79964 Federal Register / Vol. 75, No. 244 / Tuesday, December 21, 2010 / Rules and Regulations 

Dated: December 2, 2010. 

Robert Papp, 

Admiral, U.S. Coast Guard, Commandant. 

Lisa P. Jackson, 

Administrator, U.S. Environmental Protection 

Agency. 

[FR Doc. 2010–32018 Filed 12–20–10; 8:45 am] 

BILLING CODE 9110–04–P; 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA EPA–HQ–OAR–2005–0161; FRL–9241– 

4] 

RIN 2060–AQ31 

Regulation of Fuels and Fuel 

Additives: Modifications to Renewable 

Fuel Standard Program 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final r ule. 

SUMMARY: EPA is finalizing amendments 

to certain of the Renewable Fuel 

Standard program regulations that were 

published on March 26, 2010, and that 

took effect on July 1, 2010 (‘‘the RFS2 

regulations’’). Following publication of 

the RFS2 regulations, promulgated in 

response to the requirements of the 

Energy Independence and Security Act 

of 2007, EPA discovered some technical 

errors and areas within the final RFS2 

regulations that could benefit from 

clarification or modification. In a direct 

final rule and parallel notice of 

proposed rulemaking published on May 

10, 2010, EPA included language to 

amend the regulations to make the 

appropriate corrections, clarifications, 

and modifications. However, EPA 

received adverse comment on a few 

provisions in the direct final rule and, 

on June 30, 2010, withdrew those 

provisions prior to their effective date of 

July 1, 2010. In today’s action, EPA is 

addressing the comments received on 

the portions of the direct final rule that 

were withdrawn and is taking final 

action regarding the withdrawn 

provisions based on consideration of the 

comments received. 

DATES: This final rule is effective on 

January 1, 2011. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2005–0161. All 

documents in the docket are listed on 

the http:://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., CBI or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

generally available either electronically 

through http://www.regulations.gov or 

in hard copy at the Air and Radiation 

Docket, ID No. EPA–HQ–OAR–2005– 

0161, EPA West, Room 3334, 1301 

Constitution Ave., NW., 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) 566–9744. 

FOR FURTHER INFORMATION CONTACT: 

Megan Brachtl, Compliance and 

Innovative Strategies Division, Office of 

Transportation and Air Quality (6405J), 

Environmental Protection Agency, 1200 

Pennsylvania Avenue, NW., 20460; 

telephone number: (202) 343–9473; fax 

number: (202) 343–2802; e-mail 

address: brachtl.megan@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

A. Does this action apply to me? 

Entities potentially affected by this 

final rule include those involved with 

the production, importation, 

distribution, and sale of transportation 

fuels, including gasoline and diesel fuel 

and renewable fuels such as ethanol and 

biodiesel. Regulated categories and 

entities affected by this action include: 

Category NAICS codesa SIC codesb Examples of potentially regulated parties 

Industry ........................................ 324110 2911 Petroleum refiners, importers. 

Industry ........................................ 325193 2869 Ethyl alcohol manufacturers. 

Industry ........................................ 325199 2869 Other basic organic chemical manufacturers. 

Industry ........................................ 424690 5169 Chemical and allied products merchant wholesalers. 

Industry ........................................ 424710 5171 Petroleum bulk stations and terminals. 

Industry ........................................ 424720 5172 Petroleum and petroleum products merchant wholesalers. 

Industry ........................................ 454319 5989 Other fuel dealers. 

a North American Industry Classification System (NAICS). 

bStandard Industrial Classification (SIC) system code. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this action. This table lists 

the types of entities that EPA is now 

aware could potentially be regulated by 

this action. Other types of entities not 

listed in the table could also be 

regulated. To determine whether your 

activities would be regulated by this 

action, you should carefully examine 

the applicability criteria of Part 80, 

subpart M of title 40 of the Code of 

Federal Regulations. If you have any 

questions regarding the applicability of 

this action to a particular entity, consult 

the person in the FOR FURTHER

INFORMATION CONTACT section above. 

II. Renewable Fuel Standard (RFS2) 

Program Amendments 

EPA issued final regulations 

implementing changes to the Renewable 

Fuel Standard program required by 

EISA on March 26, 2010, at 75 FR 14670 

(‘‘the RFS2 regulations’’). Following 

publication of the RFS2 regulations, 

EPA discovered some technical errors 

and areas that could benefit from 

clarification or modification and, in 

parallel proposed and direct final rules 

published on May 10, 2010 (75 FR 

26049, 75 FR 26026), included 

amendments to the regulations to 

correct these deficiencies. EPA received 

adverse comment on a few of the 

amendments and therefore, on June 30, 

2010, withdrew the portions of the 

direct final rule that were the subject of 

adverse comment (75 FR 37733). The 

withdrawn provisions consist of the 

following: 

—Certain of the amendments to 

§ 80.1401, specifically those which 

moved the definitions of ‘‘actual peak 

capacity,’’ ‘‘baseline volume,’’ and 

‘‘permitted capacity’’ from 

§ 80.1403(a), revised the definition of 

‘‘actual peak capacity’’ to clarify how 

it is calculated, and revised the 

definition of ‘‘permitted capacity’’ to 

clarify the dates by which permits 

used to establish a facility’s permitted 

capacity must have been issued or 

revised; 


jlentini on DSKJ8SOYB1PROD with RULES
Federal Register / Vol. 75, No. 244 / Tuesday, December 21, 2010 / Rules and Regulations 79965 

—§ 80.1425, which clarified that RINs 

generated after July 1, 2010, may only 

be generated and transferred using the 

EPA Moderated Transaction System 

(EMTS) and will not be identified by 

a 38-digit code, and that the value of 

EEEEEEEE in a batch-RIN will be 

determined by the number of gallonRINs generated for the batch; 

—§ 80.1426(d)(1), § 80.1426(f)(3)(iv), 

and § 80.1426(f)(3)(v), which clarified 

that a unique batch code in the RIN, 

or its equivalent in EMTS, is used to 

identify a batch of renewable fuel 

from a given renewable fuel producer 

or importer; 

—Table 2 to § 80.1426, which clarified 

the extent to which renewable fuel 

producers must use advanced 

technologies in order for their fuel to 

qualify for certain pathways identified 

in Table 1 to § 80.1426; 

—§ 80.1426(f)(12), which clarified the 

requirements for gas used for process 

heat at a renewable fuel facility to be 

considered biogas for purposes of 

Table 1 to § 80.1426; 

—§ 80.1452(b), which clarified that RINs 

must be generated in EMTS within 

five business days of being assigned to 

a batch of renewable fuel and clarified 

the information required to be 

submitted via EMTS for each batch of 

renewable fuel produced or imported; 

and, 

—§ 80.1452(c), which clarified that 

transactions involving RINs generated 

on or after July 1, 2010, must be 

conducted via EMTS within five 

business days of a reportable event, 

and clarified the meaning of the term 

‘‘reportable event’’ and the 

information required to be submitted 

via EMTS for each transaction 

involving RINs generated on or after 

July 1, 2010. 

EPA published a parallel proposed rule 

(75 FR 26049) on the same day as the 

direct final rule (75 FR 26026). The 

proposed rule invited comment on the 

provisions of the direct final rule and 

indicated that a second comment period 

would not be offered on the proposal in 

the event that portions of the direct final 

rule were withdrawn in response to 

adverse comment. In this action, we are 

responding to the comments received on 

the portions of the direct final rule that 

were subsequently withdrawn, and we 

are taking final action regarding the 

withdrawn provisions based on 

consideration of these comments. We 

are also finalizing a minor amendment 

to § 80.1451(b)(1)(ii)(M) which was 

described in the preamble to the direct 

final rule and was included in the 

accompanying regulations, but the 

amendatory language prefacing the 

regulation inadvertently omitted 

reference to it. As a result, the Office of 

the Federal Register did not codify the 

amended regulation even though it was 

included in the direct final rule. The 

modification simply removes the words 

‘‘of renewable fuel’’ to make the 

regulatory language consistent with 

other entries in the subparagraph. We 

received no adverse comment on this 

proposed amendment, and we consider 

it a non-substantive technical 

correction. 

A. Permitted Capacity for Renewable 

Fuel Production Facilities 

In the final RFS2 regulations, we 

specified in § 80.1403(a)(1) that the 

‘‘baseline volume’’ of fuel that is exempt 

from the 20 percent greenhouse gas 

(GHG) reduction requirement at 

grandfathered facilities described in 

§§ 80.1403(c) and (d) would be 

determined by their ‘‘permitted 

capacity’’ or, if that could not be 

determined, by their ‘‘actual peak 

capacity.’’ In the registration provisions 

at § 80.1450(b)(1)(v)(B), we identified 

the permits that are relevant in 

establishing ‘‘permitted capacity.’’ 

Specifically, for facilities that 

commenced construction on or before 

December 19, 2007, the final RFS2 

regulations stated that ‘‘permitted 

capacity’’ is based on permits issued or 

revised no later than December 19, 

2007. For ethanol facilities that 

commenced construction after 

December 19, 2007, and on or before 

December 31, 2009, and that are fired 

with natural gas, biomass, or a 

combination thereof, the RFS2 

regulations stated that ‘‘permitted 

capacity’’ is based on permits issued or 

revised no later than December 31, 

2009. 

In the final RFS2 regulations, we did 

not include in the definition of 

‘‘permitted capacity’’ references 

identical to those placed in the 

registration section to the latest issuance 

dates of permits that could be used to 

establish ‘‘permitted capacity.’’ 

Therefore, in the direct final rule 

published at 75 FR 26026 (May 10, 

2010), EPA modified the definition of 

‘‘permitted capacity’’ to specify the same 

dates for relevant permits as were 

provided in the registration provisions 

in the final RFS2 regulations. We 

believed that such a revision would 

improve the clarity of the regulations, 

while not changing the substance of the 

requirements. 

However, we received adverse 

comments during and after the comment 

period expressing concern over the 

modified definition of ‘‘permitted 

capacity,’’ which commenters stated 

posed ‘‘new constraints’’ on the 

qualification of eligible fuel volumes 

that could be exempt at grandfathered 

facilities. One commenter described an 

ethanol facility fired by natural gas, and 

therefore potentially eligible for an 

exemption from the 20 percent GHG 

reduction requirement pursuant to 

§ 80.1403(d), for which permits were 

issued and construction completed prior 

to December 31, 2009, and for which an 

application for a permit revision seeking 

an increase in permitted capacity was 

submitted to the permitting authority in 

2008. The commenter claimed that the 

revised permit reflected the facility’s 

original plant design, however the 

permitting authority did not issue a 

revised permit for the facility until 

March 2010. According to the revised 

definition of ‘‘permitted capacity’’ in the 

regulations as amended by the direct 

final rule and according to the original 

registration requirements of the final 

RFS2 regulations, permits issued or 

revised after December 31, 2009, could 

not be used to establish ‘‘permitted 

capacity,’’ and therefore the additional 

capacity in the revised permit could not 

be included in the facility’s baseline 

volume. The commenter explained that 

many ethanol producers originally 

applied for permits for their facilities 

based on conservative initial production 

volumes supported by their plant 

designers’ emission guarantees, and that 

after an initial period of operation, 

performance testing, and fine tuning of 

operations, they have found that they 

could produce greater volumes. They 

explained that many developers of 

ethanol facilities, including their own, 

sought to obtain construction permits 

without going through EPA’s New 

Source Review (NSR) program, and 

were able to do so by obtaining 

construction permits that specified less 

than 100 tons per year of emissions even 

though their facilities were capable of 

emitting more and producing a 

correspondingly greater volume of 

renewable fuel. In May 2007, when EPA 

changed to 250 tons per year the 

emissions threshold that would trigger 

NSR for ethanol production facilities, 

these plants then found it in their 

interest to seek increases in their 

permitted capacity beyond that 

specified in their earlier-issued permits, 

since they could do so without 

triggering NSR. The commenter argued 

that ethanol facilities should be allowed 

to use the capacity in such later-issued 

permits, including their own March 

2010 revised permit, to establish their 

‘‘permitted capacity’’ under RFS2. 

