22896 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 80, 85, 86, 94, 1027, 1033, 

1039, 1042, 1043, 1045, 1048, 1051, 

1054, 1060, 1065, and 1068 

[EPA–HQ–OAR–2007–0121; FRL–9097–4] 

RIN 2060–AO38 

Control of Emissions From New Marine 

Compression-Ignition Engines at or 

Above 30 Liters per Cylinder 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is finalizing emission 

standards for new marine diesel engines 

with per-cylinder displacement at or 

above 30 liters (called Category 3 marine 

diesel engines) installed on U.S. vessels. 

These emission standards are equivalent 

to those adopted in the amendments to 

Annex VI to the International 

Convention for the Prevention of 

Pollution from Ships (MARPOL Annex 

VI). The emission standards apply in 

two stages—near-term standards for 

newly built engines will apply 

beginning in 2011; long-term standards 

requiring an 80 percent reduction in 

NOX emissions will begin in 2016. We 

are also finalizing a change to our diesel 

fuel program that will allow for the 

production and sale of 1,000 ppm sulfur 

fuel for use in Category 3 marine 

vessels. In addition, the new fuel 

requirements will generally forbid the 

production and sale of other fuels above 

1,000 ppm sulfur for use in most U.S. 

waters, unless alternative devices, 

procedures, or compliance methods are 

used to achieve equivalent emissions 

reductions. We are adopting further 

provisions under the Act to Prevent 

Pollution from Ships, especially to 

apply the emission standards to engines 

covered by MARPOL Annex VI that are 

not covered by the Clean Air Act, and 

to require that these additional engines 

use the specified fuels (or equivalents). 

The final regulations also include 

technical amendments to our motor 

vehicle and nonroad engine regulations; 

many of these changes involve minor 

adjustments or corrections to our 

recently finalized rule for new nonroad 

spark-ignition engines, or adjustment to 

other regulatory provisions to align with 

this recent final rule. 

DATES: This final rule is effective on 

June 29, 2010. The incorporation by 

reference of certain publications listed 

in this regulation is approved by the 

Director of the Federal Register as of 

June 29, 2010. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2007–0121. 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 

available either electronically in http:// 

www.regulations.gov or in hard copy at 

the EPA–HQ–OAR–2007–0121 Docket, 

EPA/DC, 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 EPA– 

HQ–OAR–2007–0121 is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: 

Amy Kopin, U.S. EPA, Office of 

Transportation and Air Quality, 

Assessment and Standards Division 

(ASD), Environmental Protection 

Agency, 2000 Traverwood Drive, Ann 

Arbor, MI 48105; telephone number: 

(734) 214–4417; fax number: (734) 214– 

4050; e-mail address: 

Kopin.Amy@epa.gov, or Assessment and 

Standards Division Hotline; telephone 

number: (734) 214–4636. 

SUPPLEMENTARY INFORMATION: 

General Information 

Does This Action Apply to Me? 

This action affects companies that 

manufacture, sell, or import into the 

United States new marine compressionignition engines with per cylinder 

displacement at or above 30 liters for 

use on vessels flagged or registered in 

the United States; companies and 

persons that make vessels that will be 

flagged or registered in the United States 

and that use such engines; and the 

owners or operators of such U.S. 

vessels. Additionally, this action may 

affect companies and persons that 

rebuild or maintain these engines. 

Finally, this action may also affect those 

that manufacture, import, distribute, 

sell, and dispense fuel for use by 

Category 3 marine vessels. Affected 

categories and entities include the 

following: 

Category NAICS Code a Examples of potentially affected entities 

Industry .................................... 333618 Manufacturers of new marine diesel engines. 

Industry .................................... 336611 Manufacturers of marine vessels. 

Industry .................................... 811310 Engine repair and maintenance. 

Industry .................................... 483 Water transportation, freight and passenger. 

Industry .................................... 324110 Petroleum Refineries. 

Industry .................................... 424710, 424720 Petroleum Bulk Stations and Terminals; Petroleum and Petroleum Products Wholesalers. 

Industry .................................... 483113 Coastal and Great Lakes Freight Transportation 

Industry .................................... 483114 Coastal and Great Lakes Passenger Transportation 

Note: 

a North American Industry Classification System (NAICS). 

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 will be regulated by this action. 

Other types of entities not listed in the 

table may also be regulated. To 

determine whether your company is 

regulated by this action, you should 

carefully examine the applicability 

criteria in 40 CFR 80.501, 94.1, 1042.1, 

and 1065.1, and the final regulations. If 

you have questions, consult the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 

Table of Contents 

I. Overview 

A. What Are the Elements of EPA’s 

Coordinated Strategy for Ships? 

B. Why Is EPA Making This Rule? 

C. Statutory Basis for Action 

II. Air Quality, Health and Welfare Impacts 

A. Public Health Impacts 

B. Environmental Impacts 

C. Air Quality Modeling Results 

D. Emissions From Ships With Category 3 

Engines 

III. Engine Standards 

A. What Category 3 Marine Engines Are 

Covered? 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 22897 

1This final rule generally applies to vessels with 

the largest marine diesel engines, which are called 

Category 3 engines in our regulations. In this 

preamble, we often refer to vessels using these 

engines as Category 3 vessels. We also refer to them 

as ocean-going vessels although this intended to be 

only a descriptive term. While the large majority of 

these vessels operate in the oceans, some operate 

solely in our internal waters such as in the Great 

Lakes. Therefore, we do not use the term oceangoing vessels to exclude the few vessels with 

Category 3 engines that operate only in fresh-water 

lakes or rivers or to exclude ocean-going vessels 

with Category 2 or Category 1 engines, but rather 

to reflect the way the vessels being regulated are 

more commonly known to the general public. Note 

also that, pursuant to 40 CFR 1043 which 

implements APPS, the fuel requirements described 

in this rule, unless otherwise specified, generally 

apply also to fuel used in gas turbines and steam 

boilers on marine vessels. 

2Proposal to Designate an Emission Control Area 

for Nitrogen Oxides, Sulphur Oxides and 

Particulate Matter, Submitted by the United States 

and Canada. IMO Document MEPC59/6/5, 27 

March, 2009. A copy of this document can be found 

at http://www.epa.gov/otaq/regs/nonroad/marine/

ci/mepc-59-eca-proposal.pdf. 

B. What Standards Are We Finalizing for 

Newly Manufactured Engines? 

C. Are the Standards Feasible? 

IV. Fuel Standards 

A. Background 

B. Diesel Fuel Standards Prior to This Final 

Rule 

C. Applicability 

D. Fuel Sulfur Standards 

E. Technical Amendments to the Current 

Diesel Fuel Sulfur Program Regulations 

V. Emission Control Areas for U.S. Coasts 

A. What Is an ECA? 

B. U.S. Emission Control Area Designation 

C. Technological Approaches To Comply 

With Fuel Standards 

D. ECA Designation and Foreign-Flagged 

Vessels 

VI. Certification and Compliance Program 

A. Compliance Provisions for Category 3 

Engines 

B. Compliance Provisions To Implement 

Annex VI NOX Regulation and the NOX

Technical Code 

C. Changes to the Requirements Specific to 

Engines Below 30 Liters per Cylinder 

D. Other Regulatory Issues 

E. U.S. Vessels Enrolled in the Maritime 

Security Program 

VII. Costs and Economic Impacts 

A. Estimated Fuel Costs 

B. Estimated Engine Costs 

C. Cost Effectiveness 

D. Economic Impact Analysis 

VIII. Benefits 

A. Overview 

B. Quantified Human Health Impacts 

C. Monetized Benefits 

D. What Are the Limitations of the Benefits 

Analysis? 

E. Comparison of Costs and Benefits 

IX. Public Participation 

X. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

XI. Statutory Provisions and Legal Authority 

I. Overview 

This final rule is part of a coordinated 

strategy to address emissions from 

ocean-going vessels and is an important 

step in EPA’s ongoing National Clean 

Diesel Campaign. In recent years, we 

have adopted major new programs 

designed to reduce emissions from new 

diesel engines, including those used in 

highway (66 FR 5001, January 18, 2001), 

nonroad (69 FR 38957, June 29, 2004), 

locomotive, and marine applications (73 

FR 25098, May 6, 2008). When fully 

phased in, these programs will 

significantly reduce emissions of 

harmful pollutants from these categories 

of engines and vehicles. This final rule 

sets out the next step in this ambitious 

effort by addressing emissions from the 

largest marine diesel engines, called 

Category 3 marine diesel engines. These 

are engines with per-cylinder 

displacement at or above 30 liters per 

cylinder, which are used primarily for 

propulsion power on ocean-going 

vessels (OGV).1

Emissions from Category 3 engines 

remain at high levels. These engines use 

emission control technology that is 

comparable to that used by nonroad 

engines in the early 1990s, and use fuel 

that can have a sulfur content of 30,000 

ppm or more. As a result, these engines 

emit high levels of pollutants that 

contribute to unhealthy air in many 

areas of the U.S. Nationally, in 2009, 

emissions from Category 3 engines 

account for about 10 percent of mobile 

source emissions of nitrogen oxides 

(NOX), about 24 percent of mobile 

source diesel PM2.5 emissions (with 

PM2.5 referring to particles with a 

nominal mean aerodynamic diameter 

less than or equal to 2.5 μm), and about 

80 percent of mobile source emissions 

of sulfur oxides (SOX). As we look into 

the future, however, emissions from 

Category 3 engines are expected to 

become an even more dominant 

inventory source. This will be due to 

both emission reductions from other 

mobile sources as new emission 

controls go into effect and to the 

anticipated activity growth for ocean 

transportation. Without new controls, 

we anticipate the contribution of 

Category 3 engines to national emission 

inventories to increase to about 24 

percent, 34 percent, and 93 percent of 

mobile source NOX, PM2.5, and SOX

emissions, respectively in 2020, growing 

to 40 percent, 48 percent, and 95 

percent respectively in 2030. The 

coordinated emission control strategy 

will lead to significant reductions in 

these emissions and important benefits 

to public health. 

The evolution of EPA’s strategy to 

control mobile source diesel emissions 

has followed a technology progression, 

beginning with the application of highefficiency advanced aftertreatment 

approaches and lower sulfur fuel 

requirements first to highway vehicles, 

then to nonroad engines and equipment, 

followed by locomotives and smaller 

marine diesel engines. The benefits of 

this approach include maximizing air 

quality benefits by focusing on the 

largest populations of sources with the 

shortest service lives, allowing engine 

manufacturers to spread initial research 

and development costs over a larger 

population of engines, and allowing 

manufacturers to address the challenges 

of applying advanced emission controls 

on smaller engines first. 

This approach also allowed us and 

the shipping community sufficient lead 

time to resolve technical issues with the 

use of advanced emission control 

technology and lower-sulfur fuel on the 

largest of these engines on vessels 

engaged in international trade. To that 

end, EPA has been working with engine 

manufacturers and other industry 

stakeholders for many years to identify 

and resolve challenges associated with 

applying advanced diesel engine 

technology to Category 3 engines to 

achieve significant NOX emission 

reductions and using lower-sulfur fuels 

to achieve significant PM and SOX

emission reductions. This work was 

fundamental in developing the emission 

limits for Category 3 engines that we are 

finalizing in this action and informed 

the position advocated by the United 

States in the international negotiations 

for more stringent tiers of international 

engine emission limits. 

Our coordinated strategy to control 

emissions from ocean-going vessels 

consists of actions at both the national 

and international levels. It includes: (1) 

The engine and fuel controls we are 

finalizing in this action under our Clean 

Air Act authority; (2) the proposal 2

submitted by the U.S. Government to 

the International Maritime Organization 

(IMO) to amend Annex VI of the 


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22898 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

3For the purpose of this final rule, the term 

‘‘ECA’’ refers to both the ECA and internal U.S. 

waters. Refer to Section VI.B. for a discussion of the 

application of the fuel sulfur and engine emission 

limits to U.S. internal waters through APPS. 

4These emission inventory reductions include 

reductions from ships operating within the 24 

nautical mile regulatory zone off the California 

Coastline, beginning with the effective date of the 

Coordinated Strategy program elements. The 

California regulation contains a provision that 

would sunset the requirements of the rule if the 

Federal program achieves equivalent emission 

reductions. See http://www.arb.ca.gov/regact/2008/ 

fuelogv08/fro13.pdf at 13 CCR 2299.2(j)(1). 

5As explained in the proposed rule leading to the 

2003 final rule, there were concerns about 

measuring PM from Category 3 marine engines (67 

FR 37569, May 29, 2002). Specifically, established 

PM test methods showed unacceptable variability 

when sulfur levels exceed 0.8 weight percent. 

However, as described in Section VI, we now 

believe these measurement issues have been 

resolved. 

International Convention for the 

Prevention of Pollution from Ships 

(MARPOL Annex VI) to designate U.S. 

coasts as an Emission Control Area 

(ECA) 3 in which all vessels, regardless 

of flag, would be required to meet the 

most stringent engine and marine fuel 

sulfur requirements in Annex VI; and 

(3) the new engine emission and fuel 

sulfur limits contained in the 

amendments to Annex VI that are 

applicable to all vessels regardless of 

flag through the Act to Prevent Pollution 

from Ships (APPS), as well as 

clarification on implementation of those 

standards, application to domestic and 

foreign-flagged vessels in internal 

waters, and application to nonparty 

foreign-flagged vessels. 

The amendments to APPS to 

incorporate Annex VI require 

compliance with MARPOL Annex VI by 

U.S. and foreign vessels that enter U.S. 

ports or operate in U.S. waters. In light 

of this, we are deciding not to revisit our 

existing approach with respect to 

foreign vessels in this rule. However, 

the MARPOL Annex VI Tier III NOX and 

stringent fuel sulfur limits are 

geographically based and would not 

become effective absent designation of 

U.S. coasts as an ECA. As noted above, 

the United States forwarded a proposal 

to IMO to amend Annex VI to designate 

U.S. coasts as an ECA. This proposal to 

amend Annex VI was approved in 

principle and circulated for adoption. 

We expect the proposed ECA 

amendment will be adopted at MEPC 

60, in March 2010. If this amendment is 

not adopted in a timely manner by IMO, 

we intend to take supplemental action 

to control emissions from vessels that 

affect U.S. air quality. 

Our coordinated strategy for oceangoing vessels will significantly reduce 

emissions from foreign and domestic 

vessels that affect U.S. air quality, and 

the impacts on human health and 

welfare will be substantial. We project 

that by 2030 this program will reduce 

annual emissions of NOX, SOX, and 

particulate matter (PM) by 1.2 million, 

1.3 million, and 143,000 tons, 

respectively, and the magnitude of these 

reductions would continue to grow well 

beyond 2030.4 These reductions are 

estimated to annually prevent between 

12,000 and 30,000 PM-related 

premature deaths, between 210 and 920 

ozone-related premature deaths, 

1,400,000 work days lost, and 9,600,000 

minor restricted-activity days. The 

estimated annual monetized health 

benefits of this coordinated strategy in 

2030 would be between $110 and $270 

billion, assuming a 3-percent discount 

rate (or between $99 and $240 billion 

assuming a 7-percent discount rate). The 

annual cost of the overall program in 

2030 would be significantly less, at 

approximately $3.1 billion. 

A. What Are the Elements of EPA’s 

Coordinated Strategy for Ships? 

Our coordinated strategy for oceangoing vessels, including the emission 

standards finalized in this action under 

the Clean Air Act, continues EPA’s 

program to progressively apply 

advanced aftertreatment emission 

control standards to diesel engines and 

reflects the evolution of this technology 

from the largest inventory source 

(highway engines), to land-based 

nonroad engines, to locomotives and 

marine diesel engines up to 30 liters per 

cylinder. The results of these forerunner 

programs are dramatic reductions in 

NOX and PM2.5 emissions on the order 

of 80 to 90 percent, which will lead to 

significant improvements in national air 

quality. 

The combination of controls in the 

coordinated strategy for ocean-going 

vessels will provide significant 

reductions in PM2.5, NOX, SOX, and 

toxic compounds, both in the near term 

(as early as 2011) and in the long term. 

These reductions will be achieved in a 

manner that: (1) Is very cost effective 

compared to additional controls on 

portside vehicles and equipment and 

other land-based mobile sources that are 

already subject to stringent technologyforcing emission standards; (2) leverages 

the international program adopted by 

IMO to ensure that all ships that operate 

in areas that affect U.S. air quality are 

required to use stringent emission 

control technology; and (3) provides the 

lead time needed to deal with the 

engineering design workload that is 

involved in applying advanced highefficiency aftertreatment technology to 

these very large engines. Overall, the 

coordinated strategy constitutes a 

comprehensive program that addresses 

the problems caused by ocean-going 

vessel emissions from both a near-term 

and long-term perspective. It does this 

while providing for an orderly and costeffective implementation schedule for 

the vessel owners and manufacturers, 

and in a way that is consistent with the 

international requirements for these 

vessels. 

The human health and welfare 

impacts of emissions from Category 3 

vessels, along with estimates of their 

contribution to national emission 

inventories, are described in Section II. 

The new tiers of engine emission 

standards under the Clean Air Act for 

addressing these emissions, and our 

justifications for them, are discussed in 

Section III. Section IV contains changes 

to our existing marine diesel fuel 

program. In Section V, we describe a 

key component of the coordinated 

strategy: The recently-submitted 

proposal to amend MARPOL Annex VI 

to designate U.S. coasts as an ECA, as 

well as the IMO amendment process. 

In addition to the new emission 

limits, we are finalizing several 

revisions to our Clean Air Act testing, 

certification, and compliance provisions 

to better ensure emission control in use. 

We are also finalizing regulations for the 

purpose of implementing MARPOL 

Annex VI pursuant to the Act to Prevent 

Pollution from Ships (33 U.S.C. 1901 et 

seq.). These revisions are described in 

Section VI. Sections VII and VIII present 

the estimated costs and benefits of our 

coordinated program to address OGV 

emissions. 

(1) What CAA Standards Is EPA 

Finalizing? 

We are finalizing new tiers of 

Category 3 marine diesel engine 

standards under our Clean Air Act 

authority, as well as certain revisions to 

our marine fuel program. 

Category 3 Engine Standards. 

Previous standards for Category 3 

engines were adopted in 2003. These 

Tier 1 standards are equivalent to the 

first tier of MARPOL Annex VI NOX

limits and require the use of control 

technology comparable to that used by 

nonroad engines in the early 1990s. We 

did not adopt PM standards at that time 

because the vast majority of PM 

emissions from Category 3 engines are 

the result of the sulfur content of the 

residual fuel they use and because of 

measurement issues.5 The combination 

of the engine and fuel standards we are 

finalizing and the U.S. Government 

proposal for ECA designation will 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 22899 

6Note that the MARPOL Annex VI standards are 

referred to as Tiers I, II, and III; EPA’s Category 3 

emission standards are referred to as Tiers 1, 2, and 

3. 

require all vessels that operate in coastal 

areas that affect U.S. air quality to 

control emissions of NOX, SOX, and PM. 

We are revising our engine 

requirements under the Clean Air Act to 

include two additional tiers of NOX

standards for new Category 3 marine 

diesel engines installed on vessels 

flagged or registered in the United 

States. The near-term Tier 2 standards 

will apply beginning in 2011 and will 

require more efficient use of engine 

technologies being used today, 

including engine timing, engine cooling, 

and advanced computer controls. The 

long-term Tier 3 standards will apply 

beginning in 2016 and will require the 

use of more advanced technology such 

as selective catalytic reduction. 

Because much of the operation of U.S. 

vessels occurs in areas that will have 

little, if any, impact on U.S. air quality, 

our Clean Air Act program will allow 

the use of alternative emission control 

devices (AECDs) that will permit a ship 

to meet less stringent requirements on 

the open sea. The use of these devices 

will be subject to certain restrictions, 

including a requirement that the AECD 

not disable emission controls while 

operating in areas where emissions can 

reasonably be expected to adversely 

affect U.S. air quality, and that the 

engine is equipped with a NOX emission 

monitoring device. In addition, the 

engine will be required to meet the Tier 

2 NOX limits when the AECD is 

implemented, and an AECD will not be 

allowed on any Tier 2 or earlier engine. 

In addition to the NOX emission 

limits, we are finalizing standards for 

emissions of hydrocarbons (HC) and 

carbon monoxide (CO) from new 

Category 3 engines. As explained in 

Section III.B.1, below, we are not setting 

a standard for PM emissions for 

Category 3 engines. However, significant 

PM emissions control will be achieved 

through the ECA fuel sulfur 

requirements that will apply through 

APPS to ships that operate in areas that 

affect U.S. air quality. We are also 

requiring engine manufacturers to 

measure and report PM emissions 

pursuant to our authority in section 208 

of the Clean Air Act. 

Fuel Sulfur Limits. We are finalizing 

fuel sulfur limits under section 211(c) of 

the Clean Air Act that match the limits 

that apply under Annex VI in ECAs. 

First, we are revising our existing diesel 

fuel program to allow for the production 

and sale of 1,000 ppm sulfur fuel for use 

in Category 3 marine vessels. This will 

allow production and distribution of 

fuel consistent with the new sulfur 

limits that will become applicable, 

under Annex VI, in ECAs beginning in 

2015. Our current diesel fuel program 

sets a sulfur limit of 15 ppm that will 

be fully phased-in by December 1, 2014 

for land-based nonroad, locomotive, and 

marine (NRLM) diesel fuel produced for 

distribution, sale and use in the United 

States. Without this change to our 

existing diesel fuel regulations, fuel 

with a sulfur content of up to 1,000 ppm 

could be used in Category 3 marine 

vessels, but it could not be legally 

produced in the U.S. after June 1, 2014. 

Second, we are generally forbidding the 

production and sale of fuel oil with a 

sulfur content above 1,000 ppm for use 

in the waters within the proposed ECA 

(see Note 3, supra). The exception to 

this is if the vessel uses alternative 

devices, procedures, or compliance 

methods that achieve equivalent 

emission control as operating on 1,000 

ppm sulfur fuel. 

(2) What Is the U.S. Government 

Proposal for Designation of an Emission 

Control Area? 

MARPOL Annex VI contains 

international standards for air emissions 

from ships, including NOX, SOX, and 

PM emissions. The Annex VI NOX and 

SOX/PM limits are set out in Table I–1. 

Annex VI was adopted by the Parties in 

1997 but did not go into force until 

2005, after it was ratified by fifteen 

countries representing at least 50 

percent of the world’s merchant 

shipping tonnage. These Annex VI NOX

standards currently apply to all engines 

above 130 kW installed on a ship 

constructed on or after January 1, 2000 

and reduce NOX emissions by about 30 

percent from uncontrolled levels. As 

originally adopted, Annex VI included 

two fuel sulfur limits: A global limit of 

45,000 ppm and a more stringent 15,000 

ppm limit for SOX Emission Control 

Areas (SECAs). This approach ensures 

that the cleanest fuel is used in areas 

that demonstrate a need for additional 

SOX reductions, while retaining the 

ability of ships to use higher-sulfur 

residual fuel on the open ocean. 

Annex VI was amended in October 

2008, adding two tiers of NOX limits 

(Tier II and Tier III) and two sets of fuel 

sulfur standards.6 These amendments 

will enter into force on July 1, 2010. The 

most stringent NOX and fuel sulfur 

limits are regionally based and will 

apply only in designated ECAs. 

TABLE I–1—ANNEX VI NOX EMISSION STANDARDS AND FUEL SULFUR LIMITS

Less than 130 

RPM 

130–2,000 

RPM a

Over 2,000 

RPM 

NOX g/kW-hr ............................. Tier I ......................................... b 2004 17.0 45.0·n(¥0.20) 9.8 

Tier II ........................................ 2011 14.4 44.0·n(¥0.23) 7.7 

Tier III ....................................... 2016 3.4 9.0·n(¥0.23) 2.0 

Global ECA 

Fuel Sulfur ....................................................................................... 2004 c 45,000 ppm 2005 c 15,000 ppm 

2012 c 35,000 ppm 2010 c 10,000 ppm 

2020 c d 5,000 ppm 2015 c 1,000 ppm 

Notes: 

a Applicable standards are calculated from n (maximum in-use engine speed in revolutions per minute (rpm)), rounded to one decimal place. b Tier 1 NOX standards apply for engines originally manufactured after 2004, and proposed also to certain earlier engines. c Annex VI standards are in terms of percent sulfur. Global sulfur limits are 4.5%; 3.5%; 0.5%. ECA sulfur limits are 1.5%; 1.0%; 0.1%. d Subject to a feasibility review in 2018; may be delayed to 2025. 

To realize the benefits from the 

MARPOL Annex VI Tier III NOX and 

most stringent fuel sulfur controls, areas 

must be designated as Emission Control 

Areas. On July 17, 2009, the IMO 

approved in principle a U.S.-Canada 

proposal to amend MARPOL Annex VI 

to designate North American coastal 

waters as an ECA (referred to as the 


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22900 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

7Proposal to Designate an Emission Control Area 

for Nitrogen Oxides, Sulphur Oxides and 

Particulate Matter, Submitted by the United States 

and Canada. IMO Document MEPC59/6/5, 27 

March 2009. A copy of this document can be found 

at http://www.epa.gov/otaq/regs/nonroad/marine/

ci/mepc-59-eca-proposal.pdf. 

‘‘U.S./Canada ECA’’ or the ‘‘North 

American ECA’’).7 In addition, France 

has joined the ECA proposal on behalf 

of the Saint Pierre and Miquelon 

archipelago. A description of this 

proposal and the IMO ECA designation 

process is set out in Section V. ECA 

designation would ensure that ships 

that affect U.S. air quality meet stringent 

NOX and fuel sulfur requirements while 

operating within 200 nautical miles of 

U.S. coasts. We expect the North 

American proposal will be adopted by 

the Parties to MARPOL Annex VI in 

March 2010, entering into force as early 

as 2012. If, however, the proposed 

amendment is not adopted in a timely 

manner, we intend to take supplemental 

action to control harmful emissions 

from vessels that affect U.S. air quality. 

(3) Regulations To Implement Annex VI 

The United States became a party to 

MARPOL Annex VI by depositing its 

instrument of ratification with IMO on 

October 8, 2008. This was preceded by 

the President signing into law the 

Maritime Pollution Prevention Act of 

2008 (Pub. L. 110–280) on July 21, 2008, 

that contains amendments to the Act to 

Prevent Pollution from Ships (33 U.S.C. 

1901 et seq.). These APPS amendments 

require compliance with Annex VI by 

all persons subject to the engine and 

vessel requirements of Annex VI. The 

amendments also authorize the U.S. 

Coast Guard and EPA to enforce the 

provisions of Annex VI against domestic 

and foreign vessels and to develop 

implementing regulations, as necessary. 

In addition, APPS gives EPA sole 

authority to certify engines installed on 

U.S. vessels to the Annex VI 

requirements. This final rule contains 

regulations codifying the Annex VI 

requirements and regulations to 

implement several aspects of the Annex 

VI engine and fuel regulations, which 

we are finalizing under that APPS 

authority. Our cost and benefit analyses 

for the coordinated strategy include the 

costs for U.S. vessels to implement the 

requirements of this MARPOL Annex VI 

program, including requirements that 

will apply upon entry into force of the 

North American ECA. 

(4) Technical Amendments 

The finalized regulations also include 

technical amendments to our motor 

vehicle and nonroad engine regulations. 

Many of these changes involve minor 

adjustments or corrections to our 

recently finalized rule for new nonroad 

spark-ignition engines, or adjustment to 

other regulatory provisions to align with 

this recent final rule. 

(5) Summary 

The emission control requirements in 

our coordinated strategy are the 

MARPOL Annex VI global Tier II NOX

standards included in the amendments 

to Annex VI and the ECA Tier III NOX

limits and fuel sulfur limits that will 

apply when the U.S. coasts are 

designated as an ECA through an 

additional amendment to Annex VI. The 

Annex VI requirements, including the 

future ECA requirements, will be 

enforceable for U.S. and foreign vessels 

operating in U.S. waters through the Act 

to Prevent Pollution from Ships. 

We are also adopting the NOX

emission standards for Category 3 

engines on U.S. vessels under section 

213 of the Clean Air Act. 

Finally, we are adopting additional 

requirements that are not part of the 

Annex VI program or the ECA. These 

are (1) limits on hydrocarbon and 

carbon monoxide emissions for Category 

3 engines; (2) a PM measurement 

requirement to obtain data on PM 

emissions from engines operating on 

distillate fuel; and (3) changes to our 

diesel fuel program under the Clean Air 

Act to allow production and sale of 

ECA-compliant fuel. We are also 

changing our emission control program 

for smaller marine diesel engines to 

harmonize with the Annex VI NOX

requirements for U.S. vessels that 

operate internationally. 

B. Why Is EPA Making This Rule? 

(1) Category 3 Engines Contribute to 

Serious Air Quality Problems 

Category 3 engines generate 

significant emissions of PM2.5, SOX, and 

NOX that contribute to nonattainment of 

the National Ambient Air Quality 

Standards (NAAQS) for PM2.5 and 

ground-level ozone (smog). NOX and 

SOX are both precursors to secondary 

PM2.5 formation. Both PM2.5 and NOX

adversely affect human health. NOX is a 

key precursor to ozone as well. NOX, 

SOX and PM2.5 emissions from oceangoing vessels also cause harm to public 

welfare, including contributing to 

deposition of nitrogen and sulfur, 

visibility impairment and other harmful 

environmental impacts across the U.S. 

The health and environmental effects 

associated with these emissions are a 

classic example of a negative externality 

(an activity that imposes 

uncompensated costs on others). With a 

negative externality, an activity’s social 

cost (the costs borne to society imposed 

as a result of the activity taking place) 

is not taken into account in the total 

cost of producing goods and services. In 

this case, as described in this section 

below and in Section II, emissions from 

ocean-going vessels impose public 

health and environmental costs on 

society, and these added costs to society 

are not reflected in the costs of 

providing the transportation services. 

The market system itself cannot correct 

this externality because firms in the 

market are rewarded for minimizing 

their production costs, including the 

costs of pollution control. In addition, 

firms that may take steps to use 

equipment that reduces air pollution 

may find themselves at a competitive 

disadvantage compared to firms that do 

not. To correct this market failure and 

reduce the negative externality from 

these emissions, we are setting a cap on 

the rate of emission production from 

these sources. EPA’s coordinated 

strategy for ocean-going vessels will 

accomplish this since both domestic 

and foreign ocean-going vessels will be 

required to reduce their emissions to a 

technologically feasible limit. 

Emissions from ocean-going vessels 

account for substantial portions of the 

country’s ambient PM2.5, SOX and NOX

levels. We estimate that in 2009 these 

engines account for about 80 percent of 

mobile source sulfur dioxide (SO2) 

emissions, 10 percent of mobile source 

NOX emissions and about 24 percent of 

mobile source diesel PM2.5 emissions. 

Emissions from ocean-going vessels are 

expected to dominate the mobile source 

inventory in the future, due to both the 

expected emission reductions from 

other mobile sources as a result of more 

stringent emission controls and due to 

growth in the demand for ocean 

transportation services. By 2030, the 

coordinated strategy will reduce annual 

SO2 emissions from these diesel engines 

by 1.3 million tons, annual NOX

emissions by 1.2 million tons, and PM2.5

emissions by 143,000 tons, and those 

reductions will continue to grow 

beyond 2030 as fleet turnover to the 

clean engines continues. While a share 

of these emissions occur at sea, our air 

quality modeling results described in 

Section II show they have a significant 

impact on ambient air quality far inland. 

