organization that is any not for profit enterprise that is independently owned and operated and is not dominant in its field.

After considering the economic impacts of the proposed rule on small entities, I certify that the proposed rule will not have a significant impact on a substantial number of small entities. While we cannot predict the exact number of small entities that will be subject to the control requirements of the final rule, the proposed rule provides that GACT for certain subcategories ( 85 thousand m3/ day ( 3 MMSCF/ D)) is no control. That should minimize impacts on those small businesses that operate area source oil and natural gas production facilities. The proposed rule would require installation of emissions controls only at facilities that operate a TEG dehydration unit with an average annual natural gas throughput of 85 thousand m3/ day ( 3 MMSCF/ D) or higher. Exempting potential sources under 85 45 thousand m3/ day ( 3 MMSCF/ D) will limit the number of sources who would have to comply with the emission control requirements from approximately 38,000 potential sources to 2,222.

EPA performed an economic impact analysis to estimate the changes in product price and production quantities for the proposed rule. However, sales and revenues data were not readily available for the affected industries, so EPA began its analysis by examining the annual cost of control.

The annual per unit cost of compliance with the proposed rule would be $ 17,699. The throughput cost for natural gas has experienced significant volatility within the past several years, making a point estimate difficult to identify. Therefore, EPA assumed a throughput value at the high end of the range of recent costs, at $ 88.29 per thousand cubic meters ($ 2.50 per thousand cubic feet), for this analysis.

One frequently used approach for determining whether or not a rule would have a significant impact on a small entity is to compare annualized control cost with annualized revenue from sales. Typically, costs less than 1 percent of revenues are not considered as imposing a significant impact. In the present case, the annual per unit cost of compliance is estimated to be $ 17,699. Using the 46 aforementioned 1 percent criterion for significant impact,

annual revenues would have to be less than $ 1,769,900 in order for significant impact to occur. At $ 88.29 per thousand cubic meters ($ 2.50 per thousand cubic feet) of throughput, that revenue translates to 20,046 thousand cubic meters per year ( 707,960 thousand cubic feet per year)

throughput, or 54.9 thousand m3/ day ( 1.94 MMSCF/ D). Since the cutoff for installation of emissions controls for the proposed rule is 85 thousand m3/ day ( 3 MMSCF/ D), the Agency determined the annual cost of control for those entities affected by the proposed rule is not sufficient to generate a significant impact on a substantial number of small entities.

Although the proposed rule will not have a significant economic impact on a substantial number of small entities,

EPA nonetheless has tried to reduce the impact of the rule on small entities. In the proposed rule, the Agency is applying the minimum level of control and the minimum level of monitoring, recordkeeping, and reporting to affected sources allowed by the CAA. In addition, as mentioned above, the natural gas throughput criteria should reduce the size of small entity impacts. We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such 47 impacts.

D. Unfunded Mandates Reform Act Title II of the Unfunded Mandates Reform Act of 1995 ( UMRA), Public Law 104 4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, we generally must prepare a written statement, including a cost benefit analysis, for proposed or final rules with Federal mandates that may result in expenditures by State, local, and tribal governments, in the aggregate, or by the private sector, of $ 100 million or more in any 1 year. Before promulgating an EPA rule for which a written statement is needed, section 205 of the UMRA generally requires us to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost effective, or leastburdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply where they are inconsistent with applicable law. Moreover, section 205 allows us to adopt an alternative other than the leastcostly most cost effective, or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before we establish any regulatory requirements that may significantly 48 or uniquely affect small governments, including tribal governments, we must have developed under section 203 of the UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments,

enabling officials of affected small governments to have meaningful and timely input in the development of our regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements.

We have determined that the options considered in today's proposed rule contain no Federal mandate that may result in estimated costs of $ 100 million or more to State,

local, and tribal governments, in the aggregate, or the private sector in any 1 year. The maximum total annual cost of the proposed rule for any 1 year has been estimated to be less than $ 40 million. Thus, today's proposed rule is not subject to the requirements of sections 202 and 205 of the UMRA.

E. Executive Order 13132: Federalism Executive Order 13132 ( 64 FR 43255, August 10, 1999)

requires us to develop an accountable process to ensure " meaningful and timely input by State and local officials in the development of regulatory policies that have federalism 49 implications." " Policies that have federalism implications"

is defined in the Executive Order to include regulations that have " substantial direct effects on the States, or on the distribution of power and responsibilities among the various levels of government."