We also received additional 

comments after the close of the 


jlentini on DSKJ8SOYB1PROD with RULES
79966 Federal Register / Vol. 75, No. 244 / Tuesday, December 21, 2010 / Rules and Regulations 

1Pursuant to § 80.1403(a)(3)(i) in the RFS2 

regulations issued March 26, 2010, ‘‘actual peak 

capacity’’ is based on the last five calendar years 

prior to 2008 for facilities qualifying under 

§ 80.1403(c) unless no such capacity exists, in 

which case it is based on any calendar year after 

startup during the first three years of operation. For 

facilities qualifying pursuant to § 80.1403(d), 

‘‘actual peak capacity’’ is based on any calendar year 

after start-up during the first three years of 

operation, as specified in § 80.1403(a)(3)(ii). 

comment period from a collective group 

of ethanol facilities in Illinois 

referencing the initial commenter’s 

comments that the cut-off dates in the 

revised definition of ‘‘permitted 

capacity’’ created restrictions for their 

facilities that would prohibit them from 

having the ‘‘inherent capacity’’ of their 

facilities qualify for the grandfathering 

exemption under RFS2. In addition, the 

commenters referenced what they felt 

was an inequitable allowance for 

facilities located in states that did not 

place production limits in their air 

permits, who therefore were allowed to 

use ‘‘actual peak capacity’’ (which is 

based on actual production records 1) to 

establish their baseline volume exempt 

from the 20 percent GHG reduction 

requirement under RFS2. The 

commenters further cited potential cost 

effects if their full ‘‘inherent capacity’’ 

was not allowed to be included in the 

exempt baseline volume, such as the 

additional costs associated with either 

plant modifications (presumably needed 

to qualify their non-exempt fuel as 

meeting the 20 percent GHG reduction 

requirement) or exporting the nonexempt volume of fuel for consumption 

outside of the United States. 

The commenters proposed revised 

language for the definition of ‘‘permitted 

capacity’’ that would allow an extended 

time frame for facilities to seek permit 

modifications to reflect their ‘‘inherent 

capacity.’’ They proposed that EPA 

modify the final RFS2 regulations to 

allow facilities to use as their baseline 

volume the capacity limits in permits 

issued by regulatory authorities which 

were applied for within three years after 

start-up of a new or expanded facility 

(but not less than one year after the 

effective date of the final rule) and 

issued within not more than two years 

thereafter. The commenters also stated 

that many facilities had no notice of 

EPA’s time limitation on those permits 

in either the proposed or final RFS2 rule 

(74 FR 24904, published May 26, 2009, 

and 75 FR 14670, published March 26, 

2010) and therefore had inadequate 

notice to make appropriate plans to 

apply for and obtain new permits within 

the RFS2 deadlines. They further 

expressed concern that the permit cutoff date that restricts grandfathered 

production capacity precedes the date of 

the proposed rule. They also cited a 

statement made in the proposed RFS2 

rule that EPA’s guiding principal is to 

‘‘allow production increases within a 

plant’s inherent capacity’’ (74 FR 24904, 

24926, May 26, 2009). One commenter 

also referred to EPA’s RFS2 Summary 

and Analysis of Comments, p. 3–139 

(Pub. No. EPA–420–R–10–003, February 

2010), in which, they state, EPA 

assumed that permitted capacity would 

likely reflect maximum inherent 

capacity. The commenter said that such 

an assumption would be valid for some 

situations, but not valid for others, 

especially with the limitations EPA 

intended to place on the date of permits 

that could be used to establish 

‘‘permitted capacity.’’ 

The Energy Independence and 

Security Act of 2007 (EISA or ‘‘the Act’’) 

provides that the 20 percent GHG 

reduction requirement applies to ‘‘new 

facilities’’ that commence construction 

after the date of enactment. It also 

provides that ‘‘for calendar years 2008 

and 2009, any ethanol plant that is fired 

with natural gas, biomass, or any 

combination thereof is deemed to be in 

compliance with [the] 20 percent 

reduction requirement * * *’’ In the 

proposed RFS2 rule we noted that the 

term ‘‘new facility’’ is not defined in 

EISA and, therefore, that EPA would 

need to interpret the term in the context 

of the RFS2 regulations. We also noted 

ambiguity in the statutory section 

related to ethanol facilities that 

commenced construction in 2008 and 

2009 and that are fired with natural gas 

or biomass, in that the Act was not clear 

as to whether these facilities should be 

‘‘deemed compliant’’ with the 20 percent 

GHG reduction requirement for only the 

two years specified, or indefinitely. For 

both types of facilities, we believe the 

approach we are finalizing in this rule 

provides an appropriate method of 

implementing statutory requirements 

that is consistent with the text and 

objectives of the statute, while also 

leading to a workable program. 

First, with respect to ‘‘deemed 

compliant’’ ethanol facilities fired with 

natural gas or biomass for which 

construction commenced after 

enactment of EISA but on or before 

December 31, 2009, we believe, as 

discussed in the proposed RFS2 rule, 

that Congress could have intended that 

these facilities are only ‘‘deemed 

compliant’’ for those two years or for a 

longer or indefinite time period 

(assuming they continued to be fired 

with natural gas or biomass). The 

ambiguity can be seen through a 

comparison of the first sentence of EISA 

Section 210(a) and the second sentence. 

The first sentence provides that ‘‘for 

calendar year 2008, transportation fuel 

sold or introduced into commerce in the 

United States’’ that is produced by 

facilities that commenced construction 

after the date of enactment of EISA must 

meet the 20 percent GHG reduction 

requirement. This sentence is very 

specific, applying directly to 

‘‘transportation fuel’’ that is ‘‘sold or 

introduced into commerce’’ in 2008. The 

second sentence in this section does not 

specifically refer to fuel, but instead 

refers to ‘‘any ethanol plant that is fired 

with natural gas, biomass, or any 

combination thereof’’ and provides that 

such facilities are ‘‘deemed compliant’’ 

with the 20 percent GHG reduction 

requirements of the Act. The sentence is 

introduced by the words ‘‘[f]or 2008 and 

2009.’’ Since fuel from facilities that 

commenced construction prior to the 

date of enactment is already exempt 

from the 20 percent GHG reduction 

requirement by virtue of CAA Section 

211(o)(2)(A)(i), the ‘‘deemed compliant’’ 

provision in the second sentence of 

EISA 210(a) clearly applies to ethanol 

facilities that commenced construction 

after that date. 

We believe the scope of the 

exemption is ambiguous, however, 

because Congress did not specifically 

refer to fuel sold in specified years in 

the second sentence, as they did in the 

first sentence, but instead referred to 

‘‘ethanol plants.’’ Because of this 

construct, it is unclear exactly what fuel 

should be covered by the exemption. 

EPA identified two general approaches 

to interpreting this provision in its 

proposed rule: Either interpreting it to 

provide a limited two year exemption, 

or interpreting it to provide an 

exemption for fuel produced by 

qualifying facilities that would be of 

equal duration to the exemption 

provided in CAA Section 211(o)(2)(i) for 

fuel from facilities that commenced 

construction prior to EISA enactment. 

We reasoned that it would be a harsh 

result for investors in these new 

facilities, and generally inconsistent 

with the energy independence goals of 

EISA, to interpret the Act such that 

these facilities would only be 

guaranteed two years of participation in 

the RFS2 program. Therefore in our 

final RFS2 regulations we provided an 

indefinite exemption from the 20 

percent GHG reduction requirement for 

their baseline volumes (determined 

through either ‘‘permitted capacity’’ or, 

if ‘‘permitted capacity’’ cannot be 

determined, ‘‘actual peak capacity’’) 

provided that they continue to be fired 

by natural gas, biomass, or a 

combination thereof. 

Contrary to the commenters’ 

assertions, nothing in EISA suggests that 


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Federal Register / Vol. 75, No. 244 / Tuesday, December 21, 2010 / Rules and Regulations 79967 

2We note that while some air permits may not 

contain restrictions on plant capacity, most contain 

restrictions on emission rates, fuel consumption, 

throughputs, and sizes of vessels. Thus, there are 

some limitations on capacity that are related to 

restrictions on these parameters in the air permit. 

these ‘‘deemed compliant’’ facilities 

should be allowed to continually 

expand their production beyond levels 

achieved in 2008 and 2009 simply 

because they could do so without 

additional physical construction. 

Rather, the approach EPA has adopted 

of seeking to limit the exempt volume 

at these grandfathered facilities to that 

which was lawfully allowed in 

applicable permits issued no later than 

December 31, 2009, is fully consistent 

with the statutory references to 2008 

and 2009. 

We believe it is consistent with the 

statutory text to limit the grandfathered 

production from ‘‘deemed compliant’’ 

facilities to the maximum volume 

allowed under applicable permits in the 

2008 to 2009 timeframe. We also believe 

that this approach is supported by the 

same policy considerations, discussed 

below, that have led us to a similar 

approach for facilities that commenced 

construction prior to EISA enactment. 

We have only deviated from this 

concept with respect to those ‘‘deemed 

compliant’’ facilities for which capacity 

cannot be determined by reference to 

applicable permits. Those facilities, 

some of which may not have been 

operational in the 2008 to 2009 

timeframe, by necessity are allowed to 

establish their baseline volume by 

reference to actual production levels 

(‘‘actual peak capacity’’) within a 

specified time period after they 

commence operations. For both 

‘‘deemed compliant’’ facilities and 

facilities that commenced construction 

prior to EISA enactment, we believe that 

allowing facilities to establish their 

baseline volume by actual production 

for any calendar year within the first 

three years of operation is appropriate 

because it allows a reasonable amount 

of time to correct possible production 

launch problems. This is an exception 

to the general rule, and is allowed only 

if permit limits are not available to 

establish baseline volume. 

While there may be instances, as 

suggested by commenters, in which 

facilities that use ‘‘actual peak capacity’’ 

to establish their baseline volume could 

come closer to obtaining an exemption 

for what the owner may consider their 

‘‘inherent capacity’’ than those 

establishing their baseline volume 

through permit limits, EPA notes that 

this need not always be the case. For 

example, some plants, whose baseline 

volume is established through ‘‘actual 

peak capacity’’ because they do not have 

a capacity stated on a permit, may not, 

due to certain start-up problems or 

market conditions, actually produce up 

to their projected or potential capacity 

during the first three years of operation. 

Nonetheless, they are required under 

the final RFS2 regulations to use the 

maximum annual production during 

these first three years of operation to 

establish their baseline volume.2 On the 

other hand, some plants that applied for 

permits reflecting a certain ‘‘permitted 

capacity’’ that may have been based on 

their facility’s projected maximum 

capacity, but who in practice may not be 

able to achieve this capacity or do not 

do so for some period of time due to 

market conditions, are allowed under 

the final RFS2 regulations to use this 

higher ‘‘permitted capacity’’ to establish 

their baseline volume. In these 

scenarios, baseline volume established 

through ‘‘permitted capacity’’ may be 

greater than the baseline volume that 

could be achieved by a comparable 

facility by reference to actual 

production during the first three years 

of operation. Thus, while it is true that 

‘‘permitted capacity’’ does not always 

reflect potential capacity, ‘‘actual peak 

capacity’’ also does not necessarily 

reflect a facility’s potential capacity, as 

demonstrated in our examples above. 

Therefore, we disagree with the 

commenters’ statement that facilities 

using ‘‘actual peak capacity’’ to establish 

their baseline volume have an unfair 

advantage over facilities that must use 

their ‘‘permitted capacity’’ to establish 

their baseline volume. 