Both ozone and PM2.5 are associated 

with serious public health problems, 

including premature mortality, 

aggravation of respiratory and 

cardiovascular disease (as indicated by 

increased hospital admissions and 

emergency room visits, school absences, 

lost work days, and restricted activity 

days), changes in lung function and 

increased respiratory symptoms, altered 


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8U. S. EPA (2004). Final Regulatory Impact 

Analysis: Control of Emissions from Nonroad Diesel 

Engines, Chapter 3. Report No. EPA420–R–04–007. 

http://www.epa.gov/nonroad-diesel/2004fr.htm#ria. 

9State of California Air Resources Board. (2004). 

Roseville Rail Yard Study. Sacramento, CA: 

California EPA, California Air Resources Board 

(CARB). Stationary Source Division. This document 

is available electronically at: http://www.arb.ca.gov/ 

diesel/documents/rrstudy.htm. 

10 Di, P., Servin, A., Rosenkranz, K., Schwehr, B., 

Tran, H., (2006). Diesel Particulate Matter Exposure 

Assessment Study for the Ports of Los Angeles and 

Long Beach. Sacramento, CA: California EPA, 

California Air Resources Board (CARB). Retrieved 

March 19, 2009 from http://www.arb.ca.gov/regact/ 

marine2005/portstudy0406.pdf. 

11This type of screening-level analysis is an 

inexact tool and not appropriate for regulatory 

decision-making; it is useful in beginning to 

understand potential impacts and for illustrative 

purposes. Additionally, the emissions inventories 

used as inputs for the analyses are not official 

estimates and likely underestimate overall 

emissions because they are not inclusive of all 

emission sources at the individual ports in the 

sample. 

12 ICF International. September 28, 2007. 

Estimation of diesel particulate matter 

concentration isopleths for marine harbor areas and 

rail yards. Memorandum to EPA under Work 

Assignment Number 0–3, Contract Number EP–C– 

06–094. This memo is available in Docket EPA– 

HQ–OAR–2007–0121. 

13 ICF International. September 28, 2007. 

Estimation of diesel particulate matter population 

exposure near selected harbor areas and rail yards. 

Memorandum to EPA under Work Assignment 

Number 0–3, Contract Number EP–C–06–094. This 

memo is available in Docket EPA–HQ–OAR–2007– 

0121. 

14 ICF International, December 10, 2008. 

Estimation of diesel particulate matter population 

exposure near selected harbor areas with revised 

harbor emissions. Memorandum to EPA under 

Work Assignment Number 2–9. Contract Number 

EP–C–06–094. This memo is available in Docket 

EPA–HQ–OAR–2007–0121. 

15 ICF International. December 1, 2008. 

Estimation of diesel particulate matter 

concentration isopleths near selected harbor areas 

with revised emissions. Memorandum to EPA 

under Work Assignment Number 1–9. Contract 

Number EP–C–06–094. This memo is available in 

Docket EPA–HQ–OAR–2007–0121. 

16The Agency selected a representative sample 

from the top 150 U.S. ports including coastal and 

Great Lake ports. 

17These areas are defined in section 162 of the 

Act as those national parks exceeding 6,000 acres, 

wilderness areas and memorial parks exceeding 

5,000 acres, and all international parks which were 

in existence on August 7, 1977. Section 169 of the 

Clean Air Act provides additional authority to 

address existing visibility impairment and prevent 

future visibility impairment in the 156 national 

parks, forests and wilderness areas categorized as 

mandatory class I Federal areas. 

respiratory defense mechanisms, and 

chronic bronchitis. Diesel exhaust is of 

special public health concern, and since 

2002 EPA has classified it as likely to be 

carcinogenic to humans by inhalation at 

environmental exposures. Recent 

studies are showing that populations 

living near large diesel emission sources 

such as major roadways, rail yards, and 

marine ports are likely to experience 

greater diesel exhaust exposure levels 

than the overall U.S. population, putting 

them at greater health risks.8 9 10

EPA recently updated its initial 

screening-level analysis 11 of selected 

marine port areas to better understand 

the populations that are exposed to 

diesel particulate matter emissions from 

these facilities.12 13 14 15 This screeninglevel analysis focused on a 

representative selection of national 

marine ports.16 Of the 45 marine ports 

selected, the results indicate that at least 

18 million people, including a 

disproportionate number of low-income 

households, African-Americans, and 

Hispanics, live in the vicinity of these 

facilities and are being exposed to 

ambient diesel PM levels that are 2.0 μg/ 

m3 and 0.2 μg/m3 above levels found in 

areas further from these facilities. 

Considering only ocean-going marine 

engine diesel PM emissions, the results 

indicate that 6.5 million people are 

exposed to ambient diesel particulate 

matter (DPM) levels that are 2.0 μg/m3

and 0.2 μg/m3 above levels found in 

areas further from these facilities. 

Because those populations exposed to 

diesel PM emissions from marine ports 

are more likely to be low-income and 

minority residents, these populations 

would benefit from the controls being 

proposed in this action. The detailed 

findings of this study are available in 

the public docket for this rulemaking. 

Even outside port areas, millions of 

Americans continue to live in areas that 

do not meet existing air quality 

standards today. With regard to PM2.5

nonattainment, in 2005 EPA designated 

39 nonattainment areas for the 1997 

PM2.5 NAAQS (70 FR 943, January 5, 

2005). These areas are composed of 208 

full or partial counties with a total 

population exceeding 88 million. The 

1997 PM2.5 NAAQS was recently revised 

and the 2006 PM2.5 NAAQS became 

effective on December 18, 2006. As of 

December 22, 2008, there are 58 2006 

PM2.5 nonattainment areas composed of 

211 full or partial counties. These 

numbers do not include individuals 

living in areas that may fail to maintain 

or achieve the PM2.5 NAAQS in the 

future. Currently, ozone concentrations 

exceeding the 8-hour ozone NAAQS 

occur over wide geographic areas, 

including most of the nation’s major 

population centers. As of December 

2008, there are approximately 132 

million people living in 57 areas (293 

full or partial counties) designated as 

not in attainment with the 8-hour ozone 

NAAQS. These numbers do not include 

people living in areas where there is a 

potential that the area may fail to 

maintain or achieve the 8-hour ozone 

NAAQS. 

In addition to public health impacts, 

there are serious public welfare and 

environmental impacts associated with 

PM2.5 and ozone emissions. Specifically, 

NOX and SOX emissions from diesel 

engines contribute to the acidification, 

nitrification, and eutrophication of 

water bodies. NOX, SOX and direct 

emissions of PM2.5 can contribute to the 

substantial impairment of visibility in 

many parts of the U.S. where people 

live, work, and recreate, including 

national parks, wilderness areas, and 

mandatory class I Federal areas.17 The 

deposition of airborne particles can also 

reduce the aesthetic appeal of buildings 

and culturally important articles 

through soiling, and can contribute 

directly (or in conjunction with other 

pollutants) to structural damage by 

means of corrosion or erosion. Finally, 

ozone causes damage to vegetation 

which leads to crop and forestry 

economic losses, as well as harm to 

national parks, wilderness areas, and 

other natural systems. 

EPA has already adopted many 

emission control programs that are 

expected to reduce ambient PM2.5 and 

ozone levels, including the Nonroad 

Spark Ignition Engine rule (73 FR 

59034, Oct 8, 2008), the Locomotive and 

Marine Diesel Engine Rule (73 FR 

25098, May 6, 2008), the Clean Air 

Interstate Rule (CAIR) (70 FR 25162, 

May 12, 2005), the Clean Air Nonroad 

Diesel Rule (69 FR 38957, June 29, 

2004), the Heavy Duty Engine and 

Vehicle Standards and Highway Diesel 

Fuel Sulfur Control Requirements (66 

FR 5002, Jan. 18, 2001), and the Tier 2 

Vehicle and Gasoline Sulfur Program 

(65 FR 6698, Feb. 10, 2000). The 

additional PM2.5, SOX, and NOX

emission reductions resulting from the 

coordinated approach described in this 

action will assist States in attaining and 

maintaining the PM2.5 and ozone 

NAAQS near term and in the decades to 

come. 

Our air quality modeling projects that 

in 2020 at least 13 counties with about 

30 million people may violate the 1997 

standards for PM2.5 and 50 counties 

with about 50 million people may 

violate the 2008 standards for ozone. 

These numbers likely underestimate the 

impacted population since they do not 

include the people who live in areas 

which do not meet the 2006 PM2.5

NAAQS. In addition, these numbers do 

not include the additional 13 million 

people in 12 counties who live in areas 

that have air quality measurements 

within 10 percent of the 1997 PM2.5

NAAQS and the additional 80 million 

people in 135 counties who live in areas 


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22902 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

that have air quality measurements 

within 10% of the 2008 ozone NAAQS. 

The emission reductions resulting from 

this coordinated strategy will assist 

these and other States to both attain and 

maintain the PM2.5 and ozone NAAQS. 

State and local governments are 

working to protect the health of their 

citizens and comply with requirements 

of the Clean Air Act. As part of this 

effort, they recognize the need to secure 

additional major reductions in diesel 

PM2.5, SOX and NOX emissions by 

undertaking numerous State level 

actions, while also seeking Agency 

action, including the Category 3 engine 

standards being finalized in this final 

rule and the U.S. proposal to IMO to 

amend Annex VI to designate U.S. 

coastal areas as an ECA, and related 

certification and fuel provisions under 

the Clean Air Act to complement that 

ECA proposal. EPA’s coordinated 

strategy to reduce OGV emissions 

through engine emission controls and 

fuel sulfur limits will play a critical part 

in State efforts to attain and maintain 

the NAAQS through the next two 

decades. 

In addition to regulatory programs, 

the Agency has a number of innovative 

programs that partner government, 

industry, and local communities 

together to help address challenging air 

quality problems. Under the National 

Clean Diesel Campaign, EPA promotes a 

variety of emission reduction strategies 

such as retrofitting, repairing, replacing 

and repowering engines, reducing idling 

and switching to cleaner fuels. 

In 2008, Congress appropriated 

funding for the Diesel Emission 

Reduction Program under the Energy 

Policy Act of 2005 (EPAct 2005) to 

reduce emissions from heavy-duty 

diesel engines in the existing fleet. The 

EPAct 2005 directs EPA to break the 

funding into two different components: 

a National competition and a State 

allocation program. The National 

Program, with 70 percent of the funding, 

consists of three separate competitions: 

(1) The National Clean Diesel Funding 

Assistance Program; (2) the National 

Clean Diesel Emerging Technologies 

Program; and (3) the SmartWay Clean 

Diesel Finance Program. The State Clean 

Diesel Grant and Loan Program utilizes 

the remaining 30 percent of the funding. 

In the first year of the program, EPA 

awarded 119 grants totaling $49.2 

million for diesel emission reduction 

projects and programs across the 

country for cleaner fuels, verified 

technologies, and certified engine 

configurations. 

Through $300 million in funding 

provided to the Diesel Emission 

Reduction Program under the American 

Reinvestment and Recovery Act of 2009, 

EPA will promote and preserve jobs 

while improving public health and 

achieving significant reductions in 

diesel emissions. 

Furthermore, EPA’s National Clean 

Diesel Campaign, through its Clean 

Ports USA program, is working with 

port authorities, terminal operators, 

shipping, truck, and rail companies to 

promote cleaner diesel technologies and 

strategies through education, incentives, 

and financial assistance for diesel 

emission reductions at ports. Part of 

these efforts involves clean diesel 

programs that can further reduce 

emissions from the existing fleet of 

diesel engines. Finally, many of the 

companies operating in States and 

communities suffering from poor air 

quality have voluntarily entered into 

Memoranda of Understanding (MOUs) 

designed to ensure that the cleanest 

technologies are used first in regions 

with the most challenging air quality 

issues. 

Taken together, these voluntary 

approaches can augment the 

coordinated strategy and help States and 

communities achieve larger reductions 

sooner in the areas of our country that 

need them the most. The Agency 

remains committed to furthering these 

programs and others so that all of our 

citizens can breathe clean healthy air. 

(2) Advanced Emission Technology 

Solutions Are Available 

Air pollution from marine diesel 

exhaust is a challenging problem. 

However, we believe manufacturers can 

apply a combination of existing and 

new technologies to meet the emission 

standards we are adopting in this final 

rule. Optimizing air intake fuel injection 

systems can substantially reduce 

engine-out emissions. Further NOX

control can be achieved with advanced 

technology such as aftertreatment 

devices with high-efficiency catalysts. 

As discussed in greater detail in Section 

III.C, the development of these 

aftertreatment technologies for highway 

and nonroad diesel applications has 

advanced rapidly in recent years, so that 

very large emission reductions in NOX

emissions can be achieved. 

Manufacturers might also deploy other 

advanced technologies such as waterbased in-cylinder controls to reduce 

NOX emissions. 

While aftertreatment technologies can 

be sensitive to sulfur, their use will be 

required only in ECAs designated under 

MARPOL Annex VI, and they are 

expected to be able to operate on ECA 

fuel meeting a 1,000 ppm fuel sulfur. 

With the lead time available and the 

assurance of 1,000 ppm fuel for oceangoing vessels in 2015, as would be 

required through ECA designation for 

U.S. coasts, we are confident the 

application of advanced NOX

technology to Category 3 marine engines 

will proceed at a reasonable rate of 

progress and will result in systems 

capable of achieving the finalized 

standards on schedule. Use of this lower 

sulfur fuel will also result in substantial 

PM emission reductions, since PM 

emissions from Category 3 engines come 

mostly from the use of high sulfur 

residual fuel. Note that vessels may be 

equipped with alternative devices, 

procedures, or compliance methods 

provided they achieve equivalent 

emissions reductions. 

C. Statutory Basis for Action 

Authority for the actions proposed in 

this documents is granted to the 

Environmental Protections Agency by 

sections 114, 203, 205, 206, 207, 208, 

211, 213, 216, and 301(a) of the Clean 

Air Act as amended in 1990 (42 U.S.C. 

7414, 7522, 7524, 7525, 7541, 7542, 

7545, 7547, 7550 and 7601(a)), and by 

sections 1901–1915 of the Act to 

Prevent Pollution from Ships (33 U.S.C. 

1909 et seq.). 

(1) Clean Air Act Basis for Action 

EPA is proposing the fuel 

requirements pursuant to its authority 

in section 211(c) of the Clean Air Act, 

which allows EPA to regulate fuels that 

contribute to air pollution that 

endangers public health or welfare (42 

U.S.C. 7545(c)). As discussed previously 

in EPA’s Clean Air Nonroad Diesel rule 

(69 FR 38958) and in Section II, the 

combustion of high sulfur diesel fuel by 

nonroad, locomotive, and marine diesel 

engines contributes to air quality 

problems that endanger public health 

and welfare. Section II also discusses 

the significant contribution to these air 

quality problems by Category 3 marine 

vessels. Additional support for the 

procedural and enforcement-related 

aspects of the fuel controls in the final 

rule, including the recordkeeping 

requirements, comes from Clean Air Act 

sections 114(a) and 301(a) (42 U.S.C. 

sections 7414(a) and 7601(a)). 

EPA is finalizing emission standards 

for new Category 3 marine diesel 

engines pursuant to its authority under 

section 213(a)(3) of the Clean Air Act, 

which directs the Administrator to set 

standards regulating emissions of NOX, 

volatile organic compounds (VOCs), or 

CO for classes or categories of engines, 

such as marine diesel engines, that 

contribute to ozone or carbon monoxide 

concentrations in more than one 

nonattainment area. These ‘‘standards 

shall achieve the greatest degree of 


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18U.S. EPA (2004). Air Quality Criteria for 

Particulate Matter. Volume I EPA600/P–99/002aF 

and Volume II EPA600/P–99/002bF. Retrieved on 

March 19, 2009 from Docket EPA–HQ–OAR–2003– 

0190 at http://www.regulations.gov/. 

19U.S. EPA (2005). Review of the National 

Ambient Air Quality Standard for Particulate 

Matter: Policy Assessment of Scientific and 

Technical Information, OAQPS Staff Paper. EPA– 

452/R–05–005a. Retrieved March 19, 2009 from 

http://www.epa.gov/ttn/naaqs/standards/pm/data/

pmstaffpaper_20051221.pdf. 

20The PM NAAQS is currently under review and 

the EPA is considering all available science on PM 

health effects, including information which has 

been published since 2004, in the development of 

the upcoming PM Integrated Science Assessment 

Document (ISA). A second draft of the PM ISA was 

completed in July 2009 and was submitted for 

Continued 

emission reduction achievable through 

the application of technology which the 

Administrator determines will be 

available for the engines or vehicles, 

giving appropriate consideration to cost, 

lead time, noise, energy, and safety 

factors associated with the application 

of such technology.’’ 

EPA is finalizing a PM measurement 

requirement for new Category 3 marine 

diesel engines pursuant to its authority 

under section 208, which requires 

manufacturers and other persons subject 

to Title II requirements to ‘‘provide 

information the Administrator may 

reasonably require * * * to otherwise 

carry out the provisions of this part 

***’’ 

EPA is also acting under its authority 

to implement and enforce the Category 

3 marine diesel emission standards. 

Section 213(d) provides that the 

standards EPA adopts for marine diesel 

engines ‘‘shall be subject to Sections 

206, 207, 208, and 209’’ of the Clean Air 

Act, with such modifications that the 

Administrator deems appropriate to the 

regulations implementing these 

sections.’’ In addition, the marine 

standards ‘‘shall be enforced in the same 

manner as [motor vehicle] standards 

prescribed under section 202’’ of the 

Act. Section 213(d) also grants EPA 

authority to promulgate or revise 

regulations as necessary to determine 

compliance with and enforce standards 

adopted under section 213. 

As required under section 213(a)(3), 

we believe the evidence provided in 

Section III.C and in Chapter 4 of Final 

Regulatory Impact Analysis (RIA) 

indicates that the stringent NOX

emission standards finalized in this 

final rule for newly built Category 3 

marine diesel engines are feasible and 

reflect the greatest degree of emission 

reduction achievable through the use of 

technology that will be available in the 

model years to which they apply. We 

have given appropriate consideration to 

costs in finalizing these standards. Our 

review of the costs and costeffectiveness of these standards indicate 

that they are reasonable and comparable 

to the cost-effectiveness of other mobile 

source emission reduction strategies 

that have been required. We have also 

reviewed and given appropriate 

consideration to the energy factors of 

this rule in terms of fuel efficiency as 

well as any safety and noise factors 

associated with these standards. 

The information in Section II and 

Chapter 2 of the Final Regulatory Impact 

Analysis regarding air quality and 

public health impacts provides strong 

evidence that emissions from Category 3 

marine diesel engines significantly and 

adversely impact public health or 

welfare. EPA has already found in 

previous rules that emissions from new 

marine diesel engines contribute to 

ozone and CO concentrations in more 

than one area which has failed to attain 

the ozone and carbon monoxide 

NAAQS (64 FR 73300, December 29, 

1999). 

The NOX and PM emission reductions 

achieved through the coordinated 

strategy will be important to States’ 

efforts to attain and maintain the Ozone 

and the PM2.5 NAAQS in the near term 

and in the decades to come, and will 

significantly reduce the risk of adverse 

effects to human health and welfare. 

(2) APPS Basis for Action 

EPA is finalizing regulations to 

implement MARPOL Annex VI 

pursuant to its authority in section 1903 

of the Act to Prevent Pollution from 

Ships (APPS). Section 1903 gives the 

Administrator the authority to prescribe 

any necessary or desired regulations to 

carry out the provisions of Regulations 

12 through 19 of Annex VI. 

The Act to Prevent Pollution from 

Ships implements Annex VI and makes 

those requirements enforceable 

domestically. However, certain 

clarifications are necessary for 

implementing Regulation 13 and the 

requirements of the NOX Technical 

Code with respect to issuance of Engine 

International Air Pollution Prevention 

(EIAPP) certificates and approval of 

alternative compliance methods. 

Clarification is also needed with respect 

to the application of the Annex VI 

requirements to certain U.S. and foreign 

vessels that operate in U.S. waters. 

II. Air Quality, Health and Welfare 

Impacts 

The coordinated strategy will 

significantly reduce emissions of NOX, 

PM, and SOX from ocean-going vessels. 

Emissions of these compounds 

contribute to PM and ozone 

nonattainment and environmental 

effects including deposition, visibility 

impairment and harm to ecosystems 

from ozone. In addition diesel 

particulate matter is associated with a 

host of adverse health effects, including 

cancer. 

This section summarizes the general 

health and welfare effects of these 

emissions and the modeled projections 

of changes in air quality due to the 

coordinated strategy. Interested readers 

are encouraged to refer to the RIA for 

more in-depth discussions. 

A. Public Health Impacts 

(1) Particulate Matter 

Particulate matter is a generic term for 

a broad class of chemically and 

physically diverse substances. It can be 

principally characterized as discrete 

particles that exist in the condensed 

(liquid or solid) phase spanning several 

orders of magnitude in size. Since 1987, 

EPA has delineated that subset of 

inhalable particles small enough to 

penetrate to the thoracic region 

(including the tracheobronchial and 

alveolar regions) of the respiratory tract 

(referred to as thoracic particles). 

Current NAAQS use PM2.5 as the 

indicator for fine particles (with PM2.5

referring to particles with a nominal 

mean aerodynamic diameter less than or 

equal to 2.5 μm), and use PM10 as the 

indicator for purposes of regulating the 

coarse fraction of PM10 (referred to as 

thoracic coarse particles or coarsefraction particles; generally including 

particles with a nominal mean 

aerodynamic diameter greater than 2.5 

μm and less than or equal to 10 μm, or 

PM10–2.5). Ultrafine particles are a subset 

of fine particles, generally less than 100 

nanometers (0.1 μm) in aerodynamic 

diameter. 

Fine particles are produced primarily 

by combustion processes and by 

transformations of gaseous emissions 

(e.g., SOX, NOX and VOC) in the 

atmosphere. The chemical and physical 

properties of PM2.5 may vary greatly 

with time, region, meteorology, and 

source category. Thus, PM2.5 may 

include a complex mixture of different 

pollutants including sulfates, nitrates, 

organic compounds, elemental carbon 

and metal compounds. These particles 

can remain in the atmosphere for days 

to weeks and travel hundreds to 

thousands of kilometers. 

(a) Health Effects of PM 

Scientific studies show ambient PM is 

associated with a series of adverse 

health effects. These health effects are 

discussed in detail in EPA’s 2004 

Particulate Matter Air Quality Criteria 

Document (PM AQCD) and the 2005 PM 

Staff Paper.18 19 20 Further discussion of 


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22904 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

review by the Clean Air Scientific Advisory 

Committee (CASAC) of EPA’s Science Advisory 

Board. Comments from the general public have also 

been requested. For more information, see http://

cfpub.epa.gov/ncea/cfm/recordisplay.cfm?

deid=210586. 

21U.S. EPA (2006). National Ambient Air Quality 

Standards for Particulate Matter. 71 FR 61144, 

October 17, 2006. 

22 Ku ̈nzli, N., Jerrett, M., Mack, W.J., et al. (2004). 

Ambient air pollution and atherosclerosis in Los 

Angeles. Environ Health Perspect.,113, 201–206 

23This study is included in the 2006 Provisional 

Assessment of Recent Studies on Health Effects of 

Particulate Matter Exposure. The provisional 

assessment did not and could not (given a very 

short timeframe) undergo the extensive critical 

review by CASAC and the public, as did the PM 

AQCD. The provisional assessment found that the 

‘‘new’’ studies expand the scientific information and 

provide important insights on the relationship 

between PM exposure and health effects of PM. The 

provisional assessment also found that ‘‘new’’ 

studies generally strengthen the evidence that acute 

and chronic exposure to fine particles and acute 

exposure to thoracic coarse particles are associated 

with health effects. Further, the provisional science 

assessment found that the results reported in the 

studies did not dramatically diverge from previous 

findings, and taken in context with the findings of 

the AQCD, the new information and findings did 

not materially change any of the broad scientific 

conclusions regarding the health effects of PM 

exposure made in the AQCD. However, it is 

important to note that this assessment was limited 

to screening, surveying, and preparing a provisional 

assessment of these studies. For reasons outlined in 

Section I.C of the preamble for the final PM NAAQS 

rulemaking in 2006 (see 71 FR 61148–49, October 

17, 2006), EPA based its NAAQS decision on the 

science presented in the 2004 AQCD. 

24 Dockery, D.W., Pope, C.A. III, Xu, X, et al. 

(1993). An association between air pollution and 

mortality in six U.S. cities. N Engl J Med, 329, 

1753–1759. Retrieved on March 19, 2009 from 

http://content.nejm.org/cgi/content/full/329/24/ 

1753. 

25Pope, C.A., III, Thun, M.J., Namboodiri, M.M., 

Dockery, D.W., Evans, J.S., Speizer, F.E., and Heath, 

C.W., Jr. (1995). Particulate air pollution as a 

predictor of mortality in a prospective study of U.S. 

adults. Am. J. Respir. Crit. Care Med, 151, 669–674. 

26 Krewski, D., Burnett, R.T., Goldberg, M.S., et al. 

(2000). Reanalysis of the Harvard Six Cities study 

and the American Cancer Society study of 

particulate air pollution and mortality. A special 

report of the Institute’s Particle Epidemiology 

Reanalysis Project. Cambridge, MA: Health Effects 

Institute. Retrieved on March 19, 2009 from 

http://es.epa.gov/ncer/science/pm/hei/Rean-Exec

Summ.pdf. 

27Pope, C. A., III, Burnett, R.T., Thun, M.J., Calle, 

E.E., Krewski, D., Ito, K., Thurston, G.D., (2002). 

Lung cancer, cardiopulmonary mortality, and longterm exposure to fine particulate air pollution. J. 

Am. Med. Assoc., 287, 1132–1141. 

28U.S. EPA (2002). Health Assessment Document 

for Diesel Engine Exhaust. EPA/600/8–90/057F 

Office of Research and Development, Washington 

DC. Retrieved on March 17, 2009 from http://cfpub.

epa.gov/ncea/cfm/recordisplay.cfm?deid=29060. 

pp. 1–1 1–2. 

29U.S. EPA (2002). Health Assessment Document 

for Diesel Engine Exhaust. EPA/600/8–90/057F 

Office of Research and Development, Washington, 

DC. Retrieved on March 17, 2009 from http:// 

cfpub.epa.gov/ncea/cfm/recordisplay.cfm?

deid=29060. 

30U.S. EPA (2002). Health Assessment Document 

for Diesel Engine Exhaust. EPA/600/8–90/057F 

Office of Research and Development, Washington 

DC. Retrieved on March 17, 2009 from http:// 

cfpub.epa.gov/ncea/cfm/recordisplay.cfm?

deid=29060. pp. 1–1 1–2. 

health effects associated with PM can 

also be found in the RIA for this rule. 

Health effects associated with shortterm exposures (hours to days) to 

ambient PM include premature 

mortality, aggravation of cardiovascular 

and lung disease (as indicated by 

increased hospital admissions and 

emergency department visits), increased 

respiratory symptoms including cough 

and difficulty breathing, decrements in 

lung function, altered heart rate rhythm, 

and other more subtle changes in blood 

markers related to cardiovascular 

health.21 Long-term exposure to PM2.5

and sulfates has also been associated 

with mortality from cardiopulmonary 

disease and lung cancer, and effects on 

the respiratory system such as reduced 

lung function growth or development of 

respiratory disease. A new analysis 

shows an association between long-term 

PM2.5 exposure and a subclinical 

measure of atherosclerosis.22 23

Studies examining populations 

exposed over the long term (one or more 

years) to different levels of air pollution, 

including the Harvard Six Cities Study 

and the American Cancer Society Study, 

show associations between long-term 

exposure to ambient PM2.5 and both all 

cause and cardiopulmonary premature 

mortality.24 25 26 In addition, an 

extension of the American Cancer 

Society Study shows an association 

between PM2.5 and sulfate 

concentrations and lung cancer 

mortality.27

(b) Health Effects of Diesel Particulate 

Matter 

Marine diesel engines emit diesel 

exhaust (DE), a complex mixture 

composed of carbon dioxide, oxygen, 

nitrogen, water vapor, carbon monoxide, 

nitrogen compounds, sulfur compounds 

and numerous low-molecular-weight 

hydrocarbons. A number of these 

gaseous hydrocarbon components are 

individually known to be toxic, 

including aldehydes, benzene and 1,3- 

butadiene. The diesel particulate matter 

(DPM) present in DE consists of fine 

particles (< 2.5 μm), including a 

subgroup with a large number of 

ultrafine particles (< 0.1 μm). These 

particles have a large surface area which 

makes them an excellent medium for 

adsorbing organics and their small size 

makes them highly respirable. Many of 

the organic compounds present in the 

gases and on the particles, such as 

polycyclic organic matter (POM), are 

individually known to have mutagenic 

and carcinogenic properties. Diesel 

exhaust varies significantly in chemical 

composition and particle sizes between 

different engine types (heavy-duty, 

light-duty), engine operating conditions 

(idle, accelerate, decelerate), and fuel 

formulations (high/low sulfur fuel). 

Also, there are emissions differences 

between on-road and nonroad engines 

because the nonroad engines are 

generally of older technology. This is 

especially true for marine diesel 

engines.28

After being emitted in the engine 

exhaust, diesel exhaust undergoes 

dilution as well as chemical and 

physical changes in the atmosphere. 

The lifetime for some of the compounds 

present in diesel exhaust ranges from 

hours to days.29

(i) Diesel Exhaust: Potential Cancer 

Effects 

In EPA’s 2002 Diesel Health 

Assessment Document (Diesel HAD),30

exposure to diesel exhaust was 

classified as likely to be carcinogenic to 

humans by inhalation from 

environmental exposures, in accordance 

with the revised draft 1996/1999 EPA 

cancer guidelines. A number of other 

agencies (National Institute for 

Occupational Safety and Health, the 

International Agency for Research on 

Cancer, the World Health Organization, 

California EPA, and the U.S. 

Department of Health and Human 

Services) have made similar 

classifications. However, EPA also 

concluded in the Diesel HAD that it is 

not possible currently to calculate a 

cancer unit risk for diesel exhaust due 

to a variety of factors that limit the 

current studies, such as limited 

quantitative exposure histories in 

occupational groups investigated for 

lung cancer. 

For the Diesel HAD, EPA reviewed 22 

epidemiologic studies on the subject of 

the carcinogenicity of workers exposed 

to diesel exhaust in various 

occupations, finding increased lung 

cancer risk, although not always 

statistically significant, in 8 out of 10 

cohort studies and 10 out of 12 casecontrol studies within several 

industries. Relative risk for lung cancer 

associated with exposure ranged from 

1.2 to 1.5, although a few studies show 

relative risks as high as 2.6. 

Additionally, the Diesel HAD also relied 

on two independent meta-analyses, 

which examined 23 and 30 occupational 

studies respectively, which found 

statistically significant increases in 

smoking-adjusted relative lung cancer 

risk associated with exposure to diesel 

exhaust of 1.33 to 1.47. These metaanalyses demonstrate the effect of 

pooling many studies and in this case 

show the positive relationship between 


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31Bhatia, R., Lopipero, P., Smith, A. (1998). 

Diesel exposure and lung cancer. Epidemiology, 

9(1), 84–91. 

32Lipsett, M. Campleman, S. (1999). 

Occupational exposure to diesel exhaust and lung 

cancer: a meta-analysis. Am J Public Health, 80(7), 

1009–1017. 

33 Ishinishi, N. Kuwabara, N. Takaki, Y., et al. 

(1988). Long-term inhalation experiments on diesel 

exhaust. In: Diesel exhaust and health risks. Results 

of the HERP studies. Ibaraki, Japan: Research 

Committee for HERP Studies; pp.11–84. 