Today's proposal does not have federalism implications.

It will not have substantial direct effects on the States,

on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. Thus, Executive Order 13132 does not apply to the proposed rule.

In the spirit of Executive order 13132, and consistent with our policy to promote communication between us and State and local governments, we specifically solicit comment on the proposed rule from State and local officials.

F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments Executive Order 13175 ( 65 FR 67249, November 6, 2000)

requires us to develop an accountable process to ensure " meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications." The proposed rule does not have tribal implications, as specified in Executive Order 13175. 50 The proposed rule does not significantly or uniquely affect the communities of Indian tribal governments. We do not know of any area source TEG dehydration units owned or operated by Indian tribal governments. However if there are any, the effect of the proposed rule on communities of tribal governments would not be unique or disproportionate to the effect on other communities. Thus, Executive Order 13175 does not apply to the proposed rule. We specifically solicit comment on the proposed rule from tribal officials.

G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks Executive Order 13045 ( 62 FR 19885, April 23, 1997)

applies to any rule that: ( 1) is determined to be " economically significant" as defined under Executive Order 12866, and ( 2) concerns an environmental health or safety risk that the EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the EPA must evaluate the environmental health or safety effects of the proposed rule on children, and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the EPA.

The EPA interprets Executive Order 13045 as applying only to those regulatory actions that are based on health or 51 safety risks, such that the analysis required under section 5 501 of the Executive Order has the potential to influence the regulation. The proposed rule is not subject to Executive Order 13045 because it is based on technology performance and not on health or safety risks. No children's risk analysis was performed because no alternative technologies exist that would provide greater stringency at a reasonable cost. Furthermore, the proposed rule has been determined not to be " economically significant" as defined under Executive Order 12866.

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This rule is not a " significant energy action" as defined in Executive Order 13211, " Actions Concerning Regulations That Significantly Affect Energy Supply,

Distribution, or Use" ( 66 FR 28355 ( May 22, 2001)) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, we have concluded that this rule is not likely to have any adverse energy effects.

I. National Technology Transfer and Advancement Act Section 12( d) of the National Technology Transfer and Advancement Act ( NTTAA) of 1995 ( Public Law No. 104 113; 52 15 U. S. C. 272 note) directs us to use voluntary consensus standards in their regulatory and procurement activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards ( e. g., materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA directs EPA to provide Congress, through annual reports to the OMB, with explanations when an agency does not use available and applicable voluntary consensus standards.

The proposed rule does not involve any additional technical standards. Therefore, the requirements of the NTTAA do not apply to this action. However, we would like to note that the draft standard ASTM Z7420Z, which was cited in the final Oil and Natural Gas Production NESHAP ( 64 FR 32609 32664, June 17, 1999) as a potentially practical method to use in lieu of EPA Method 18, has now been finalized by ASTM and approved by EPA for use in rules where Method 18 is cited. This new standard is ASTM D6420

99( 2004), " Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography/ Mass Spectrometry" and it is appropriate for inclusion in the proposed rule in addition to EPA Method 18 codified at 40 53 CFR part 60, Appendix A, for measurement of total organic carbon, total HAP, total volatile HAP, and benzene.

Similar to EPA's performance based Method 18, ASTM D6420 99( 2004) is also a performance based method for measurement of total gaseous organic compounds. However,

ASTM D6420 99( 2004) was written to support the specific use of highly portable and automated gas chromatographs/ mass spectrometers ( GC/ MS). While offering advantages over the traditional Method 18, the ASTM method does allow some less stringent criteria for accepting GC/ MS results than required by Method 18. Therefore, ASTM D6420 99( 2004) is a suitable alternative to Method 18 only where: ( 1) the target compound( s) are those listed in Section 1.1 of ASTM D6420

99( 2004), and ( 2) the target concentration is between 150 ppbv and 100 ppmv. For target compound( s) not listed in Section 1.1 of ASTM D6420 99( 2004), but potentially detected by mass spectrometry, the proposed rule specifies that the additional system continuing calibration check after each run, as detailed in Section 10.5.3 of the ASTM method, must be followed, met, documented, and submitted with the data report even if there is no moisture condenser used or the compound is not considered water soluble. For target compound( s) not listed in Section 1.1 of ASTM D6420

99( 2004), and not amenable to detection by mass 54 spectrometry, ASTM D6420 99( 2004) does not apply.