With respect to facilities that 

commenced construction before the date 

of enactment of EISA, commenters also 

state that EPA should interpret the EISA 

grandfathering provisions to allow 

volumes from such facilities to be 

exempt up to the maximum of their 

‘‘inherent capacity.’’ The statute does not 

use the term ‘‘inherent capacity,’’ and 

instead applies the 20 percent GHG 

reduction requirement to ‘‘new facilities 

that commence construction’’ after the 

date of enactment. In the RFS2 

rulemaking, EPA addressed the issue of 

how to implement this grandfathering 

provision by defining both the facilities 

and their production volumes that 

would be grandfathered, and 

considering all other production 

volumes to be subject to the 20 percent 

GHG reduction threshold. EPA 

identified the grandfathered volumes in 

two steps. First, EPA identified the 

facilities that could be considered 

available for grandfathering by using 

definitions of ‘‘facility’’ and ‘‘commence 

construction’’ that were similar but not 

identical to those used in EPA’s 

stationary source Prevention of 

Significant Deterioration (PSD) 

permitting program. After identifying 

these facilities, EPA followed a second 

step to identify what volumes at those 

facilities would be grandfathered. In this 

final rulemaking, EPA is addressing the 

same issue of what volume should be 

grandfathered as we did for the final 

RFS2 rulemaking. 

EPA rejected the approach of 

determining that any and all volumes 

produced at qualifying facilities should 

be considered grandfathered. EPA also 

rejected the approach specified in the 

NPRM of requiring facilities to report on 

expenses for replacements, additions, 

and repairs so that EPA could determine 

on a case-by-case basis if such activities 

warranted considering the facility as 

effectively ‘‘new’’ for purposes of the 

grandfathering provisions. Instead, EPA 

chose an approach that extends an 

indefinite exemption to baseline 

volumes at qualifying facilities, and 

defines the grandfathered volume by 

reference to ‘‘permitted capacity’’ 

contained in air permits that govern the 

operation of a facility at the time of the 

statutory deadline. If such capacity is 

not stipulated in the permit, then the 

baseline is established by ‘‘actual peak 

capacity’’ achieved within either the last 

five calendar years prior to 2008 or, if 

the plant is not yet in operation, the first 

three years after start-up. The ‘‘permitted 

capacity’’ or the actual operations 

history of the plant would define a 

baseline volume, and increases above 

105 percent of this volume would be 

considered production by a new facility. 

These criteria are objective and their use 

avoids the case-by-case decision-making 

that would be required if less objective 

criteria were applied. 

In this rulemaking, EPA proposed to 

clarify but not change this approach, 

and commenters have suggested that 

EPA now change the approach 

substantially. EPA rejects this request 

for a change in approach for many of the 

same reasons given in the preamble to 

the final RFS2 regulations. 

First, EPA notes that the statute does 

not define the terms ‘‘new facility’’ or 

‘‘commence construction,’’ providing 

EPA discretion to interpret these terms 

in a reasonable fashion that promotes 

the goals of the statute. EPA notes that 

there were no objections to how EPA 

defined the universe of facilities that 

can produce grandfathered renewable 

fuel in the proposed RFS2 regulations. 

Rather, commenters raised issues 

regarding what volumes and years of 

production from these facilities (and 

from any modifications or expansions to 

the facilities) should be considered 

grandfathered. The only issue raised in 


jlentini on DSKJ8SOYB1PROD with RULES
79968 Federal Register / Vol. 75, No. 244 / Tuesday, December 21, 2010 / Rules and Regulations 

3Table 1.1.1 from ‘‘Renewable Fuel Standard 

Program (RFS2) Regulatory Impact Analysis’’ (EPA– 

420–R–10–006); February 2010. 

the current set of comments, however, is 

the extent to which volumes above 

those allowed at the time of the 

statutory deadlines should be 

grandfathered. 

As in the RFS2 rulemaking, EPA is 

faced with two basic approaches. The 

first approach is raised by commenters 

who suggest applying the concept of 

‘‘maximum capacity’’ or ‘‘inherent 

capacity’’ on a case-by-case basis. Some 

commenters have suggested this could 

be limited in time to a set number of 

years in the future. Under this approach, 

EPA would evaluate each permit 

revision that occurs and would need to 

determine if the changes undertaken 

were within the ‘‘inherent capacity’’ of a 

qualifying facility. If they were not, the 

volumes would be considered produced 

by a new facility for which construction 

commenced after the statutory deadline. 

EPA does not agree that this is either 

a required or an appropriate approach. 

EISA does not define the phrase ‘‘new 

facilities that commence construction,’’ 

nor does it refer to or require that EPA 

follow the approach suggested by the 

commenters. As was the case in the 

proposed and final RFS2 rules, EPA is 

concerned about the lack of objectivity 

and concreteness in applying a concept 

such as ‘‘inherent capacity.’’ There is no 

clear or concrete meaning to this term. 

In practice, renewable fuel facilities can 

and do evolve over time. A facility and 

its operations are typically in a constant 

state of flux to address changing 

circumstances and to optimize 

production under those circumstances. 

These changing circumstances can 

involve a full range of activities that 

may include changes in equipment or 

operations, with any of these changes 

ranging from minor to major. Once one 

aspect of facility design or operation 

that constrains capacity is optimized, 

another aspect becomes the constraining 

factor. This process, which can include 

what is often referred to as 

debottlenecking, is iterative and can 

continue indefinitely. Thus the terms 

‘‘inherent capacity,’’ ‘‘nameplate 

capacity,’’ and ‘‘design capacity’’ have 

meaning only in a general or broad 

sense. EPA does not believe it could 

develop criteria that would fairly and 

objectively define these terms. Without 

such criteria, the case-by-case analysis 

to implement such an approach would 

be difficult to accomplish in a fair and 

consistent manner, thus making such an 

approach undesirable. Instead, EPA’s 

approach is definitive, allowing in all 

cases 105 percent of ‘‘permitted 

capacity’’ or, if permit limits are not 

available, 105 percent of ‘‘actual peak 

capacity’’ to establish baseline volumes. 

The 105 percent factor allows a 

consistent and definitive allowance 

beyond ‘‘permitted capacity’’ or ‘‘actual 

peak capacity’’ measures. As stated in 

the preamble to the final RFS2 rule, it 

provides an allowance for 

debottlenecking and minor changes that 

may be brought about by normal 

maintenance that is consistent with the 

proper operation of a facility, while 

being sufficiently small so as to not 

encourage plant expansions that are 

unrelated to debottlenecking and 

normal maintenance procedures (75 FR 

14670, 14689, March 26, 2010). EPA 

believes that such an allowance is 

consistent with the concept of applying 

the 20 percent GHG reduction 

requirement to ‘‘new facilities that 

commence construction’’ after EISA, 

while not also introducing a difficult 

case-by-case implementation approach 

to the rules as suggested by the 

commenters. 

Under the approach taken in the final 

RFS2 rule and clarified in the direct 

final rule, future changes in production 

above 105 percent of the baseline 

volume would be treated as production 

by a new facility that commenced 

construction after the statutory 

deadline. Typically the increase in 

production, whether caused by a permit 

change or otherwise, would be the result 

of changes made in order to increase 

production, whether physical changes 

in equipment or changes in operation. 

These changes would make the plant 

different in a way that would allow it to 

produce more renewable fuel. 

Implementation of these changes would 

be considered construction, whether it 

is from a process of physical 

construction, physical replacement, 

change in operation, redesign, or 

reconfiguration. EPA broadly interprets 

the terms ‘‘new’’ and ‘‘construction’’ in 

the final RFS2 rule to encompass the 

kinds of changes typically taken to 

increase production. 

EPA recognizes that the approach we 

have taken in the final RFS2 rule 

encompasses a broad variety of 

physical, operational, and other 

efficiency changes. EPA favors its 

approach because it gives reasonable 

meaning to the terms in EISA in a way 

that provides clear and objective 

criteria, and it avoids the problems and 

complexities noted above with the caseby-case approach that tries to 

implement an ‘‘inherent capacity’’ 

criterion. It is also a reasonable way to 

further the goals of the grandfathering 

provision and for evaluating future 

increases in production. 

By arguing that the ‘‘inherent 

capacity’’ of a plant built before 

enactment must be grandfathered 

regardless of permit limitations on the 

date of enactment, commenters seem to 

be equating the term ‘‘construction’’ in 

the statute with ‘‘physical construction.’’ 

Their rationale is that if the increased 

volumes are not derived from new 

physical construction of a facility after 

the date of enactment, then any and all 

fuel from that grandfathered facility 

must be covered by the exemption. 

However, the term ‘‘construction’’ is not 

defined in EISA and need not be viewed 

in this manner. For example, Congress 

defined the term ‘‘construction’’ in CAA 

section 169(2) for the PSD program to 

include ‘‘modifications’’ as defined in 

CAA section 111(a)(4). That term is 

defined in the statute to include ‘‘any 

change in, or change in the method of 

operation of, a stationary source which 

increases the amount of any air 

pollutant emitted by such source or 

which results in the emission of any air 

pollutant not previously emitted.’’ The 

definition of ‘‘commence construction’’ 

adopted in the final RFS2 regulations 

specifically incorporates by reference 

the definition of ‘‘begin actual 

construction’’ from the PSD regulations, 

where the term ‘‘construction’’ is defined 

as ‘‘any physical change or change in the 

method of operation * * * that would 

result in a change in emissions.’’ (See 40 

CFR 80. 1403(a)(4), 52.21(b)(1) and 

53.21(b)(8).) EPA’s treatment of postenactment ‘‘construction’’ under the 

final RFS2 regulations to include 

operational modifications leading to the 

production of additional renewable fuel 

is therefore comparable to the approach 

adopted by Congress in the PSD 

program with respect to modifications 

that may lead to increased emissions. 

The approach EPA adopted in the 

final RFS2 rule, and which we reaffirm 

today, reasonably promotes the goals of 

this statutory provision. EPA’s analysis 

as part of the RFS2 rulemaking showed 

that the aggregate volumes of 

grandfathered ethanol for the entire 

industry would be approximately 15 

billion gallons (74 FR 24904, 24925, 

May 26, 2009). Given the volume 

mandates and GHG reduction 

thresholds for the other three categories 

of renewable fuel (advanced biofuel, 

biomass-based diesel, and cellulosic 

biofuel), 15 billion gallons is (by 

coincidence) approximately the 

maximum amount of grandfathered 

ethanol that could be used in the RFS2 

program for compliance purposes.3 In 

addition, EISA provides a considerable 

benefit to facilities claiming exemption 

from the 20 percent GHG reduction 

threshold. Such an exemption is not 


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Federal Register / Vol. 75, No. 244 / Tuesday, December 21, 2010 / Rules and Regulations 79969 

provided to similar facilities for which 

construction commences after the 

statutory deadlines. The exemption 

reasonably preserves the investment 

decisions of owners made prior to the 

time of enactment of EISA. Those 

investment decisions were clearly based 

on the practices of the facilities 

constructed on or before the statutory 

deadlines, including any permit-related 

constraints in existence at the time. Any 

future increases in production based on 

future permit changes could generally 

be an enhancement to the value of the 

facility and would be based on future 

decisions, not investment decisions 

made prior to enactment of EISA. 

We acknowledge the statement we 

made in the proposal for the RFS2 

regulations, referenced by one of the 

commenters, that ‘‘our guiding 

philosophy of protecting historical 

business investments that were made to 

comply with the provisions of RFS1 are 

realized by allowing production 

increases within a facility’s inherent 

capacity,’’ (74 FR 24904, 24926, May 26, 

2009). We need to point out, however, 

that the statement was made in the 

context of soliciting comment on 

allowing a 10 percent tolerance level 

above ‘‘permitted capacity’’ and, as 

noted above, we proposed that 

‘‘permitted capacity’’ would be 

ascertained at the time of facility 

registration. The 10 percent allowance 

was, therefore, proposed for comment as 

a straightforward and readilyimplementable mechanism to reflect in 

grandfathered volumes as much of a 

plant’s ‘‘inherent capacity’’ as practical 

while avoiding case-by-case assessments 

into the future indefinitely. In the same 

paragraph in the proposal, we further 

state that ‘‘at the same time, the 

alternative of requiring compliance with 

the 20% GHG reduction requirement for 

increases in volume above 10% over the 

baseline volume, [sic] would place new 

volumes from grandfathered facilities on 

a level playing field with product from 

new grass roots facilities. We believe 

that a level playing field for new 

investments is fair and consistent with 

the provisions of EISA,’’ (74 FR 24904, 

24926, May 26, 2009). 