34Heinrich, U., Fuhst, R., Rittinghausen, S., et al. 

(1995). Chronic inhalation exposure of Wistar rats 

and two different strains of mice to diesel engine 

exhaust, carbon black, and titanium dioxide. Inhal 

Toxicol, 7, 553–556. 

35Mauderly, J.L., Jones, R.K., Griffith, W.C., et al. 

(1987). Diesel exhaust is a pulmonary carcinogen in 

rats exposed chronically by inhalation. Fundam. 

Appl. Toxicol., 9, 208–221. 

36Nikula, K.J., Snipes, M.B., Barr, E.B., et al. 

(1995). Comparative pulmonary toxicities and 

carcinogenicities of chronically inhaled diesel 

exhaust and carbon black in F344 rats. Fundam. 

Appl. Toxicol, 25, 80–94. 

37U.S. EPA (2002). Health Assessment Document 

for Diesel Engine Exhaust. EPA/600/8–90/057F 

Office of Research and Development, Washington, 

DC. Retrieved on March 17, 2009 from http:// 

cfpub.epa.gov/ncea/cfm/recordisplay.cfm?

deid=29060. p. 9–9. 

38 Di, P., Servin, A., Rosenkranz, K., Schwehr, B., 

Tran, H., (2006). Diesel Particulate Matter Exposure 

Assessment Study for the Ports of Los Angeles and 

Long Beach. Sacramento, CA: California EPA, 

California Air Resources Board (CARB). Retrieved 

March 19, 2009 from http://www.arb.ca.gov/regact/ 

marine2005/portstudy0406.pdf. 

39 ICF International. September 28, 2007. 

Estimation of diesel particulate matter 

concentration isopleths for marine harbor areas and 

Continued 

diesel exhaust exposure and lung cancer 

across a variety of diesel exhaustexposed occupations.31 32

In the absence of a cancer unit risk, 

the Diesel HAD sought to provide 

additional insight into the significance 

of the diesel exhaust-cancer hazard by 

estimating possible ranges of risk that 

might be present in the population. An 

exploratory analysis was used to 

characterize a possible risk range by 

comparing a typical environmental 

exposure level for highway diesel 

sources to a selected range of 

occupational exposure levels. The 

occupationally observed risks were then 

proportionally scaled according to the 

exposure ratios to obtain an estimate of 

the possible environmental risk. A 

number of calculations are needed to 

accomplish this, and these can be seen 

in the EPA Diesel HAD. The outcome 

was that environmental risks from 

diesel exhaust exposure could range 

from a low of 10¥4 to 10¥5 to as high 

as 10¥3, reflecting the range of 

occupational exposures that could be 

associated with the relative and absolute 

risk levels observed in the occupational 

studies. Because of uncertainties, the 

analysis acknowledged that the risks 

could be lower than 10¥4 or 10¥5, and 

a zero risk from diesel exhaust exposure 

was not ruled out. 

(ii) Diesel Exhaust: Other Health Effects 

Noncancer health effects of acute and 

chronic exposure to diesel exhaust 

emissions are also of concern to the 

EPA. EPA derived a diesel exhaust 

reference concentration (RfC) from 

consideration of four well-conducted 

chronic rat inhalation studies showing 

adverse pulmonary effects.33 34 35 36 The 

RfC is 5 μg/m3 for diesel exhaust as 

measured by DPM. This RfC does not 

consider allergenic effects such as those 

associated with asthma or immunologic 

effects. There is growing evidence, 

discussed in the Diesel HAD, that 

exposure to diesel exhaust can 

exacerbate these effects, but the 

exposure-response data are presently 

lacking to derive an RfC. The EPA 

Diesel HAD states, ‘‘With DPM [diesel 

particulate matter] being a ubiquitous 

component of ambient PM, there is an 

uncertainty about the adequacy of the 

existing DE [diesel exhaust] noncancer 

database to identify all of the pertinent 

DE-caused noncancer health hazards.’’ 

(p. 9–19). The Diesel HAD concludes 

‘‘that acute exposure to DE [diesel 

exhaust] has been associated with 

irritation of the eye, nose, and throat, 

respiratory symptoms (cough and 

phlegm), and neurophysiological 

symptoms such as headache, 

lightheadedness, nausea, vomiting, and 

numbness or tingling of the 

extremities.’’ 37

(iii) Ambient PM2.5 Levels and Exposure 

to Diesel Exhaust PM 

The Diesel HAD also briefly 

summarizes health effects associated 

with ambient PM and discusses the 

EPA’s annual PM2.5 NAAQS of 15 μg/ 

m3. There is a much more extensive 

body of human data showing a wide 

spectrum of adverse health effects 

associated with exposure to ambient 

PM, of which diesel exhaust is an 

important component. The PM2.5

NAAQS is designed to provide 

protection from the noncancer and 

premature mortality effects of PM2.5 as 

a whole. 

(iv) Diesel Exhaust PM Exposures 

Exposure of people to diesel exhaust 

depends on their various activities, the 

time spent in those activities, the 

locations where these activities occur, 

and the levels of diesel exhaust 

pollutants in those locations. The major 

difference between ambient levels of 

diesel particulate and exposure levels 

for diesel particulate is that exposure 

accounts for a person moving from 

location to location, proximity to the 

emission source, and whether the 

exposure occurs in an enclosed 

environment. 

Occupational Exposures 

Occupational exposures to diesel 

exhaust from mobile sources, including 

marine diesel engines, can be several 

orders of magnitude greater than typical 

exposures in the non-occupationally 

exposed population. 

Over the years, diesel particulate 

exposures have been measured for a 

number of occupational groups. A wide 

range of exposures have been reported, 

from 2 μg/m3 to 1,280 μg/m3, for a 

variety of occupations. As discussed in 

the Diesel HAD, the National Institute of 

Occupational Safety and Health 

(NIOSH) has estimated a total of 

1,400,000 workers are occupationally 

exposed to diesel exhaust from on-road 

and nonroad vehicles including marine 

diesel engines. 

Elevated Concentrations and Ambient 

Exposures in Mobile Source-Impacted 

Areas 

Regions immediately downwind of 

marine ports may experience elevated 

ambient concentrations of directlyemitted PM2.5 from diesel engines. Due 

to the unique nature of marine ports, 

emissions from a large number of diesel 

engines are concentrated in a small area. 

A 2006 study from the California Air 

Resources Board (CARB) evaluated air 

quality impacts of diesel engine 

emissions within the Ports of Long 

Beach and Los Angeles in California, 

one of the largest ports in the U.S.38 The 

port study employed the ISCST3 

dispersion model. With local 

meteorological data used in the 

modeling, annual average 

concentrations were substantially 

elevated over an area exceeding 200,000 

acres. Because the ports are located near 

heavily-populated areas, the modeling 

indicated that over 700,000 people lived 

in areas with at least 0.3 μg/m3 of portrelated diesel PM in ambient air, about 

360,000 people lived in areas with at 

least 0.6 μg/m3 of diesel PM, and about 

50,000 people lived in areas with at 

least 1.5 μg/m3 of ambient diesel PM 

directly from the port. This study 

highlights the substantial contribution 

ports can make to elevated ambient 

concentrations in populated areas. 

EPA recently updated its initial 

screening-level analysis of a 

representative selection of national 

marine port areas to better understand 

the populations that are exposed to 

DPM emissions from these 

facilities.39 40 41 42 As part of this study, 


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22906 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

rail yards. Memorandum to EPA under Work 

Assignment Number 0–3, Contract Number EP–C– 

06–094. This memo is available in Docket EPA– 

HQ–OAR–2007–0121. 

40 ICF International. September 28, 2007. 

Estimation of diesel particulate matter population 

exposure near selected harbor areas and rail yards. 

Memorandum to EPA under Work Assignment 

Number 0–3, Contract Number EP–C–06–094. This 

memo is available in Docket EPA–HQ–OAR–2007– 

0121. 

41 ICF International, December 10, 2008. 

Estimation of diesel particulate matter population 

exposure near selected harbor areas with revised 

harbor emissions. Memorandum to EPA under 

Work Assignment Number 2–9. Contract Number 

EP–C–06–094. This memo is available in Docket 

EPA–HQ–OAR–2007–0121. 

42 ICF International. December 1, 2008. 

Estimation of diesel particulate matter 

concentration isopleths near selected harbor areas 

with revised emissions. Memorandum to EPA 

under Work Assignment Number 1–9. Contract 

Number EP–C–06–094. This memo is available in 

Docket EPA–HQ–OAR–2007–0121. 

43The Agency selected a representative sample 

from the top 150 U.S. ports including coastal, 

inland, and Great Lake ports. 

44U.S. EPA (2006). Air Quality Criteria for Ozone 

and Related Photochemical Oxidants (Final). EPA/ 

600/R–05/004aF–cF. Washington, DC: U.S. EPA. 

Retrieved on March 19, 2009 from Docket EPA– 

HQ–OAR–2003–0190 at http:// 

www.regulations.gov/. 

45U.S. EPA (2006). Air Quality Criteria for Ozone 

and Related Photochemical Oxidants (Final). EPA/ 

600/R–05/004aF–cF. Washington, DC: U.S. EPA. 

Retrieved on March 19, 2009 from Docket EPA– 

HQ–OAR–2003–0190 at http:// 

www.regulations.gov/. 

46U.S. EPA (2007). Review of the National 

Ambient Air Quality Standards for Ozone: Policy 

Assessment of Scientific and Technical 

Information, OAQPS Staff Paper. EPA–452/R–07– 

003. Washington, DC, U.S. EPA. Retrieved on 

March 19, 2009 from Docket EPA–HQ–OAR–2003– 

0190 at http://www.regulations.gov/. 

47National Research Council (NRC), 2008. 

Estimating Mortality Risk Reduction and Economic 

Benefits from Controlling Ozone Air Pollution. The 

National Academies Press: Washington, DC. 

a computer geographic information 

system (GIS) was used to identify the 

locations and property boundaries of 45 

marine ports.43 Census information was 

used to estimate the size and 

demographic characteristics of the 

population living in the vicinity of the 

ports. The results indicate that at least 

18 million people, including a 

disproportionate number of low-income 

households, African-Americans, and 

Hispanics, live in the vicinity of these 

facilities and are being exposed to 

annual average ambient DPM levels that 

are 2.0 μg/m3 and 0.2 μg/m3 above 

levels found in areas further from these 

facilities. These populations will benefit 

from the coordinated strategy. This 

study is discussed in greater detail in 

Chapter 2 of the RIA and detailed 

findings of this study are available in 

the public docket for this rulemaking. 

(2) Ozone 

Ground-level ozone pollution is 

typically formed by the reaction of VOC 

and NOX in the lower atmosphere in the 

presence of heat and sunlight. These 

pollutants, often referred to as ozone 

precursors, are emitted by many types of 

pollution sources, such as highway and 

nonroad motor vehicles and engines, 

power plants, chemical plants, 

refineries, makers of consumer and 

commercial products, industrial 

facilities, and smaller area sources. 

The science of ozone formation, 

transport, and accumulation is 

complex.44 Ground-level ozone is 

produced and destroyed in a cyclical set 

of chemical reactions, many of which 

are sensitive to temperature and 

sunlight. When ambient temperatures 

and sunlight levels remain high for 

several days and the air is relatively 

stagnant, ozone and its precursors can 

build up and result in more ozone than 

typically occurs on a single hightemperature day. Ozone can be 

transported hundreds of miles 

downwind from precursor emissions, 

resulting in elevated ozone levels even 

in areas with low local VOC or NOX

emissions. 

(a) Health Effects of Ozone 

The health and welfare effects of 

ozone are well documented and are 

assessed in EPA’s 2006 Air Quality 

Criteria Document (ozone AQCD) and 

2007 Staff Paper.45 46 Ozone can irritate 

the respiratory system, causing 

coughing, throat irritation, and/or 

uncomfortable sensation in the chest. 

Ozone can reduce lung function and 

make it more difficult to breathe deeply; 

breathing may also become more rapid 

and shallow than normal, thereby 

limiting a person’s activity. Ozone can 

also aggravate asthma, leading to more 

asthma attacks that require medical 

attention and/or the use of additional 

medication. In addition, there is 

suggestive evidence of a contribution of 

ozone to cardiovascular-related 

morbidity and highly suggestive 

evidence that short-term ozone exposure 

directly or indirectly contributes to nonaccidental and cardiopulmonary-related 

mortality, but additional research is 

needed to clarify the underlying 

mechanisms causing these effects. In a 

recent report on the estimation of ozonerelated premature mortality published 

by the National Research Council (NRC), 

a panel of experts and reviewers 

concluded that short-term exposure to 

ambient ozone is likely to contribute to 

premature deaths and that ozone-related 

mortality should be included in 

estimates of the health benefits of 

reducing ozone exposure.47 Animal 

toxicological evidence indicates that 

with repeated exposure, ozone can 

inflame and damage the lining of the 

lungs, which may lead to permanent 

changes in lung tissue and irreversible 

reductions in lung function. People who 

are more susceptible to effects 

associated with exposure to ozone can 

include children, the elderly, and 

individuals with respiratory disease 

such as asthma. Those with greater 

exposures to ozone, for instance due to 

time spent outdoors (e.g., children and 

outdoor workers), are of particular 

concern. 

The 2006 ozone AQCD also examined 

relevant new scientific information that 

has emerged in the past decade, 

including the impact of ozone exposure 

on such health effects as changes in 

lung structure and biochemistry, 

inflammation of the lungs, exacerbation 

and causation of asthma, respiratory 

illness-related school absence, hospital 

admissions and premature mortality. 

Animal toxicological studies have 

suggested potential interactions between 

ozone and PM with increased responses 

observed to mixtures of the two 

pollutants compared to either ozone or 

PM alone. The respiratory morbidity 

observed in animal studies along with 

the evidence from epidemiologic studies 

supports a causal relationship between 

acute ambient ozone exposures and 

increased respiratory-related emergency 

room visits and hospitalizations in the 

warm season. In addition, there is 

suggestive evidence of a contribution of 

ozone to cardiovascular-related 

morbidity and non-accidental and 

cardiopulmonary mortality. 

(3) NOX and SOX

Nitrogen dioxide (NO2) is a member of 

the NOX family of gases. Most NO2 is 

formed in the air through the oxidation 

of nitric oxide (NO) emitted when fuel 

is burned at a high temperature. SO2, a 

member of the sulfur oxide (SOX) family 

of gases, is formed from burning fuels 

containing sulfur (e.g., coal or oil 

derived), extracting gasoline from oil, or 

extracting metals from ore. 

SO2 and NO2 can dissolve in water 

vapor and further oxidize to form 

sulfuric and nitric acid which react with 

ammonia to form sulfates and nitrates, 

both of which are important 

components of ambient PM. The health 

effects of ambient PM are discussed in 

Section II.A.1 of this preamble. NOX

along with non-methane hydrocarbon 

(NMHC) are the two major precursors of 

ozone. The health effects of ozone are 

covered in Section II.A.2. 

(a) Health Effects of NOX

Information on the health effects of 

NO2 can be found in the U.S. 

Environmental Protection Agency 


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48U.S. EPA (2008). Integrated Science 

Assessment for Oxides of Nitrogen—Health Criteria 

(Final Report). EPA/600/R–08/071. Washington, 

DC: U.S. EPA. Retrieved on March 19, 2009 from 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?

deid=194645. 

49U.S. EPA (2008). Integrated Science 

Assessment (ISA) for Sulfur Oxides—Health 

Criteria (Final Report). EPA/600/R–08/047F. 

Washington, DC: U.S. Environmental Protection 

Agency. Retrieved on March 18, 2009 from 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?

deid=198843. 

50 Dillman, K., Geiser, L., & Brenner, G. (2007). 

Air Quality Bio-Monitoring with Lichens. The 

Togass National Forest. USDA Forest Service. 

Retrieved March 18, 2009 from http://gis.nacse.org/ 

lichenair/?page=reports. 

51Alaska Department of Environmental 

Conservation, ‘‘Statement in Support of EPA 

Considering Alaska as Part of a Marine Emission 

Control Area,’’ October 1, 2008. 

52U.S. EPA (2008). Nitrogen Dioxide/Sulfur 

Dioxide Secondary NAAQS Review: Integrated 

Science Assessment (ISA). Washington, DC: U.S. 

Environmental Protection Agency. Retrieved on 

March 18, 2009 from http://cfpub.epa.gov/ncea/ 

cfm/recordisplay.cfm?deid=180903. 

Integrated Science Assessment (ISA) for 

Nitrogen Oxides.48 The U.S. EPA has 

concluded that the findings of 

epidemiologic, controlled human 

exposure, and animal toxicological 

studies provide evidence that is 

sufficient to infer a likely causal 

relationship between respiratory effects 

and short-term NO2 exposure. The ISA 

concludes that the strongest evidence 

for such a relationship comes from 

epidemiologic studies of respiratory 

effects including symptoms, emergency 

department visits, and hospital 

admissions. The ISA also draws two 

broad conclusions regarding airway 

responsiveness following NO2 exposure. 

First, the ISA concludes that NO2

exposure may enhance the sensitivity to 

allergen-induced decrements in lung 

function and increase the allergeninduced airway inflammatory response 

at exposures as low as 0.26 ppm NO2 for 

30 minutes. Second, exposure to NO2

has been found to enhance the inherent 

responsiveness of the airway to 

subsequent nonspecific challenges in 

controlled human exposure studies of 

asthmatic subjects. Enhanced airway 

responsiveness could have important 

clinical implications for asthmatics 

since transient increases in airway 

responsiveness following NO2 exposure 

have the potential to increase symptoms 

and worsen asthma control. Together, 

the epidemiologic and experimental 

data sets form a plausible, consistent, 

and coherent description of a 

relationship between NO2 exposures 

and an array of adverse health effects 

that range from the onset of respiratory 

symptoms to hospital admission. 

Although the weight of evidence 

supporting a causal relationship is 

somewhat less certain than that 

associated with respiratory morbidity, 

NO2 has also been linked to other health 

endpoints. These include all-cause 

(nonaccidental) mortality, hospital 

admissions or emergency department 

visits for cardiovascular disease, and 

decrements in lung function growth 

associated with chronic exposure. 

(b) Health Effects of SOX

Information on the health effects of 

SO2 can be found in the U.S. 

Environmental Protection Agency 

Integrated Science Assessment for 

Sulfur Oxides.49 SO2 has long been 

known to cause adverse respiratory 

health effects, particularly among 

individuals with asthma. Other 

potentially sensitive groups include 

children and the elderly. During periods 

of elevated ventilation, asthmatics may 

experience symptomatic 

bronchoconstriction within minutes of 

exposure. Following an extensive 

evaluation of health evidence from 

epidemiologic and laboratory studies, 

the EPA has concluded that there is a 

causal relationship between respiratory 

health effects and short-term exposure 

to SO2. Separately, based on an 

evaluation of the epidemiologic 

evidence of associations between shortterm exposure to SO2 and mortality, the 

EPA has concluded that the overall 

evidence is suggestive of a causal 

relationship between short-term 

exposure to SO2 and mortality. 

B. Environmental Impacts 

(1) Deposition of Nitrogen and Sulfur 

Emissions of NOX and SOX from ships 

contribute to atmospheric deposition of 

nitrogen and sulfur in the U.S. 

Atmospheric deposition of nitrogen and 

sulfur contributes to acidification, 

altering biogeochemistry and affecting 

animal and plant life in terrestrial and 

aquatic ecosystems across the U.S. The 

sensitivity of terrestrial and aquatic 

ecosystems to acidification from 

nitrogen and sulfur deposition is 

predominantly governed by geology. 

Prolonged exposure to excess nitrogen 

and sulfur deposition in sensitive areas 

acidifies lakes, rivers and soils. 

Increased acidity in surface waters 

creates inhospitable conditions for biota 

and affects the abundance and 

nutritional value of preferred prey 

species, threatening biodiversity and 

ecosystem function. Over time, 

acidifying deposition also removes 

essential nutrients from forest soils, 

depleting the capacity of soils to 

neutralize future acid loadings and 

negatively affecting forest sustainability. 

Major effects include a decline in 

sensitive forest tree species, such as red 

spruce (Picea rubens) and sugar maple 

(Acer saccharum), and a loss of 

biodiversity of fishes, zooplankton, and 

macro invertebrates. 

In addition to the role nitrogen 

deposition plays in acidification, 

nitrogen deposition also causes 

ecosystem nutrient enrichment leading 

to eutrophication that alters 

biogeochemical cycles. Excess nitrogen 

also leads to the loss of nitrogen 

sensitive lichen species as they are 

outcompeted by invasive grasses as well 

as altering the biodiversity of terrestrial 

ecosystems, such as grasslands and 

meadows. Nitrogen deposition 

contributes to eutrophication of 

estuaries and the associated effects 

including toxic algal blooms and fish 

kills. For a broader explanation of the 

topics treated here, refer to the 

description in Section 2.3.1 of the RIA. 

There are a number of important 

quantified relationships between 

nitrogen deposition levels and 

ecological effects. Certain lichen species 

are the most sensitive terrestrial taxa to 

nitrogen with species losses occurring at 

just 3 kg N/ha/yr in the Pacific 

Northwest, southern California and 

Alaska. A United States Forest Service 

study conducted in areas within the 

Tongass Forest in Southeast Alaska 

found evidence of sulfur emissions 

impacting lichen communities.50 The 

authors concluded that the main source 

of nitrogen and sulfur found in lichens 

from Mt. Roberts (directly north of the 

City of Juneau in southeastern Alaska) is 

likely the burning of fossil fuels by 

cruise ships and other vehicles and 

equipment in Juneau. According to the 

Alaska DEC, damage to lichen 

populations has widespread effects in 

Alaskan ecosystems.51

Across the U.S., there are many 

terrestrial and aquatic ecosystems that 

have been identified as particularly 

sensitive to nitrogen deposition. The 

most extreme effects resulting from 

nitrogen deposition on aquatic 

ecosystems are due to nitrogen 

enrichment which contributes to 

‘‘hypoxic’’ zones devoid of life. Three 

hypoxia zones of special concern in the 

U.S. are the zones located in the Gulf of 

Mexico, the Chesapeake Bay in the midAtlantic region, and Long Island Sound 

in the northeast U.S.52

(2) Deposition of Particulate Matter and 

Air Toxics 

The coordinated strategy will reduce 

NOX, SOX, and PM2.5 emissions from 

ships. Ship emissions of PM2.5 contain 

small amounts of metals: Nickel, 


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53Agrawal H., Malloy Q.G.J., Welch W.A., Wayne 

Miller J., Cocker III D.R. (2008) In-use gaseous and 

particulate matter emissions from a modern ocean 

going container vessel. Atmospheric Environment, 

42(21), 5504–5510. 

54Miller, W., et al. (2008 June 10). Measuring 

Emissions from Ocean Going Vessels. Presentation 

presented at the Fuel, Engines, and Control Devices 

Workshop, San Pedro, California. 

55 Isakson J., Persson T.A., E. Selin Lindgren E. 

(2001) Identification and assessment of ship 

emissions and their effects in the harbour of 

Gteborg, Sweeden. Atmospheric Environment, 

35(21), 3659–3666. 

56U.S. EPA (2004). Air Quality Criteria for 

Particulate Matter (AQCD). Washington, DC: U.S. 

Environmental Protection Agency. Retrieved on 

March 18, 2009 from http://cfpub.epa.gov/ncea/ 

cfm/recordisplay.cfm?deid=87903. 

57U.S. EPA (2004). Air Quality Criteria for 

Particulate Matter (AQCD). Washington, DC: U.S. 

Environmental Protection Agency. Retrieved on 

March 18, 2009 from http://cfpub.epa.gov/ncea/ 

cfm/recordisplay.cfm?deid=87903. 

58 Gawel, J.E.; Ahner, B.A.; Friedland, A.J.; Morel, 

F.M.M. (1996) Role for heavy metals in forest 

decline indicated by phytochelatin measurements. 

Nature (London), 381, 64–65. 

59U.S. EPA (2004). Air Quality Criteria for 

Particulate Matter (AQCD). Washington, DC: U.S. 

Environmental Protection Agency. Retrieved on 

March 18, 2009 from http://cfpub.epa.gov/ncea/ 

cfm/recordisplay.cfm?deid=87903. 

60Cotrufo M.F., De Santo A.V., Alfani A., Bartoli 

G., De Cristofaro A. (1995) Effects of urban heavy 

metal pollution on organic matter decomposition in 

Quercus ilex L. Woods. Environmental Pollution, 

89(1), 81–87. 

61Niklinska M., Laskowski R., Maryanski M. 

(1998). Effect of heavy metals and storage time on 

two types of forest litter: Basal respiration rate and 

exchangeable metals. Ecotoxicological 

Environmental Safety, 41, 8–18. 

62U.S. EPA (2004). Air Quality Criteria for 

Particulate Matter (AQCD). Washington, DC: U.S. 

Environmental Protection Agency. Retrieved on 

March 18, 2009 from http://cfpub.epa.gov/ncea/ 

cfm/recordisplay.cfm?deid=87903. 

63 Dickhut R.M., Canuel E.A., Gustafson K.E., Liu 

K., Arzayus K.M., Walker S.E., Edgecombe G., 

Gaylor M.O., MacDonald E.H. (2000). Automotive 

Sources of Carcinogenic Polycyclic Aromatic 

Hydrocarbons Associated with Particulate Matter in 

the Chesapeake Bay Region. Environmental Science 

& Technology, 34(21), 4635–4640. 

64Simcik M.F., Eisenreich, S.J., Golden K.A., et 

al. (1996). Atmospheric Loading of Polycyclic 

Aromatic Hydrocarbons to Lake Michigan as 

Recorded in the Sediments. Environmental Science 

and Technology, 30, 3039–3046. 

65Simcik M.F., Eisenreich S.J., Lioy P.J. (1999). 

Source apportionment and source/sink relationship 

of PAHs in the coastal atmosphere of Chicago and 

Lake Michigan. Atmospheric Environment, 33, 

5071–5079. 

66Poor N., Tremblay R., Kay H., et al. (2002). 

Atmospheric concentrations and dry deposition 

rates of polycyclic aromatic hydrocarbons (PAHs) 

for Tampa Bay, Florida, USA. Atmospheric 

Environment, 38, 6005–6015. 

67Arzavus K.M., Dickhut R.M., Canuel E.A. 

(2001). Fate of Atmospherically Deposited 

Polycyclic Aromatic Hydrocarbons (PAHs) in 

Chesapeake Bay. Environmental Science & 

Technology, 35, 2178–2183. 

68Simcik M.F., Eisenreich, S.J., Golden K.A., et 

al. (1996). Atmospheric Loading of Polycyclic 

Aromatic Hydrocarbons to Lake Michigan as 

Recorded in the Sediments. Environmental Science 

and Technology, 30, 3039–3046. 

69Simcik M.F., Eisenreich S.J., Lioy P.J. (1999). 

Source apportionment and source/sink relationship 

of PAHs in the coastal atmosphere of Chicago and 

Lake Michigan. Atmospheric Environment, 33, 

5071–5079. 

70U.S. EPA (2005). Review of the National 

Ambient Air Quality Standards for Particulate 

Matter: Policy Assessment of Scientific and 

Technical Information, OAQPS Staff Paper. 

Retrieved on April 9, 2009 from http:// 

www.epa.gov/ttn/naaqs/standards/pm/data/ 

pmstaffpaper_20051221.pdf. 

71U.S. EPA (2004). Air Quality Criteria for 

Particulate Matter (AQCD). Volume I Document No. 

EPA600/P–99/002aF and Volume II Document No. 

EPA600/P–99/002bF. Washington, DC: U.S. 

Environmental Protection Agency. Retrieved on 

March 18, 2009 from http://cfpub.epa.gov/ncea/ 

cfm/recordisplay.cfm?deid=87903. 

vanadium, cadmium, iron, lead, copper, 

zinc, and aluminum.53 54 55

Investigations of trace metals near 

roadways and industrial facilities 

indicate that a substantial burden of 

heavy metals can accumulate on 

vegetative surfaces. Copper, zinc, and 

nickel are directly toxic to vegetation 

under field conditions.56 While metals 

typically exhibit low solubility, limiting 

their bioavailability and direct toxicity, 

chemical transformations of metal 

compounds occur in the environment, 

particularly in the presence of acidic or 

other oxidizing species. These chemical 

changes influence the mobility and 

toxicity of metals in the environment. 

Once taken up into plant tissue, a metal 

compound can undergo chemical 

changes, accumulate and be passed 

along to herbivores, or can re-enter the 

soil and further cycle in the 

environment. 

Although there has been no direct 

evidence of a physiological association 

between tree injury and heavy metal 

exposures, heavy metals have been 

implicated because of similarities 

between metal deposition patterns and 

forest decline.57 58 This correlation was 

further explored in high elevation 

forests in the northeast U.S. and the data 

strongly imply that metal stress causes 

tree injury and contributes to forest 

decline in the Northeast.59

Contamination of plant leaves by heavy 

metals can lead to elevated soil levels. 

Trace metals absorbed into the plant 

frequently bind to the leaf tissue, and 

then are lost when the leaf drops. As the 

fallen leaves decompose, the heavy 

metals are transferred into the soil.60 61

Ships also emit air toxics, including 

polycyclic aromatic hydrocarbons 

(PAHs), a class of polycyclic organic 

matter (POM) that contains compounds 

which are known or suspected 

carcinogens. Since the majority of PAHs 

are adsorbed onto particles less than 1.0 

μm in diameter, long range transport is 

possible. Particles of this size can 

remain airborne for days or even months 

and travel distances up to 10,000 km 

before being deposited on terrestrial or 

aquatic surfaces.62 Atmospheric 

deposition of particles is believed to be 

the major source of PAHs to the 

sediments of Lake Michigan, 

Chesapeake Bay, Tampa Bay and other 

coastal areas of the U.S.63 64 65 66 67 PAHs 

tend to accumulate in sediments and 

reach high enough concentrations in 

some coastal environments to pose an 

environmental health threat that 

includes cancer in fish populations, 

toxicity to organisms living in the 

sediment, and risks to those (e.g., 

migratory birds) that consume these 

organisms.68 69 PAHs tend to accumulate 

in sediments and bioaccumulate in fresh 

water, flora and fauna. 

Atmospheric deposition of pollutants 

can reduce the aesthetic appeal of 

buildings and culturally important 

articles through soiling, and can 

contribute directly (or in conjunction 

with other pollutants) to structural 

damage by means of corrosion or 

erosion.70 Atmospheric deposition may 

affect materials principally by 

promoting and accelerating the 

corrosion of metals, by degrading paints, 

and by deteriorating building materials 

such as concrete and limestone. 

Particles contribute to these effects 

because of their electrolytic, 

hygroscopic, and acidic properties, and 

their ability to adsorb corrosive gases 

(principally sulfur dioxide). The rate of 

metal corrosion depends on a number of 

factors, including the deposition rate 

and nature of the pollutant; the 

influence of the metal protective 

corrosion film; the amount of moisture 

present; variability in the 

electrochemical reactions; the presence 

and concentration of other surface 

electrolytes; and the orientation of the 

metal surface. 

(3) Impacts on Visibility 

Emissions from ships contribute to 

poor visibility in the U.S. through their 

primary PM2.5 emissions, as well as 

their NOX and SOX emissions which 

contribute to the formation of secondary 

PM2.5.71 Visibility can be defined as the 

degree to which the atmosphere is 

transparent to visible light. Airborne 

particles degrade visibility by scattering 

and absorbing light. Visibility is 

important because it has direct 

significance to people’s enjoyment of 

daily activities in all parts of the 

country. Individuals value good 

visibility for the well-being it provides 

them directly, where they live and work 

and in places where they enjoy 

recreational opportunities. Visibility is 

also highly valued in significant natural 

areas such as national parks and 


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72U.S. EPA (2004). Air Quality Criteria for 

Particulate Matter (AQCD). Volume I Document No. 