As a result, EPA will allow ASTM D6420 99 for use with the proposed rule. The EPA will also allow Method 18 as an option in addition to ASTM D6420 99( 2004). This will allow the continued use of GC configurations other than GC/ MS.

Under § § 63.7( f) and 63.8( f) of 40 CFR part 63, subpart A of the General Provisions, a source may apply to EPA for permission to use alternative test methods or alternative monitoring requirements in place of any of the EPA testing methods, performance specifications, or procedures. NESHAP for Oil and Natural Gas Production  Supplemental notice of proposed rulemaking  Page 55 of 78 List of Subjects in 40 CFR Part 63 Environmental protection, Administrative practice and procedure, Air pollution control, Hazardous substances,

Intergovernmental relations, Recordkeeping and reporting requirements.

Dated:

Stephen L. Johnson, Administrator. 56 For the reasons set forth in the preamble, title 40, chapter I, part 63 of the Code of Federal Regulations is proposed to be amended as follows:

PART 63[ AMENDED]

1. The authority citation for part 63 continues to read as follows:

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

Subpart A [ AMENDED]

2. Revise § 63.14( b)( 29) to read as follows:

§ 63.14 Incorporations by reference.

* * * * *

( b) * * *

( 29) ASTM D6420 99( 2004), Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography/ Mass Spectrometry, IBR approved for § § 63.772( a)( 1)( ii), 63.5799 and 63.5850.

Subpart HH [ AMENDED]

3. Section 63.760 is amended to:

a. Revise the first and fourth sentences of paragraph ( a)( 1) introductory text;

b. Revise paragraph ( b) introductory text;

c. Add paragraph ( b)( 5);

d. Revise paragraph ( f) introductory text;

e. Revise paragraphs ( f)( 1) and ( f)( 2); 57 f. Add paragraphs ( f)( 3) through ( 6);

g. Revise the first sentence of paragraph ( g)

introductory text; and f. Add a sentence to paragraph ( h) to read as follows:

§ 63.760 Applicability and designation of affected source.

( a) * * *

( 1) Facilities that are major or area sources of hazardous air pollutants ( HAP) as defined in § 63.761.

Emissions for major source determination purposes can be estimated using the maximum natural gas or hydrocarbon liquid throughput, as appropriate, calculated in paragraphs ( a)( 1)( i) through ( iii) of this section. As an alternative to calculating the maximum natural gas or hydrocarbon liquid throughput, the owner or operator of a new or existing source may use the facility's design maximum natural gas or hydrocarbon liquid throughput to estimate the maximum potential emissions. Other means to determine the facility's major source status are allowed, provided the information is documented and recorded to the Administrator's satisfaction. A facility that is determined to be an area source, but subsequently increases its emissions or its potential to emit above the major source levels ( without first obtaining and complying with other limitations that keep its potential to emit HAP below major 58 source levels) and becomes a major source, must comply thereafter with all provisions of this subpart applicable to a major source starting on the applicable compliance date specified in paragraph ( f) of this section. Nothing in this paragraph is intended to preclude a source from limiting its potential to emit through other appropriate mechanisms that may be available through the permitting authority.

* * * * *

( b) The affected sources to which the provisions of this subpart apply shall comprise each emission point located at a facility that meets the criteria specified in paragraph ( a) of this section and listed in paragraphs ( b)( 1) through ( 4) of this section for major sources and paragraph ( b)( 5) of this section for area sources.

* * * * *

( 5) For area sources, the affected source includes each triethylene glycol dehydration unit located at a facility that meets the criteria specified in paragraph ( a)

of this section.

* * * * *

( f) The owner or operator of an affected major source shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs ( f)( 1) and ( 2) of this section. The owner or operator of an affected area source 59 shall achieve compliance with the provisions of this subpart by the dates specified in paragraphs ( f)( 3) through ( 6) of this section.

( 1) The owner or operator of an affected major source,

the construction or reconstruction of which commenced before February 6, 1998, shall achieve compliance with the applicable provisions of this subpart no later than June 17,

2002 except as provided for in § 63.6( i). * * *

( 2) The owner or operator of an affected major source,

the construction or reconstruction of which commences on or after February 6, 1998, shall achieve compliance with the applicable provisions of this subpart immediately upon initial startup or June 17, 1999, whichever date is later. *

* *

Option 1 for paragraphs ( f)( 3) through ( 6):

( 3) The owner or operator of an affected area source located in an urban area, as defined in § 63.761, the construction or reconstruction of which commences before February 6, 1998, shall achieve compliance with the provisions of this subpart no later than 3 years after the date of publication of the final rule in the Federal Register except as provided for in § 63.6( i).