Based on comments received on the 

RFS2 proposed rule, we decided to 

reject the 10 percent tolerance and ‘‘to 

interpret the exemption of the baseline 

volume of renewable fuel from the 20 

percent GHG reduction requirement as 

extending indefinitely.’’ We noted that 

any tolerance provided could, therefore, 

‘‘be present in the marketplace for a 

considerable time period.’’ Furthermore, 

we also stated that ‘‘increases in volume 

of 10 percent or greater could be the 

result of modifications other than 

debottlenecking,’’ and instead adopted a 

5 percent tolerance level (75 FR 14670, 

14689, March 26, 2010). We believe that 

these statements from the preamble to 

the RFS2 final rule are consistent with 

the arguments we have set forth above. 

We disagree with the commenters’ 

statement that facilities had inadequate 

notice of the time limitations for permits 

that could be used to establish baseline 

volume that is exempt from the 20 

percent GHG reduction requirement. 

The preamble to the proposed rule 

stated that ‘‘the facility registration 

process * * * would be used to define 

the baseline volume for individual 

facilities. Owners and operators would 

submit information substantiating the 

nameplate capacity of the plant, as well 

as historical annual peak capacity if 

such is greater than nameplate 

capacity,’’ (74 FR 24904, 24926, May 26, 

2009). In the proposal, nameplate 

capacity was defined in terms of 

permitted capacity. Furthermore, in 

discussing the facility registration 

process, the preamble stated that ‘‘in 

order to determine what production 

volumes would be grandfathered and 

thus deemed to be in compliance with 

the 20% GHG threshold, we would 

require * * * information necessary to 

establish [a facility’s] renewable fuel 

baseline volume * * * ’’ (74 FR 24904, 

24942, May 26, 2009). These 

discussions made it clear that the 

baseline volume would be determined 

in the registration process, and they did 

not indicate that making such 

determinations would be an ongoing 

process into the future. Under the RFS2 

proposal, registration was to occur by 

January 1, 2010, or 60 days prior to 

commencement of production, 

whichever was later. The January 1, 

2010, proposal date for the submission 

of permits to establish baseline volume 

with registration materials is fully 

consistent with the provision in the 

final rule that permits used to establish 

‘‘permitted capacity’’ for ‘‘deemed 

compliant’’ facilities must have been 

issued no later than December 31, 2009, 

and for other grandfathered facilities by 

December 19, 2007. While the proposal 

would have allowed grandfathered 

facilities that commenced production 

after January 1, 2010, additional time to 

submit their registration materials, the 

preamble discussion did not suggest 

that this would afford them the 

opportunity to use permits issued after 

the relevant time periods referenced in 

EISA for purposes of establishing 

baseline volume. In addition, in 

describing EPA’s basic proposal, EPA 

explained that, for facilities that 

commenced construction prior to EISA 

enactment, volumes greater than 

baseline volume ‘‘which may typically 

be due to expansions of the facility 

which occur after December 19, 2007, 

would be subject to the 20% GHG 

reduction requirement in order for the 

facility to generate RINs for the 

incremental expanded volume. The 

increased volume would be considered 

as if produced from a ‘new facility’ 

which commenced construction after 

December 19, 2007.’’ EPA believes that 

these preamble statements provided 

adequate notice to the regulated 

community that EPA was considering 

limitations on the dates of permits that 

could be used to establish baseline 

volume, and also believes that 

commenters were reasonably apprised 

based on the discussion of dates in the 

preamble and the dates referenced in 

the statute that the permit cut-off dates 

ultimately selected for this purpose 

were under consideration. 

As stated previously, the definition of 

‘‘permitted capacity’’ in the direct final 

rule was revised to include the same 

permit cut-off dates referenced in the 

existing unamended registration section 

in the final RFS2 regulations. The direct 

final rule would not have established 

these cut-off dates as new requirements, 

but would merely have provided clarity 

to the existing regulations by placing 

references to permit dates in the 

definition of ‘‘permitted capacity’’ that 

are comparable to those that already 

existed in § 80.1450(b)(1)(v)(B). 

Commenters clearly had notice of these 

permit cut-off dates in commenting on 

the direct final rule, and brought their 

concerns to EPA’s attention in the 

context of this rulemaking. EPA has 

considered these comments and has 

decided not to revise the regulations in 

the manner they have proposed, but 

instead, for all of the reasons discussed 

above, to finalize in this rule the same 

definition of ‘‘permitted capacity’’ that 

was included in the direct final rule and 

parallel proposal. 

EPA is also finalizing the 

amendments included in the direct final 

rule and parallel proposal that we did 

not receive adverse comment on, but 

that were tied to the revised definition 

of ‘‘permitted capacity’’ and therefore 

were also withdrawn in the June 30, 

2010, notice (75 FR 37733). These 

related amendments move the 

definitions of ‘‘actual peak capacity,’’ 

‘‘baseline volume,’’ and ‘‘permitted 

capacity’’ from their original locations at 

§ 80.1403(a) to § 80.1401 in order to 

consolidate them with other definitions 

used in 40 CFR part 80, subpart M. They 

revise the definition of ‘‘actual peak 

capacity’’ to clarify that actual peak 

capacity for facilities that commenced 


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79970 Federal Register / Vol. 75, No. 244 / Tuesday, December 21, 2010 / Rules and Regulations 

construction prior to December 19, 

2007, but that did not have at least one 

calendar year of actual production prior 

to 2008, should be based on any 

calendar year after startup during the 

first three years of operation. They also 

clarify that for facilities that commenced 

construction after December 19, 2007, 

but before January 1, 2010, that are fired 

with natural gas, biomass, or a 

combination thereof, ‘‘actual peak 

capacity’’ is based on any calendar year 

after startup during the first three years 

of operation. These amendments, which 

are closely tied to changes to the 

definition of ‘‘permitted capacity’’ that 

we are finalizing today, are also being 

finalized as they were proposed at 75 FR 

26049 (May 10, 2010). 

B. Treatment of Renewable 

Identification Numbers 

In order to facilitate the transition 

from RFS1 to RFS2, many of the final 

RFS2 regulations clarified the 

differences between how Renewable 

Identification Numbers (RINs) are 

treated under each program. However, 

in the final RFS2 rule, the section on 

product transfer documents (PTD) 

requirements was not clear about the 

information that must be on PTDs for 

RINs under the RFS2 program, and we 

issued several amendments to § 80.1453 

in the direct final rule to clarify the PTD 

requirements under RFS2. We did not 

receive any adverse comment on these 

amendments. 

In conjunction with the amendments 

to § 80.1453, we proposed amendments 

to § 80.1425, which provides a 

description of the 38-digit RIN. The 

amendments were meant to clarify that 

RINs generated under RFS2 are not 

identified by a 38-digit code, but rather 

that most of the information contained 

within the RFS1 38-digit code is entered 

and made available in the EPA 

Moderated Transaction System (EMTS) 

as separate data elements. We also 

proposed amendments to 

§ 80.1426(d)(1), (f)(3)(iv), and (f)(3)(v) to 

clarify that either the batch (BBBBB) 

component of the RIN or its EMTSequivalent can be used to identify a 

particular batch of renewable fuel. 

We received adverse comment from 

several parties on the proposed 

amendments to § 80.1425, who took 

issue with the elimination in EMTS of 

the SSSSSSSS and EEEEEEE 

components (start and end numbers) of 

the RFS1 38-digit RIN. The commenters 

expressed concern that the 38-digit code 

was being abandoned and claimed this 

proposed change would impact a 

regulated party’s right and ability to 

maintain an independent accounting of 

their RINs at a unit (gallon-RIN) level. 

They also claimed that without this 

information, attempts to manage RIN 

transactions would be problematic for 

the regulated community. Furthermore, 

the commenters stated that they saw no 

steps taken in the rulemaking process 

that would have notified industry of 

EPA’s intent to move away from the 38- 

digit RIN. 

In the preamble to the RFS2 NPRM, 

we outlined the concept for EMTS and 

described the circumstances 

experienced under the RFS1 program 

that led us to conclude that such a 

system would be necessary and 

preferable to the RFS1 approach to RIN 

generation and transaction. We stated 

that ‘‘in implementing RFS1, we found 

that the 38-digit standardized RINs have 

proven confusing to many parties in the 

distribution chain. Parties have made 

various errors in generating and using 

RINs. * * * We have also seen incorrect 

numbering of volume start and end 

codes,’’ (74 FR 24974). In the preamble 

to the NPRM, we also acknowledged 

that ‘‘once an error is made within a 

RIN, the error propagates throughout the 

distribution system. Correcting an error 

can require significant time and 

resources and involve many steps,’’ (74 

FR 24974). Finally, we noted that 

‘‘incorrect RINs are invalid RINs. If 

parties in the distribution system cannot 

track down and correct the error made 

by one of them in a timely manner, then 

all downstream parties that trade the 

invalid RIN will be in violation. Because 

RINs are the basic unit of compliance 

for the RFS1 program, it is important 

that parties have confidence when 

generating and using them,’’ (74 FR 

24974). 

We proposed and finalized EMTS in 

the RFS2 rulemaking process as the 

solution to address most, if not all, of 

these issues, and to handle the 

increasingly complex RIN generation 

and transaction requirements under 

RFS2 due to the increased volume 

mandates and four categories of 

renewable fuel. While the commenters 

are correct that EMTS does not employ 

the 38-digit RIN as it was originally 

conceived for the RFS1 program, the 

system is designed to allow users to 

transact RINs in a generic way while 

still maintaining the ability to know any 

individual RIN’s source at a company 

and facility level. We described this 

change in the preambles to both the 

proposed and final RFS2 regulations. 

(See 74 FR 24975 and 75 FR 14733.) 

Specifically, in the preamble to the final 

RFS2 regulations, we stated, ‘‘one major 

advantage of EMTS * * * is that the 

system will simplify trading by allowing 

RINs to be traded generically. Only 

some specifying information will be 

needed to trade RINs, such as RIN 

quantity, fuel type, RIN assignment, RIN 

year, RIN price or price per gallon. 

* * * The actual items of transactional 

information covered under RFS2 are 

very similar to those reported under 

RFS1,’’ (75 FR 14733). 

Indeed, all major components of the 

RIN as conceived under the RFS1 

program are used in EMTS with the 

exception of the ‘‘S’’ and ‘‘E’’ starting and 

ending RIN values. The S and E 

components of the 38-digit RIN served 

two purposes under RFS1. One was to 

determine the number of gallon-RINs 

contained in a batch-RIN segment, 

calculated by subtracting the ending 

RIN value from the starting RIN value. 

The second use was to ensure that the 

number of gallon-RINs represented by a 

batch-RIN did not grow or decrease as 

it was passed from buyer to seller, in 

many cases multiple times. As noted 

above, under RFS1, an overlap or 

duplication of S and E codes between 

transactions was an indication that 

something had gone wrong during the 

exchange of RIN information. 

Under RFS2, EMTS performs 

transactions of individual RINs (the 

RFS1 equivalent of gallon-RINs) with a 

simple reference to RIN quantity, and 

the system does not use S and E 

components. Being a closed system, 

there is no opportunity for a RIN owner 

to purposefully or accidentally increase 

or decrease the number of RINs 

originally associated with a batch of 

renewable fuel. The original RIN 

quantity may be subdivided into smaller 

parts as the RINs and renewable fuel are 

transferred from one party to another, 

but EMTS accounts for the original total 

number of RINs at all times. This feature 

allows EMTS to manage RIN quantities 

without the need for S and E 

components. 