EPA600/P–99/002aF and Volume II Document No. 

EPA600/P–99/002bF. Washington, DC: U.S. 

Environmental Protection Agency. Retrieved on 

March 18, 2009 from http://cfpub.epa.gov/ncea/ 

cfm/recordisplay.cfm?deid=87903. 

73U.S. EPA (2005). Review of the National 

Ambient Air Quality Standard for Particulate 

Matter: Policy Assessment of Scientific and 

Technical Information, OAQPS Staff Paper. EPA– 

452/R–05–005. Washington, DC: U.S. 

Environmental Protection Agency. 

74These areas are defined in section 162 of the 

Act as those national parks exceeding 6,000 acres, 

wilderness areas and memorial parks exceeding 

5,000 acres, and all international parks which were 

in existence on August 7, 1977. 

75As discussed in Section 3.7 of the RIA, the 

inventories used for the air quality modeling in 

2020 and 2030 differ slightly from each other. The 

difference between 2020 and 2030 is small and was 

due to an error in calculating the 200 nautical miles 

distance. In addition, as discussed in Section 3.7 of 

the RIA, the 2020 air quality control case does not 

include global controls for areas that are beyond 

200 nautical miles but within the air quality 

modeling domain. The impact of this latter 

difference is expected to be minimal. 

wilderness areas, and special emphasis 

is given to protecting visibility in these 

areas. For more information on 

visibility, see the final 2004 PM AQCD 

as well as the 2005 PM Staff Paper.72 73

EPA is pursuing a two-part strategy to 

address visibility. First, EPA has set 

secondary PM2.5 standards which act in 

conjunction with the establishment of a 

regional haze program. In setting the 

secondary PM2.5 standard, EPA has 

concluded that PM2.5 causes adverse 

effects on visibility in various locations, 

depending on PM concentrations and 

factors such as chemical composition 

and average relative humidity. Second, 

section 169 of the Clean Air Act 

provides additional authority to address 

existing visibility impairment and 

prevent future visibility impairment in 

the 156 national parks, forests and 

wilderness areas categorized as 

mandatory class I Federal areas (62 FR 

38680–81, July 18, 1997).74 In July 1999, 

the regional haze rule (64 FR 35714) was 

put in place to protect the visibility in 

mandatory class I Federal areas. 

Visibility can be said to be impaired in 

both PM2.5 nonattainment areas and 

mandatory class I Federal areas. 

(4) Plant and Ecosystem Effects of 

Ozone 

Elevated ozone levels contribute to 

environmental effects, with impacts to 

plants and ecosystems being of most 

concern. Ozone can produce both acute 

and chronic injury in sensitive species 

depending on the concentration level 

and the duration of the exposure. Ozone 

effects also tend to accumulate over the 

growing season of the plant, so that even 

low concentrations experienced for a 

longer duration have the potential to 

create chronic stress on vegetation. 

Ozone damage to plants includes visible 

injury to leaves and impaired 

photosynthesis, both of which can lead 

to reduced plant growth and 

reproduction, resulting in reduced crop 

yields, forestry production, and use of 

sensitive ornamentals in landscaping. In 

addition, the impairment of 

photosynthesis, the process by which 

the plant makes carbohydrates (its 

source of energy and food), can lead to 

a subsequent reduction in root growth 

and carbohydrate storage below ground, 

resulting in other, more subtle plant and 

ecosystems impacts. 

These latter impacts include 

increased susceptibility of plants to 

insect attack, disease, harsh weather, 

interspecies competition and overall 

decreased plant vigor. The adverse 

effects of ozone on forest and other 

natural vegetation can potentially lead 

to species shifts and loss from the 

affected ecosystems, resulting in a loss 

or reduction in associated ecosystem 

goods and services. Lastly, visible ozone 

injury to leaves can result in a loss of 

aesthetic value in areas of special scenic 

significance like national parks and 

wilderness areas. The final 2006 ozone 

AQCD presents more detailed 

information on ozone effects on 

vegetation and ecosystems. 

C. Air Quality Modeling Results 

Air quality modeling was performed 

to assess the impact of the coordinated 

strategy. We looked at impacts on future 

ambient PM2.5 and ozone levels, as well 

as nitrogen and sulfur deposition levels 

and visibility impairment. In this 

section, we present information on 

current levels of pollution as well as 

model projected levels of pollution for 

2020 and 2030.75

The air quality modeling uses EPA’s 

Community Multiscale Air Quality 

(CMAQ) model. The CMAQ modeling 

domain is rectangular in shape and 

encompasses all of the lower 48 States, 

portions of Canada and Mexico, and 

areas extending into the ocean up to 

1,000 nautical miles (nm), depending on 

the coast. The smallest area of ocean 

coverage is over the northeast U.S. In 

places like Maine and Cape Cod, the 

easternmost points of the contiguous 

U.S., the distance to the edge of the 

CMAQ modeling domain is 

approximately 150 nm. The rest of the 

U.S. shoreline has at least 200 nm 

between the shoreline and boundary of 

the air quality modeling. The CMAQ 

modeling domain is described in more 

detail in Section 2.4.5.2 of the RIA. The 

performance of the CMAQ modeling 

was evaluated using a 2002 base case 

simulation. More detail about the 

performance evaluation is contained 

within the Section 2.4.5.4 of the RIA. 

The model was able to reproduce 

historical concentrations of ozone and 

PM2.5 at land-based monitors with low 

amounts of bias and error. While we are 

not able to evaluate the model’s 

performance over the ocean due to the 

absence of surface monitors, there is no 

evidence to suggest that model 

performance is unsatisfactory over the 

ocean. 

The emission control scenarios used 

in the air quality modeling are slightly 

different than the final coordinated 

strategy emission control scenarios. For 

example, the 2020 air quality impacts 

are based on inventory estimates that 

were modeled using incorrect ECA 

boundary information off of the western 

coast of the U.S. A calculation error 

placed the western 200 nautical mile 

(nm) ECA boundary approximately 50 

nm closer to shore. Additionally, the 

2020 air quality control case does not 

reflect emission reductions related to 

global controls for areas that are beyond 

200 nm but within the CMAQ air 

quality modeling domain. Finally, the 

emission control scenarios do not 

consider the exemption of Great Lakes 

steamships from the final fuel sulfur 

standards. The impact of these 

differences is expected to be minimal. 

(1) Particulate Matter 

The coordinated strategy described in 

this final rule will significantly reduce 

ambient PM concentrations through 

reductions in emissions of direct PM, as 

well as NOX and SOX which contribute 

to secondary PM. 

(a) Current Levels 

PM2.5 concentrations exceeding the 

level of the PM2.5 NAAQS occur in 

many parts of the country. In 2005, EPA 

designated 39 nonattainment areas for 

the 1997 PM2.5 NAAQS (70 FR 943, 

January 5, 2005). These areas are 

composed of 208 full or partial counties 

with a total population exceeding 88 

million. The 1997 PM2.5 NAAQS was 

recently revised and the 2006 24-hour 

PM2.5 NAAQS became effective on 

December 18, 2006. On October 8, 2009, 

the EPA issued final nonattainment area 

designations for the 24-hour PM2.5

NAAQS (74 FR 58688, November 13, 

2009). These designations include 31 

areas composed of 120 full or partial 

counties. 

(b) Projected Levels 

A number of State governments have 

told EPA that they need the reductions 

the coordinated strategy will provide in 

order to meet and maintain the PM2.5


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76See the Advanced Notice of Proposed Rule 

Making at Docket Number: EPA–HQ–OAR–2007– 

0121. 

77On September 16, 2009, the Administrator 

announced that the EPA is reconsidering the 2008 

ozone standards to determine whether they 

adequately protect public health and the 

environment. She also announced that the Agency 

will propose to temporarily stay the 2008 standards 

for the purpose of attainment and nonattainment 

area designations. Under the stay, all activities to 

designate areas for the 2008 ozone standards would 

be suspended for the duration of the 

reconsideration period. EPA intends to complete 

the reconsideration by August 31, 2010. If, as a 

result of the reconsideration, EPA determines that 

the 2008 ozone standards are not supported by the 

scientific record and promulgates different ozone 

standards, the new 2010 ozone standards would 

replace the 2008 ozone standards and the 

requirement to designate areas for the 2008 

standards would no longer apply. If EPA 

promulgates new ozone standards in 2010, EPA 

intends to accelerate the designations process to 

that the designations would be effective in August 

2011. 

NAAQS.76 Most areas designated as not 

attaining the 1997 PM2.5 NAAQS will 

need to attain the 1997 standards in the 

2010 to 2015 time frame, and then 

maintain them thereafter. The 2006 24- 

hour PM2.5 nonattainment areas will be 

required to attain in the 2014 to 2019 

time frame and then maintain thereafter. 

The fuel sulfur emission standards will 

become effective in 2010 and 2015, and 

the NOX engine emission standards will 

become effective in 2016. Therefore, the 

coordinated strategy emission 

reductions will be useful to States in 

attaining or maintaining the PM2.5

NAAQS. 

EPA has already adopted many 

emission control programs that are 

expected to reduce ambient PM2.5 levels 

and which will assist in reducing the 

number of areas that fail to achieve the 

PM2.5 NAAQS. Even so, our air quality 

modeling for this rule projects that in 

2020, with all current controls but 

excluding the reductions expected to 

occur as a result of the coordinated 

strategy, at least 13 counties with a 

population of almost 30 million may not 

attain the 1997 annual PM2.5 standard of 

15 μg/m3 and 47 counties with a 

population of over 53 million may not 

attain the 2006 24-hour PM2.5 standard 

of 35 μg/m3. These numbers do not 

account for those areas that are close to 

(e.g., within 10 percent of) the PM2.5

standards. These areas, although not 

violating the standards, will also benefit 

from the additional reductions from this 

rule ensuring long term maintenance of 

the PM2.5 NAAQS. 

Air quality modeling of the expected 

impacts of the coordinated strategy 

shows that in 2020 and 2030 all of the 

modeled counties will experience 

decreases in their annual and 24-hour 

PM2.5 design values. For areas with 

current annual PM2.5 design values 

greater than 15μg/m3, the modeled 

future-year, population-weighted annual 

PM2.5 design values are expected to 

decrease on average by 0.8 μg/m3 in 

2020 and by 1.7 μg/m3 in 2030. For 

areas with current 24-hour PM2.5 design 

values greater than 35μg/m3, the 

modeled future-year, populationweighted annual PM2.5 design values are 

expected to decrease on average by 1.3 

μg/m3 in 2020 and by 3.4 μg/m3 in 2030. 

In 2030, the maximum projected 

decrease for an annual PM2.5 design 

value is 6.0 μg/m3 in Miami, FL, and the 

maximum projected decrease for a 24- 

hour PM2.5 design value is 11.7 μg/m 3

in Los Angeles, CA. The air quality 

modeling methodology and the 

projected reductions are discussed in 

more detail in Chapter 2 of the RIA. 

(2) Ozone 

(a) Current Levels 

In 2008, the U.S. EPA amended the 

ozone NAAQS (73 FR 16436, March 27, 

2008). The final 2008 ozone NAAQS 

rule set forth revisions to the previous 

1997 NAAQS for ozone to provide 

increased protection of public health 

and welfare. As of July 31, 2009 there 

are 54 areas designated as 

nonattainment for the 1997 8-hour 

ozone NAAQS, comprising 282 full or 

partial counties with a total population 

of almost 127 million people. These 

numbers do not include the people 

living in areas where there is a future 

risk of failing to maintain or attain the 

1997 8-hour ozone NAAQS. The 

numbers above likely underestimate the 

number of counties that are not meeting 

the ozone NAAQS because the 

nonattainment areas associated with the 

more stringent 2008 8-hour ozone 

NAAQS have not yet been designated.77

Table II–1 provides an estimate, based 

on 2005–07 air quality data, of the 

counties with design values greater than 

the 2008 8-hour ozone NAAQS of 0.075 

ppm. 

TABLE II–1—COUNTIES WITH DESIGN VALUES GREATER THAN THE 2008 OZONE NAAQS BASED ON 2005–2007 AIR

QUALITY DATA

Number of 

counties Population a

1997 Ozone Standard: counties within the 54 areas currently designated as nonattainment (as of 7/31/09) 282 126,831,848 

2008 Ozone Standard: additional counties that would not meet the 2008 NAAQSb ..................................... 227 41,285,262 

Total .......................................................................................................................................................... 509 168,117,110 

Notes: 

aPopulation numbers are from 2000 census data. 

bAttainment designations for the 2008 ozone NAAQS have not yet been made. Nonattainment for the 2008 Ozone NAAQS will be based on 

three years of air quality data from later years. Also, the county numbers in this row include only the counties with monitors violating the 2008 

Ozone NAAQS. The numbers in this table may be an underestimate of the number of counties and populations that will eventually be included in 

areas with multiple counties designated nonattainment. 

(b) Projected Levels 

States with 8-Hour ozone 

nonattainment areas are required to take 

action to bring those areas into 

compliance in the future. Based on the 

final rule designating and classifying 8- 

hour ozone nonattainment areas for the 

1997 standard (69 FR 23951, April 30, 

2004), most 8-hour ozone nonattainment 

areas will be required to attain the 1997 

ozone NAAQS in the 2007 to 2013 time 

frame and then maintain the NAAQS 

thereafter. In addition, there will be 

attainment dates associated with the 

designation of nonattainment areas as a 

result of the reconsideration of the 2008 

ozone NAAQS. Many of these 

nonattainment areas will need to adopt 

additional emission reduction programs, 

and the NOX reductions that will result 

from the coordinated strategy will be 

particularly important for these States. 

EPA has already adopted many 

emission control programs that are 

expected to reduce ambient ozone levels 

and assist in reducing the number of 

areas that fail to achieve the ozone 

NAAQS. Even so, our air quality 

modeling projects that in 2020, with all 


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78Chappelka, AH, Samuelson, LJ. (1998). 

Ambient ozone effects on forest trees of the Eastern 

United States: a review. New Phytologist, 139, 91– 

108. 79Note that while the coordinated strategy does 

not eliminate ship emissions, it will be 

directionally helpful in reducing ship emissions. 80Prasad A.M, Iverson L.R. (2003). Little’s range 

and FIA importance value database for 135 eastern 

U.S. tree species. Northeastern Research Station, 

USDA Forest Service, Delaware, Ohio. [online] 

Retrieved on March 19, 2009, from http:// 

www.fs.fed.us/ne/delaware/4153/global/littlefia/ 

index.html. 

81Heck W.W., Cowling E.B. (1997) The need for 

a Long Term Cumulative Secondary Ozone 

Standard—an Ecological Perspective. Air and Waste 

Management Association, EM, 23–33. 

82U.S. EPA. U.S. EPA’s 2008 Report on the 

Environment (Final Report). U.S. Environmental 

Protection Agency, Washington, DC, EPA/600/R– 

07/045F (NTIS PB2008–112484). 

current controls but excluding the 

reductions achieved through the 

coordinated strategy, up to 50 counties 

with a population of almost 50 million 

may not attain the 2008 ozone standard 

of 0.075 ppm. These numbers do not 

account for those areas that are close to 

(e.g., within 10 percent of) the 2008 

ozone standard. These areas, although 

not violating the standards, will also 

benefit from the additional reductions 

from this rule ensuring long-term 

maintenance of the ozone NAAQS. 

These air quality modeling results 

suggest that emission reductions 

achieved through the coordinated 

strategy will improve both the average 

and population-weighted average ozone 

design value concentrations for the U.S. 

in 2020 and 2030. In addition, the air 

quality modeling shows that on average 

the coordinated program described in 

this action will help bring counties 

closer to ozone attainment as well as 

assist counties whose ozone 

concentrations are within 10 percent 

below the standard. For example, in 

projected nonattainment counties, on a 

population-weighted basis, the 8-hour 

ozone design value will on average 

decrease by 0.5 ppb in 2020 and 1.6 ppb 

in 2030. The air quality modeling 

methodology and the projected 

reductions are discussed in more detail 

in Chapter 2 of the RIA. 

It should be noted that even though 

our air quality modeling predicts 

important reductions in nationwide 

ozone levels, three counties (of 661 that 

were part of the analysis) are expected 

to experience an increase in their ozone 

design values in 2030. There are two 

counties in Washington, Clallam County 

and Clark County, and Orange County, 

CA, which will experience 8-hour ozone 

design value increases due to the NOX

disbenefits which occur in these VOClimited ozone nonattainment areas. 

Briefly, NOX reductions at certain times 

and in some areas can lead to increased 

ozone levels. The air quality modeling 

methodology (Section 2.4.5), the 

projected reductions (Section 2.4), and 

the limited NOX disbenefits (Section 

2.4.2.2.2), are discussed in more detail 

in Chapter 2 of the RIA. 

(c) Case Study of Shipping Emissions 

and Ozone Impacts on Forests 

The section below attempts to 

estimate the impacts of the coordinated 

strategy on forests through a case study. 

Assessing the impact of ground-level 

ozone on forests in the United States 

involves understanding the risk/effect of 

tree species to ozone ambient 

concentrations and accounting for the 

prevalence of those species within the 

forest. As a way to quantify the risk/ 

effect of particular plants to groundlevel ozone, scientists have developed 

ozone-exposure/tree-response functions 

by exposing tree seedlings to different 

ozone levels and measuring reductions 

in growth as ‘‘biomass loss.’’78

With knowledge of the distribution of 

sensitive species and the level of ozone 

at particular locations, it is possible to 

estimate a ‘‘biomass loss’’ for each 

species across their range. EPA 

performed an analysis for 2020 in which 

we examined biomass loss with and 

without ship emissions to determine the 

benefit of reducing these emissions on 

sensitive tree species in the U.S.79 The 

biomass loss attributable to shipping 

appears to range from 0 to 6.5% 

depending on the particular species. 

The species most sensitive to ozone 

related biomass loss in the U.S. is black 

cherry (Prunus serotina); the area of its 

range with more than 10% total biomass 

loss in 2020 decreased by 8.5% in the 

case in which emissions from ships 

were removed. Likewise, yellow-poplar 

(Liriodendron tulipifera), eastern white 

pine (Pinus strobus), aspen (Populus 

spp.), and ponderosa pine (Pinus 

ponderosa) saw areas with more then 

2% biomass loss reduced by 2.1% to 

3.8% in 2020. This 2% level of biomass 

loss is important, because a consensus 

workshop on ozone effects reported that 

a 2% annual biomass loss causes harm 

due to the potential for compounding 

effects over multiple years as short-term 

negative effects on seedlings affect longterm forest health.80 81

(3) Nitrogen and Sulfur Deposition 

(a) Current Levels 

Over the past two decades, the EPA 

has undertaken numerous efforts to 

reduce nitrogen and sulfur deposition 

across the U.S. Analyses of long-term 

monitoring data for the U.S. show that 

deposition of both nitrogen and sulfur 

compounds has decreased over the last 

17 years although many areas continue 

to be negatively impacted by deposition. 

Deposition of inorganic nitrogen and 

sulfur species routinely measured in the 

U.S. between 2004 and 2006 were as 

high as 9.6 kg N/ha/yr and 21.3 kg S/ 

ha/yr. The data shows that reductions 

were more substantial for sulfur 

compounds than for nitrogen 

compounds. These numbers are 

generated by the U.S. national 

monitoring network and they likely 

underestimate nitrogen deposition 

because NH3 is not measured. In the 

eastern U.S., where data are most 

abundant, total sulfur deposition 

decreased by about 36% between 1990 

and 2005 while total nitrogen 

deposition decreased by 19% over the 

same time frame.82

(b) Projected Levels 

The emissions reductions that result 

from the coordinated strategy will 

significantly reduce the annual total 

sulfur and nitrogen deposition occurring 

in sensitive U.S. ecosystems including 

forests, wetlands, lakes, streams, and 

estuaries. For sulfur deposition, 

adopting the coordinated strategy will 

result in reductions ranging from 5% to 

20% in 2020 along the entire Atlantic 

and Gulf coasts with higher levels of 

reduction, exceeding 25%, occurring in 

the near-land coastal waters of the U.S. 

In a few land areas on the Atlantic and 

Gulf coasts, such as the southern parts 

of the States of Louisiana, Texas, and 

Florida, 2020 sulfur deposition 

reductions will be much higher, i.e., 

over 30%. Along the Pacific Coast, 

sulfur deposition reductions will exceed 

25% in the entire Southern California 

area, and the Pacific Northwest. For a 

map of 2020 sulfur reductions and 

additional information on these impacts 

see Section 2.4.3 of the RIA. 

Overall, nitrogen deposition 

reductions in 2020 resulting from the 

coordinated strategy described in this 

action are less than sulfur deposition 

reductions. Nitrogen deposition 

reductions will range from 3% to 7% 

along the entire Atlantic, Pacific and 

Gulf Coasts. As with sulfur deposition 

reductions, a few areas such as the 

southern parts of the States of 

Louisiana, Texas, and Florida will 

experience larger reductions of nitrogen 

up to 9%. The Pacific coastal waters 

will see higher nitrogen reductions, 

exceeding 20% in some instances. See 

Section 2.4.3 of the RIA for a map and 

additional information on nitrogen 

deposition impacts. 


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83The level of visibility impairment in an area is 

based on the light-extinction coefficient and a unit 

less visibility index, called a ‘‘deciview’’, which is 

used in the valuation of visibility. The deciview 

metric provides a scale for perceived visual changes 

over the entire range of conditions, from clear to 

hazy. Under many scenic conditions, the average 

person can generally perceive a change of one 

deciview. The higher the deciview value, the worse 

the visibility. Thus, an improvement in visibility is 

a decrease in deciview value. 

84These emission inventory reductions include 

reductions from ships operating within the 24 

nautical mile regulatory zone off the California 

Coastline, beginning with the effective date of the 

Coordinated Strategy program elements. The 

California regulation contains a provision that 

would sunset the requirements of the rule if the 

Federal program achieves equivalent emission 

reductions. See http://www.arb.ca.gov/regact/2008/ 

fuelogv08/fro13.pdf at 13 CCR 2299.2(j)(1). 

(4) Visibility 

(a) Current Levels 

As mentioned in Section II.C.1, 

millions of people live in nonattainment 

areas for the PM2.5 NAAQS. These 

populations, as well as large numbers of 

individuals who travel to these areas, 

are likely to experience visibility 

impairment. In addition, while visibility 

trends have improved in mandatory 

class I Federal areas, the most recent 

data show that these areas continue to 

suffer from visibility impairment. In 

summary, visibility impairment is 

experienced throughout the U.S., in 

multi-State regions, urban areas, and 

remote mandatory class I Federal areas. 

(b) Projected Levels 

The air quality modeling conducted 

for the coordinated strategy was also 

used to project visibility conditions in 

133 mandatory class I Federal areas 

across the U.S. in 2020 and 2030. The 

results indicate that improvements in 

visibility due to OGV emissions 

reductions will occur in all 133 

mandatory class I Federal areas in the 

future, although all areas will continue 

to have annual average deciview levels 

above background in 2020 and 2030.83

The average visibility on the 20 percent 

worst days at these scenic locales is 

projected to improve by 0.22 deciviews, 

or 1.4 percent in 2020 and by 0.43 

deciviews or 2.7% in 2030. 

The greatest improvements in 

visibilities will occur in coastal areas. 

For instance, the Agua Tibia Wilderness 

area (near Los Angeles) will see a 9% 

improvement (2.17 DV) in 2020 and a 

17% improvement (4.6 DV) in 2030 as 

a result of the emission reductions from 

the coordinated strategy. National parks 

and national wilderness areas in other 

parts of the country will also see 

improvements. For example, in 2030 the 

Swanquarter National Wildlife Refuge 

(North Carolina) will have a 5% 

improvement in visibility (1.11 DV) and 

Acadia National Park (Maine) will have 

a 6% improvement (1.27 DV) with the 

coordinated strategy. Even inland 

mandatory class I Federal areas are 

projected to see improvements as a 

result of the controls from the 

coordinated strategy. For example in 

2030, the Grand Canyon National Park, 

located in the State of Arizona, will see 

a 54% improvement in visibility (0.42 

DV) with the coordinated strategy. For 

the table which contains the full 

visibility results over the 133 analyzed 

areas see Section 2.2.4.2 of the RIA. 

D. Emissions From Ships With Category 

3 Engines 

(1) Overview 

This section describes the 

contribution of Category 3 vessels to 

national emission inventories of NOX, 

PM2.5, and SO2. A Category 3 vessel has 

a Category 3 propulsion engine. 

Emissions from a Category 3 vessel 

include the emissions from both the 

propulsion and auxiliary engines on 

that vessel. Propulsion and auxiliary 

engine emissions were estimated 

separately to account for differences in 

emission factors, engine size and load, 

and activity. 

We estimate that in 2009, Category 3 

vessels will contribute almost 913,000 

tons (10 percent) to the national mobile 

source NOX inventory, about 71,000 

tons (24 percent) to the mobile source 

diesel PM2.5 inventory, and nearly 

597,000 tons (80 percent) to the mobile 

source SO2 inventory. Expressed as a 

percentage of all anthropogenic 

emissions, Category 3 vessels contribute 

6 percent to the national NOX inventory, 

3 percent to the national PM2.5

inventory, and 11 percent to the total 

SO2 inventory in 2009. In 2030, absent 

the strategy discussed in this rule, these 

vessels will contribute about 2.1 million 

tons (40 percent) to the mobile source 

NOX inventory, 168,000 tons (75 

percent) to the mobile source diesel 

PM2.5 inventory, and about 1.4 million 

tons (95 percent) to the mobile source 

SO2 inventory. Expressed as a 

percentage of all anthropogenic 

emissions, Category 3 vessels will 

contribute 19 percent to the national 

NOX inventory, 5 percent to the national 

PM2.5 inventory, and 15 percent to the 

total SO2 inventory in 2030. Under this 

strategy, by 2030, annual NOX emissions 

from these vessels will be reduced by 

1.2 million tons, PM2.5 emissions by 

143,000 tons, and SO2 emissions by 1.3 

million tons.84

Each sub-section below discusses one 

of the three affected pollutants, 

including expected emission reductions 

that will result from the combination of 

the proposed CAA NOX standards along 

with the ECA designation through 

amendment to MARPOL Annex VI and 

related fuel standards. Table II–2 

summarizes the impacts of these 

reductions for 2020 and 2030 on a 

national basis. Chapter 3 of the RIA also 

presents regional emissions inventories, 

such as those for the Great Lakes. Table 

II–3 provides the estimated 2030 NOX

emission reductions (and PM 

reductions) for the coordinated strategy 

compared to the Locomotive and Marine 

rule, Clean Air Nonroad Diesel (CAND) 

program, and the Heavy-Duty Highway 

rule. Further details on our inventory 

estimates are available in Chapter 3 of 

the RIA. Note that the inventories 

presented here do not consider the 

exemption of Great Lakes steamships 

from the final fuel sulfur standards. This 

change to the program is not expected 

to have a significant impact on national 

inventory estimates. We intend to 

follow up with a more detailed study of 

the impacts of the emission control 

program on Great Lakes carriers which 

may provide information that will help 

us refine our Great Lakes emission 

inventories. 

As described in Chapter 3 of the RIA, 

the Category 3 vessel emission 

inventories presented in this section are 

estimated by combining two sets of 

emissions inventories, one for U.S. port 

areas and one for operation on the open 

ocean. With regard to operation on the 

open ocean, it was necessary to specify 

an outer boundary of the modeling 

domain; otherwise, emissions from 

ships operating as far away as Asia or 

Europe would be included in the U.S. 

emission inventory. For simplicity, we 

set the outer boundary for inventory 

modeling roughly equivalent to the U.S. 

Exclusive Economic Zone (EEZ). It 

consists of the area that extends 200 

nautical miles (nm) from the official 

U.S. baseline, which is recognized as 

the low-water line along the coast as 

marked on the official U.S. nautical 

charts in accordance with the articles of 

the Law of the Sea. The U.S. region was 

then clipped to the boundaries of the 

U.S. EEZ. While this area will exclude 

emissions that occur outside the 200 nm 

boundary but that are transported to the 

U.S. landmass, it has the advantage of 

corresponding to an area in which the 

United States has a clear environmental 

interest. This area also corresponds well 

to the CMAQ modeling domain for most 

coasts. 


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85The ECA proposal and associated Technical 

Support Document can be found at http:// 

www.epa.gov/otaq/oceanvessels.htm. France has 

since joined the ECA proposal on behalf of the Saint 

Pierre and Miquelon archipelago. 

TABLE II–2—ESTIMATED NATIONAL (50 STATE) REDUCTIONS IN EMISSIONS FROM CATEGORY 3 COMMERCIAL MARINE

VESSELS a

Pollutant [short tons] 2020 2030 

NOX: 

NOX Emissions without Coordinated Strategy ......................................................................................................... 1,361,000 2,059,000 

NOX Emissions with Coordinated Strategy .............................................................................................................. 952,000 878,000 

NOX Reductions Resulting from Coordinated Strategy ........................................................................................... 409,000 1,181,000 

Direct PM2.5: 

PM2.5 Emissions without Coordinated Strategy ....................................................................................................... 110,000 168,000 

PM2.5 Emissions with Coordinated Strategy ............................................................................................................ 16,000 25,000 

PM2.5 Reductions Resulting from Coordinated Strategy ......................................................................................... 94,000 143,000 

SO2: 

SO2 Emissions without Coordinated Strategy ......................................................................................................... 928,000 1,410,000 

SO2 Emissions with Coordinated Strategy .............................................................................................................. 51,000 78,000 

SO2 Reductions Resulting from Coordinated Strategy ............................................................................................ 877,000 1,332,000 

Notes: 

aEmissions are included within 200 nautical miles of the U.S. coastline. 

TABLE II–3—PROJECTED 2030 EMISSIONS REDUCTIONS FROM RECENT MOBILE SOURCE RULES

[Short Tons] a

Rule NOX PM2.5

Category 3 Marine ........................................................................................................................................................... 1,181,000 143,000 

Locomotive and Marine ................................................................................................................................................... 795,000 27,000 

Clean Air Nonroad Diesel ................................................................................................................................................ 738,000 129,000 

Heavy-Duty Highway ....................................................................................................................................................... 2,600,000 109,000 

Notes: 

a Locomotive and Marine Rule (73 FR 25098, May 6, 2008) Clean Air Nonroad Diesel Rule (69 FR 38957, June 29, 2004) Heavy-Duty Highway Rule (66 FR 5001, January 18, 2001). 

(2) NOX Emission Reductions 

In 2009, annual emissions from 

Category 3 marine vessels will total 

about 913,000 tons. Earlier Tier 1 NOX

engine standards became effective in 

2000, but the reductions due to the Tier 

1 standards are offset by the growth in 

this sector, resulting in increased NOX

emissions of 1.4 million tons and 2.1 

million tons in 2020 and 2030, 

respectively. 

As shown in Table II–2, the 

coordinated strategy will reduce annual 

NOX emissions from the current 

national inventory baseline by 409,000 

tons in 2020 and 1,181,000 tons in 2030. 

As shown in Table II–3, the 2030 NOX

reductions for the coordinated strategy 

will exceed those for the other two 

nonroad rules. 

(3) PM2.5 Emissions Reductions 

In 2009, annual emissions from 

Category 3 marine vessels will total 

about 71,000 tons. By 2030, these 

engines, absent the coordinated strategy, 

would contribute about 168,000 tons. 