( 4) The owner or operator of an affected area source located in an urban area, as defined in § 63.761, the 60 construction or reconstruction of which commences on or after February 6, 1998, shall achieve compliance with the provisions of this subpart immediately upon initial startup or date of publication of the final rule in the Federal Register, whichever date is later.

( 5) The owner or operator of an affected area source located in a rural area, as defined in § 63.761, the construction or reconstruction of which commences before [ INSERT DATE OF PUBLICATION OF THE PROPOSED RULE IN THE FEDERAL REGISTER] shall achieve compliance with the provisions of this subpart no later than 3 years after the date of publication of the final rule in the Federal Register except as provided for in § 63.6( i).

( 6) The owner or operator of an affected area source located in a rural area, as defined in § 63.761, the construction or reconstruction of which commences on or after [ INSERT DATE OF PUBLICATION OF THE PROPOSED RULE IN THE FEDERAL REGISTER] shall achieve compliance with the provisions of this subpart immediately upon initial startup or date of publication of the final rule in the Federal Register, whichever date is later.

* * * * *

Option 2 for paragraphs ( f)( 3) through ( 6):

( 3) Except as otherwise provided in paragraph ( f)( 5) of 61 this section, the owner or operator of an affected area source, the construction or reconstruction of which commenced before February 6, 1998, shall achieve compliance with the applicable provisions of this subpart no later than three years after the date of publication of the final rule in the Federal Register except as provided for in § 63.6( i).

( 4) Except as otherwise provided in paragraph ( f)( 6)

of this section, the owner or operator of an affected area source, the construction or reconstruction of which commences on or after February 6, 1998, shall achieve compliance with the applicable provisions of this subpart immediately upon startup or the date of publication of the final rule in the Federal Register, whichever date is later,

except as provided for in § 63.6( i).

( 5) If an area source, the construction or reconstruction of which commenced before February 6, 1998,

becomes an affected area source due to subsequent county reclassification ( based on the most recent decennial census data) from rural to urban, as defined in § 63.761, the owner or operator of such source must comply with the applicable provisions of this subpart no later than three years after the date of publication of the updated list of urban counties in the Federal Register, except as provided for in § 63.6( i). 62 ( 6) If an area source, the construction or reconstruction of which commences on or after February 6,

1998, becomes an affected area source due to subsequent county reclassification ( based on the most recent decennial census data) from rural to urban, as defined in § 63.761, the owner or operator of such source must comply with the applicable provisions of this subpart on the date of publication of the updated list of urban counties in the Federal Register, or initial startup, whichever date is later, except as provided for in § 63.6( i)

* * * * *

( g) The following provides owners or operators of an affected source at a major source with information on overlap of this subpart with other regulations for equipment leaks. * * *

* * * * *

( h) * * * Unless otherwise required by law, the owner or operator of an area source subject to the provisions of this subpart is exempt from the permitting requirements established by 40 CFR part 70 or 40 CFR part 71.

* * * * *

4. Section 63.761 is amended by adding, in alphabetical order, the definitions of " rural area" and " urban area" to read as follows: 63 § 63.761 Definitions.

* * * * *

Rural area means a county not defined as an urban area.

* * * * *

Option 1 for the definition of " urban area":

Urban area is defined by use of the 2000 U. S. Census Bureau statistical decennial census data to classify designated counties in the U. S. into one of two classifications:

( 1) Urban 1 areas which are counties that contain a part of a metropolitan statistical area with a population greater than 250,000;

( 2) Urban 2 areas which are counties where more than 50 percent of the population is classified by the U. S. Census Bureau as urban.

* * * * *

Option 2 for the definition of " urban area":

Urban area is defined by use of the most current U. S.

Census Bureau statistical decennial census data to classify designated counties in the U. S. into one of two classifications:

( 1) Urban 1 areas which are counties that contain a part of a metropolitan statistical area with a population greater than 250,000; 64 ( 2) Urban 2 areas which are counties where more than 50 percent of the population is classified by the U. S. Census Bureau as urban.