We believe that the comment we 

received suggesting that a regulated 

party’s right and ability to maintain an 

independent accounting of their RINs at 

a unit level would be negatively affected 

by eliminating the use of the 38-digit 

RIN is unfounded. In the preambles to 

both the proposed and final RFS2 rules, 

we discussed the fact that, like under 

the RFS1 program, there is no ‘‘good 

faith’’ provision with respect to RIN 

ownership. To help companies manage 

their RINs in such a ‘‘buyer beware’’ 

environment, we proposed and finalized 

that a RIN purchaser can accept or reject 

RINs from specific RIN generators or 

from classes of RIN generators (74 FR 

24975, 75 FR 14733). In practice, this 

allowance has translated into a function 

within EMTS that allows a RIN account 

holder to block RINs generated by 

specific companies and/or facilities. 


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Federal Register / Vol. 75, No. 244 / Tuesday, December 21, 2010 / Rules and Regulations 79971 

4A base plant is one representing average energy 

usage and no advanced technologies. See the 

Regulatory Impact Analysis for the RFS2 final rule, 

EPA–420–R–10–006, February 2010, Section 

1.5.1.3. 

EMTS now also allows a RIN transferee 

to review details of RINs offered by a 

transferor, such as the RIN generators’ 

company and facility ID numbers, prior 

to accepting or rejecting the transaction. 

In this way, a RIN account holder can 

protect himself or herself from being 

transferred RINs generated by a 

company with whom the RIN account 

holder chooses not to do business, even 

if indirectly. There is also a function 

within EMTS that allows a RIN account 

holder to transact unique, as opposed to 

generic, RINs. Unique RINs carry 

specific information related to the RIN 

generator, date of production, and batch 

number. As discussed above, EMTS is a 

closed system, and the total number of 

RINs associated with a particular batch 

of renewable fuel cannot increase or 

decrease even as the RINs are 

subdivided and transferred to multiple 

RIN owners. This fundamental 

characteristic of EMTS, together with 

the added features of being able to block 

certain RINs and trade unique ones, 

enhances the ability of any RIN account 

holder to protect their interests. 

As for the commenters’ concerns that 

they were not notified of EPA’s intent to 

move away from the 38-digit RIN during 

the RFS2 rulemaking process, EPA 

disagrees. As discussed above, EPA 

introduced the concept and basic 

functionality of EMTS in the preamble 

to the RFS2 NPRM (74 FR 24904) and 

development of the new system 

commenced shortly thereafter. The 

process of development and testing was 

conducted openly and with significant 

stakeholder input and participation, 

including direct involvement by at least 

one of the commenters. A number of 

workshops, webinars and discussions 

were held throughout the period 

between publication of the NPRM and 

issuance of the final RFS2 regulations. 

In addition, presentation materials, 

users’ guides, data schema, data 

templates, and tutorials were offered for 

interested parties to understand and 

provide input on system design and 

development. Based on this input, EPA 

was able to successfully deploy EMTS 

on July 1, 2010, concurrent with the 

RFS2 regulations taking effect. 

We believe that the transition from 

the 38-digit RIN under RFS1 to the 

generic RIN under RFS2 allows for 

greater system flexibility and integrity, 

while maintaining the detailed RIN 

information necessary for regulated 

parties to perform independent checks 

on RINs they generate, receive, and 

transfer. In addition, we believe that the 

information presented throughout the 

rulemaking process for RFS2 adequately 

and transparently prepared regulated 

parties for the transition to EMTS. For 

these reasons, we are finalizing the 

amendment to the introductory text to 

§ 80.1425 as it was set forth in the May 

10, 2010, direct final rule and parallel 

proposal (75 FR 26026, 75 FR 26049). 

Specifically, we are amending the text 

to clarify that RINs generated after July 

1, 2010, may only be generated and 

transferred using EMTS and will not be 

identified by a 38-digit code. We are 

also amending § 80.1425(i) to simply 

clarify that the value of EEEEEEEE is a 

number representing the last gallon-RIN 

associated with a volume of renewable 

fuel. 

In addition to the proposed 

amendments to § 80.1425, we also 

proposed amendments to 

§ 80.1426(d)(1), (f)(3)(iv), and (f)(3)(v) to 

clarify that either the batch (BBBBB) 

component in the RIN or its EMTSequivalent would be used to identify a 

particular batch of renewable fuel. A 

commenter stated that the phrase ‘‘or its 

equivalent in EMTS’’ when referring to 

batch-identifying information in EMTS 

is not clearly defined, and they 

expressed concern that this language 

would limit regulated companies from 

properly certifying their data and would 

inhibit the ability of accountants to 

attest to their clients’ data. The 

commenter also requested that the 

language be clarified so that regulated 

parties can certify their data and 

accountants can reasonably rely on it. 

Under RFS1, the BBBBB code was a 

unique user-specified value that could 

only contain numbers and had to 

contain five digits. The requirement to 

assign a ‘‘unique’’ batch number allowed 

the regulated community and EPA to 

determine which RINs were associated 

with each volume of renewable fuel, 

and it prevented double-counting by 

requiring renewable fuel producers or 

importers to generate one, and only one, 

RIN for each volume of renewable fuel. 

Because it could represent up to one 

calendar month’s worth of renewable 

fuel production (or importation) and up 

to 99,999,999 gallons, RIN generators 

frequently generated 12 batches in a 

calendar year, one for each month. In 

EMTS, the batch number is a unique 

user-specified value that can contain up 

to 20 alphanumeric or other characters. 

It is a field required for RIN generation 

and a RIN owner may view the batch 

number associated with any RIN in their 

possession. We believe that the larger 

field format and ability to use letters as 

well as other characters to identify a 

batch in EMTS enhances a regulated 

party’s ability to certify their RIN data— 

either as RIN generators or as RIN 

owners—and, in turn, allows a party’s 

CPA to attest to the validity of such 

data. At the same time, we agree with 

the comment that the proposed language 

was vague and does not adequately 

describe what the EMTS-equivalent of 

the BBBBB code is. We are therefore not 

finalizing the amendments to these 

sections and will revert to the language 

in the final RFS2 regulations that simply 

refer to a ‘‘unique batch identifier,’’ 

which may be either the five-digit 

BBBBB component or the EMTS batch 

number of up to 20 characters. 

C. Advanced Technologies for 

Renewable Fuel Pathways 

The final RFS2 rule includes two corn 

ethanol pathways in Table 1 to 

§ 80.1426 that require the use of one or 

two advanced technologies at the 

production facility as a prerequisite to 

the generation of RINs. The five 

advanced technologies available for this 

purpose are listed in Table 2 to 

§ 80.1426. In developing this list of 

advanced technologies, EPA relied upon 

modeling that included the use of one 

or more advanced technologies at a base 

corn-ethanol plant.4. In all cases, the 

modeling assumed use of a given 

advanced technology across 100 percent 

of the ethanol production. The 

pathways in Table 1 and the list of 

advanced technologies in Table 2 

represent the application of advanced 

technologies to 100 percent of 

production, consistent with the 

modeling they were based on. 

However, neither the list in Table 2 

nor the pathway descriptions in Table 1 

were explicit on this percent of usage. 

As a result, some producers of corn 

ethanol assumed that any degree of 

implementation of advanced 

technologies, even to the point of de 

minimis GHG benefit, would be 

acceptable and consistent with the letter 

of the regulations. In the direct final rule 

and parallel proposal published on May 

10, 2010 (75 FR 26026, 75 FR 26049), 

we announced a revision to Table 2 to 

§ 80.1426 to clarify the degree to which 

advanced technologies must be 

implemented in order to represent a 

valid advanced technology for the 

generation of RINs. The announced 

revision specified that the advanced 

technologies must be applied to all 

production at the corn ethanol facility. 

In response to the direct final rule, we 

received adverse comments from several 

stakeholders objecting to the changes to 

Table 2 to § 80.1426. As a result, we 

withdrew the changes to Table 2 to 

§ 80.1426 in a Federal Register notice 


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5 75 FR 59622, September 28, 2010. 

published on June 30, 2010 (75 FR 

37733). 

There were several alternative 

approaches to advanced technologies 

that were suggested by commenters, 

including the creation of additional 

pathways to add to Table 1 to § 80.1426. 

EPA notes at the outset that the scope 

of this rulemaking effort as it relates to 

Tables 1 and 2 to § 80.1426 is to clarify 

the regulatory language that identifies 

the pathways and specifications for 

advanced technologies that were 

modeled as part of the RFS2 rulemaking 

effort and that were determined to lead 

to an appropriate level of GHG 

reduction. EPA continues to evaluate 

additional pathways on its own 

initiative, and may approve the use of 

additional pathways, as it recently did 

for canola oil biodiesel.5 EPA has also 

established a petition process in 

§ 80.1416 to allow parties seeking the 

addition of new pathways to Table 1 to 

§ 80.1426 to bring those pathways to 

EPA’s attention for evaluation. EPA 

urges parties seeking EPA consideration 

of new pathways to utilize that process. 

While EPA will fully evaluate any 

petitions for new pathways when and if 

they are submitted to EPA pursuant to 

§ 80.1416, EPA also provides in this 

preamble some preliminary thoughts 

regarding some of the commenters’ 

suggestions for new pathways, even 

though they are beyond the scope of this 

rulemaking effort. 

One commenter suggested that EPA 

incorporate into Table 2 an energybased metric for identifying the extent 

to which each advanced technology 

must be used at corn ethanol facilities 

in order to be deemed to achieve a 20 

percent GHG reduction. The commenter 

suggested that this approach could be 

accomplished by basing the metric on 

the pathway in Table 1 to § 80.1426 that 

specifies no greater that 50 percent 

drying of distillers grains and solubles 

(DGS) and no advanced technologies. 

The premise of the comment is that any 

combination of advanced technologies 

that reduces energy usage by a specified 

amount will achieve the 20 percent 

GHG threshold. EPA rejects this 

approach as an oversimplification that 

is not currently consistent with the 

modeling used by EPA in developing 

the list of pathways and advanced 

technologies in Tables 1 and 2 to 

§ 80.1426. First, EPA’s modeling 

assumed an industry average for the 

various advanced technologies, and not 

any specific brand or type of 

technology. As such, the results cannot 

be translated into the specific 

equipment used and operated at a single 

plant. The precision of the modeling 

does not support an extrapolation down 

to specific technology at a specific 

plant, which would be required under 

the commenter’s approach. 

Second, EPA modeled various 

scenarios, including a base plant with 

100 percent drying of DGS, a base plant 

with 100 percent wet DGS, and various 

combinations of advanced technologies. 

In some cases use of just one specific 

technology such as CHP or corn oil 

fractionation was modeled. In other 

cases a base plant was modeled while 

progressively adding different advanced 

technologies. EPA’s modeling by 

necessity did not cover the universe of 

all possible combinations of advanced 

technologies, and as such does not 

allow for a precise quantification of 

each advanced technology either by 

itself or in combination with a second 

advanced technology. The modeling 

does provide clear indication that (1) 

There can be interactive effects between 

pairs of advanced technologies, (2) 

advanced technologies can have 

complex impacts, and the reductions in 

GHG emissions are not all based on just 

a simple linear reduction in energy use, 

and (3) different combinations of 

advanced technologies are likely to lead 

to a range of results across the various 

combinations. EPA’s conclusion in the 

final RFS2 rulemaking was that the GHG 

benefits of the use of advanced 

technologies as specified in Tables 1 

and 2 to § 80.1426 would in all cases 

allow at least a limited degree of GHG 

reduction beyond the 20 percent 

threshold, with the exact degree of 

reduction dependent on the specific 

combination of advanced technologies 

and drying of DGS. As a result, the 

modeling performed by EPA to date 

does not support specifying a simple 

formula that could allow usage of 

advanced technologies as a function of 

measured reductions in energy usage. 

Thus EPA believes there is not a 

technical basis at this time for the 

approach suggested by the commenter. 