As shown in Table II–2, the 

coordinated strategy will reduce annual 

PM2.5 emissions by 94,000 tons in 2020 

and 143,000 tons in 2030. As seen in 

Table II–3, the 2030 PM2.5 emission 

reduction will be larger than any of the 

reductions achieved with other recent 

rules. 

(4) SO2 Emissions Reductions 

In 2009, annual emissions from 

Category 3 marine vessels will total 

about 597,000 tons. By 2030, these 

engines, absent the coordinated strategy, 

will contribute about 1.4 million tons. 

As shown in Table II–2 the 

coordinated strategy will reduce annual 

SO2 emissions by 877,000 tons in 2020 

and 1.3 million tons in 2030. 

III. Engine Standards 

This section details the emission 

standards, implementation dates, and 

other major requirements being 

finalized under the Clean Air Act. A 

discussion of the technological 

feasibility of the finalized NOX

standards follows the description of the 

proposed program. 

Other elements of our coordinated 

strategy to control emissions from ships 

are discussed in subsequent sections. 

Provisions related to our Clean Air Act 

fuel controls are described in Section 

IV. Section V summarizes the U.S. and 

Canada’s recent proposal to amend 

MARPOL Annex VI to designate much 

of the U.S. and Canadian coasts as an 

Emission Control Area.85 Finally, 

provisions revising our Clean Air Act 

test procedures and related certification 

requirements, provisions to implement 

MARPOL Annex VI through APPS, and 

various changes we are making to our 

Category 1 and 2 (marine diesel engines 

with per cylinder displacement less 

than 30 liters per cylinder) marine 

diesel engine program are described in 

Section VI. 

A. What Category 3 Marine Engines Are 

Covered? 

Consistent with our existing marine 

diesel emission control program, the 

engine emission standards being 

finalized will apply to any new marine 

diesel engine with per-cylinder 

displacement at or above 30 liters 

installed on a vessel flagged or 

registered in the United States. 

With regard to marine diesel engines 

on foreign vessels that enter U.S. ports, 

we are retaining our current approach 

and not applying this Clean Air Act 

program to those engines. This is 

appropriate because engines on foreign 

vessels are subject to the same NOX

limits through MARPOL Annex VI, and 

the United States can enforce 

compliance pursuant to Annex VI and 

the recent amendments to the Act to 

Prevent Pollution from Ships (33 U.S.C. 

1901 et seq.). At the same time, 

however, the effectiveness of this 

approach is contingent on the 

designation of U.S. coasts as an ECA 


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22914 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

86Certain public vessels such as military vessels 

and foreign vessels in innocent passage may be 

exempt. 

pursuant to MARPOL Annex VI, since 

the Annex VI Tier III NOX limits are 

geographic in scope and apply only if an 

ECA has been adopted. We anticipate 

that MARPOL Annex VI will be 

amended to include the North American 

ECA proposal. However, if the proposed 

amendment is not adopted in a timely 

manner by IMO, we will reconsider 

whether additional action is necessary 

to control harmful emissions from all 

vessels affecting U.S. air quality. Section 

V contains a description of the ECA 

designation process. 

The combination of this Clean Air Act 

program, MARPOL Annex VI, and APPS 

will apply comparable emission 

standards to the vast majority of vessels 

entering U.S. ports or operating in U.S. 

waters.86 Most significantly, these 

vessels will be required to meet the NOX

limits described below. As described 

later in this Section III and in Section 

VI, there will be some minor differences 

between the finalized Clean Air Act 

program and the requirements that 

apply under MARPOL Annex VI. 

Nevertheless, with respect to U.S. air 

quality, these differences will have a 

negligible effect on emissions from 

foreign vessels. 

B. What Standards Are We Finalizing 

for Newly Manufactured Engines? 

This subsection details the emission 

standards (and implementation dates) 

we are finalizing for freshly 

manufactured (i.e., new) Category 3 

engines on U.S. vessels. As described in 

Section III.C, we believe the standards 

will be challenging to manufacturers, 

yet ultimately feasible and cost-effective 

within the finalized lead time. These 

standards, along with other parts of our 

program, are the outcome of our work 

with stakeholders to resolve the 

challenges associated with applying 

advanced diesel engine technology to 

Category 3 engines to achieve significant 

NOX reductions. 

(1) NOX Standards 

We are finalizing new Tier 2 and Tier 

3 NOX emission standards for Category 

3 marine diesel engines. Our existing 

Tier 1 NOX standards for Category 3 

engines were dependent on the rated 

speed of the engine for speeds between 

130 revolutions per minute (rpm) and 

2,000 rpm. Fixed standards applied for 

lower and higher speeds. Thus, the 

standards were expressed as an equation 

that applies for speeds between 130 rpm 

and 2,000 rpm, along with fixed values 

that were calculated from the equation 

for 130 rpm and 2,000 rpm that apply 

for lower and higher speeds. This was 

done to account for the fact that brakespecific NOX emissions are inherently 

higher for lower speed engines (and 

lower for higher speed engines). Note 

that this same approach is used by the 

IMO for the same technical reasons. We 

are continuing this approach for Tier 2 

and Tier 3, as shown in Table III–1. 

TABLE III–1—NOX EMISSION STANDARDS FOR CATEGORY 3 ENGINES

[g/kW-hr] 

Less than 

130 RPM 

130–2,000 

RPM a

Over 2,000 

RPM 

Tier 1 ................................................................................................................... b 2004 17.0 45.0·n(¥0.20) 9.8 

Tier 2 ................................................................................................................... 2011 14.4 44.0·n(¥0.23) 7.7 

Tier 3 ................................................................................................................... 2016 3.4 9.0·n(¥0.20) 2.0 

Notes: 

aApplicable standards are calculated from n (maximum in-use engine speed in RPM), rounded to one decimal place. 

bTier 1 NOX standards applied for engines originally manufactured after 2004, and also to certain earlier engines. 

Our analysis, which is described in 

the RIA, shows that these standards will 

give the greatest degree of emission 

control achievable considering 

compliance costs, lead time, and other 

relevant factors. The technological bases 

are also discussed briefly below. 

Note that other important provisions 

related to compliance with these 

standards are described in Section VI. 

This includes provisions to ensure 

effective control of NOX emissions over 

a broad range of operating conditions. 

(a) Tier 2 NOX Limits 

We are finalizing the proposed Tier 2 

NOX emission standards for Category 3 

marine diesel engines. In-cylinder 

emission control technology for 

Category 3 marine engines has 

progressed substantially in recent years. 

Significant reductions can be achieved 

in the near term with little or no impact 

on overall vessel performance. These 

technologies include traditional engineout controls such as electronicallycontrolled high-pressure common-rail 

fuel systems, turbocharger optimization, 

compression-ratio changes, and 

electronically-controlled exhaust valves. 

We are setting a near-term NOX

emission standard requiring a reduction 

of approximately 20 percent below the 

current Tier 1 standard beginning 2011. 

(b) Tier 3 NOX Limits 

While the Tier 2 standards will 

achieve modest reductions quickly, the 

finalized Tier 3 standards are intended 

to achieve much greater emission 

reductions through the use of more 

advanced emission control technology. 

These standards will achieve reductions 

of about 80 percent from the current 

Tier 1 standards. As explained in the 

RIA, we evaluated the possibility of 

requiring the Tier 3 limits on an earlier 

schedule than 2016. However, we found 

that a schedule requiring Tier 3 limits 

prior to 2016 had significant feasibility 

issues, and are therefore finalizing the 

2016 implementation date for Tier 3 

standards. Under the finalized 

approach, manufacturers of Category 3 

engines will have about the same 

amount of lead time allowed 

manufacturers for smaller diesel marine 

engines and for locomotives. 

(2) PM and SOX Standards 

We are not establishing new engine 

standards for PM or SOX emissions. We 

intend to rely instead on the use of 

cleaner fuels as described in Section IV 

and V. SOX emissions and the majority 

of the direct PM emissions from 

Category 3 marine engines operated on 

residual fuels are a direct result of fuel 

quality, most notably the sulfur in the 

fuel, and engine-based PM controls are 

not currently feasible for engines using 

these higher sulfur fuels. Other 

components of residual fuel, such as ash 

and heavy metals, also contribute 

directly to PM. 

Using cleaner distillate fuel is the 

most effective means to achieve 

significant PM and SOX reductions for 


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87Flynn, P., et al., ‘‘Minimum Engine Flame 

Temperature Impacts on Diesel and Spark-Ignition 

Engine NOX Production’’, SAE 2000–01–1177, 2000. 

88Heywood, John B., ‘‘Internal Combustion 

Engine Fundamentals’’, McGraw-Hill, 1988. 

Category 3 engines. We are finalizing 

requirements to substantially reduce the 

sulfur content of fuel purchased in the 

U.S. for use in an ECA. This 

complements Annex VI which requires 

that fuels used in ECAs around the 

world have sulfur levels no higher than 

1,000 ppm. This sulfur limit is expected 

to necessitate the use of distillate fuel 

which will result not only in reductions 

in sulfate PM emissions, but also 

reductions in organic PM and metallic 

ash particles in the exhaust. 

Even though the sulfur limit is much 

lower than current levels, it is not clear 

if this fuel sulfur level would be low 

enough to allow Category 3 engines to 

be equipped with the catalytic PM 

filters similar to those being used by 

trucks today. If we were to require 

technology that needs lower sulfur fuel, 

such as 15 ppm, ship operators would 

need to have access to this fuel around 

the world and at this time, it is not clear 

if 15 ppm sulfur fuel could be made 

available globally. Operating on higher 

sulfur fuel, such as for outside of our 

waters, could otherwise result in 

damage to the PM control equipment. In 

any case, the 1,000 ppm sulfur fuel 

requirement alone will eliminate 85 

percent of PM emissions from ships 

operating in ECAs. 

To further our understanding of PM 

emissions from ships, we are requiring 

engine manufacturers to measure and 

report PM emissions even though we are 

not finalizing a PM standard. The 

information gathered will help support 

our efforts as we continue to evaluate 

the feasibility of achieving further PM 

reductions. It will also help us to better 

characterize the PM emission rates 

associated with operating Category 3 

engines on distillate fuel. If we 

determine that further PM reductions 

are feasible or that a specific PM limit 

is necessary to ensure anticipated 

reductions in PM emissions from ships, 

we may propose PM standards for 

Category 3 engines in the future. 

(3) HC and CO Standards 

We are finalizing HC and CO 

standards of 2.0 g/kW-hr and 5.0 g/kWhr, respectively. Emission control 

technologies for Category 3 marine 

engines have been concentrated on 

reducing NOX and PM emissions, but 

these emission standards will prevent 

increases in emissions of HC and CO 

that might otherwise occur as a result of 

use of certain technologies for 

controlling NOX, such as those that 

significantly degrade combustion 

efficiency. 

(4) CO2 Standards 

We are not adopting CO2 standards for 

marine diesel engines at this time. 

Marine diesel engines are included in 

other ongoing Agency actions, including 

our Advance Notice of Proposed 

Rulemaking (ANPRM) for mobile 

sources (73 FR 44353, July 30, 2008) and 

our Greenhouse Gas Reporting Rule (74 

FR 16448, April 10, 2009). In addition, 

EPA is participating in the U.S. 

Government delegation to IMO, which 

is currently engaged in negotiations for 

an international program to address 

greenhouse emissions from ships. 

C. Are the Standards Feasible? 

We have analyzed a variety of 

technologies available for NOX

reduction in the Category 3 marine 

sector. As described in more detail in 

our RIA, we are projecting that marine 

diesel engine manufacturers will choose 

to use in-cylinder, or engine designbased emission control technologies to 

achieve the NOX reductions required to 

meet the final Tier 2 standard. 

The in-cylinder, or engine-out, NOX

emissions of a diesel engine can be 

controlled by utilizing engine design 

and calibration parameters (e.g., fuel 

delivery and valve timing) to limit the 

formation of NOX. NOX formation rate 

has a strong exponential relationship to 

combustion temperature. Therefore, 

high temperatures result in high NOX

formation rates.87 88 Any changes to 

engine design and calibration which can 

reduce the peak temperature realized 

during combustion will also reduce 

NOX emissions. Many of the approaches 

and technologies for reducing incylinder NOX emissions are discussed 

in our RIA. 

To achieve the 80 percent NOX

reductions required to meet the final 

Tier 3 standard, we believe many 

manufacturers will choose selective 

catalytic reduction (SCR) exhaust 

aftertreatment technology. SCR is a 

commonly-used technology for meeting 

stricter NOX emissions standards in 

diesel applications worldwide. 

Stationary power plants fueled with 

coal, diesel and natural gas have used 

SCR for three decades as a means of 

controlling NOX emissions, and 

European heavy-duty truck 

manufacturers are currently using this 

technology to meet Euro 5 emissions 

limits. To a lesser extent, SCR has been 

introduced on diesel engines in the U.S. 

market, but the applications have been 

limited to marine ferryboat and 

stationary electrical power generation 

demonstration projects in California and 

several of the Northeast States. SCR 

systems are currently being designed 

and developed for use on ocean-going 

vessels worldwide, and we project that 

SCR will continue to be a viable 

technology for control of Category 3 

NOX emissions. 

When operating in the ECA, SCR 

units would be active, meaning that 

urea would be injected into the exhaust 

to facilitate catalytic reduction of NOX

emissions. When outside of the ECA, 

the unit would likely be inactive, 

meaning that urea would not be injected 

into the exhaust. When the SCR unit is 

inactive, the exhaust flow could either 

continue to pass through the SCR unit 

or be diverted around the catalyst. 

Under the MARPOL NOX Technical 

Code, a means for monitoring the use of 

urea must be provided which must 

include ‘‘sufficient information to allow 

a ready means of demonstrating that the 

consumption of such additional 

substances is consistent with achieving 

compliance with the applicable NOX

limit.’’ In addition, where a NOX

reducing device, such as SCR, is used, 

one of the options for providing 

verification of compliance with the NOX

standard is through direct measurement 

and monitoring of NOX emissions. A 

more detailed discussion of SCR 

technology can be found in our RIA. 

SCR is not the only approach under 

consideration for meeting the Tier 3 

standards. Manufacturers may choose a 

combination of other in-cylinder 

technologies, such fuel-water 

emulsification, direct water injection, 

intake air humidification, or exhaust gas 

recirculation (EGR) to reduce NOX

emissions and meet the final standards. 

These ‘‘in-cylinder’’ approaches could be 

calibrated and applied in one manner to 

achieve Tier 3 NOX levels when 

operating with an ECA, and then 

adjusted, or re-calibrated, in another 

manner to achieve Tier 2 NOX levels 

when operating outside an ECA. This is 

discussed in more detail in the RIA. 

Another technology, which is 

currently under investigation, is the use 

of an exhaust gas cleaning unit (EGCS) 

to reduce NOX emissions. One 

significant technological issue that must 

be addressed is the prevention of 

nitrates from being introduced into the 

water. In a typical diesel exhaust gas 

mixture, NOX is composed of roughly 5– 

10% NO2, with the majority of the 

remainder in the form of NO. NO2 is 

soluble in water, and therefore may be 

removed by the water in the scrubber. 

It is possible to treat the exhaust 

upstream of the scrubber to convert 


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89Per 40 CFR 1043.20, ‘‘ECA associated areas’’ are 

U.S. internal waters that are navigable from the 

ECA. This term does not include internal waters 

that are shoreward of ocean waters that are not part 

of an emission control area. Though the outer limits 

of the sulfur limitation are the same as for the 

proposed ECA, the sulfur limitation in this final 

rule is not dependent on adoption of the ECA. 

90For the purpose of the discussion in this 

section with regard to the CAA fuel standards in 40 

CFR 80, ‘‘Category 3 vessel’’ refers to a commercial 

vessel with a Category 3 propulsion engine; 

‘‘Category 2 vessel’’ refers to a commercial or 

recreational vessel with a Category 2 propulsion 

engine; and ‘‘Category 1 vessel’’ refers to a 

commercial or recreational vessel with only 

Category 1 or smaller engines. The fuel provisions 

being finalized today apply to all of the engines on 

a given vessel. 

91For the purposes of this final rule (and the final 

40 CFR Part 80 regulations), the term ‘‘marine’’ as 

it is used here refers to Category 1 and 2 marine 

diesel engines unless otherwise stated. 

more of the NOX to NO2, thereby 

facilitating the use of a scrubber to 

remove NO2. However, we are 

concerned that this would add to 

nitrogen loading of the water in which 

the ship is operating. As discussed in 

Section II.B.1, nitrogen loading can lead 

to serious water quality impacts. This 

issue is addressed in the IMO EGCS 

guidelines by limiting the amount of 

nitrates that may be removed by the 

scrubber, and washed overboard. 

However, a scrubber design may be 

acceptable if it removes nitrates from 

the wash water, which in turn are 

disposed of properly, or prevents 

nitrates from forming in the wash water. 

One manufacturer has stated that their 

unique EGCS design converts NOX to 

nitrogen (N2), rather than nitrates. This 

is discussed in more detail in the RIA. 

IV. Fuel Standards 

A. Background 

EPA is finalizing standards for fuel 

manufactured or distributed in the U.S. 

that are consistent with those recently 

adopted as amendments to MARPOL 

Annex VI. As amended, Annex VI 

includes revised fuel sulfur standards 

for use in engines onboard ships, and it 

also set more stringent fuel sulfur limits 

for ‘‘any fuel oil used onboard ships 

* * * operating within an Emission 

Control Area’’ (Annex VI, Regulation 

14). 

Under the Annex, the process by 

which an Emission Control Area (ECA) 

is to be designated is through 

amendment of the Annex. The U.S. and 

Canadian governments have submitted a 

proposal to amend MARPOL Annex VI 

to designate an ECA to include waters 

off much of the U.S. and Canada. 

Specifically, the proposed ECA includes 

the waters off of the contiguous 48 

States, Southeastern Alaska, and the 

Main Hawaiian Islands, extending to a 

distance of 200 nautical miles from the 

coastline. This amendment was 

considered at the July 2009 Marine 

Environment Protection Committee 

(MEPC 59), and we expect that the 

amendment will be adopted in March 

2010, at MEPC 60. If this amendment is 

not adopted in a timely manner by IMO, 

we intend to take supplemental action 

to control emissions from vessels that 

affect U.S. air quality. 

EPA is in this notice finalizing fuel 

sulfur limits under section 211(c) of the 

Clean Air Act that match the limits that 

apply under Annex VI in ECAs. The 

adoption of such standards will: (1) 

Allow for the production and sale of up 

to 1,000 ppm sulfur fuel for use in 

Category 3 marine vessels; and (2) forbid 

the production and sale of fuel oil above 

1,000 ppm sulfur for use in the waters 

within an ECA and ECA associated 

areas (per 40 CFR 1043.20) except as 

allowed under 40 CFR Part 1043, as 

described below.89 90

There are a few exceptions that will 

allow for the use of fuel greater than 

1,000 ppm sulfur in an ECA. First, as an 

alternative to using lower sulfur fuel, 

Annex VI allows for the use of 

approaches, such as exhaust gas 

scrubbers, that can achieve equivalent 

emission reductions even when the fuel 

is operating on high sulfur residual fuel. 

In the event that a vessel is using an 

alternative device, procedure, or 

compliance method, provided they 

achieve equivalent emissions 

reductions, fuel oil above 1,000 ppm 

sulfur may be purchased in the U.S. for 

use in an ECA and ECA associated 

areas. This is discussed in more detail 

in Section V of this preamble. As 

discussed further in Section VI.B.5, 

existing steamships operating 

exclusively on the Great Lakes are not 

subject to the 1,000 ppm sulfur 

requirement, and vessels that have been 

granted temporary relief on the basis of 

serious economic hardship are also not 

subject to the standard. These three 

exceptions are all set out in the 

regulations at 40 CFR Part 1043. 

The majority of vessels with a 

Category 3 propulsion engine operate on 

high-sulfur, heavy fuel oil (HFO) (also 

known as residual, or bunker, fuel). Due 

to their use of heavy fuel, these marine 

diesel engines have very high PM and 

SO2 emissions. Sulfur in the fuel is 

emitted from engines primarily as SO2; 

however a small fraction is emitted as 

sulfur trioxide (SO3) which immediately 

forms sulfate and is emitted as PM by 

the engine. In addition, much of the SO2

emitted from the engine reacts in the 

atmosphere to form secondary PM. 

Reductions in residual fuel sulfur levels 

will lead to significant sulfate PM and 

SO2 emission reductions which will 

provide dramatic environmental and 

public health benefits. However, in most 

cases, fuels that meet the long-term fuel 

sulfur standards will likely be distillate 

fuels, rather than HFO. In addition to 

reductions in sulfate PM, switching 

from HFO to distillate fuel may reduce 

black carbon emissions, fine particle 

counts, organic carbon, and metallic ash 

particles. Further information on these 

impacts as well as a discussion of the 

technological feasibility of fuel 

switching, or using alternative 

approaches, is discussed in Section V. 

HFO sold for use by these vessels is 

currently not subject to any EPA sulfur 

limits (as it is not regulated by our 

current sulfur program) and generally 

has very high levels of sulfur. The 

finalized modifications to our existing 

diesel fuel program prohibit the 

production and sale of this fuel for use 

in an ECA associated area, and fuel sold 

for use in such areas will not be allowed 

to exceed a sulfur content of 1,000 ppm, 

except as allowed under 40 CFR Part 

1043. In a complementary fashion, the 

amendment to MARPOL Annex VI 

designating the North American ECA 

will ensure that fuel used in an ECA, 

including fuel purchased in another 

country but used within the North 

American ECA, also either meets a 1,000 

ppm sulfur limit or meets required 

emissions limits through the use of 

alternative devices, procedures, or 

compliance methods, provided they 

achieve equivalent emissions reductions 

(equivalents). Under our finalized 

regulations, fuel sold for use by 

Category 3 vessels without equivalents 

in an ECA and ECA associated areas 

will be allowed to have a sulfur content 

as high as this 1,000 ppm sulfur limit 

(except as otherwise allowed under 40 

CFR Part 1043), while fuel sold for use 

in Category 1 (marine diesel engines up 

to 7 liters per cylinder displacement) 

and Category 2 (marine diesel engines 

from 7 to 30 liters per cylinder) vessels 

will continue to be subject to the 

nonroad, locomotive, and marine 91

(NRLM) diesel fuel sulfur requirements. 

In the event that the North American 

ECA is not approved in a timely 

manner, we will revisit the standards 

being finalized here in that context. 

B. Diesel Fuel Standards Prior to This 

Final Rule 

The Nonroad Diesel program 

(finalized on June 29, 2004 (69 FR 

38958)) reduces the sulfur content of 

NRLM diesel fuel from uncontrolled 

levels down to a maximum sulfur level 

of 15 ppm. Refiners and importers are 


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92Category 3 marine engines frequently are 

designed to use residual fuels and include special 

fuel handling equipment to use the residual fuel. 

93For the purposes of the diesel sulfur program, 

the term heating oil basically refers to any No. 1 or 

No. 2 distillate other than jet fuel, kerosene, and 

diesel fuel used in highway or NRLM applications. 

For example, heating oil includes fuel which is 

suitable for use in furnaces and similar applications 

and is commonly or commercially known or sold 

as heating oil, fuel oil, or other similar trade names. 

required to produce or import all NRLM 

diesel fuel at a sulfur level of 15 ppm 

or less by June 1, 2014. The main 

compliance mechanism of the diesel 

sulfur program is the Designate and 

Track (D&T) provisions, which allows 

NRLM diesel fuel to be distinguished 

from similar products (e.g., heating oil) 

and yet provides a means for diesel fuel 

to be fungibly transported through the 

fuel production and distribution system. 

Under D&T, refiners and importers are 

required to designate the type and sulfur 

level of each batch of fuel produced or 

imported. As this fuel is transferred 

through the distribution system, product 

transfer documents (PTDs) must be 

exchanged each time the batch changes 

custody. Along with PTDs, other 

required elements of D&T include 

quarterly and annual reporting, fuel 

pump labeling, and recordkeeping. 

The Nonroad Diesel program also 

contains certain provisions to ease 

refiners’ transition to the lower sulfur 

standards and to enable the efficient 

distribution of all diesel fuels. These 

provisions, as discussed more below in 

Section IV.B.2, include special 

provisions for qualified small refiners, 

transmix processors, and entities in the 

fuel distribution system. 

(1) Scope of the Nonroad Diesel Fuel 

Program 

The sulfur standards finalized by the 

Nonroad Diesel rule apply to all the 

diesel fuel that is produced and sold for 

use in NRLM diesel applications (all 

fuel used in NRLM diesel engines, 

except for fuels heavier than a No. 2 

distillate used in Category 2 and 3 

marine engines 92 and any fuel that is 

exempted for national security or other 

reasons). While the Nonroad Diesel rule 

did not set sulfur standards for other 

distillate fuels (such as jet fuel, heating 

oil, kerosene, and No. 4 fuel oil), it did 

implement provisions to prevent the 

inappropriate use of heating oil and 

other higher sulfur distillate fuels in 

NRLM and locomotive and marine (LM) 

diesel applications. Sale of distillate 

fuels for use in nonroad, locomotive, or 

marine diesel engines will generally be 

prohibited unless the fuel meets the 

diesel fuel sulfur standards of 40 CFR 

Part 80.93 The regulated fuels under our 

diesel fuel sulfur program include those 

fuels listed in the regulations at 40 CFR 

80.2(qqq). 

The sulfur standards do not apply to: 

(1) No. 1 distillate fuel used to power 

aircraft; (2) Number 4, 5, and 6 fuels 

(e.g., residual fuels or residual fuel 

blends, intermediate fuel oil (IFO) 

Heavy Fuel Oil Grades 30 and higher), 

used for stationary source purposes; (3) 

any distillate fuel with a T–90 

distillation point greater than 700 °F, 

when used in Category 2 or 3 marine 

diesel engines (this includes Number 4, 

5, and 6 fuels (e.g., IFO Heavy Fuel Oil 

Grades 30 and higher), including fuels 

meeting the American Society for 

Testing and Materials (ASTM) 

specifications DMB, DMC, and RMA–10 

and heavier); and (4) any fuel for which 

a national security or research and 

development exemption has been 

approved or fuel that is exported from 

the U.S. The criterion that any distillate 

fuel with a T–90 greater than 700 °F will 

not be subject to the sulfur standards 

when used in Category 2 or 3 marine 

engines was intended to exclude fuels 

heavier than No. 2 distillate, including 

blends containing residual fuel. In 

addition, residual fuel was not subject 

to the sulfur standards. 

While many marine diesel engines 

use No. 2 distillate, ASTM 

specifications for marine fuels identify 

four kinds of marine distillate fuels: 

DMX, DMA, DMB, and DMC. DMX is a 

special light distillate intended mainly 

for use in emergency engines. DMA 

(also called marine gas oil, or ‘‘MGO’’) is 

a general purpose marine distillate that 

contains no trace of residual fuel. These 

fuels can be used in all marine diesel 

engines but are primarily used by 

Category 1 engines. DMX and DMA 

fuels intended for use in any marine 

diesel engine are subject to EPA’s fuel 

sulfur standards. 

DMB, also called marine diesel oil, is 

not typically used with Category 1 

engines, but is used for Category 2 and 

3 engines. DMB is allowed to have a 

trace of residual fuel, which can be high 

in sulfur. This contamination with 

residual fuel usually occurs due to the 

distribution process, when distillate is 

brought on board a vessel via a barge 

that has previously contained residual 

fuel, or using the same supply lines as 

are used for residual fuel. DMB is 

produced when fuels such as DMA are 

brought on board the vessel in this 

manner. EPA’s fuel sulfur standards do 

apply to the distillate that is used to 

produce the DMB, for example the DMA 

distillate, up to the point that it becomes 

DMB. However, DMB itself is not 

subject to the EPA fuel sulfur standards 

when it is used in Category 2 or 3 

engines. 

DMC is a grade of marine fuel that 

may contain some residual fuel and is 

often a residual fuel blend. This fuel is 

similar to No. 4 diesel, and can be used 

in Category 2 and Category 3 marine 

diesel engines. DMC is produced by 

blending a distillate fuel with residual 

fuel, for example at a location 

downstream in the distribution system. 

EPA’s fuel sulfur standards apply to the 

distillate that is used to produce the 

DMC, up to the point that it is blended 

with the residual fuel to produce DMC. 

However, DMC itself is not subject to 

the EPA fuel sulfur standards when it is 

used in Category 2 or 3 marine engines. 

Residual fuel was not previously 

covered by the sulfur content standards 

as it is not a distillate fuel. Residual fuel 

is typically designated by the prefix RM 

(e.g., RMA, RMB, etc.). These fuels are 

also identified by their nominal 

viscosity (e.g., RMA10, RMG35, etc.). 

Most residual fuels require treatment by 

an onboard purifier-clarifier centrifuge 

system, although RMA and RMB do not 

require this. 

The distillation criterion adopted by 

EPA, T–90 greater than 700 °F, was 

designed to identify those fuels that are 

not subject to the sulfur standards when 

used in Category 2 or 3 marine diesel 

engines. It is intended to exclude DMB, 

DMC, and other heavy distillates or 

blends, when used in Category 2 or 3 

marine diesel engines. We are not 

amending this provision in this action. 

However, under this final rule, all of 

these fuels, and any other diesel fuels or 

fuel oils, will be subject to a 1,000 ppm 

sulfur limit if they are produced or sold 

for use in an ECA, except as otherwise 

allowed under 40 CFR Part 1043. 

(2) Flexibilities 

Compliance flexibilities were 

provided in the nonroad diesel sulfur 

regulations for qualified small refiners 

(69 FR 39047; Section IV.B.1) and for 

transmix processors (69 FR 39045; 

Section IV.A.3.d). Small refiners were 

provided, among other flexibility 

options, additional time for compliance 

with the 15 ppm NRLM standard, until 

June 1, 2014. Transmix processors, who 

distill off-specification interface 

mixtures of petroleum products from 

pipeline systems into gasoline and 

distillate fuel, have a simple refinery 

configuration that does not make it costeffective for them to install and operate 

a hydrotreater to reduce distillate fuel 

sulfur content. As a result, transmix 

processors were provided with the 

flexibility to continue to produce all of 

their NRLM diesel fuel to meet the 500 

ppm sulfur standard until June 1, 2014, 

and all of their LM diesel fuel to meet 

a 500 ppm sulfur limit indefinitely. The 


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latter flexibility also allows for an outlet 

for off-spec fuel that may be produced 

in the distribution system. 

The D&T provisions, first established 

to distinguish highway from nonroad 

500 ppm fuel, were thus continued 

beyond 2014 to ensure that 500 ppm 

NRLM could be distinguished from 

similar fuel (e.g., heating oil that has a 

sulfur level of 500 ppm). In 2014 and 

beyond, D&T is essential to ensure that 

heating oil is not being inappropriately 

shifted downstream of the refiner into 

the NRLM and LM diesel fuel markets, 

circumventing the NRLM standards (as 

mentioned above in Section IV.B.1). 

Provisions in the Nonroad Diesel rule to 

ensure that heating oil is not used in 

NRLM applications include the use of a 

fuel marker to distinguish heating oil 

from NRLM and LM diesel fuel, dye 

solvent yellow 124, which is added to 

heating oil at the terminal level. The 

D&T provisions also provided parties in 

the diesel fuel industry with inherent 

flexibility. D&T maximizes the 

efficiency of the distribution system by 

allowing for fungible distribution of 

physically similar products, and 

minimizing the need for product 

segregation. Under D&T, diesel fuel with 

similar sulfur levels can be fungibly 

shipped up to the point of distribution 

from a terminal (where off-highway 

diesel fuels must be dyed red, pursuant 

to Internal Revenue Service (IRS) 

requirements, to indicate its tax exempt 

status). 