* * * * *

5. Section 63.764 is amended to:

a. Add paragraph ( d);

b. Revise paragraph ( e)( 1), introductory text; and c. Add paragraph ( g) to read as follows:

§ 63.764 General standards.

* * * * *

( d) Except as specified in paragraph ( e)( 1) of this section, the owner or operator of an affected source located at an existing or new area source of HAP emissions shall comply with the standards in this subpart as specified in paragraphs ( d)( 1) through ( 3) of this section.

( 1) The control requirements for glycol dehydration unit process vents specified in § 63.765;

( 2) The monitoring requirements specified in § 63.773;

and ( 3) The recordkeeping and reporting requirements specified in § § 63.774 and 63.775.

* * * * *

( e) * * *

( 1) The owner or operator is exempt from the 65 requirements of paragraphs ( c)( 1) and ( d) of this section if the criteria listed in paragraphs ( e)( 1)( i) or ( ii) of this section are met, except that the records of the determination of these criteria must be maintained as required in § 63.774( d)( 1).

* * * * *

( g) Unless otherwise required by law, the owner or operator of an area source subject to the provisions of this subpart is exempt from the permitting requirements established by 40 CFR part 70 or part 71.

( h) [ Reserved]

* * * * *

6. Section 63.765 is amended by revising paragraph ( a)

to read as follows:

§ 63.765 Glycol dehydration unit process vent standards.

( a) This section applies to each glycol dehydration unit subject to this subpart with an actual annual average natural gas flowrate equal to or greater than 85 thousand standard cubic meters per day, and with actual average benzene glycol dehydration unit process vent emissions equal to or greater than 0.90 megagrams per year, that must be controlled for HAP emissions as specified in either paragraph ( c)( 1)( i) or paragraph ( d)( 1) of § 63.764.

* * * * * 66 7. Section 63.772 is amended to:

a. Revise paragraph ( a)( 1) introductory text;

b. Add paragraphs ( a)( 1)( i) and ( ii);

c. Revise the first sentence of paragraph ( b)( 2)( ii);

d. Revise paragraph ( e)( 3)( iii) introductory text,

e. Revise paragraph ( e)( 3)( iii)( B)( 2); and f. Revise the first and second sentences of paragraph ( e)( iv) introductory text to read as follows:

§ 63.772 Test methods, compliance procedures, and compliance demonstrations.

( a) * * *

( 1) For a piece of ancillary equipment and compressors to be considered not in VHAP service, it must be determined that the percent VHAP content can be reasonably expected never to exceed 10.0 percent by weight. For the purposes of determining the percent VHAP content of the process fluid that is contained in or contacts a piece of ancillary equipment or compressor, you shall use the method in either paragraph ( a)( 1)( i) or ( ii) of this section.

( i) Method 18 of 40 CFR part 60, appendix A; or ( ii) ASTM D6420 99( 2004), Standard Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography Mass Spectrometry ( incorporated by reference   see § 63.14), provided that the 67 provisions of paragraphs ( A) through ( D) of this section are followed:

( A) The target compound( s) are those listed in section 1.1 of ASTM D6420 99( 2004);

( B) The target concentration is between 150 parts per billion by volume and 100 parts per million by volume;

( C) For target compound( s) not listed in Table 1.1 of ASTM D6420 99( 2004), but potentially detected by mass spectrometry, the additional system continuing calibration check after each run, as detailed in section 10.5.3 of ASTM D6420 99( 2004), is conducted, met, documented, and submitted with the data report, even if there is no moisture condenser used or the compound is not considered water soluble; and ( D) For target compound( s) not listed in Table 1.1 of ASTM D6420 99( 2004), and not amenable to detection by mass spectrometry, ASTM D6420 99( 2004) may not be used.

* * * * *

( b) * * *

( 2) * * *

( ii) The owner or operator shall determine an average mass rate of benzene emissions in kilograms per hour through direct measurement using the methods in § 63.772( a)( 1)( i) or ( ii), or an alternative method according to § 63.7( f). * * *

* * * * * 68 ( e) * * *

( 3) * * *

( iii) To determine compliance with the control device percent reduction performance requirement in § 63.771( d)( 1)( i)( A), ( d)( 1)( ii), and ( e)( 3)( ii), the owner or operator shall use either Method 18, 40 CFR part 60,

appendix A, or Method 25A, 40 CFR part 60, appendix A; or ASTM D6420 99( 2004) as specified in § 63.772( a)( 1)( ii).