We also received a suggestion that the 

table of advanced technologies be 

modified to include the option of 

‘‘energy efficient plant design’’ that 

could be achieved through documented 

low energy use. In this approach, EPA 

would establish a level of energy input 

per gallon of product that would reflect 

achievement of the 20 percent GHG 

reduction threshold, and industry 

would be free to use any method to 

achieve that required energy utilization 

standard. Records of fuel and electricity 

use in the facility would be submitted 

to demonstrate attainment of the 

standard. This suggestion is clearly 

beyond the scope of this rulemaking 

effort, which is limited to clarifying the 

regulatory language related to the 

modeling and analyses that EPA 

conducted as part of the RFS2 

rulemaking. Although the commenter 

suggested that the energy utilization 

standard could be set using existing 

modeling tied to an existing pathway in 

Table 1 to § 80.1426, EPA believes that 

this would not be technically justified 

for the same reasons, described above, 

that it would not be appropriate to use 

this metric to establish specifications 

regarding use of advanced technologies. 

Thus, the suggested approach would 

likely require new analyses to identify 

an appropriate energy utilization 

standard that would take into account 

all possible direct and indirect effects 

associated with multiple possible 

permutations of facility technology and 

practice. It could also require additional 

recordkeeping and reporting 

requirements as well as new formulas or 

tabulated values in the regulations for 

converting energy use into GHG 

reductions. All such changes would 

entail dramatically different approaches 

to the identification of pathways that 

achieve the necessary amount of GHG 

reduction to qualify under the Act than 

were finalized in the RFS2 rulemaking. 

Therefore, we did not propose and are 

not adopting the commenter’s suggested 

approach in today’s rulemaking. Parties 

advocating this approach are 

encouraged to utilize the petition 

process in § 80.1416 to request that EPA 

further evaluate this concept and, in the 

context of their petition, to address the 

concerns that EPA noted above. 

A number of commenters suggested 

that application of advanced 

technologies to 100 percent of the 

production at a corn ethanol plant was 

not feasible. One commenter pointed 

out that common and legitimate 

downtime for an advanced technology, 

even if it is of a very short duration, 

could preclude a corn ethanol producer 

from generating any RINs if Table 2 to 

§ 80.1426 requires application of an 

advanced technology to all production 

at a facility. Another commenter 

suggested that advanced technologies be 

required to be applied to 90 percent of 

the production at a corn ethanol facility, 

instead of 100 percent. In response, we 

do recognize that there may be 

occasions in which an advanced 

technology must be halted or bypassed 

for a short time for maintenance, repair, 

or other reasons. To determine whether 

the regulations could be modified to 

address this concern, we reviewed the 

original lifecycle GHG modeling for 

corn ethanol plants that was done for 

the RFS2 final rule. The modeling 


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indicates that use of the advanced 

technologies as specified should in all 

cases provide a minimum margin of 

compliance beyond the 20 percent GHG 

reduction threshold, and in some cases 

a larger margin. Thus a small reduction 

in the application of advanced 

technologies should still ensure that the 

20 percent GHG threshold is met. EPA 

recognizes that this is a question of 

degree and is basing this on expert 

judgment and not specific new 

modeling. As such, no more than a 

small reduction in percent usage is 

warranted absent further modeling. As a 

result, we have modified the regulatory 

requirements so that advanced 

technologies must be applied to at least 

90 percent of the production at a corn 

ethanol facility. Moreover, we are 

requiring that compliance with this 90 

percent criterion be made over the 

course of a calendar year, consistent 

with the approach to the maximum 

allowable fraction of DGS that can be 

dried under certain corn ethanol 

pathways in Table 1 to § 80.1426. This 

approach relies on judgment based on 

the lifecycle modeling that was 

previously performed, as described 

above, to provide some flexibility for 

downtime of an advanced technology 

while still requiring the requisite level 

of GHG reduction. 

Since compliance with the advanced 

technologies in Table 2 to § 80.1426 is 

determined on an annual basis, any 

RINs that are generated based upon the 

use of one or more of these technologies 

could be considered invalid if the 

technologies are not employed in 

accordance with the specifications in 

Table 2, including any requirement 

based upon use of these technologies for 

90 percent of production on a calendar 

year basis. We note, however, that in 

determining an appropriate remedy for 

a violation arising from a renewable fuel 

producer’s failure to properly employ 

advanced technologies in accordance 

with the specifications in Table 2 to 

§ 80.1426, EPA may consider a number 

of factors, including the volume of fuel 

for which RINs were generated that was 

produced without the advanced 

technologies, the reasons that the 

advanced technologies were not 

employed, and efforts taken by the 

renewable fuel producer to remedy the 

harm caused by the violation. 

Another suggested change would have 

allowed GHG reductions for ethanol 

volume that is grandfathered under 

§ 80.1403 to be used as a credit for 

ethanol volume that has not been 

grandfathered. Such an approach could 

mean that all the GHG reductions 

associated with applying a given 

advanced technology to an entire corn 

ethanol plant could be deemed to apply 

to only the volume that is in excess of 

the plant’s grandfathered baseline 

volume. We do not believe that this 

would be appropriate. Not only did we 

not propose such an approach to 

compliance with the 20 percent GHG 

reduction threshold, but it would 

amount to transferring GHG reductions 

from grandfathered volume to nongrandfathered volume. In so doing, a 

corn ethanol producer could claim that 

its non-grandfathered ethanol met the 

20 percent GHG reduction threshold 

even if the plant as a whole did not and 

there was no discernable difference in 

plant operations between the 

grandfathered and non-grandfathered 

volume. The regulations do not allow 

GHG reduction credits to be assumed for 

grandfathered volume and then used to 

offset the GHG emissions from the nongrandfathered portion of the facility’s 

production. Non-grandfathered 

production must be assessed separately. 

Some commenters raised a concern 

that the proposed language requiring 

application of advanced technologies to 

‘‘all’’ production at a facility necessarily 

required that the advanced technologies 

be applied to volumes that are 

grandfathered and are not subject to the 

20 percent GHG reduction threshold for 

renewable fuel. This was not our 

intention. Advanced technologies are 

not required for volumes that are 

grandfathered according to § 80.1403. 

Thus, we have modified the regulations 

to clarify that Tables 1 and 2 to 

§ 80.1426 do not apply to volumes of 

fuel for which RINs are generated 

pursuant to § 80.1426(f)(6). 

With regard to corn oil extraction, we 

believe that the description in Table 2 

to § 80.1426 requires additional 

modification to more accurately reflect 

the lifecycle modeling that was 

conducted. For instance, some 

commenters pointed out that the terms 

‘‘thin stillage’’ and ‘‘distillers grains and 

solubles’’ do not accurately describe the 

byproduct categories to which corn oil 

extraction can be applied. More 

appropriate might be thin stillage and 

wet cake, or alternatively just the whole 

stillage which precedes the derivatives 

thin stillage and wet cake. Our lifecycle 

modeling assumed that corn oil 

extraction was applied to all the 

byproducts that are included in whole 

stillage. However, after further 

consideration, we believe that a more 

straightforward approach to specifying 

the required application of corn oil 

extraction in the regulations would be to 

identify the amount of oil that must be 

extracted rather than the amount of 

whole stillage to which the technology 

must be applied. This approach is 

consistent with a suggestion from one 

commenter and will result in the same 

GHG reductions as our proposed 

approach. This approach will also allow 

corn-ethanol producers utilizing the 

corn oil extraction advanced technology 

to apply it to particular byproducts as 

they see fit, providing only that the 

requisite quantity of oil is extracted. 

The lifecycle modeling that led us to 

include corn oil fractionation in Table 2 

to § 80.1426 assumed an oil extraction 

rate of 1.48 pounds of oil per bushel of 

corn. As described above, we have 

determined that a 10 percent reduction 

in the application of this advanced 

technology can be accommodated while 

still ensuring that the 20 percent GHG 

threshold has been met. An oil 

extraction rate of 1.33 pounds per 

bushel represents 90 percent of the 

value we assumed in developing Table 

2 to § 80.1426. Thus, in today’s rule we 

are modifying the description of corn oil 

extraction to require a minimum of 1.33 

pounds of oil to be extracted from whole 

stillage or its derivatives per bushel of 

corn that is processed into ethanol. This 

oil extraction rate is substantially less 

than the total amount of oils contained 

in byproducts from corn ethanol 

processing. As a result, we believe this 

approach will address concerns from 

some commenters that the proposed 

language would have required all oil to 

be removed from distillers grains, 

potentially creating an unmarketable 

product. Although one commenter 

suggested a corn oil extraction rate of 

1.0 pound per bushel, we do not believe 

that this level of implementation of this 

advanced technology would ensure that 

the 20 percent GHG reduction threshold 

has been met. 

With regard to combined heat and 

power (CHP), one commenter expressed 

concern that the application of CHP to 

all of the production at a corn ethanol 

facility could require the installation of 

new boilers sized to produce electricity. 

The commenter argued that such actions 

were unnecessary and would make CHP 

commercially unviable. However, the 

identification of advanced technologies 

in Table 2 to § 80.1426 and the 

calculation of their required usage rate 

is designed to ensure that the 20 percent 

GHG reduction threshold can be met. 

The costs of implementation of CHP 

were not considered in determining the 

technical issue of the GHG reduction 

threshold determination. However, we 

have reviewed the modeling conducted 

as part of the RFS2 rulemaking and have 

determined that application of CHP to 

90 percent of production at a corn 

ethanol facility will achieve a 20 

percent GHG reduction, and we have 


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modified Table 2 to § 80.1426 

accordingly. 

In conjunction with the modifications 

to Table 2 to § 80.1426 as described 

above, we are finalizing additional 

recordkeeping and attest engagement 

requirements to help ensure that RINs 

are properly generated for corn ethanol 

produced at facilities that employ 

advanced technologies listed in Table 2 

to § 80.1426. Specifically, we are 

finalizing a requirement at 

§ 80.1454(b)(3)(xi) that, for RINs 

generated for ethanol produced from 

corn starch at a facility using advanced 

technologies in accordance with the 

requirements in Tables 1 and 2 to 

§ 80.1426, producers must maintain 

documentation to demonstrate that 

advanced technologies used to qualify 

such ethanol for RIN generation were 

employed at least 90 percent of the time 

on a calendar year basis. In addition, we 

are finalizing an amendment to the 

attest engagement procedures for 

renewable fuel producers at 

§ 80.1464(b)(1)(iii) that, for RINs 

generated for ethanol produced from 

corn starch at a facility that used 

advanced technologies in accordance 

with the requirements in Tables 1 and 

2 to § 80.1426, will require verification 

that the advanced technologies used to 

qualify such ethanol for RIN generation 

were employed at least 90 percent of the 

time on a calendar year basis. We 

believe that these requirements are 

natural outgrowths of the final changes 

being made to Table 2 to § 80.1426 in 

response to comments received on our 

proposed amendments to this section, 

and that these additional recordkeeping 

and attestation requirements are 

necessary to ensure compliance with 

and enforceability of this aspect of the 

RFS program. 

D. Use of Biogas from a Dedicated 

Pipeline at Renewable Fuel Production 

Facilities 

EPA proposed to amend 40 CFR 

80.1426(f)(12) to clarify the 

requirements that must be met in order 

for gas used for process heat at a 

renewable fuel production facility to be 

considered biogas for purposes of the 

‘‘production process requirements’’ 

column of Table 1 to § 80.1426. In order 

to differentiate the requirements 

associated with biogas transported via a 

dedicated pipeline versus those 

associated with biogas transported via a 

common carrier pipeline, we proposed 

to subdivide the requirements under 

§ 80.1426(f)(12). Thus revisions to 

§ 80.1426(f)(12)(i) were proposed to 

describe the requirements for biogas 

transported via a dedicated pipeline, 

and revisions to § 80.1426(f)(12)(ii) were 

proposed to describe the requirements 

for biogas transported via a common 

carrier pipeline. In drafting the 

proposed revised regulations applicable 

to biogas in a dedicated pipeline in 

§ 80.1426(f)(12)(i), we mistakenly 

included language in paragraph 

§ 80.1426(f)(12)(i)(D) that referred to 

biogas placed in a common carrier 

pipeline, and proposed requiring that 

such pipeline ultimately serve the 

renewable fuel producer’s facility. A 

commenter rightfully expressed 

confusion over the proposed 

amendment at § 80.1426(f)(12)(i), since 

§ 80.1426(f)(12)(ii) is the appropriate 

section for references to biogas in a 

common carrier pipeline. We received 

no other comments on our proposed 

changes to § 80.1426(f)(12). 