(3) Northeast/Mid-Atlantic Area 

In the Northeast, heating oil is 

distributed in significant quantities. 

Discussions with terminal operators in 

the Northeast (and other representatives 

of heating oil users and distributors) 

during the development of the Nonroad 

Diesel rule revealed concerns that the 

heating oil marker requirement would 

represent a significant burden on 

terminal operators and users of heating 

oil given the large volume of heating oil 

used in the Northeast. These parties 

suggested that if EPA prohibited the sale 

and use of diesel fuel produced by those 

utilizing the flexibilities described 

above, this area could be exempted from 

the marker requirement. 

Thus, the Northeast/Mid-Atlantic 

(NE/MA) area was developed (69 FR 

39063, Section IV.D.1.b.ii; see also 40 

CFR 80.510(g) for the specific States and 

counties that comprise the NE/MA 

area). As there would be no way to 

distinguish heating oil from 500 ppm 

NRLM and 500 ppm LM diesel fuel in 

2014 and beyond without the fuel 

marker, these fuel types are not allowed 

to be produced/imported, distributed 

and/or sold in the NE/MA area during 

this time period (500 ppm NRLM diesel 

fuel may not be produced/imported, 

distributed and/or sold in the NE/MA 

area after 2012). 

Similarly, high sulfur NRLM 

(HSNRLM) produced through the use of 

credits is not allowed in Alaska. 

However, EPA-approved small refiners 

in Alaska may produce HSNRLM diesel 

fuel. To receive this approval, a small 

refiner must provide EPA with a 

compliance plan showing how their 

HSNRLM diesel fuel will be segregated 

from all other distillate fuels through its 

distribution to end-users. 

(4) Nonroad Diesel Program Transition 

Schedule 

The transition to lower sulfur diesel 

fuel for NRLM equipment is depicted in 

Figure VI–1 below. The transition for 

urban (areas served by the Federal Aid 

Highway System) and rural Alaska are 

shown below in Figure VI–2. 

BILLING CODE 6560–50–P 


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BILLING CODE 6560–50–C 


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94Annex VI, Regulation 14 (located in the 

rulemaking docket, EPA–HQ–OAR–2007–0121– 

0107). 

C. Applicability 

Assuming adoption of an amendment 

to MARPOL Annex VI establishing a 

U.S. ECA, pursuant to Annex VI, the 

fuel used in that ECA cannot exceed 

1,000 ppm sulfur beginning January 1, 

2015.94 As mentioned above, we are 

incorporating a similar 1,000 ppm sulfur 

limit into our CAA regulations at 40 

CFR Part 80 through both a prohibition 

on the production and sale of fuel oil 

above 1,000 ppm sulfur for use in any 

marine vessels (Categories 1, 2, and 3) 

in an ECA and ECA associated areas 

except as allowed under 40 CFR Part 

1043, and an allowance for the 

production and use of 1,000 ppm sulfur 

fuel to be used in Category 3 marine 

vessels. Fuel produced and sold for use 

in any engine on Category 1 and 

Category 2 marine vessels will continue 

to be subject to the existing diesel sulfur 

requirements which are more stringent 

than those being finalized in this action 

for Category 3 marine vessels. We 

requested comment on whether or not 

Category 1 and 2 engines installed on 

Category 3 marine vessels should be 

allowed to use 1,000 ppm sulfur fuel. To 

reduce burden that could potentially be 

caused by requiring that these engines 

burn 15 ppm diesel fuel (which could 

result in a vessel needing to carry three 

different types of fuel onboard), we are 

finalizing that Category 1 and 2 

auxiliary engines installed on Category 

3 marine vessels will be allowed to use 

1,000 ppm fuel. 

Discussions with stakeholders in the 

diesel fuel production and distribution 

industry have indicated that they 

anticipate that most (if not all) fuel oil 

that could meet a 1,000 ppm sulfur 

standard would be considered a 

distillate or diesel fuel, because at a 

1,000 ppm sulfur level it is nearly 

impossible for fuel to have a T–90 

distillation point at or above 700 °F (i.e., 

be considered residual fuel). As 

discussed in Section IV.B.1, fuel with a 

T–90 less than 700 °F will be required 

to meet the standards of our existing 

diesel sulfur program which, in 2014 

and beyond, is 15 ppm. We believe that 

because of the limits on the sulfur 

content of fuel used in ECAs, the 

existing diesel fuel sulfur program 

should be revised to allow for the 

production, distribution, purchase, and 

use of 1,000 ppm sulfur fuel oil for use 

in Category 3 marine vessels. Therefore, 

we are finalizing a new 1,000 ppm 

sulfur category for fuel oil produced and 

purchased for use in Category 3 marine 

vessels (called ‘‘ECA marine fuel’’). This 

finalized fuel sulfur requirement will 

largely supplement the existing diesel 

fuel sulfur requirements and will 

harmonize EPA’s diesel sulfur program 

with the requirements of Annex VI. 

Under this final action, owners of 

Category 3 marine vessels will be able 

to purchase and use 1,000 ppm sulfur 

ECA marine fuel, which will allow 

those vessels to comply with the sulfur 

limits in any ECA worldwide and in 

ECA associated areas. 

D. Fuel Sulfur Standards 

As discussed above in Section IV.C, in 

addition to the prohibition on the sale 

of fuel greater than 1,000 ppm sulfur for 

use in marine vessels (except as allowed 

under 40 CFR Part 1043) operating 

within an ECA and ECA associated 

areas, we are also finalizing the 

allowance of the production, 

distribution, and sale of 1,000 ppm 

sulfur ECA marine fuel, which we 

discuss more in this section. 

Prior to this action, and pending the 

establishment of the North American 

ECA, the kind of fuel produced and sold 

for use by Category 3 marine vessels had 

uncontrolled sulfur levels as it was not 

subject to the NRLM sulfur limits. This 

was reflected in the regulations by 

exempting these kinds of fuel from the 

definition of NRLM diesel fuel and the 

NRLM sulfur limits (40 CFR 80.2(nnn)). 

The combined effect of Annex VI and 

these regulations is to require that any 

fuel sold for use in a Category 3 marine 

vessel operating in an ECA be 1,000 

ppm sulfur or lower, except as allowed 

under 40 CFR Part 1043. Fuel oil used 

or sold for use in Category 3 marine 

vessels in an ECA and ECA associated 

areas will therefore go from 

uncontrolled, high sulfur levels to no 

higher than 1,000 ppm sulfur (except as 

otherwise allowed under 40 CFR Part 

1043). Under Annex VI, fuel with sulfur 

levels greater than 1,000 ppm cannot be 

used in a marine vessel without sulfur 

abatement technology operating in an 

ECA, no matter where the fuel is 

purchased. Consistent with this, the 

finalized section 211(c) controls will 

prohibit the production and sale of any 

fuel for use in an ECA and ECA 

associated areas that is above 1,000 ppm 

sulfur, except as allowed under 40 CFR 

Part 1043. 

The requirements for 1,000 ppm 

sulfur fuel oil will apply to the North 

Sea, the Baltic Sea, and any other ECAs 

established around the world, so this 

fuel will be produced by refiners in 

other countries. Under EPA’s NRLM 

program prior to this final rule, 1,000 

ppm sulfur fuel would have been 

subject to the 15 ppm NRLM sulfur limit 

in 2014 and later. If EPA were to require 

that fuel produced, distributed, and sold 

for use for Category 3 vessels in the 

North American ECA and ECA 

associated areas meet the 15 ppm sulfur 

standard after 2014, we believe that 

Category 3 vessel owners would simply 

purchase 1,000 ppm sulfur fuel 

elsewhere to be used here in the North 

American ECA. This could be an 

extremely inefficient process for ship 

owners. It would also mean a loss of 

sales for U.S. refiners of fuel that these 

Category 3 vessel owners purchase. 

These impacts would add to the costs 

and burdens of the program with no 

corresponding environmental benefit. 

Therefore, we believe that it is 

reasonable to allow U.S. refiners and 

importers to produce 1,000 ppm sulfur 

fuel for use by Category 3 vessels. Thus, 

we are finalizing a new fuel sulfur 

standard of 1,000 ppm for fuel 

produced, distributed, and sold for use 

in Category 3 marine vessels. While we 

expect use of this fuel to be 

concentrated in the area of the North 

American ECA and ECA associated 

areas (and any other ECA), we are 

allowing its use by Category 3 marine 

vessels in all locations, to encourage its 

general use. After 2014, no fuel above 15 

ppm can be used in Category 1 or 

Category 2 vessels. 

We note that the combination of the 

Annex VI ECA provisions and the 

modifications proposed in this action 

for the diesel sulfur program will 

achieve very significant benefits 

compared to the existing program. The 

production and use of 1,000 ppm ECA 

marine fuel, as well as 15 ppm NRLM 

diesel fuel, will replace much higher 

sulfur fuel usage, and there is no 

additional benefit to be gained by 

requiring the sale of 15 ppm sulfur 

diesel fuel for use by Category 3 vessels 

as a practical matter because we believe 

Category 3 vessels would simply 

purchase 1,000 ppm sulfur fuel 

elsewhere. In order to incorporate these 

modifications into our existing program 

under the Clean Air Act, we needed to 

create a new fuel designation for 

allowable fuel under our program. 

(1) Amendments to the Diesel Fuel 

Sulfur Program 

We are prohibiting the production, 

distribution, and sale or offer for sale of 

any fuel for use in any marine diesel 

vessels (Categories 1, 2, and 3) operating 

in the North American ECA and ECA 

associated areas that is greater than 

1,000 ppm sulfur, except as otherwise 

allowed under 40 CFR Part 1043. We are 

also finalizing a sulfur standard of 1,000 

ppm for fuel produced, distributed, and 

sold or offered for sale for use in 

Category 3 marine vessels operating in 


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an ECA and ECA associated areas. To 

simplify the existing diesel fuel sulfur 

program, we are also eliminating the 

500 ppm LM diesel fuel standard once 

the 1,000 ppm ECA marine fuel 

standard becomes effective. Under the 

diesel sulfur program prior to this final 

rule, 500 ppm LM diesel fuel could be 

produced by transmix processors 

indefinitely, and could be used by 

locomotives and marine vessels that do 

not require 15 ppm. The original intent 

of allowing for this fuel was to serve as 

an outlet for interface and downgraded 

diesel fuel post-2014 that would 

otherwise not meet the 15 ppm sulfur 

standard. However, we believe that the 

1,000 ppm sulfur ECA marine fuel can 

now serve as this outlet. We believe that 

transmix generated near the coasts 

would have ready access to marine 

applications, and transmix generated in 

the mid-continent could be shipped via 

rail or fuel barge to markets on the 

coasts. 

Elimination of the 500 ppm LM diesel 

fuel standard will simplify the diesel 

sulfur program such that sulfur can 

serve as the distinguishing factor for 

fuels available for use after 2014 (the 

designated products under the diesel 

fuel program will thus be: 15 ppm motor 

vehicle, nonroad, locomotive, and 

marine (MVNRLM) diesel fuel, heating 

oil, and 1,000 ppm ECA marine fuel). 

With this approach, beginning in 2014, 

only 15 ppm NRLM diesel fuel can be 

used in locomotive and Category 1/ 

Category 2 marine diesel applications 

(and 1,000 ppm ECA marine fuel could 

be used in Category 3 marine vessels). 

Further, this will help to streamline the 

D&T program as there will no longer be 

a need for a fuel marker to distinguish 

500 ppm LM diesel fuel from heating 

oil. Below, we discuss the aspects of 

D&T that we are changing, which we 

believe will greatly simplify the diesel 

sulfur program. 

(a) Compliance and Implementation 

(i) Northeast/Mid-Atlantic Area and the 

Fuel Marker 

With the elimination of the 500 ppm 

LM designation in 2014, parties in the 

fuel production and distribution 

industry will still be required to register 

and designate their products and adhere 

to PTD, fuel pump labeling, and 

recordkeeping requirements. But we 

believe that the tracking portion of D&T 

can be simplified. Annual reporting was 

required under § 80.601 for D&T 

through June 30, 2015 (the final annual 

report is due August 31, 2015). The final 

reporting period was set to ensure that 

heating oil was not being 

inappropriately shifted into the 500 

ppm LM diesel fuel pool. However, with 

the elimination of this fuel designation, 

the final annual reporting period will 

instead be July 1, 2013 through May 31, 

2014, with the report due to EPA on 

August 31, 2014. 

As stated in the preamble to the 

proposed rule, we believe that the 

elimination of the 500 ppm LM diesel 

fuel designation will also, beginning 

June 1, 2014, negate the need for the 

heating oil marker and the NE/MA area. 

After 2014, the heating oil marker 

requirement in the diesel sulfur program 

prior to this final rule was for the sole 

purpose of distinguishing heating oil 

from 500 ppm LM diesel fuel, to prevent 

heating oil from swelling the 500 ppm 

LM diesel fuel pool. Also, as there is no 

marker requirement for heating oil in 

the NE/MA area, the diesel sulfur 

program did not allow for 500 ppm LM 

diesel fuel to be produced, distributed, 

or purchased for use in the NE/MA area 

after 2012. As also noted in the 

proposed rule, without 500 ppm LM 

diesel fuel there is no need for the 

heating oil marker; fuel designations 

and sulfur level could serve as the 

distinguishing factor between the 

available fuels (15 ppm MVNRLM diesel 

fuel, 1,000 ppm ECA marine fuel, and 

heating oil). Further, there is no need for 

the NE/MA area without the heating oil 

marker. Thus, we are finalizing to 

remove the NE/MA area designation and 

the heating oil marker requirement. 

(ii) PTDs and Labeling 

We are finalizing new PTD language 

for the 1,000 ppm ECA marine fuel 

designation at regulation § 80.590. As 

stated in regulation § 80.590(a)(7)(vii), 

we are adding the following statement 

to PTDs accompanying 1,000 ppm 

sulfur ECA marine fuel: ‘‘1,000 ppm 

sulfur (maximum) ECA Marine Fuel. For 

use in Category 3 marine vessels only. 

Not for use in engines not installed on 

Category 3 marine vessels.’’ 

Appendix V of Annex VI also 

includes language that is required on 

bunker delivery notes. Compliance 

requirements of this action, such as 

PTDs, are not intended to supplant or 

replace requirements of Annex VI (and 

we encourage regulated entities to 

consult Annex VI to ensure that they are 

fully aware of all requirements that 

must be met in addition to EPA’s 

requirements). However, if a party’s 

bunker delivery note also contains the 

information required under our 

regulations for PTDs, we will consider 

the bunker delivery note to also suffice 

as a PTD. 

We are also finalizing new pump 

labeling language for the 1,000 ppm 

sulfur ECA marine fuel designation at 

regulation § 80.574. Diesel fuel pump 

labels required under the existing diesel 

sulfur regulations must be prominently 

displayed in the immediate area of each 

pump stand from which diesel fuel is 

offered for sale or dispensing. However, 

we understand that there may be cases 

where it is not feasible to affix a label 

to a fuel pump stand due to space 

constraints (such as diesel fuel pumps at 

marinas) or where there is no pump 

stand, thus the current regulations allow 

for alternative labeling with EPA 

approval. Previously approved 

alternative labeling has included the use 

of permanent placards in the immediate 

vicinity of the fuel pump; and we will 

also allow other reasonable alternatives 

to labeling for situations where pump 

labeling may not be feasible. As stated 

in regulation § 80.574, we are replacing 

the 500 ppm LM diesel fuel pump label 

language with the following fuel pump 

label language for 1,000 ppm sulfur ECA 

marine fuel: ‘‘1,000 ppm SULFUR ECA 

MARINE FUEL (1,000 ppm Sulfur 

Maximum). For use in Category 3 

marine vessels only. Warning—Federal 

law prohibits use in any engine that is 

not installed on a Category 3 marine 

vessel; use of fuel oil with a sulfur 

content greater than 1,000 ppm in an 

ECA is prohibited, except as allowed by 

40 CFR Part 1043.’’ 

Under this program, we are also 

eliminating MVNRLM diesel fuel 

labeling requirements from EPA’s 

regulations. In 2014 and beyond, EPA 

will not require ‘‘visible evidence’’ of red 

dye in off-road fuels; however this 

requirement still exists in IRS’s taxation 

regulations to denote that off-road fuels 

are untaxed. EPA’s required label for 15 

ppm NRLM diesel fuel (instead of one 

15 ppm MVNRLM diesel fuel label) is 

mainly to denote that 15 ppm NRLM 

will be dyed red, while 15 ppm MV 

diesel fuel will not. Further, after 

October 1, 2014, all MVNRLM diesel 

fuel available for purchase and/or 

distribution will be 15 ppm. We believe 

that it is not appropriate for EPA to 

retain a labeling requirement for 

MVNRLM diesel fuel given the fact that 

the red dye provision is no longer EPA’s 

requirement. Please note, however, that 

marketers and wholesale purchaserconsumers are still free to continue to 

label their pump stands to help with 

consumer awareness. Labeling will 

continue to be required for heating oil 

and, as proposed above, for 1,000 ppm 

sulfur ECA marine fuel. 

Additionally, EPA will consult with 

IRS regarding handling labels in IRS’s 

regulations at Title 26 of the Code of 

Federal Regulations. 


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95Proposal to Designate an Emission Control 

Area for Nitrogen Oxides, Sulphur Oxides and 

Particulate Matter, Submitted by the United States 

and Canada. IMO Document MEPC59/6/5, 27 March 

2009. A copy of this document can be found at 

http://www.epa.gov/otaq/regs/nonroad/marine/ci/ 

mepc-59-eca-proposal.pdf. 

96Note that MARPOL Annex VI expresses these 

standards in units of % (m/m) sulfur. 10,000 ppm 

S equals 1 percent S. 

(b) Timing of the Standard 

Currently, all refiners and importers 

are required to produce all of their 

NRLM diesel fuel to meet the 15 ppm 

standard beginning June 1, 2014. To 

allow transition time for the distribution 

system, terminals are allowed until 

August 1, 2014 to begin dispensing 15 

ppm NRLM diesel fuel, retailers and 

wholesale purchaser-consumers are 

allowed until October 1, 2014, and endusers are allowed until December 1, 

2014. To be consistent with the existing 

diesel program, we are allowing refiners 

to begin producing 1,000 ppm sulfur 

ECA marine fuel beginning June 1, 2014, 

and downstream parties will follow the 

current NRLM transition schedule 

(August, October, and December). We 

believe that following the same 

transition schedule as the existing diesel 

sulfur program would best facilitate the 

availability of 1,000 ppm ECA marine 

fuel for purchase and use by the Annex 

VI January 1, 2015 date. 

(2) Proposed Alternative Options 

We identified two potential 

alternatives in the proposed rule to the 

changes to the existing diesel fuel sulfur 

program discussed above: The creation 

of an expanded NE/MA area and the 

retention of the 500 ppm LM diesel fuel 

designation. We requested comment on 

these alternative options, as well as any 

additional alternative options. We 

received a comment stating that the 500 

ppm sulfur designation should be 

retained because, the commenter stated, 

Category 3 engines can use both 500 

ppm and 1,000 ppm sulfur fuel. Another 

commenter who supported the 

elimination of this fuel category noted 

that if it is determined that the 500 ppm 

LM designation is necessary for the 

locomotive industry, it would support 

the concept of an expanded NE/MA area 

as a secondary option. 

E. Technical Amendments to the 

Current Diesel Fuel Sulfur Program 

Regulations 

Following publication of the technical 

amendments to the Highway and 

Nonroad Diesel Regulations (71 FR 

25706, May 1, 2006), we discovered 

additional errors and clarifications 

within the diesel regulations at 40 CFR 

Part 80, Subpart I that we are addressing 

in this action. These items are merely 

typographical/printing error and 

grammar corrections. A list of the 

changes that we are making to Subpart 

I is below in Table IV–1. 

TABLE IV–1—TECHNICAL AMENDMENTS TO THE DIESEL FUEL SULFUR

REGULATIONS

Section Description of change 

80.525(a)–(d) ..... Removal of the term 

‘‘motor vehicle’’ from 

this section. 

80.551(f) ............. Correction of printing 

error. 

80.561 ................ Correction of typographical error in title. 

80.570(a) and (b) Amended to correct date 

(‘‘November 30, 2010’’ 

instead of ‘‘September 

30, 2010’’. 

80.593 ................ Correction of typographical error in introductory text. 

80.599(e)(4) ....... Correction of printing error 

in definition of terms 

‘‘#1MV15I’’ and 

‘‘NPMV15I’’. 

80.600(a)(12) ..... Amended to correct date 

(‘‘May 31, 2014’’ instead 

of ‘‘June 1, 2014’’). 

80.600(i) ............. Amended to remove duplicate sentence. 

80.601(b)(3)(x) ... Amended to correct dates 

(‘‘August 31’’ instead of 

‘‘August 1’’). 

80.612(b) ............ Amended to fix typographical error in paragraph. 

V. Emission Control Areas for U.S. 

Coasts 

The finalized Clean Air Act standards 

described above are part of a 

coordinated strategy for ensuring that all 

ships that affect U.S. air quality will be 

required to meet stringent NOX and fuel 

sulfur requirements. Another 

component of this strategy consists of 

pursuing ECA designation for U.S. and 

Canadian coasts in accordance with 

Annex VI of MARPOL. ECA designation 

will ensure that all ships, foreignflagged and domestic, are required to 

meet stringent NOX and fuel sulfur 

requirements while operating within 

200 nautical miles of most U.S. coasts. 

This section describes what an ECA is, 

the process for obtaining ECA 

designation at the International 

Maritime Organization, and summarizes 

the U.S. and Canadian proposal for an 

amendment to MARPOL Annex VI 

designating most U.S. and Canadian 

coasts as an ECA (referred to as the 

‘‘North American ECA’’), submitted to 

IMO on March 27, 2009.95

This section also discusses 

technological approaches to comply 

with the fuel standards. These 

approaches include switching to lower 

sulfur fuel and equivalents, such as 

exhaust gas cleaning units. We also 

discuss how emissions from foreignflagged ships may be covered should 

approval of the U.S. ECA be delayed. 

A. What Is an ECA? 

(1) What Emissions Standards Apply in 

an ECA? 

MARPOL Annex VI contains 

international standards to control air 

emissions from ships. The NOX and 

SOX/PM programs each contain two sets 

of standards. The global standards for 

the sulfur content of fuel and NOX

emissions from engines apply to ships at 

all times. In recognition that some areas 

may require further control, Annex VI 

also contains more stringent NOX and 

SOX/PM geographic-based standards 

that apply to ships operating in 

designated Emission Control Areas. 

Once a North American ECA is 

designated through amendment to 

MARPOL Annex VI, the requirements 

will be enforceable for most vessels 

through the Act to Prevent Pollution 

from Ships (see Section VI.B). 

The current global fuel sulfur (S) limit 

is 45,000 ppm 96 S and will tighten to 

35,000 ppm S in 2012. Depending on a 

2018 fuel availability review, the 

MARPOL Annex VI global fuel sulfur 

limit will be further reduced to 5,000 

ppm S as early as 2020. In contrast, 

ships operating in designated ECAs are 

subject to a fuel sulfur limit of 15,000 

ppm S. The ECA limit is reduced to 

10,000 ppm S in July 2010 and 1,000 

ppm S in 2015. In addition, Tier 3 NOX

standards will apply to new engines 

operating in ECAs beginning in 2016. 

These Tier 3 NOX standards represent 

an 80 percent reduction in NOX beyond 

current Tier 1 standards and are 

anticipated to require the use of 

aftertreatment technology such as SCR. 

We are adopting similar Tier 3 

standards as part of our Clean Air Act 

program (see Section III). 

There are currently two ECAs in effect 

today, exclusively controlling SOX; thus 

they are called Sulfur Emission Control 

Areas, or SECAs. The first SECA was 

designated to control the emissions of 

SOX in the Baltic Sea area and entered 

into force in May 2005. The second 

SECA was designated to control the 

emissions of SOX in the North Sea area 

and entered into force in November 

2006. 


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(2) What Is the Process for Obtaining 

ECA Designation? 

A proposal to amend Annex VI to 

designate an ECA can be submitted by 

a party to Annex VI. A party is a country 

that ratified Annex VI. The proposal for 

amendment must be approved by the 

Parties to MARPOL Annex VI; this 

would take place at a meeting of the 

Marine Environment Protection 

Committee (MEPC). The U.S. deposited 

its Instrument of Ratification with the 

IMO on October 8, 2008. Annex VI 

entered into force for the U.S. on 

January 8, 2009, making the U.S. eligible 

to apply for an ECA. 

The criteria and procedures for ECA 

designation are set out in Appendix III 

to MARPOL Annex VI. A proposal to 

designate an ECA must demonstrate a 

need to prevent, reduce, and control 

emissions of SOX, PM, and/or NOX from 

ships operating in that area. The specific 

criteria are summarized below: 

• A delineation of the proposed area 

of application; 

• A description of the areas at risk on 

land and at sea, from the impacts of ship 

emissions; 

• An assessment of the contribution 

of ships to ambient concentrations of air 

pollution or to 

• Adverse environmental impacts; 

• Relevant information pertaining to 

the meteorological conditions in the 

proposed area of 

• Application to the human 

populations and environmental areas at 

risk; 

• Description of ship traffic in the 

proposed ECA; 

• Description of the control measures 

taken by the proposing Party or Parties; 

• Relative costs of reducing emissions 

from ships compared with land-based 

controls; and 

• An assessment of the economic 

impacts on shipping engaged in 

international trade. 

An amendment to designate an ECA 

must be adopted by the Parties to Annex 

VI, as an amendment to Annex VI. The 

proposal to amend Annex VI was 

approved at MEPC 59, and circulated for 

adoption. The earliest possible adoption 

date is at MEPC 60, which will take 

place in March 2010 entering into force 

as early as August 2012. 

B. U.S. Emission Control Area 

Designation 

EPA worked with the U.S. Coast 

Guard, State Department, the National 

Oceanic and Atmospheric 

Administration and other agencies to 

develop the analysis supporting ECA 

designation for U.S. coasts contained in 

the U.S. and Canadian submittal to IMO. 

In addition, we collaborated with 

Environment Canada and the California 

Air Resources Board. In developing the 

ECA proposal, EPA consulted with 

stakeholders including representatives 

from the shipping industry, ports, 

master mariners, environmental 

interests and representatives from State 

and local governments. EPA began 

conducting outreach in advance of this 

year’s ECA proposal; in fact we have 

been engaged with this industry for 

many years with regards to the 

development of an Emission Control 

Area for the United States. Stakeholders 

also had the opportunity to comment on 

the strategy we announced in the 

Advance Notice of Proposed 

Rulemaking (ANPRM) for the Category 3 

Marine Diesel Engine Rule, published 

on December 7, 2007. In the ANPRM, 

EPA outlined an approach to regulating 

emissions from both new and existing 

vessels using a framework that aligns 

with MARPOL Annex VI, including 

applying the standards for Emission 

Control Areas along U.S. coasts. 

The proposal for ECA designation that 

the USG submitted to IMO earlier this 

year is for a combined U.S./Canada ECA 

submission. This approach has several 

advantages. First, the emission 

reductions within a Canadian ECA will 

lead to air quality improvements in the 

U.S. Second, a joint ECA helps 

minimize any competitive issues 

between U.S. and Canadian ports, such 

as in the Puget Sound area, which could 

arise from ECA standards. Third, IMO 

encourages a joint submittal where there 

is a common interest in emission 

reductions on neighboring waters. In 

addition, France has since joined the 

ECA proposal on behalf of the Saint 

Pierre and Miquelon archipelago. 

(1) What Areas Would Be Covered in a 

North American ECA? 

The area included in the North 

American ECA submittal to IMO for 

ECA designation generally extends 200 

nautical miles from the coastal baseline, 

except where this distance would enter 

the Exclusive Economic Zones (EEZ) of 

a neighboring country. This area would 

include the Pacific Coast, the Atlantic/ 

Gulf Coast and the Southeastern 

Hawaiian Islands. On the Pacific Coast, 

the ECA would be bounded in the north 

such that it includes the approaches 

into Anchorage, Alaska, but not the 

Aleutian Islands or points north. It 

would continue contiguously to the 

south including the Pacific coasts of 

Canada and the U.S., with its 

southernmost boundary at the point 

where California meets the border with 

Mexico. In the Atlantic/Gulf Coast, the 

ECA would be bounded in the west by 

the border of Texas with Mexico and 

continue contiguously to the east 

around the peninsula of Florida and 

north up the Atlantic coasts of the U.S. 

and Canada and would be bounded in 

the north by the 60th North parallel. 

The Southeastern Hawaiian Islands that 

were included in the ECA submittal are 

Hawaii, Maui, Oahu, Molokai, Niihau, 

Kauai, Lanai, and Kahoolawe. 

Not included in the ECA submittal 

were the Pacific U.S. territories, smaller 

Hawaiian Islands, the U.S. territories of 

Puerto Rico and the U.S. Virgin Islands, 

Western Alaska including the Aleutian 

Islands, and the U.S. and Canadian 

Arctic. The U.S. and Canada did not 

make a determination or imply that 

these areas suffer no adverse impact 

from shipping. Rather, we concluded 

that information must be gathered to 

properly assess these areas. If further 

information supports the need for an 

ECA designation in any of these areas, 

we would submit a future, proposal for 

ECA designation of these areas. 

BILLING CODE 6560–50–P 


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BILLING CODE 6560–50–C 

We are currently performing the 

analyses necessary to support an ECA 

designation for Puerto Rico and the U.S. 

Virgin Islands and will be engaging 

stakeholders as part of that effort. That 

outreach will include neighboring 

countries, shipping companies, 

environmental organizations, and other 

stakeholders. Puerto Rico has a 

population of 4 million people, sees 

significant shipping traffic and 

experiences the highest asthma rate in 

the United States. Addressing the 

impact of ship emissions on Puerto Rico 


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22926 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

and U.S. Virgin Islands is a top priority 

for the Agency. We plan to complete the 

appropriate analysis and stakeholder 

outreach regarding an ECA designation 

for these U.S. territories such that the 

U.S. with any interested Caribbean 

neighbors could make a proposal to the 

IMO in advance of MEPC 61 with the 

intent to see the ECA adopted at MEPC 

62 (July 2011) and enter into force 28 

months later (December 2013). In this 

way, we can be confident that there will 

be ample time for consideration and 

adoption of such an ECA well in 

advance of January 1, 2015 when the 

1,000 ppm fuel sulfur standard enters 

into effect. 

Establishing the ECA boundary for 

Puerto Rico and the U.S. Virgin Islands 

would require vessels operating in this 

area to meet Tier 3 NOX requirements 

that become effective in 2016. EPA will 

remove the Tier 3 NOX exemption from 

applying to Puerto Rico and the U.S. 

Virgin Islands through an appropriate 

rule amendment once the Caribbean 

ECA boundary is established. 

(2) What Analyses Were Performed in 

Support of a North American ECA? 

We performed a comprehensive 

analysis to estimate the degree of human 

health risk and environmental 

degradation that is posed by air 

emissions from ships operating in their 

ports and along our coasts. To evaluate 

the risk to human populations, state-ofthe-art assessment tools were used to 

apply widely accepted methods with 

advanced computer modeling 

techniques. The analyses incorporated 

detailed ship traffic data, the most 

recent emissions estimates, detailed 

observed meteorological data, current 

scientific understanding of exhaust 

plume behavior (both physical 

dispersion and photochemical reaction) 

and the latest epidemiologic databases 

of health effects attributable to pollutant 

exposure levels to estimate the current 

impacts of shipping on human health 

and the environment. In addition, 

sulfate and nitrate deposition modeling 

was performed to assess the impacts of 

nitrogen nutrient loading and 

acidification on U.S. ecosystems. 