Alternatively, any other method or data that have been validated according to the applicable procedures in Method 301, 40 CFR part 63, appendix A, as specified in § 63.7( f)

may be used. The following procedures shall be used to calculate percent reduction efficiency:

* * * * *

( B) * * *

( 2) When the TOC mass rate is calculated, all organic compounds ( minus methane and ethane) measured by Method 18,

40 CFR part 60, appendix A, or Method 25A, 40 CFR part 60,

appendix A, or ASTM D6420 99( 2004) as specified in § 63.772( a)( 1)( ii), shall be summed using the equations in paragraph ( e)( 3)( iii)( B)( 1) of this section.

* * * * *

( iv) To determine compliance with the enclosed combustion device total HAP concentration limit specified in 69 § 63.771( d)( 1)( i)( B), the owner or operator shall use either Method 18, 40 CFR part 60, appendix A, or Method 25A, 40 CFR part 60, appendix A, or ASTM D6420 99( 2004) as specified in § 63.772( a)( 1)( ii), to measure either TOC ( minus methane and ethane) or total HAP. Alternatively, any other method or data that have been validated according to Method 301 of appendix A of this part, as specified in § 63.7( f), may be used. * * *

* * * * *

8. Section 63.774 is amended by revising paragraph ( d)( 1) introductory text to read as follows:

( d) * * *

( 1) An owner or operator that is exempt from control requirements under § 63.764( e)( 1) shall maintain the records specified in paragraph ( d)( 1)( i) or ( d)( 1)( ii) of this section, as appropriate, for each glycol dehydration unit that is not controlled according to the requirements of paragraph ( c)( 1)( i) or ( d)( 1) of § 63.764.

* * * * *

9. Section 63.775 is amended to:

a. Add paragraph ( c);

b. Revise paragraph ( e) introductory text; and c. Add paragraph ( e)( 3) to read as follows:

§ 63.775 Reporting requirements. 70 * * * * *

( c) Each owner or operator of an area source subject to this subpart for shall submit the information listed in paragraphs ( c)( 1) through ( 6) of this section, except as provided in paragraph ( c)( 7).

( 1) The initial notifications required under § 63.9( b)( 2) shall be submitted not later than 1 year following the date of publication of the final rule in the Federal Register.

( 2) If an owner or operator is required by the Administrator to conduct a performance evaluation for a continuous monitoring system, the date of the performance evaluation as specified in § 63.8( e)( 2).

( 3) The planned date of a performance test at least 60 days before the test in accordance with § 63.7( b). Unless requested by the Administrator a site specific test plan is not required by this subpart. If requested by the Administrator, the owner or operator must submit the sitespecific test plan required by § 63.7( c) with the notification of the performance test. A separate notification of the performance test is not required if it is included in the initial notification submitted in accordance with paragraph ( c)( 1) of this section.

( 4) A Notification of Compliance Status as described 71 in paragraph ( d) of this section.

( 5) Periodic reports as described in paragraph ( e)( 3)

of this section.

( 6) Startup, shutdown, and malfunction reports specified in § 63.10( d)( 5) shall be submitted as required.

Separate startup, shutdown, and malfunction reports as described in § 63.10( d)( 5) are not required if the information is included in the Periodic Report specified in paragraph ( e) of this section.

( 7) Each owner or operator of a triethylene glycol dehydration unit subject to this subpart that is exempt from the control requirements for glycol dehydration unit process vents in § 63.765, is exempt from all reporting requirements for area sources in this subpart, for that unit.

* * * * *

( e) Periodic Reports. An owner or operator of a major source shall prepare Periodic Reports in accordance with paragraphs ( e)( 1) and ( 2) of this section and submit them to the Administrator. An owner or operator of an area source shall prepare Periodic Reports in accordance with paragraph ( e)( 3) of this section and submit them to the Administrator.

* * * * *

( 3) An owner or operator of an area source shall prepare and submit Periodic Reports in accordance with 72 paragraphs ( e)( 3)( i) through ( iii) of this section.

( i) Periodic reports must be submitted on an annual basis. The first reporting period shall cover the period beginning on the date the Notification of Compliance Status Report is due and ending on December 31. The report shall be submitted within 30 days after the end of the reporting period.