EPA agrees that the amendment at 

§ 80.1426(f)(12)(i)(D) was proposed in 

error and therefore is finalizing all 

proposed amendments to 

§ 80.1426(f)(12), with the exception of 

§ 80.1426(f)(12)(i)(D). We considered 

retaining the provision by deleting the 

words ‘‘common carrier’’ that modify the 

reference to ‘‘pipeline.’’ However, 

§ 80.1426(f)(12)(i) already specifies that 

the biogas discussed in this section is 

‘‘directly transported to the facility.’’ 

Therefore, a modified 

§ 80.1426(f)(12)(i)(D) is not necessary, 

and we have simply deleted the 

provision. We also noted a 

typographical error and some 

potentially confusing text in 

§ 80.1426(f)(12)(ii)(C) and have taken 

this opportunity to make the 

appropriate corrections. 

E. Time Limits for Reporting 

Transactions in EMTS 

The final RFS2 regulations require 

any RIN generator to submit, via their 

account in the EPA Moderated 

Transaction System (EMTS), 

information about any batch of 

renewable fuel and the RINs generated 

for it within five days of the production 

or importation of the batch (see 

§ 80.1452(b) at 75 FR 14887). Likewise, 

the final RFS2 regulations also require 

any party that engages in RIN 

transactions to submit, via their EMTS 

account, information about the 

transaction within five business days 

(see § 80.1452(c) at 75 FR 14887). These 

transactional time limits were finalized 

in order to strike a balance between the 

need for EMTS to be a ‘‘real time’’ 

system and the need for some amount 

of flexibility to accommodate existing 

business practices related to conducting 

renewable fuel and RIN transactions. 

After the RFS2 regulations were 

finalized, EPA received numerous 

inquiries from regulated parties about 

whether the five day limit applied to 

both the transactional buyer and seller 

together, or whether each seller and 

each buyer had five days to perform 

their respective actions in EMTS. We 

therefore proposed to amend 

§ 80.1452(b) and (c) to clarify our 

original intent with respect to when RIN 

information needed to be submitted to 

EMTS. Specifically, we proposed to 

revise § 80.1452(b) to clarify that RIN 

information must be entered into EMTS 

within five business days of RINs being 

assigned to a batch of renewable fuel 

and to clarify the information required 

to be submitted via EMTS for each such 

batch. We also proposed to revise 

§ 80.1452(c) to clarify that transactions 

involving RINs generated on or after 

July 1, 2010, must be conducted via 

EMTS within five business days of a 

reportable event, to clarify the meaning 

of the term ‘‘reportable event,’’ and to 

clarify the information required to be 

submitted via EMTS for each 

transaction involving RINs generated on 

or after July 1, 2010. 

We received one adverse comment on 

the proposed amendatory language to 

§ 80.1452(b) and (c) that expressed 

concern over a buyer’s inability to check 

the accuracy and validity of RINs that 

may be received via a renewable fuel 

product transfer document (PTD) and an 

inability to prevent RINs with errors 

from being traded further. As discussed 

above, in addition to the adverse 

comment, we received feedback from 

regulated parties prior to the publication 

of the direct final and parallel proposed 

rules on May 10, 2010 (75 FR 26026, 75 

FR 26049), that the five business day 

requirement for both parties may be 

acceptable on the seller’s side of the 

transaction, but that it can prove 

difficult for a buyer to confirm or send 

transactional information within five 

days of the PTD date. This difficulty 

may be due to the fact that the PTD may 

be generated and sent when the fuel is 

shipped, and the shipping may take 

longer than a week, or because all RINs 

may be aggregated on one PTD that is 

sent weekly or monthly along with 

renewable fuel. 

Based on the comment received as 

part of this rulemaking and the 

additional feedback received prior to 

this rulemaking, we are finalizing an 

amendment to § 80.1452(c) that will 

increase the number of days a buyer has 

to submit transactional information to 

EMTS. Specifically, a buyer will have 

ten business days from the date on the 

PTD to submit information about a 

transaction, including accepting a 

transaction initiated by a seller, in 

EMTS. The seller will still be required 

to submit information within five 


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business days of the date on the PTD. 

Thus the buyer will have a minimum of 

five days, and a maximum of up to ten 

days if the seller acts on the same date 

as the date on the PTD, to enter the 

required information into EMTS. 

Although the comment makes 

reference both to 80.1452(b) and (c), we 

believe that the amendatory language to 

§ 80.1452(c) alleviates the problem cited 

by the commenter and therefore we are 

finalizing the amendment to 80.1452(b), 

to allow up to five business days after 

RIN assignment for a RIN generator to 

submit RIN information for a batch of 

renewable fuel to EMTS, as proposed at 

75 FR 26049 (May 10, 2010). We also 

noted inconsistency and some 

potentially confusing text at 

§ 80.1452(b)(1), (b)(2), (b)(4), and (b)(5) 

and have taken this opportunity to make 

the appropriate corrections. 

III. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order 12866, (58 FR 

51735, October 4, 1993) the Agency 

must determine whether the regulatory 

action is ‘‘significant’’ and therefore 

subject to OMB review and the 

requirements of the Executive Order. 

The Order defines ‘‘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 or 

adversely affect in a material way the 

economy, a sector of the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

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 entitlements, grants, user fees, 

or loan programs or 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. 

It has been determined that this action 

is not a ‘‘significant regulatory action’’ 

under the terms of Executive Order 

12866 and is therefore not subject to 

OMB review. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. The 

corrections, clarifications, and 

modifications to the final RFS2 

regulations contained in this rule are 

within the scope of the information 

collection requirements submitted to the 

Office of Management and Budget 

(OMB) for the final RFS2 regulations. 

OMB has previously approved the 

information collection requirements 

contained in the existing regulations at 

40 CFR part 80, subpart M under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. and has 

assigned OMB control number 2060– 

0640. The OMB control numbers for 

EPA’s regulations in 40 CFR are listed 

in 40 CFR part 9. 

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 today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (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 which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this final rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

This final rule will note impose any 

requirements on small entities that were 

not already considered under the final 

RFS2 regulations, as it makes relatively 

minor corrections and modifications to 

those regulations. 

D. Unfunded Mandates Reform Act 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and tribal governments, in the aggregate, 

or the private sector in any one year. We 

have determined that this action will 

not result in expenditures of $100 

million or more for the above parties 

and thus, this rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. It 

only applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers and makes 

relatively minor corrections and 

modifications to the RFS2 regulations. 

E. Executive Order 13132 (Federalism) 

This action 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. This action only 

applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers and makes 

relatively minor corrections and 

modifications to the RFS2 regulations. 

Thus, Executive Order 13132 does not 

apply to this action. 

F. Executive Order 13175 (Consultation 

and Coordination With Indian Tribal 

Governments) 

This final rule does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers. This action 

makes relatively minor corrections and 

modifications to the RFS regulations, 

and does not impose any enforceable 

duties on communities of Indian tribal 

governments. Thus, Executive Order 

13175 does not apply to this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it does not establish 

an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not subject to Executive 

Order 13211 (66 FR 18355, May 22, 

2001), because it is not a significant 

regulatory action under Executive Order 

12866. 


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I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory 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, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 

This action does not involve technical 

standards. Therefore, EPA did not 

consider the use of any voluntary 

consensus standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations. 

Executive Order (EO) 12898 (59 FR 

7629, February 16, 1994) establishes 

federal executive policy on 

environmental justice. Its main 

provision directs federal agencies, to the 

greatest extent practicable and 

permitted by law, to make 

environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this final 

rule will not have disproportionately 

high and adverse human health or 

environmental effects on minority or 

low-income populations because it does 

not affect the level of protection 

provided to human health or the 

environment. These technical 

amendments do not relax the control 

measures on sources regulated by the 

RFS regulations and therefore will not 

cause emissions increases from these 

sources. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this rule and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

This action is not a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). 

L. Clean Air Act Section 307(d) 

This rule is subject to Section 307(d) 

of the CAA. Section 307(d)(7)(B) 

provides that ‘‘[o]nly an objection to a 

rule or procedure which was raised with 

reasonable specificity during the period 

for public comment (including any 

public hearing) may be raised during 

judicial review.’’ This section also 

provides a mechanism for the EPA to 

convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to the EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration to 

the EPA should submit a Petition for 

Reconsideration to the Office of the 

Administrator, U.S. EPA, Room 3000, 

Ariel Rios Building, 1200 Pennsylvania 

Ave., NW., Washington, DC 20460, with 

a copy to both the person(s) listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Director of the 

Air and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

U.S. EPA, 1200 Pennsylvania Ave., 

NW., Washington, DC 20460. 

List of Subjects in 40 CFR Part 80 

Environmental protection, Fuel 

additives, Gasoline, Imports, Motor 

vehicle pollution, Reporting and 

recordkeeping requirements. 

Dated: December 14, 2010. 

Lisa P. Jackson, 

Administrator. 

■ For the reasons set forth in the 

preamble, 40 CFR part 80 is amended as 

follows: 

PART 80—REGULATION OF FUELS 

AND FUEL ADDITIVES 

■ 1. The authority citation for part 80 

continues to read as follows: 

Authority: 42 U.S.C. 7414, 7542, 7545, and 

7601(a). 

■ 2. Section 80.1401 is amended by 

adding definitions of ‘‘Actual peak 

capacity’’, ‘‘Baseline volume’’, and 

‘‘Permitted capacity’’, in alphabetical 

order to read as follows: 

§ 80.1401 Definitions. 

* * * * * 

Actual peak capacity means 105% of 

the maximum annual volume of 

renewable fuels produced from a 

specific renewable fuel production 

facility on a calendar year basis. 

(1) For facilities that commenced 

construction prior to December 19, 

2007, the actual peak capacity is based 

on the last five calendar years prior to 

2008, unless no such production exists, 

in which case actual peak capacity is 

based on any calendar year after startup 

during the first three years of operation. 

(2) For facilities that commenced 

construction after December 19, 2007 

and before January 1, 2010 that are fired 

with natural gas, biomass, or a 

combination thereof, the actual peak 

capacity is based on any calendar year 

after startup during the first three years 

of operation. 

(3) For all other facilities not included 

above, the actual peak capacity is based 

on the last five calendar years prior to 

the year in which the owner or operator 

registers the facility under the 

provisions of § 80.1450, unless no such 

production exists, in which case actual 

peak capacity is based on any calendar 

year after startup during the first three 

years of operation. 

* * * * * 

Baseline volume means the permitted 

capacity or, if permitted capacity cannot 

be determined, the actual peak capacity 

of a specific renewable fuel production 

facility on a calendar year basis. 

* * * * * 

Permitted capacity means 105% of 

the maximum permissible volume 

output of renewable fuel that is allowed 

under operating conditions specified in 

the most restrictive of all applicable 

preconstruction, construction and 

operating permits issued by regulatory 

authorities (including local, regional, 

state or a foreign equivalent of a state, 

and federal permits, or permits issued 

by foreign governmental agencies) that 

govern the construction and/or 

operation of the renewable fuel facility, 

based on an annual volume output on 

a calendar year basis. If the permit 

specifies maximum rated volume output 

on an hourly basis, then annual volume 

output is determined by multiplying the 

hourly output by 8,322 hours per year. 

(1) For facilities that commenced 

construction prior to December 19, 

2007, the permitted capacity is based on 


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Federal Register / Vol. 75, No. 244 / Tuesday, December 21, 2010 / Rules and Regulations 79977 

permits issued or revised no later than 

December 19, 2007. 