Two contrasting future scenarios were 

evaluated: One in which ships continue 

to operate with current emissions 

performance while operating in the 

specified area, and one in which ships 

comply with ECA standards. The 

analysis demonstrated that ECA 

designation for U.S. coasts could save 

thousands of lives each year, relieve 

millions of acute respiratory symptoms, 

and benefit many of the most sensitive 

ecosystems. This analysis is consistent 

with, and incorporated in, the benefits 

estimates presented in Section VIII. 

C. Technological Approaches To 

Comply With Fuel Standards 

When operating within the ECA, all 

ships would have to comply with the 

0.1 percent fuel sulfur limit beginning 

in 2015 and vessels built after December 

31, 2015 would have to comply with the 

Tier 3 NOX limits described above. This 

section describes how ships would 

comply with the fuel standards. 

Approaches for compliance with the 

NOX standards are discussed in Section 

3 above. 

(1) Fuel Switching 

As discussed above, the MARPOL 

Annex VI fuel sulfur limit for ships 

operating in an ECA is 15,000 ppm 

today and reduces to 10,000 ppm in July 

2010 and further to 1,000 ppm in 2015. 

We anticipate that the 1,000 ppm fuel 

sulfur limit, beginning in 2015, will 

likely result in the use of distillate fuel 

for operation in ECAs. This would 

require the vessel to switch from a 

higher sulfur fuel to 1,000 ppm S fuel 

before entering the ECA. The practical 

implications of fuel switching are 

discussed below. 

Currently, the majority of ocean-going 

vessels use residual fuel (also called 

HFO or IFO) in their main propulsion 

engines, as this fuel is relatively 

inexpensive and has a good energy 

density. This fuel is relatively dense 

(‘‘heavy’’) and is created as a refining byproduct from typical petroleum 

distillation. Residual fuels typically are 

composed of heavy, residuum 

hydrocarbons and can contain various 

contaminants such as heavy metals, 

water and sulfur compounds. It is these 

sulfur compounds that cause the SOX

emissions when the fuel is combusted. 

If the vessel does not employ the use of 

a sulfur scrubber or other technology, it 

will most likely operate on a marine 

distillate fuel while in an ECA in order 

to meet the sulfur emission 

requirements. 

The sulfur in marine fuel is primarily 

emitted as SO2; however, a small 

fraction (about 2 percent) is converted to 

SO3. SO3 almost immediately forms 

sulfate and is emitted as direct PM by 

the engine. Consequently, emissions of 

SO2 and sulfate PM are very high for 

engines operating on residual fuel. 

Switching from high sulfur residual fuel 

to lower sulfur distillate fuel results in 

large reductions in SO2 and sulfate PM 

emissions. In addition to high sulfur 

levels, residual fuel contains relatively 

high concentrations of low volatility, 

high molecular weight organic 

compounds and metals. Organic 

compounds that contribute to PM can be 

present either as a nucleation aerosol or 

as a material adsorbed on the surfaces 

of agglomerated elemental carbon soot 

particles and metallic ash particles. The 

sulfuric acid aerosol in the exhaust 

provides a nucleus for agglomeration of 

organic compounds. Operation on 

higher volatility distillate fuel reduces 

both nucleation and adsorption of 

organic compounds into particulate 

matter. Therefore, in addition to direct 

sulfate PM reductions, switching from 

residual fuel to distillate fuel reduces 

organic PM and metallic ash particles in 

the exhaust. 

In the majority of vessels which 

operate on residual fuel, marine 

distillate fuel is still used for operation 

during routine maintenance, prior to 

and immediately after engine shutdown, or in emergencies. Standard 

procedures today have been established 

to ensure that this operational fuel 

switchover is performed safely and 

efficiently. Mainly, in order for the 

vessel to completely switch between 

residual and distillate fuel, the fuel 

pumps and wetted lines will need to be 

completely purged by the new fuel to 

ensure that the ship is burning the 

correct fuel for the area. This purging 

will vary from ship to ship due to 

engine capacity, design, operation, and 

efficiency. Provided the ship has 

separate service tanks for distillate and 

residual fuel (most, if not all, vessels 

do), fuel switching time should be 

limited only by maximum allowable 

rate of fuel temperature change. 

Additionally, for a longer operation 

period such as would occur while in an 

ECA, we investigated several other fuel 

switching topics to ensure that vessels 

would not have long-term issues from 

operating on the marine distillate fuels. 

Marine distillate fuels are similar in 

composition and structure to other 

petroleum-based middle distillate fuels 

such as diesel and No. 2 heating oil, but 

they have a much lower allowable 

sulfur content than residual fuels. This 

lower sulfur content means that by 

combusting marine distillate fuel in 

their propulsion engines, vessels 

operating within the ECA would meet 

the stricter SOX requirements. However, 

sulfur content is not the only difference 

between the marine residual and 

distillate fuels; they also have different 

densities, viscosities, and other 

specification limits. 

The maritime industry has analyzed 

the differences between residual and 

distillate fuel compositions to address 

any potential issues that could arise 

from switching operation of a Category 

3 engine from residual fuel to distillate 

fuel. The results from this research has 


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97MAN B&W Diesel, ‘‘Operation on Low-Sulphur 

Fuels; Two-Stroke Engines,’’ 2004. 

98Wartsila, ‘‘Low Sulphur Guidelines,’’ January 9, 

2006. 

99American Petroleum Institute, ‘‘Technical 

Considerations of Fuel Switching Practices,’’ API 

Technical Issues Workgroup, June 3, 2009. 

100American Bureau of Shipping, ‘‘ABS Notes: 

Use of Low-Sulphur Marine Fuel for Main and 

Auxiliary Diesel Engines,’’ Fuel Oil Piping, EWZ– 

001–02–P04–W007, Attachment G—Revision 1. 

101United States Coast Guard, ‘‘Avoiding 

Propulsion Loss from Fuel Switching: American 

Petroleum Institute, Technical Considerations,’’ 

Marine Safety Alert 03–09, June 16, 2009. 

evolved into routine operational 

switching procedures that ensure a safe 

and efficient way for the Category 3 

engines to switch operation between the 

residual and distillate fuels. Engine 

manufacturers, fuel suppliers, the 

American Bureau of Shipping, and the 

U.S. Coast Guard have provided 

guidance on fuel switching 

procedures.97 98 99 100 101 A brief 

summary of the fuel differences, as well 

as any potential issues and their usual 

solutions, is presented below. 

(a) Fuel Density 

Due to its chemical composition, 

residual fuel has a slightly higher 

density than marine distillates. Using a 

less dense fuel could affect the ballast 

of a ship at sea and would have to 

require compensation. Therefore, when 

beginning to operate on the distillate 

fuel, the vessel operator would have to 

pay attention to the vessel’s ballast and 

may have to compensate for any 

changes that may occur. We anticipate 

that these procedures would be similar 

to operating the vessel with partiallyfull fuel tanks. 

Another consideration when 

switching to a lower density fuel is the 

change in volumetric energy content. 

Distillate fuel has a lower energy 

density content on a per gallon basis 

when compared to the residual fuel; 

however, per ton, distillate fuel’s energy 

density is larger than the residual fuel. 

This means that when switching from 

residual fuel to distillate fuel, if the 

vessel’s tanks are volumetrically limited 

(i.e., the tanks can only hold a set 

quantity of fuel gallons), the distance a 

vessel can travel on the distillate fuel 

may be slightly shorter than the distance 

the vessel could travel on the residual 

fuel due to the lower volumetric energy 

content of distillate fuel, which could 

require compensation. This distance 

reduction would be approximately 5 

percent and would only be of concern 

while the vessel was operating on the 

distillate fuel (i.e., while in the U.S. 

ECA) as the majority of the time the 

vessel will be operating on the residual 

fuel. However, if the vessel is limited by 

weight (draft), the higher energy content 

per ton of fuel would provide an 

operational advantage. 

(b) Kinematic Viscosity 

Residual fuel’s kinematic viscosity is 

much higher than marine distillate 

fuel’s viscosity. Viscosity is the 

‘‘thickness’’ of the fuel. If this parameter 

is lowered from the typical value used 

within a pump, some issues could arise. 

If a distillate fuel is used in a system 

that typically operates on residual fuel, 

the decrease in viscosity could cause 

problems with high-pressure fuel 

injection pumps due to the increased 

potential for internal leakage of the 

thinner fuel through the clearances in 

the pumping elements. Internal leakage 

is part of the design of a fuel pump and 

is used in part to lubricate the pumping 

elements. However, if this leakage rate 

is too high, the fuel pump could 

produce less than optimal fuel injection 

pressures. If the distillate fuel’s lower 

viscosity becomes an issue, it is possible 

to cool the fuel and increase the 

viscosity above 2 centistokes, which is 

how most vessels operate today during 

routine fuel switchovers. 

(c) Flash Point 

Flash point is the temperature at 

which the vapors off the fuel ignite with 

an outside ignition source. This can be 

a safety concern if the owner/operator 

uses an onroad diesel fuel rather than a 

designated ‘‘marine distillate’’ fuel for 

operation because marine fuels have a 

specified minimum flash point of 60 °C 

(140 °F) to ensure onboard safety, 

whereas onroad diesel has a minimum 

specified flash point of 52 °C (125.6 °F). 

However, since most distillate fuels are 

created in the same fashion, typical 

flash points of onroad diesel are above 

60 °C (140 °F), and would meet the 

marine fuel specification for this 

property. Bunker suppliers ensure that 

marine fuels meet a minimum flash 

point of 60 °C (140 °F) through fuel 

testing as designated on the bunker 

delivery note. 

(d) Lubricity 

Lubricity is the ability of the fuel to 

lubricate the engine/pump during 

operation. Fuels with higher viscosity 

and high sulfur content tend to have 

very good lubricity without the use of 

specific lubricity-improving additives. 

Refining processes that lower fuel sulfur 

levels and their viscosities can also 

remove some of the naturally-occurring 

lubricating compounds. Severe 

hydrotreating of fuel to obtain ultra-low 

sulfur levels can result in poor fuel 

lubricity. Therefore, refineries 

commonly add lubricity improvers to 

ultra-low sulfur diesel. This will most 

likely become a concern when very low 

levels of sulfur are present in the fuel 

and/or the fuel has been hydrotreated to 

reduce sulfur, e.g., if ultra-low sulfur 

highway diesel (ULSD) is used in the 

engine. Several groups have conducted 

studies on this subject, and for some 

systems where fuel lubricity has become 

an issue, lubricity additives can be 

utilized or the owner/operator can 

install a lubricating system for the fuel 

pump. 

(e) Lube Oil 

Lube oils are used to neutralize acids 

formed in combustion, most commonly 

sulfuric acids created from sulfur in the 

fuel. The quantity of acid-neutralizing 

additives in lube oil should match the 

total sulfur content of the fuel. If 

excessive amounts of these additives are 

used, they may create deposits on 

engine components. Marine engine 

manufacturers have recommended that 

lube oil only needs to be adjusted if the 

fuel is switched for more than one week, 

but the oil feed rate may need to be 

reduced as well as engine operating 

power. Additional research has been 

conducted in this area and several oil 

companies have been working to create 

a lubricating oil that would be 

compatible with several different types 

of fuel. 

(f) Asphaltenes 

Asphaltenes are heavy, non-volatile, 

aromatic compounds which are 

contained naturally in some types of 

crude oil. Asphaltenes may precipitate 

out of the fuel solution when a fuel rich 

in carbon disulfide, such as residual 

fuel, is mixed with a lighter 

hydrocarbon fuel, such as n-pentane or 

n-heptane found in some distillate fuels. 

When these heavy aromatic compounds 

fall out of the fuel solution, they can 

clog filters, create deposition along the 

fuel lines/combustion chamber, seize 

the fuel injection pump, or cause other 

system troubles. This risk can be 

minimized through onboard test kits 

and by purchasing distillate and 

residual fuel from the same refiner. 

However, according to the California Air 

Resources Board, the formation of 

asphaltenes is not seen as an issue based 

on data from previous maritime rules. 

As can be seen, if vessel operators 

choose to operate on marine distillate 

fuel while in the ECA, some prudence 

is required. However, as described 

above, issues that could arise with 

switching between residual and 

distillate fuel are addressed through 

changes to operating procedures. To 

conduct a successful switchover 

between the residual and marine 


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22928 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

102 International Maritime Organization, ‘‘2009 

Guidelines for Exhaust Gas Cleaning Systems,’’ 

Resolution MEPC.184(59), Adopted on 17 July 

2009, MEPC 59/24/Add.1/Annex 9. 

distillate fuels, vessel operators will 

need to keep the above issues in mind 

and follow the engine manufacturer’s 

standard fuel switching procedure. 

(g) Boilers 

Steamships operate through the use of 

steam produced by boilers. In addition, 

boilers are often used on dieselpropelled ships for auxiliary power. 

Many of these boilers are designed to 

operate on heavy fuel oil. As such, the 

fuel must be heated and the system 

optimized to atomize heavy fuel oil and 

then mix it with air for combustion. To 

operate these systems on distillate fuel, 

certain modifications to the boiler may 

be necessary to the burner and fuel 

systems. These modifications are more 

likely to be necessary for older boilers. 

First, as with diesel engines, residual 

fuel needs to be heated to flow through 

the pumps. Distillate fuel does not. In 

addition, the fuel pumps and injection 

nozzles must be matched to the 

viscosity and lubricity of the fuel. 

Second, the fuel burners and air mixing 

system must be matched to the fuel. In 

modern boilers, burners generally are 

able to operate on distillate fuel and 

heavy fuel oil. The air mixing generally 

needs to be reduced when using 

distillate fuel which evaporates easier. 

The control system must be adjusted so 

that the main burner does not accidently 

re-ignite after a flame-out. If the boiler 

loses its ignition source (flame) too high 

of a mass of fuel may be vaporized for 

the boiler to be safely re-lighted. In this 

case, the boiler should be purged before 

relighting the flame. Third, proper 

monitoring of the boiler operation will 

optimize flame supervision and 

minimize the risk of problems when 

operating on distillate fuel. 

(2) Equivalents 

Regulation 4 of Annex VI allows for 

alternative devices, procedures, or 

compliance methods if they are ‘‘at least 

as effective in terms of emissions 

reductions as that required by this 

Annex.’’ As an alternative to operating 

on lower sulfur fuel, an exhaust gas 

cleaning device may be used to remove 

SOX and PM emissions from the 

exhaust. These devices are colloquially 

known as SOX scrubbers. This section 

describes the technological feasibility of 

SOX scrubbers and how they may be 

used to achieve equivalent emission 

reductions as fuel switching. 

SOX scrubbers are capable of 

removing up to 95 percent of SOX from 

ship exhaust using the ability of 

seawater to absorb SOX. SOX scrubbers 

have been widely used in stationary 

source applications, where they are a 

well-established SOX reduction 

technology. In these applications, lime 

or caustic soda are typically used to 

neutralize the sulfuric acid in the 

washwater. While SOX scrubbers are not 

widely used on ocean-going vessels, 

there have been prototype installations 

to demonstrate their viability in this 

application such as the Krystallon 

systems installed on the P&O ferry Pride 

of Kent and the Holland America Line 

cruise ship the ms Zaandam. These 

demonstrations have shown scrubbers 

can replace and fit into the space 

occupied by the exhaust silencer units 

and can work well in marine 

applications. 

There are two main scrubber 

technologies. The first is an open-loop 

design which uses seawater as exhaust 

washwater and discharges the treated 

washwater back to the sea. Such openloop designs are also referred to as 

seawater scrubbers. In a seawater 

scrubber, the exhaust gases are brought 

into contact with seawater, either 

through spraying seawater into the 

exhaust stream or routing the exhaust 

gases through a water bath. The SO2 in 

the exhaust reacts with oxygen to 

produce sulfur trioxide which then 

reacts with water to form sulfuric acid. 

The sulfuric acid in the water then 

reacts with carbonate and other salts in 

the seawater to form sulfates which may 

be removed from the exhaust. The 

washwater is then treated to remove 

solids and raise the pH prior to 

discharge back to the sea. The solids are 

collected as sludge and held for proper 

disposal ashore. 

A second type of SOX scrubber which 

uses a closed-loop design is also feasible 

for use on marine vessels. In a closed 

loop system, fresh water is used as 

washwater, and caustic soda is injected 

into the washwater to neutralize the 

sulfur in the exhaust. A small portion of 

the washwater is bled off and treated to 

remove sludge, which is held and 

disposed of at port, as with the openloop design. The treated effluent is held 

onboard or discharged at open sea. 

Additional fresh water is added to the 

system as needed. While this design is 

not completely closed-loop, it can be 

operated in zero discharge mode for 

periods of time. 

Exhaust gas scrubbers can achieve 

reductions in particulate matter as well. 

By removing sulfur from the exhaust, 

the scrubber removes most of the direct 

sulfate PM. Sulfates are a large portion 

of the PM from ships operating on high 

sulfur fuels. By reducing the SOX

emissions, the scrubber will also control 

much of the secondary PM formed in 

the atmosphere from SOX emissions. 

However, simply mixing alkaline water 

in the exhaust does not necessarily 

remove much of the carbonaceous PM, 

ash, or metals in the exhaust. While SO2

associates with the washwater, particles 

can only be washed out of the exhaust 

through direct contact with the water. In 

simple scrubber designs, much of the 

mass of particles can reside in gas 

bubbles and escape out the exhaust. 

Manufacturers have been improving 

their scrubber designs to address 

carbonaceous soot and other fine 

particles. Finer water sprays, longer 

mixing times, and turbulent action 

would be expected to directionally 

reduce PM emissions through contact 

impactions. One scrubber design uses 

an electric charge on the water to attract 

particles in the exhaust to the water. In 

another design, demisters are used that 

help effectively wash out PM from the 

exhaust stream. In either of these 

designs, however, the systems would be 

effective at removing SO2 from the 

exhaust even if the additional hardware 

needed for non-sulfate PM reduction 

were not used. 

Annex VI does not present specific 

exhaust gas limits that are deemed to be 

equivalent to the primary standard of 

operating on lower sulfur fuel. Prior to 

the recent amendments to Annex VI, 

Regulation 14 included a limit of 6 

g/kW-hr SO2 as an alternative to the 

15,000 ppm sulfur limit for sulfur 

emission control areas. Under the 

amended requirements, the specific SO2

limit was removed and more general 

language on equivalents was included. 

IMO has developed guidelines for the 

use of exhaust gas cleaning systems 

(EGCS) such as SOX scrubbers as an 

alternative to operating on lower sulfur 

fuel.102 These guidelines include a table 

of SO2 limits intended to correspond 

with various fuel sulfur levels. Based on 

the methodology that was used to 

determine the SO2 limit of 6.0 g/kW-hr 

for existing ECAs, the corresponding 

limit is 0.4 g/kW-hr SO2 for a 1,000 ppm 

fuel sulfur limit. This limit is based on 

an assumed fuel consumption rate of 

200 g/kW-hr and the assumption that all 

sulfur in the fuel is converted to SO2 in 

the exhaust. The IMO guidelines also 

allow for an alternative approach of 

basing the limit on a ratio of SO2 to CO2. 

This has the advantage of being easier 

to measure during in-use monitoring. In 

addition, this ratio holds more constant 

at lower loads than a brake-specific 

limit, which would approach infinity as 

power approaches zero. For the existing 

15,000 ppm fuel sulfur limit in ECAs, a 

SO2 (ppm)/CO2 (%) limit of 65 was 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 22929 

103Ohio Environmental Council, Earth Day 

Coalition, Marsh Area Regional Council, Ohio 

League of Conservation Voters, OAR–2007–0121– 

0314; Northeast States for Coordinated Air Use 

Management, OAR–2007–0121–0227; American 

Lung Association with Environmental Defense 

Fund, OAR–2007–0121–0366 and OAR–2007– 

0121–0227; Santa Barbara Air Pollution Control 

District, OAR–2007–0121–0231; Clean Air Task 

Force, OAR–2007–0121–0264 and OAR–2007– 

0121–0227; South Coast Air Quality Management 

District, OAR–2007–0121–0309 and OAR–2007– 

0121–0232. 

developed. The equivalent limit for a 

1,000 ppm fuel sulfur level is 4.0 SO2

(ppm)/CO2 (%). 

It is our intent that the IMO 

guidelines will be used by the U.S. 

Government in making the 

determination whether an EGCS meets 

the requirements of MARPOL Annex VI, 

Regulation 4. We are currently working 

with the U.S. Coast Guard on 

developing the U.S. Government 

process for approving equivalents. It is 

not yet clear if a request for an 

equivalent determination will be made 

to EPA or the U.S. Coast Guard. To 

prevent multiple requests from having 

to be made, today’s regulations require 

such a request to be made to EPA only. 

This could change as a result of the 

discussions between EPA and the U.S. 

Coast Guard. If so, we will update the 

regulatory text accordingly. 

Scrubbers are effective at reducing 

SO2 emissions and sulfate PM emissions 

from the exhaust. However, as discussed 

above, the effectiveness of the scrubber 

at removing PM emissions other than 

sulfates is dependent on the scrubber 

design. In addition to sulfate PM 

reductions, switching from residual fuel 

to distillate fuel results in reductions in 

organic PM and metallic ash particles in 

the exhaust. We expect that ECGS 

designs will achieve similar PM 

reductions as fuel switching; however, if 

this turns out to not be the case, we will 

address this issue, as appropriate, 

through further action. 

Water-soluble components of the 

exhaust gas such as SO2, SO3, and NO2

form sulfates and nitrates that are 

dissolved into the discharge water. 

Scrubber washwater also includes 

suspended solids, heavy metals, 

hydrocarbons and polycyclic aromatic 

hydrocarbons (PAH). Before the 

scrubber water is discharged, there are 

several approaches that may be used to 

process the scrubber water to remove 

solid particles. Heavier particles may be 

trapped in a settling or sludge tank for 

disposal. The removal process may 

include cyclone technology similar to 

that used to separate water from 

residual fuel prior to delivery to the 

engine. However, depending on particle 

size distribution and particle density, 

settling tanks and hydrodynamic 

separation may not effectively remove 

all suspended solids. Other approaches 

include filtration and flocculation 

techniques. Flocculation, which is used 

in many waste water treatment plants, 

refers to adding a chemical agent to the 

water that will cause the fine particles 

to aggregate so that they may be filtered 

out. Sludge separated from the scrubber 

water would be stored on board until it 

is disposed of at proper facilities. 

The IMO guidelines for the use of 

exhaust gas cleaning devices such as 

SOX scrubbers include recommended 

monitoring and water discharge 

practices. The washwater should be 

continuously monitored for pH, PAHs 

and turbidity. Further, the IMO 

guidance include specifications for 

these same items, as well as nitrate 

content when washwater is discharged 

in ports, harbors or estuaries. Finally, 

the IMO guidance recommends that 

washwater residue (sludge) be delivered 

ashore to adequate reception facilities 

and not discharged to the sea or burned 

on board. 

Any discharges directly into waters of 

the United States may be subject to 

Clean Water Act or other U.S. 

regulation. To the extent that the air 

pollution control technology results in a 

wastewater discharge, such discharge 

will require a permit under the Clean 

Water Act’s National Pollutant 

Discharge Elimination System (NPDES) 

permit program. For example, the 

NPDES Vessel General Permit in Section 

2.2.26 contains conditions for Exhaust 

Gas Scrubber Washwater Discharge. 

Also, the Act to Prevent Pollution for 

Ships may apply to such discharge. 

D. ECA Designation and ForeignFlagged Vessels 

In our previous marine diesel engine 

rulemakings, EPA did not extend our 

Clean Air Act standards to engines on 

vessels flagged by other countries. In 

our 2003 rule, many States and 

localities expressed concern about the 

high levels of emissions from oceangoing vessels. We examined our 

position and concluded that no change 

was necessary at that time because the 

Tier 1 standards we adopted for 

Category 3 engines on U.S. vessels were 

the same as those contained in 

MARPOL Annex VI. We indicated we 

would re-examine this issue in our 

current rulemaking and would also 

review the progress made by the 

international community toward the 

adoption of new more stringent 

international standards that reflect the 

application of advanced emission 

control technologies. 

We received comments from a broad 

range of interested parties on the 

Advanced Notice of Proposed 

Rulemaking (ANPRM) for this 

rulemaking. Generally, those 

commenters remained concerned about 

the contribution of ocean-going vessels 

to air quality problems. Many took the 

position that EPA should cover engines 

on foreign-flagged OGV under Clean Air 

Act section 213 since they account for 

the vast majority of OGV emissions in 

the United States and because of their 

perception, at the time these comments 

were submitted, that the international 

process to set stringent standards was 

stalled. 

In the Notice of Proposed Rulemaking 

(NPRM) for this rulemaking, we 

provided background on EPA’s past 

statements with regard to the 

application of our Clean Air Act section 

213 standards to engines on foreignflagged vessels, and summarized 

comments we received on this issue in 

response to our ANPRM. Because the 

NOX standards adopted in the 

amendments to Annex VI are 

comparable in stringency and timing to 

our final CAA NOX standards, we did 

not believe it necessary to extend our 

Clean Air Act Tier 2 and 3 standards to 

engines on foreign-flagged vessels. 

Therefore, we did not seek to resolve the 

issue of whether section 213 of the Act 

allows us to set standards for engines on 

foreign-flagged vessels. However, we 

stated that our proposed decision rested 

on the timely adoption of an 

amendment to Annex VI designating the 

U.S. coastal waters as an ECA, since the 

most stringent of the NOX standards will 

be applicable in such areas. We 

maintain the position we expressed in 

the NPRM, particularly in light of the 

recent approval, and circulation for 

adoption, of the North American ECA. 

If the amendment designating a U.S. 

ECA is not timely adopted by the Parties 

to IMO, we will revisit this issue. 

EPA received a number of comments 

in response to the NPRM on the issue 

of whether EPA should or could address 

emissions from engines on foreignflagged vessels. Most commenters 

reiterate their positions as stated in 

comments received on the ANPRM.103

Environmental group commenters who 

previously expressed their position that 

EPA has authority—and even 

obligation—within the Clean Air Act to 

regulate foreign-flagged vessels, 

maintain that position and recognize 

that application of the new standards to 

all vessels, including those that are 

foreign-flagged, is necessary to achieve 

the new standards’ public health and 

environmental benefits. While some 

commenters accept EPA’s position that 

it will revisit this issue without delay in 


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22930 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

104Ohio Environmental Council, Earth Day 

Coalition, Marsh Area Regional Council, Ohio 

League of Conservation Voters, OAR–2007–0121– 

0314; Northeast States for Coordinated Air Use 

Management, OAR–2007–0121–0227; American 

Lung Association with Environmental Defense 

Fund, OAR–2007–0121–0366 and OAR–2007– 

0121–0227. 

105Santa Barbara Air Pollution Control District, 

OAR–2007–0121–0231. 

106Clean Air Task Force, OAR–2007–0121–0264 

and OAR–2007–0121–0227; South Coast Air 

Quality Management District, OAR–2007–0121– 

0309 and OAR–2007–0121–0232; Earthjustice, 

Friends of the Earth, and Center for Biological 

Diversity, OAR–2007–0121–0320. 

107Earthjustice, Friends of the Earth, and Center 

for Biological Diversity, OAR–2007–0121–0320. 

108World Shipping Council, OAR–2007–0121– 

0227 and OAR–2007–0121–0325; Marine Engineers 

Beneficial Association, OAR–2007–0121–0259. 

the event that a U.S. ECA designation is 

not timely adopted by the Parties to the 

IMO,104 others are concerned about the 

potential for delay within the IMO and, 

thus, urge EPA to commence a parallel 

rulemaking as a backstop to that 

potential delay.105 Still others find 

EPA’s reliance on an ECA designation to 

be insufficient and suggest that EPA 

should presently assert authority and 

extend this rule’s application to foreignflagged vessels.106 That suggestion also 

includes a concern that too much 

reliance on the IMO for authority to 

regulate foreign-flagged vessels could 

expose a gap wherein ships that are 

flagged in nations that are not parties to 

Annex VI would go unregulated in U.S. 

waters.107 To close that gap, the 

commenter recommends direct 

application of CAA standards to all 

foreign-flagged vessels. That concern 

echoes industry commenters’ calls for 

equal application of the standards to all 

vessels in U.S. waters to ensure a ‘‘level 

playing field’’ and ‘‘uniform treatment of 

the entire merchant fleet.’’ 108

We appreciate the comments we 

received and are committed to revisiting 

the issue if the U.S. ECA proposal is not 

timely adopted. However, we continue 

to believe we need not revisit this issue 

at this time given that foreign-flagged 

vessels will be subject to standards 

under APPS that are comparable to 

those for U.S.-flagged vessels under 

section 213 of the CAA. The issue of 

whether EPA is compelled to cover 

foreign-flagged vessels under section 

213 of the CAA was raised in Bluewater 

v. EPA, 372 F.3d 404 (DC Cir. 2004), a 

challenge to EPA’s decision in 2003 not 

to revisit the issue of whether foreignflagged vessels may and should be 

covered by nonroad emissions standards 

issued under section 213 of the CAA. In 

finding Bluewater’s claim to be 

premature, the Bluewater court referred 

back to its determination in Engine Mfrs. 

Ass’n v. EPA, 88 F.3d at 1086–87, that 

‘‘new nonroad engine’’ as used in 

213(a)(3) is ambiguous and reiterated 

EPA’s undisputed finding that there 

would be no significant loss of emission 

reductions by not revisiting the issue. 

We do not believe circumstances have 

changed to call into question the 

Bluewater court’s finding as applied to 

today’s setting. In fact, the only changed 

circumstances further support EPA’s 

decision not to revisit the issue. Since 

issuance of the 2003 final rule and the 

court’s decision in Bluewater, Annex VI 

has entered into force, and the United 

States has become a Party to Annex VI 

and has successfully negotiated 

significant new emission and fuel 

standards. In addition, Congress has 

adopted amendments to the Act to 

Prevent Pollution from Ships to 

implement both the original and 

amended Annex VI requirements. 

Therefore, given that foreign-flagged 

vessels are subject to the original and 

new Annex VI NOX and fuel 

requirements under the operation of 

APPS, we do not believe it is currently 

necessary to address whether EPA may 

or should cover foreign-flagged vessels 

under section 213 of the CAA. See 

South Coast v. EPA, 554 F.3d 1076, 

1081 (DC Cir. 2009) (‘‘Deferring 

resolution of the issue until it will have 

an effect remains reasonable and the 

petitioners’ objection therefore remains 

premature.’’). 

However, as noted above, we are 

committed to revisiting this issue if the 

proposed ECA, within which the most 

stringent NOX and fuel requirements are 

applicable, is not timely adopted. 

Meetings to discuss adoption of the 

U.S.-proposed ECA are scheduled 

shortly after this rule is finalized, and 

thus, taking into consideration the lead 

times adopted, little time is lost in not 

revisiting this issue in this rulemaking. 

We also note that ships that are flagged 

in nations that are not a Party to Annex 

VI are subject to Annex VI requirements 

in U.S. waters under the Act to Prevent 

Pollution from Ships. Our regulations to 

implement the requirements of Annex 

VI with respect to such vessels make 

clear the applicability of those 

provisions to such vessels. 

VI. Certification and Compliance 

Program 

This section describes the regulatory 

changes being finalized for the CAA 

Category 3 engine compliance program. 