( ii) Subsequent reporting periods begin every January 1 and end on December 31. Subsequent reports shall be submitted within 30 days following the end of the reporting period.

( iii) The periodic reports must contain the information included in paragraph ( e)( 2) of this section.

* * * * *

10. Revise Table 2 to subpart HH of part 63 to read as follows:

TABLE 2 TO SUBPART HH OF PART 63   APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HH General Provisions Reference Applicable to subpart HH Explanation § 63.1( a)( 1)........ Yes § 63.1( a)( 2)........ Yes § 63.1( a)( 3)........ Yes § 63.1( a)( 4)........ Yes § 63.1( a)( 5)........ No.............. Section reserved.

§ 63.1( a)( 6) through ( a)( 8)............. Yes 73 § 63.1( a)( 9)........ No.............. Section reserved.

§ 63.1( a)( 10)....... Yes § 63.1( a)( 11)....... Yes § 63.1( a)( 12) through ( a)( 14).... Yes § 63.1( b)( 1)........ No.............. Subpart HH specifies applicability.

§ 63.1( b)( 2)........ Yes § 63.1( b)( 3)........ No § 63.1( c)( 1)........ No.............. Subpart HH specifies applicability.

§ 63.1( c)( 2)........ No § 63.1( c)( 3)........ No.............. Section reserved.

§ 63.1( c)( 4)........ Yes § 63.1( c)( 5)........ Yes § 63.1( d)........... No.............. Section reserved.

§ 63.1( e)........... Yes § 63.2.............. Yes Except definition of major source is unique for this source category and there are additional definitions in subpart HH.

§ 63.3( a) through ( c)................ Yes § 63.4( a)( 1) through ( a)( 3)............. Yes § 63.4( a)( 4)........ No.............. Section reserved.

§ 63.4( a)( 5)........ Yes § 63.4( b)........... Yes § 63.4( c)........... Yes § 63.5( a)( 1)........ Yes § 63.5( a)( 2)........ No.............. Preconstruction review required only for major sources that commence construction after promulgation of the standard.

§ 63.5( b)( 1)........ Yes 74 § 63.5( b)( 2)........ No.............. Section reserved.

§ 63.5( b)( 3)........ Yes § 63.5( b)( 4)........ Yes § 63.5( b)( 5)........ Yes § 63.5( b)( 6)........ Yes § 63.5( c)........... No.............. Section reserved.

§ 63.5( d)( 1)........ Yes § 63.5( d)( 2)........ Yes § 63.5( d)( 3)........ Yes § 63.5( d)( 4)........ Yes § 63.5( e)........... Yes § 63.5( f)( 1)........ Yes § 63.5( f)( 2)........ Yes § 63.6( a)........... Yes § 63.6( b)( 1)........ Yes § 63.6( b)( 2)........ Yes § 63.6( b)( 3)........ Yes § 63.6( b)( 4)........ Yes § 63.6( b)( 5)........ Yes § 63.6( b)( 6)........ No.............. Section reserved.

§ 63.6( b)( 7)........ Yes § 63.6( c)( 1)........ Yes § 63.6( c)( 2)........

§ 63.6( c)( 3) through ( c)( 4)............. No.............. Section reserved.

§ 63.6( c)( 5)........ Yes § 63.6( d)........... No.............. Section reserved.

§ 63.6( e)........... Yes § 63.6( e)( 1)( i)..... No.............. Except as otherwise specified. Addressed in § 63.762.

§ 63.6( e)( 1)( ii).... Yes 75 § 63.6( e)( 1)( iii)... Yes § 63.6( e)( 2)........ Yes § 63.6( e)( 3)( i)..... Yes § 63.6( e)( 3)( i)( A).. No.............. Except as otherwise specified. Addressed in § 63.762( c).

§ 63.6( e)( 3)( i)( B).. Yes § 63.6( e)( 3)( i)( C).. Yes § 63.6( e)( 3)( ii) through ( 3)( vi).... Yes § 63.6( e)( 3)( vii)... Yes § 63.6( e)( 3)( vii)( A) ................... Yes § 63.6( e)( 3)( vii)( B) ................... Yes............. Except that the plan must provide for operation in compliance with § 63.762( c).

§ 63.6( f)( 1)........ Yes § 63.6( f)( 2)........ Yes § 63.6( f)( 3)........ Yes § 63.6( g)........... Yes § 63.6( h)........... No Subpart HH does not contain opacity or visible emission standards.