(2) For facilities that commenced 

construction after December 19, 2007 

and before January 1, 2010 that are fired 

with natural gas, biomass, or a 

combination thereof, the permitted 

capacity is based on permits issued or 

revised no later than December 31, 

2009. 

(3) For facilities other than those 

described in paragraphs (1) and (2) of 

this definition, permitted capacity is 

based on the most recent applicable 

permits. 

* * * * * 

■ 3. Section 80.1403 is amended by 

revising paragraph (a) to read as follows: 

§ 80.1403 Which fuels are not subject to 

the 20% GHG thresholds? 

(a) For purposes of this section, the 

following definitions apply: 

(1) Commence construction, as 

applied to facilities that produce 

renewable fuel, means that: 

(i) The owner or operator has all 

necessary preconstruction approvals or 

permits (as defined at 40 CFR 

52.21(b)(10)), and has satisfied either of 

the following: 

(A) Begun, or caused to begin, a 

continuous program of actual 

construction on-site (as defined in 40 

CFR 52.21(b)(11)). 

(B) Entered into binding agreements 

or contractual obligations, which cannot 

be cancelled or modified without 

substantial loss to the owner or 

operator, to undertake a program of 

actual construction of the facility. 

(ii) For multi-phased projects, the 

commencement of construction of one 

phase does not constitute 

commencement of construction of any 

later phase, unless each phase is 

mutually dependent for physical and 

chemical reasons only. 

(2) [Reserved] 

* * * * * 

■ 4. Section 80.1425 is amended by 

revising the introductory text and 

paragraph (i) to read as follows: 

§ 80.1425 Renewable Identification 

Numbers (RINs). 

RINs generated on or after July 1, 2010 

shall not be generated as a 38-digit code, 

but shall be identified by the 

information specified in paragraphs (a) 

through (i) of this section and 

introduced into EMTS as data elements 

during the generation of RINs pursuant 

to § 80.1452(b). For RINs generated prior 

to July 1, 2010, each RIN is a 38-digit 

code of the following form: 

KYYYYCCCCFFFFFBBBBBRRD

SSSSSSSSEEEEEEEE 

* * * * * 

(i) EEEEEEEE is a number 

representing the last gallon-RIN 

associated with a volume of renewable 

fuel. 

■ 5. Section 80.1426 is amended as 

follows: 

■ a. By revising introductory text to 

paragraph (f)(1). 

■ b. By revising Table 2 to § 80.1426. 

■ c. By revising paragraph (f)(12). 

§ 80.1426 How are RINs generated and 

assigned to batches of renewable fuel by 

renewable fuel producers or importers? 

* * * * * 

(f) * * * 

(1) Applicable pathways. D codes 

shall be used in RINs generated by 

producers or importers of renewable 

fuel according to the pathways listed in 

Table 1 to this section, subparagraph 6 

of this section, or as approved by the 

Administrator. In choosing an 

appropriate D code, producers and 

importers may disregard any incidental, 

de minimis feedstock contaminants that 

are impractical to remove and are 

related to customary feedstock 

production and transport. Tables 1 and 

2 to this section do not apply to, and 

impose no requirements with respect to, 

volumes of fuel for which RINs are 

generated pursuant to subparagraph 6 of 

this section. 

* * * * * 

TABLE 2 TO § 80.1426—ADVANCED TECHNOLOGIES

Corn oil fractionation that is applied to at least 90% of the corn used to produce ethanol on a calendar year basis. 

Corn oil extraction that is applied to the whole stillage and/or derivatives of whole stillage and results in recovery of corn oil at an annual average rate equal to or greater than 1.33 pounds oil per bushel of corn processed into ethanol. 

Membrane separation in which at least 90% of ethanol dehydration is carried out using a hydrophilic membrane on a calendar year basis. 

Raw starch hydrolysis that is used for at least 90% of starch hydrolysis used to produce ethanol instead of hydrolysis using a traditional high 

heat cooking process, calculated on a calendar year basis. 

Combined heat and power such that, on a calendar year basis, at least 90% of the thermal energy associated with ethanol production (including 

thermal energy produced at the facility and that which is derived from an off-site waste heat supplier), exclusive of any thermal energy used 

for the drying of distillers grains and solubles, is used to produce electricity prior to being used to meet the process heat requirements of the 

facility. 

* * * * * 

(12) For purposes of Table 1 to this 

section, process heat produced from 

combustion of gas at a renewable fuel 

facility is considered derived from 

biomass if the gas is biogas. 

(i) For biogas directly transported to 

the facility without being placed in a 

commercial distribution system, all of 

the following conditions must be met: 

(A) The producer has entered into a 

written contract for the procurement of 

a specific volume of biogas with a 

specific heat content. 

(B) The volume of biogas was sold to 

the renewable fuel production facility, 

and to no other facility. 

(C) The volume and heat content of 

biogas injected into the pipeline and the 

volume of gas used as process heat are 

measured by continuous metering. 

(ii) For biogas that has been gathered, 

processed and injected into a common 

carrier pipeline, all of the following 

conditions must be met: 

(A) The producer has entered into a 

written contract for the procurement of 

a specific volume of biogas with a 

specific heat content. 

(B) The volume of biogas was sold to 

the renewable fuel production facility, 

and to no other facility. 

(C) The volume of biogas that is 

withdrawn from the pipeline is 

withdrawn in a manner and at a time 

consistent with the transport of fuel 

between the injection and withdrawal 

points. 

(D) The volume and heat content of 

biogas injected into the pipeline and the 

volume of gas used as process heat are 

measured by continuous metering. 

(E) The common carrier pipeline into 

which the biogas is placed ultimately 


jlentini on DSKJ8SOYB1PROD with RULES
79978 Federal Register / Vol. 75, No. 244 / Tuesday, December 21, 2010 / Rules and Regulations 

serves the producer’s renewable fuel 

facility. 

(iii) The process heat produced from 

combustion of gas at a renewable fuel 

facility described in paragraph (f)(12)(i) 

of this section shall not be considered 

derived from biomass if any other party 

relied upon the contracted volume of 

biogas for the creation of RINs. 

* * * * * 

6. Section 80.1451 is amended by 

revising paragraph (b)(1)(ii)(M) to read 

as follows: 

§ 80.1451 What are the reporting 

requirements under the RFS program? 

* * * * * 

(b) * * * 

(1) * * * 

(ii) * * * 

(M) The type of co-products produced 

with each batch. 

* * * * * 

■ 7. Section 80.1452 is amended as 

follows: 

■ a. By revising paragraphs (b) 

introductory text, (b)(1), (b)(2), (b)(4), 

(b)(5), (b)(6), (b)(9), (b)(13), and (b)(15). 

■ b. By revising paragraphs (c) 

introductory text, (c)(4), (c)(5), and 

(c)(7). 

§ 80.1452 What are the requirements 

related to the EPA Moderated Transaction 

System (EMTS)? 

* * * * * 

(b) Starting July 1, 2010, each time a 

domestic or foreign producer or 

importer of renewable fuel assigns RINs 

to a batch of renewable fuel pursuant to 

§ 80.1426(e), all the following 

information must be submitted to EPA 

via the submitting party’s EMTS 

account within five (5) business days of 

the date of RIN assignment. 

(1) The name of the renewable fuel 

producer or importer. 

(2) The EPA company registration 

number of the renewable fuel or foreign 

ethanol producer, as applicable. 

* * * * * 

(4) The EPA facility registration 

number of the renewable fuel or foreign 

ethanol producer, as applicable. 

(5) The importer’s EPA facility 

registration number if applicable. 

(6) The D code of RINs generated for 

the batch. 

* * * * * 

(9) The fuel type of the batch. 

* * * * * 

(13) The type and quantity of 

feedstock(s) used for the batch. 

* * * * * 

(15) The type and quantity of coproducts produced with the batch of 

renewable fuel. 

* * * * * 

(c) Starting July 1, 2010, each time 

any party sells, separates, or retires RINs 

generated on or after July 1, 2010, all the 

following information must be 

submitted to EPA via the submitting 

party’s EMTS account within five (5) 

business days of the reportable event. 

Starting July 1, 2010, each time any 

party purchases RINs generated on or 

after July 1, 2010, all the following 

information must be submitted to EPA 

via the submitting party’s EMTS 

account within ten (10) business days of 

the reportable event. The reportable 

event for a RIN purchase or sale occurs 

on the date of transfer per 

§ 80.1453(a)(4). The reportable event for 

a RIN separation or retirement occurs on 

the date of separation or retirement as 

described in § 80.1429. 

* * * * * 

(4) The RIN status (Assigned or 

Separated). 

(5) The D code of the RINs. 

* * * * * 

(7) The date of transfer per 

§ 80.1453(a)(4), if applicable. 

* * * * * 

■ 8. Section 80.1454 is amended by 

revising paragraph (b)(3)(xi) and adding 

a new paragraph (b)(3)(xii). 

§ 80.1454 What are the recordkeeping 

requirements under the RFS program? 

* * * * * 

(b) * * * 

(3) * * * 

(xi) For RINs generated for ethanol 

produced from corn starch at a facility 

using a pathway in Table 1 to § 80.1426 

that requires the use of one or more of 

the advanced technologies listed in 

Table 2 to § 80.1426, documentation to 

demonstrate that employment of the 

required advanced technology or 

technologies was conducted in 

accordance with the specifications in 

Tables 1 and 2 to § 80.1426, including 

any requirement for application to 90% 

of the production on a calendar year 

basis. 

(xii) All commercial documents and 

additional information related to details 

of RIN generation. 

* * * * * 

■ 9. Section 80.1464 is amended by 

revising paragraph (b)(1)(iii) to read as 

follows: 

§ 80.1464 What are the attest engagement 

requirements under the RFS program? 

* * * * * 

(b) * * * 

(1) * * * 

(iii) Verify that the proper number of 

RINs were generated and assigned 

pursuant to the requirements of 

§ 80.1426 for each batch of renewable 

fuel produced or imported. For RINs 

generated for ethanol produced from 

corn starch at a facility using a pathway 

in Table 1 to § 80.1426 that requires the 

use of one or more of the advanced 

technologies listed in Table 2 to 

§ 80.1426, verify that the required 

advanced technology or technologies 

were employed in accordance with the 

specifications in Tables 1 and 2 to 

§ 80.1426, including any requirement 

for application to 90% of the production 

on a calendar year basis. 

* * * * * 

[FR Doc. 2010–31910 Filed 12–20–10; 8:45 am] 

BILLING CODE 6560–50–P 

DEPARTMENT OF TRANSPORTATION 

National Highway Traffic Safety 

Administration 

49 CFR Part 578 

[Docket No. NHTSA–2010–0114; Notice 2] 

RIN 2127–AK78 

Civil Penalties 

AGENCY: National Highway Traffic 

Safety Administration (NHTSA), DOT. 

ACTION: Final Rule. 

SUMMARY: This document increases the 

maximum civil penalty amounts for 

related series of violations of the 

National Traffic and Motor Vehicle 

Safety Act, as amended (Vehicle Safety 

Act) and increases the liability for a 

violation of odometer disclosure or 

other odometer requirements with 

intent to defraud. This action is taken 

pursuant to the Federal Civil Monetary 

Penalty Inflation Adjustment Act of 

1990, as amended by the Debt 

Collection Improvement Act of 1996, 

which requires NHTSA to review and, 

as warranted, adjust penalties based on 

inflation at least every four years. 

DATES: This final rule is effective 

January 20, 2011. 

ADDRESSES: Petitions for reconsideration 

should refer to the docket number and 

be submitted to: Administrator, National 

Highway Traffic Safety Administration, 

1200 New Jersey Avenue, SE., West 

Building, Fourth Floor, Washington, DC 

20590, with a copy to the DOT docket. 

Copies to the docket may be submitted 

electronically [identified by DOT Docket 

ID Number NHTSA–2010–0114] by 

visiting the following Web site: 

• Federal eRulemaking Portal: Go to 

http://www.regulations.gov. Follow the 

online instructions for submitting 

comments. 

Privacy Act: Anyone is able to search 

the electronic form of all comments 


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