§ 63.6( i)( 1) through ( i)( 14)............ Yes § 63.6( i)( 15)....... No Section reserved.

§ 63.6( i)( 16)....... Yes § 63.6( j)........... Yes § 63.7( a)( 1)........ Yes § 63.7( a)( 2)........ Yes............. But the performance test results must be submitted within 180 days after the compliance date.

§ 63.7( a)( 3)........ Yes § 63.7( b)........... Yes § 63.7( c)........... Yes 76 § 63.7( d)........... Yes § 63.7( e)( 1)........ Yes § 63.7( e)( 2)........ Yes § 63.7( e)( 3)........ Yes § 63.7( e)( 4)........ Yes § 63.7( f)........... Yes § 63.7( g)........... Yes § 63.7( h)........... Yes § 63.8( a)( 1)........ Yes § 63.8( a)( 2)........ Yes § 63.8( a)( 3)........ No.............. Section reserved.

§ 63.8( a)( 4)........ Yes § 63.8( b)( 1)........ Yes § 63.8( b)( 2)........ Yes § 63.8( b)( 3)........ Yes § 63.8( c)( 1)........ Yes § 63.8( c)( 2)........ Yes § 63.8( c)( 3)........ Yes § 63.8( c)( 4)........ No § 63.8( c)( 5) through ( c)( 8)............. Yes § 63.8( d)........... Yes § 63.8( e)........... Yes............. Subpart HH does not specifically required continuous emissions monitor performance evaluation, however, the Administrator can request that one be conducted.

§ 63.8( f)( 1) through ( f)( 5)............. Yes § 63.8( f)( 6)........ No.............. Subpart HH does not require continuous emissions monitoring.

§ 63.8( g)........... No.............. Subpart HH specifies continuous monitoring system data reduction requirements. 77 § 63.9( a)........... Yes § 63.9( b)( 1)........ Yes § 63.9( b)( 2)........ Yes............. Existing sources are given 1 year ( rather than 120 days) to submit this notification.

§ 63.9( b)( 3)........ Yes § 63.9( b)( 4)........ Yes § 63.9( b)( 5)........ Yes § 63.9( c)........... Yes § 63.9( d)........... Yes § 63.9( e)........... Yes § 63.9( f)........... Yes § 63.9( g)........... Yes § 63.9( h)( 1) through ( h)( 3)............. Yes § 63.9( h)( 4)........ No.............. Section reserved.

§ 63.9( h)( 5) through ( h)( 6)............. Yes § 63.9( i)........... Yes § 63.9( j)........... Yes § 63.10( a).......... Yes § 63.10( b)( 1)....... Yes............. § 63.774( b)( 1) requires sources to maintain the most recent 12 months of data on site and allows offsite storage for the remaining 4 years of data.

§ 63.10( b)( 2)....... Yes § 63.10( b)( 3)....... No.............. Section reserved.

§ 63.10( c)( 1)....... Yes § 63.10( c)( 2) through ( c)( 4)..... No.............. Sections reserved.

§ 63.10( c)( 5) through ( c)( 8)..... Yes § 63.10( c)( 9)....... No.............. Section reserved.

§ 63.10( c)( 10) through ( c)( 15).... Yes 78 § 63.10( d)( 1)....... Yes § 63.10( d)( 2)....... Yes § 63.10( d)( 3)....... Yes § 63.10( d)( 4)....... Yes § 63.10( d)( 5)....... Yes............. Subpart HH requires major sources to submit a startup, shutdown and malfunction report semi annually.

§ 63.10( e)( 1)....... Yes § 63.10( e)( 2)....... Yes § 63.10( e)( 3)( i).... Yes............. Subpart HH requires major sources to submit Periodic Reports semi annually. Area sources are required to submit Periodic Reports annually.

§ 63.10( e)( 3)( i)( A) ................... Yes § 63.10( e)( 3)( i)( B) ................... Yes § 63.10( e)( 3)( i)( C) ................... No.............. Subpart HH does not require quarterly reporting for excess emissions.

§ 63.10( e)( 3)( ii) through ( viii)..... Yes § 63.10( f).......... Yes § 63.11( a) and ( b).. Yes § 63.12( a) through ( c)................ Yes § 63.13( a) through ( c)................ Yes § 63.14( a) and ( b).. Yes § 63.15( a) and ( b).. Yes