In general, these changes are being 

finalized to ensure that the benefits of 

the standards are realized in-use and 

throughout the useful life of these 

engines, and to incorporate lessons 

learned over the last few years from the 

existing test and compliance program. 

The most obvious change is that we 

are applying the plain language 

regulations of 40 CFR part 1042 to 

Category 3 engines. These part 1042 

regulations were adopted in 2008 for 

Category 1 and Category 2 engines (73 

FR 25098, May 6, 2008). They were 

structured to contain the provisions that 

are specific to marine engines and 

vessels in part 1042, and apply the parts 

1065 and 1068 for other provisions not 

specific to marine engines. This 

approach is not intended to significantly 

change the compliance program from 

the program currently applicable to 

Category 3 engines under 40 CFR part 

94, except as specifically noted in this 

notice. These plain language regulations 

supersede the regulations in part 94 for 

Category 3 engines beginning with the 

2011 model year. See Section VI.E for 

additional discussion of the transition 

from part 94 to part 1042. 

The changes from the existing 

programs are described below along 

with other notable aspects of the 

compliance program. These changes are 

necessary to implement the new 

standards as well as to implement the 

Annex VI program as required under the 

amendments to the Act to Prevent 

Pollution from Ships. 

Finally, we are also including several 

changes and clarifications to the 

compliance program that are not 

specific to Category 3 engines. Some of 

these apply only for marine diesel 

engines below 30 liters per cylinder 

displacement. 

A. Compliance Provisions for Category 3 

Engines 

In general, we are retaining the 

certification and compliance provisions 

adopted with the Tier 1 standards for 

Category 3 engines. These include 

testing, durability, labeling, 

maintenance, prohibited acts, etc. 

However, we believe additional testing 

and compliance provisions will be 

necessary for new standards requiring 

more advanced technology and more 

sophisticated emission control systems. 

These changes, as well as other 

modifications to our certification and 

compliance provisions for Category 3 

engines, are discussed below. 

Our certification process is similar to 

the process specified in the Annex VI 

NOX Technical Code (NTC) for precertification. However, the Clean Air 

Act specifies certain requirements for 

our certification program that are 

different from the NTC requirements. 

The EPA approach differs most 

significantly from the NTC in three 

areas. First, the NTC allows but does not 

require certification of engines before 

installation (known as pre-certification 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 22931 

under the NTC), while EPA does require 

it. Second, we include various 

provisions to hold the engine 

manufacturer responsible for the 

durability of emission controls, while 

the NTC holds the engine manufacturer 

liable only before the engine is placed 

into service. Finally, we specify broader 

temperature ranges and allow 

manufacturers less discretion in setting 

engine parameters for testing, with the 

goal of adopting test procedures that 

represent a wide range of normal in-use 

operation. We believe the regulations in 

this final rule are sufficiently consistent 

with NTC that manufacturers can 

continue to use a single harmonized 

compliance strategy to certify under 

both systems. 

(1) Testing 

We are largely continuing the testing 

requirements that currently apply for 

Category 3 engines with a few 

exceptions. 

(a) General Test Procedures 

We are applying the general engine 

testing procedures of 40 CFR part 1065 

to Category 3 engines. This is part of our 

ongoing initiative to update the content, 

organization and writing style of our 

regulations. For each engine sector for 

which we have recently promulgated 

standards (such as smaller marine diesel 

engines), we refer to one common set of 

test procedures in part 1065. This is 

because we recognized that a single set 

of test procedures would allow for 

improvements to occur simultaneously 

across engine sectors. A single set of test 

procedures is easier to understand than 

trying to understand many different sets 

of procedures, and it is easier to move 

toward international test procedure 

harmonization if we only have one set 

of test procedures. 

These procedures replace those 

currently published in parts 92 and 94 

and are fundamentally similar to those 

procedures. The primary differences are 

related to tighter tolerances to reduce 

test-to-test variability. In most cases, a 

manufacturer should be able to comply 

with 1065 using its current test 

equipment. Nevertheless, full 

compliance with part 1065 would take 

some effort on the part of 

manufacturers. As such, we are 

including some flexibility to make a 

gradual transition from the part 92 and 

94 procedures. For several years, 

manufacturers will be able to optionally 

use the part 1065 procedures. Part 1065 

procedures will generally be required 

for any new testing by 2016 (except as 

noted below). This is very similar to the 

allowance already provided with 

respect to Category 1 and Category 2 

engines. 

Several manufacturers raised in their 

comments general objections to 

applying the 1065 test procedures. 

However, since we proposed to allow 

Category 3 manufacturers to submit data 

collected using the test equipment, test 

fuels, and procedures specified in the 

NOX Technical Code, we believe that 

the requirement should be finalized as 

proposed. The procedures in 1065 will 

still be the official test procedures, 

however, and manufacturers will be 

liable with respect to any test results 

from 1065 testing. We do not believe 

this allowance will have any effect on 

the stringency of the standards, or how 

manufacturers design and produce their 

engines. 

(b) Test Fuel 

Appropriate test procedures need to 

represent in-use operating conditions as 

much as possible, including 

specification of test fuels consistent 

with the fuels that compliant engines 

will use over their lifetimes. Our Part 94 

regulations allow Category 3 engine 

testing using distillate fuel, even though 

many vessels with these engines 

currently use less expensive residual 

fuel. This provision is consistent with 

the specifications of the NOX Technical 

Code. We are continuing this approach 

for Tier 2 and Tier 3. Our primary 

reason for continuing this approach is 

that we expect these Category 3 engines 

will generally be required to use 

distillate fuels in areas that will affect 

U.S. air quality for most of their 

operational lives. (We expect this 

because we expect IMO to approve our 

proposal to amend Annex VI to 

designate the U.S. coastal waters as an 

ECA.) However, since these engines will 

not be required to use low-sulfur or 

ultra low-sulfur fuel, we are also adding 

an explicit requirement that a highsulfur distillate test fuel be used for both 

Tier 2 and Tier 3 testing. Our testing 

regulations (40 CFR 1065.703) are being 

revised to specify that high-sulfur diesel 

test fuels contain 800 to 2,500 ppm 

sulfur. This will be lower than the prior 

specification of 2,000 to 4,000 ppm. 

This will allow manufacturers to test 

with fuels near the ultimate in-use limit 

of 1,000 ppm. 

(c) Testing Catalyst-Equipped Engines 

In our existing programs that require 

compliance with catalyst-based engines 

(such as the Category 1 & 2 engine 

program), we have required 

manufacturers to test prototype engines 

equipped with prototype catalyst 

systems. However, it is not clear that 

this approach would be practical for 

Category 3 engines. These are 

problematic because of their size and 

because they tend to be a least partially 

custom built on a vessel by vessel basis. 

Requiring a manufacturer to construct a 

full-scale catalyst system for each 

certification test would be extremely 

expensive. 

We are finalizing an optional special 

certification procedure to address this 

concern. The provisions are in 

§ 1042.655 of the finalized regulations. 

The emission-data engine must be tested 

in the specified manner to verify that 

the engine-out emissions comply with 

the Tier 2 standards. The catalyst 

material must be tested under 

conditions that accurately represent 

actual engine conditions for the test 

points. This catalyst testing may be 

performed on a benchscale. 

Manufacturers must include a detailed 

engineering analysis describing how the 

test data collected for the engine and 

catalyst material demonstrate that all 

engines in the family will meet all 

applicable emission standards. 

Manufacturers must verify their design 

by testing a complete production engine 

and catalysts in its final assembled 

configuration. It is important to note 

that this allowance does not limit in any 

way the manufacturers’ or operators’ 

obligations with respect to safety for 

catalyst systems, such as those specified 

by Coast Guard. 

(d) Testing Production Engines 

Under the current regulations, 

manufacturers must test a sample of 

their Category 1 and Category 2 engines 

during production. We are now 

finalizing similar provisions for 

Category 3 engines. While in the past we 

did not believe that such testing was 

necessary, circumstances have changed 

in two important ways. First, relatively 

inexpensive portable test systems have 

recently become available. This greatly 

reduces the cost of testing an engine in 

a ship. Second, the need to verify that 

production engines actually comply 

with the emission standards increases as 

standards become more stringent and 

emission control technologies become 

more complicated. 

Specifically, every new Tier 2 or later 

Category 3 engine must be tested during 

the vessel’s sea trial to show compliance 

with the applicable NOX standard. Any 

engine that fails to comply with the 

standard will need to be repaired and 

retested. Since we are not finalizing PM 

standards for Category 3 engines, and 

because PM measurement is more 

difficult than measuring only gaseous 

emission, we will not require PM 

measurement during testing after 


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22932 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

109 74 FR 16448, April 10, 2009. 

110 ‘‘Measurement Method For Particulate Matter 

Emitted From Marine Engines,’’ Submitted by the 

United States to the International Maritime 

Organization Intersessional [sic] Meeting Of the 

BLG Working Group On Air Pollution, 5 October 

2007. 

installation, provided PM emissions 

were measured during certification. 

One concern that manufacturers have 

raised in the past is that it can be 

difficult to achieve the exact test points 

in use. Therefore, we are allowing 

manufacturers flexibility with respect to 

test points when testing production 

engines, consistent with the equivalent 

allowance under the NOX Technical 

Code. Where manufacturers are unable 

to duplicate the certification test points 

during production testing, we are 

allowing them to comply with an 

alternate ‘‘at-sea standard’’ that is 10 

percent higher than the otherwise 

applicable standard. This is specified in 

§ 1042.104(g). 

Since we are requiring testing of every 

production engine, we are also 

excluding Category 3 engines from 

selective enforcement audits under 40 

CFR part 1068. 

(e) PM Measurement 

We are requiring manufacturers to 

measure PM emissions along with NOX, 

HC, and CO during certification testing 

to report these results along with the 

other test data. This is similar to our 

recently proposed requirement for 

manufacturers to measure and report 

certain greenhouse gas emissions for a 

variety of nonroad engine sectors.109

Manufacturers should be able to collect 

these data using stand-alone partial flow 

PM measurement systems. In recent 

years, several vendors have developed 

such systems to be compliant with the 

requirements of 1065. 

It is worth noting that in the past, 

there has been some concern regarding 

the use of older PM measurement 

procedures with high sulfur fuels. The 

primary issue of concern was variability 

of the PM measurement, which was 

strongly influenced by the amount of 

water bound to sulfur. However, we 

believe improvements in PM 

measurement procedures, such as those 

specified in 40 CFR 1065, have 

addressed these issues of measurement 

variability. The U.S. Government 

recently submitted proposed procedures 

for PM measurement to IMO.110

(2) Low Power Operation and Mode 

Caps 

Emission control performance can 

vary with the power at which the engine 

operates. This is potentially important 

because Category 3 engines can operate 

at relatively low power levels when they 

are operating in port areas. Ship pilots 

generally operate engines at reduced 

power for several miles to approach a 

port, with even lower power levels very 

close to shore. The International 

Organization for Standardization (ISO) 

E3 and E2 test cycles, which are used 

for emission testing of propulsion 

marine engines, are heavily weighted 

towards high power. In the absence of 

other requirements, it would be possible 

for manufacturers to meet the cycleweighted average emission standards 

without significantly reducing 

emissions at low-power modes. This 

could be especially problematic for Tier 

3 engines relying on urea-SCR for NOX

control, since the effectiveness of the 

control is directly affected by the 

amount of urea that is injected and there 

would be an obvious economic 

incentive for manufacturers and 

operators to minimize the amount of 

urea injected. 

We are addressing these concerns in 

two ways. First, we are applying mode 

caps for NOX emissions that will ensure 

that manufacturers design their 

emission controls to be fully effective at 

25 percent power. This will require that 

manufacturers meet the applicable NOX

standard at each individual test point, 

and not merely as a weighted average of 

the test points. The caps will only apply 

for NOX emissions, and manufacturers 

will not be required to meet the HC and 

CO standards at each test point. For HC 

and CO, manufacturers will only be 

required to meet the applicable 

standards as a weighted average of the 

test points. 

The other concern is related to power 

levels other than the test points. To 

address this, we will continue to rely on 

our prohibition of defeat devices to 

ensure effective control for lower 

powers. Most significantly, this will 

prohibit manufacturers from turning off 

the urea supply to SCR systems at these 

points, unless the exhaust gas 

temperature was too cool for the SCR 

catalyst to function properly. (Urea at 

these low temperatures does not react 

with NOX molecules and can lead to 

high emissions of ammonia.) 

(3) On-Off Technologies 

Many of the technologies that are 

projected to be used to meet the Tier 3 

NOX standards (such as SCR, water 

injection, and EGR) are not integral to 

operation of the engine, allowing the 

engine to be operated without them. 

They will also require the operator to 

supply the proper reductant. Thus, 

these technologies are potentially ‘‘onoff’’ technologies. Switching to distillate 

fuel instead of residual fuel to reduce 

SOX and PM emissions can be thought 

of in the same way. 

The increased operating costs of such 

controls associated with urea (or other 

reductants) or with distillate usage 

suggest that it may be reasonable to 

allow these systems to be turned off 

while a ship is operated on the open 

ocean, far away from sensitive areas that 

are affected by ship emissions. This is 

the basis of the MARPOL Annex VI ECA 

approach, with one set of limits that 

would apply when ships are operated in 

sensitive areas and another that would 

apply when ships are operated outside 

those designated areas. 

We are finalizing the proposed 

regulatory provision in § 1042.115(g) to 

address the use of on-off technologies 

on Category 3 engines subject to the Tier 

3 standards. This provision will require 

the manufacturer to obtain EPA 

approval to design the engines to have 

on-off features. It will also require the 

engine’s onboard computer to record the 

on-off operation (including geographic 

position and time) and require that the 

engine comply fully with the Tier 2 

standards when the Tier 3 controls are 

turned off. 

In response to comments, we are 

expanding this option slightly to 

address other possible technological 

solutions. In particular, we will allow a 

manufacturer to design the system to 

have a Tier 3 mode and a Tier 2 mode 

that correspond to ‘‘on’’ and ‘‘off,’’ 

without regard to whether any given 

controls are turned on or off. For 

example, under this allowance, a 

manufacturer could design the system to 

have a Tier 2 (off) mode in which the 

SCR system continues to function, while 

engine-out emissions are increased. 

Such a design would be allowed as long 

as the emission downstream of the 

aftertreatment met the Tier 2 standards. 

Our goal is to require manufacturers 

to comply with the Tier 3 standards in 

all areas where the emissions 

significantly affect U.S. air quality. We 

expect that all such areas will also 

ultimately be included in one or more 

Emission Control Areas. We describe a 

North American ECA in Section V.A, 

which is intended to include most areas 

where the emissions significantly affect 

U.S. air quality. However, we have not 

yet determined the extent to which 

Category 3 engines affect air quality in 

other areas—specifically, the U.S. 

territories, areas of Alaska west of 

Kodiak, the smallest Hawaiian islands, 

or Puerto Rico and the U.S. Virgin 

Islands. Therefore, we are including an 

interim provision to exclude those areas 

with respect to the Tier 3 standards at 

this time. We will revisit this should our 

review of available modeling results or 


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other information indicate that 

compliance with the Tier 3 standards 

should be required for some or all of 

these areas. 

(4) NOX Monitoring 

Category 3 engines equipped with onoff controls must be equipped to 

continuously monitor NOX

concentrations in the exhaust. Engine 

manufacturers will be required to 

include systems to automatically alert 

operators of any operation with the 

emission controls on where NOX

concentrations indicate malfunctioning 

emission controls. We are also requiring 

the engine to record in nonvolatile 

computer memory any such operation. 

However, we are not requiring 

monitoring NOX concentrations during 

operation for which the emission 

controls are allowed to be turned off, 

provided the record indicated that the 

controls were turned off. Where the 

NOX monitor system indicates a 

malfunction, operators will be required 

to investigate the cause and make any 

necessary adjustments or repairs. 

We are defining as a malfunction of 

the emission controls any condition that 

would cause an engine to fail to comply 

with the applicable NOX standard (See 

Section VI.A.1.d for a discussion of 

standards that will apply for installed 

engines at sea). Such malfunctions 

could include maladjustment of the 

engine or controls, inadequate 

reductant, or emission controls turned 

off completely. We recognize that it is 

not possible to perfectly correlate a 

measured NOX concentration with an 

equivalent cycle-weighted emission 

result. Therefore, the requirement will 

allow engine manufacturers to exercise 

good engineering judgment in using 

measured NOX concentrations to 

monitor the emission performance of 

the engine. Should manufacturers 

decide that it would be helpful to have 

a less subjective (and less flexible) 

requirement, we will be willing to work 

with them to make such improvements 

to this provision through a future 

rulemaking. 

(5) Parameter Adjustment 

Given the broad range of ignition 

properties for in-use residual fuels, we 

expect that our in-use adjustment 

allowance for Category 3 engines will 

result in a broad range of adjustment. 

We requested comment on a 

requirement for operators of ships 

equipped with NOX monitors to perform 

a simple NOX check test to confirm 

emissions after parameter adjustments 

or maintenance operations, using 

onboard emission measurement systems 

with electronic-logging equipment. 

While we are not adopting such a 

requirement at this time, we may do so 

in the future should we determine that 

these engines are being improperly 

adjusted in use. 

(6) In-Use Liability 

Under the Tier 1 program for Category 

3 engines, owners and operators are 

required to maintain, adjust, and 

operate the engines in such a way as to 

ensure proper function of the emission 

controls. These requirements, which are 

described in 40 CFR 94.1004, are being 

continued in the regulations in part 

1042 (See § 1042.660 of the finalized 

regulations for these requirements). 

Owners will also continue to be 

required to keep certain records onboard 

the vessel and report annually to EPA 

whether or not the vessel has complied 

with these and other requirements. 

Specifically, these provisions require 

that all maintenance, repair, adjustment, 

and alteration of the engine be 

performed using good engineering 

judgment so that the engine continues to 

meet the emission standards. Each twohour period of operation of an engine in 

a condition not complying with this 

requirement will be considered a 

separate violation. Some commenters 

expressed concern that treating each 

two-hour period of operation as a 

separate violation would be 

inappropriate for events that occur 

while the vessel is out at sea. These 

commenters correctly noted that where 

a repair cannot be made at sea, the 

operator has no choice but to continue 

operating the vessel in its noncompliant 

condition. Therefore, we are revising the 

regulations to clarify that we would not 

consider operating a vessel in need of 

repair to be a violation, if such a repair 

was not possible. 

(7) Replacement Engines 

The existing provisions of § 1042.615 

provide an exemption that allows 

manufacturers to produce new 

uncertified engines when they are 

needed to replace equivalent existing 

engines that fail prematurely. For many 

engine sectors, this practice is common, 

but represents a very small faction of a 

manufacturer’s total engine production. 

We do not believe this practice is either 

common or necessary for Category 3 

engines, and therefore we proposed to 

not allow this exemption for Category 3 

engines. However, engine manufacturers 

commented that there have been 

infrequent but real occurrences where 

they have needed to provide a Category 

3 replacement engine in response to 

premature engine failure. To address 

this concern, we are finalizing a 

provision that would allow us to make 

an exception in very unusual 

circumstances and allow a manufacturer 

to make a new Category 3 engine that is 

exempt from current emission 

standards. Even for the rare case where 

manufacturers would need to supply a 

replacement Category 3 engine, we 

would expect them generally to be able 

to provide a certified engine. It is clear 

that removing a failed engine and 

installing a replacement will involve a 

very significant effort; we would expect 

this effort to include reasonable 

modifications to accommodate a 

certified engine even if it was somewhat 

different than the engine being replaced. 

However, if manufacturers can 

demonstrate under § 1042.615 that no 

certified engine has the physical and 

performance characteristics to properly 

power the vessel, they may produce a 

new engine that is exempt from 

emission standards. This may be most 

likely for vessels that have paired 

Category 3 engines where one of the 

engines fails prematurely and cannot be 

repaired without being removed from 

the vessel. 

It is also important to note that the 

provisions of Annex VI related to 

replacement engines also apply. This 

generally limits replacement engines to 

those that are identical to the engines 

being replaced. 

B. Compliance Provisions To Implement 

Annex VI NOX Regulation and the NOX

Technical Code 

In addition to the Clean Air Act 

provisions being finalized in this action, 

we are also establishing new regulations 

to implement certain provisions of the 

Act to Prevent Pollution from Ships. 

These regulations are a new part 1043 

of title 40. 

The Act to Prevent Pollution from 

Ships establishes a general requirement 

for vessels operating in the exclusive 

economic zone and navigable waters of 

the United States to comply with 

MARPOL Annex VI. It also gives EPA 

and the Administrator the authority to 

further implement MARPOL Annex VI. 

Many of the requirements relating to 

NOX emissions and fuel sulfur limits 

can be implemented without the need 

for further elaboration because the 

Annex, along with the NOX Technical 

Code, provides instructions on how to 

demonstrate compliance with those 

requirements. However, APPS 

authorizes the Administrator to 

prescribe any necessary or desired 

additional regulations to assist in 

carrying out the provisions of 

Regulations 12 through 19 of Annex VI 

(see 33 U.S.C. 1903(c)(2)). Specifically, 

the regulations being finalized in this 

FRM in part 1043 of title 40 are 


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22934 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

111See 68 FR 9746, February 28, 2003, at 9774– 

5 for a discussion of these differences as they relate 

to Category 3 marine diesel engines. 

intended to assist in the implementation 

of the engine and fuel requirements 

contained in Regulation 13, 14, and 18 

of MARPOL Annex VI. They address 

such issues as how to obtain an Engine 

International Air Pollution Prevention 

(EIAPP) certificate (which is equivalent 

in many ways to a Clean Air Act 

certificate of conformity), exemptions 

for vessels used exclusively in domestic 

service, and requirements for vessels not 

registered by a country that is a Party to 

Annex VI. 

The requirements being finalized in 

part 1043 will generally begin July 1, 

2010. However, the ECA NOX

requirements will not begin until the 

Tier 3 NOX standards begin (or when 

the ECA enters into force for the U.S., 

whichever is later), and the ECA fuel 

requirements will not begin until 12 

months after the ECA enters into force 

for the U.S., as provided by Annex VI. 

It is also important to clarify that Annex 

VI itself was effective for the United 

States as of January 8, 2009. The 

requirement of the Annex for ships to 

have a valid International Air Pollution 

Prevention (IAPP) certificate applies for 

U.S. vessels based on when the keel is 

laid and when it is dry-docking. Vessels 

for which keels were laid (or which 

were at a similar stage of construction) 

before January 8, 2009 must have on 

board a valid IAPP certificate no later 

than the first scheduled dry-docking, 

but in no case later than January 8, 

2012. Vessels for which keels are laid 

(or which are at a similar stage of 

construction) after January 8, 2009 must 

have on board a valid IAPP certificate 

upon completion of its initial survey 

before the ship is placed into service. 

The MARPOL Annex VI NOX

requirements apply to all marine diesel 

engines above 130 kW. Similarly, the 

MARPOL Annex VI fuel requirements 

apply to all fuel oil used onboard a 

vessel, defined as any fuel delivered to 

and intended for combustion purpose 

for propulsion or operation on board 

any ship, including distillate and 

residual fuels. Thus the part 1043 

compliance program described here 

applies somewhat more broadly than 

the Clean Air Act compliance program 

described earlier for Category 3 engines. 

It is worth noting that while APPS 

generally requires compliance with 

Annex VI and future amendments to 

Annex VI, we have incorporated by 

reference the existing 2008 version of 

the Annex for certain purposes. 

Specifically, we require compliance 

with the 2008 Annex VI NOX and fuel 

requirements by non-Party vessels and 

require compliance with the ECA 

requirements by all vessels in our 

internal waters; both of these issues are 

discussed later. We fully expect to 

update this incorporation by reference 

whenever aspects of the Annex relating 

to these provisions are amended. 

However, we recognize that it is 

possible that there will be a brief period 

during which the incorporated version 

differs slightly from any amended 

provisions. To the extent that occurs, 

vessels in our internal waters and nonParty vessels would be subject to the 

requirements in the 2008 version (or the 

latest version that has been incorporated 

by reference). 

In § 1043.1(d), we clarify that these 

regulations do not limit requirements 

that would otherwise apply pursuant to 

APPS, except for excluding domestic 

vessels from the Annex VI NOX

standard (consistent with the allowance 

in Regulation 13.1.2.2 of the Annex). 

(1) EIAPP Certificates 

In general, an engine can be dualcertified under EPA’s Clean Air Act 

marine diesel engine program and the 

MARPOL Annex VI/APPS program. 

However, we require that engine 

manufacturers submit separate 

applications for the 1042 and EIAPP 

certificates. The regulations in part 1043 

specify the process that would apply. 

The process for obtaining the EIAPP is 

very similar to the process for obtaining 

a certificate of conformity under part 

1042, and although there are differences 

between the programs, manufacturers 

should be able to comply with both 

programs with very little additional 

work. The primary differences are that, 

to certify to the MARPOL Annex VI 

standards, the manufacturer must 

include a copy of the Technical File and 

onboard NOX verification procedures (as 

specified in Section 2.4 of the NOX

Technical Code) and is not required to 

provide information about useful life, 

emission labels, deterioration factors, or 

PM emissions.111 Engine manufacturers 

will be able to apply for both 

certifications using the same 

certification templates and test data. 

Consistent with our 1042 program, 

our 1043 program will require that each 

engine installed or intended to be 

installed on a U.S.-flagged vessel have 

an EIAPP before it is introduced into 

U.S. commerce. The finalized 

regulations will create a presumption 

that all marine engines manufactured, 

sold, or distributed in U.S. commerce 

will be considered to be intended to be 

installed on a U.S.-flagged vessel, 

although this presumption could be 

rebutted by clear and convincing 

evidence to the contrary (evidence that 

the engine is intended for export, for 

example). We will also require that all 

engines that are intended only for 

domestic use be labeled as such. Thus, 

all engines not labeled for domestic use 

will be presumed to be intended for use 

on vessels subject to part 1043. 

(2) Approved Methods 

The 2008 amendments to MARPOL 

Annex VI added a new provision to the 

engine standards in Regulation 13 that 

extends the Tier I NOX limits to certain 

engines installed on ships constructed 

on or after January 1, 1990 through 

December 31, 1999. Specifically, 

engines with power output greater than 

5,000 kW and with per cylinder 

displacement at or above 90 liters 

installed on such ships would be 

required to meet the Tier I NOX limits 

if a certified Approved Method is 

available. An Approved Method may be 

certified by the Administration of any 

flag state, but once one is registered 

with the IMO the owner of such an 

engine must either install the Approved 

Method or demonstrate compliance 

with the Annex VI Tier I limits through 

some other method. We are including a 

regulatory section codifying this 

requirement. These regulations are 

contained in § 1043.50. 

(3) Other Annex VI Compliance 

Requirements 

Engine manufacturers, vessel 

manufacturers, vessel owners, and fuel 

providers, fuel distributors, and other 

directly regulated stakeholders are 

required to comply with all aspects of 

Regulations 13, 14, and 18 of Annex VI 

as well as the NOX Technical Code. 

These include requirements for engine 

operation, fuel use, fuel oil quality, and 

various recordkeeping requirements 

(e.g., record book of engine parameters, 

engine technical file, fuel switching 

procedures, bunker delivery notes and 

associated fuel samples, and fuel 

sampling procedures). 

Regulation 18 of both the original and 

the revised Annex VI sets out the 

requirements for bunker delivery notes 

and associated fuel samples. All vessels 

400 gross tons and above, and each 

fixed and floating drilling rig and other 

platforms (i.e., those vessels subject to 

Regulations 5 and 6 of both the original 

and the revised Annex VI) are required 

to keep onboard the vessel bunker 

delivery notes that specify the details of 

fuel oil brought onboard for combustion 

purposes. These bunker delivery notes 

may be inspected by the competent 

authority of a Party while the ship is in 

its port or offshore terminals. The 

competent authority may also verify the 


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contents of bunker delivery notes. A 

fuel sample is required to accompany 

each bunker delivery note, sealed and 

signed by the supplier’s representative 

and the master or officer in charge of 

fuel operations. The sample should be 

taken pursuant to IMO guidelines and is 

to be retained for at least 12 months 

from the date of delivery. While the 

IMO guidelines were not in place at the 

time the original Annex was adopted, 

they were subsequently developed and 

Regulation 18 of amended Annex VI 

refers specifically to these guidelines: 

MEPC.96(47). 

Although these are Annex VI 

requirements, we are not creating a 

regulatory requirement for the 

certification of bunker delivery notes or 

fuel samples. Such a requirement would 

be infeasible with respect to the time 

and resources that would be necessary 

to certify every batch of fuel sold to a 

vessel above 400 GT in the United 

States. In addition, the requirements in 

Annex VI clearly call for the sulfur 

content of gas fuels delivered to a ship 

for combustion purposes be 

documented by the fuel supplier, and 

that the required fuel sample be sealed 

and signed by the fuel provider and the 

representative of the ship owner. 

It has been brought to the attention of 

EPA and the Coast Guard that some fuel 

providers in the United States and 

elsewhere have not been issuing bunker 

delivery notes and/or fuel samples at 

the time of fuel delivery. Ship owners 

and operators, and fuel providers, are 

reminded that the bunker delivery notes 

and fuel samples are requirements 

under Annex VI; a vessel can be found 

in noncompliance with the Annex VI 

fuel requirements if the vessel is 

inspected at a domestic or foreign port. 

Therefore, ship owners and operators 

should exercise care and diligence in 

obtaining the necessary bunker delivery 

notes and fuel samples at the time fuel 

is brought onboard, through the fuel 

contractual arrangement or through 

other agreement at the time of sale, and 

fuel providers should be certain that 

they have procedures and processes in 

place to provide the bunker delivery 

note and fuel sample for each batch of 

fuel delivered. 

(4) Non-Party Vessels 

The finalized regulations specify that 

vessels flagged by a country that is not 

a party to MARPOL (known as nonParty vessels) must comply with 

Regulations 13, 14, and 18 of Annex VI 

when operating in U.S. waters. This 

requirement fulfills the requirement of 

33 U.S.C. 1902(e), which requires the 

adoption of regulations for non-Party 

vessels such that they are not treated 

more favorably than vessels of countries 

that are party to the MARPOL Protocol. 

However, since such vessels cannot get 

EIAPP certificates, this provision 

requires non-party vessels to obtain 

equivalent documentation of 

compliance with the NOX standards of 

Annex VI. 

(5) Internal Waters 

APPS applies Annex VI requirements, 

including amendments to Annex VI that 

have entered into force for the United 

States, to ships that are in the internal 

waters of the U.S. Among the 

requirements added in the 2008 

amendments to Annex VI are more 

stringent standards for fuel quality and 

NOX emissions. Many of these standards 

apply in ‘‘Emission Control Areas’’ 

(ECAs) to be designated by the Parties 

to Annex VI. As described earlier, the 

U.S. and Canada submitted an 

application for a North American ECA, 

adoption of which is anticipated in 

March 2010. 

As some commenters have noted, the 

ECA proposal does not include U.S. or 

Canadian internal waters. While the two 

governments did not specifically seek 

designation for internal waters in their 

ECA proposal, it is evident that 

emissions in internal waters are of 

greater concern than emissions 

occurring from the baseline seaward to 

200 nautical miles. Vessel emissions in 

internal waters are often even closer to 

U.S. population centers than emissions 

in coastal waters. Emissions in internal 

waters affect U.S. air quality to an equal, 

if not greater, degree to emissions in 

coastal waters. Given these 

considerations, EPA believes that 

Congress’ direction to apply Annex VI 

requirements to ships in the internal 

waters of the United States, as well as 

its grant of authority to EPA to 

administer the relevant regulations of 

Annex VI, confers the authority to apply 

the fuel quality and emissions 

requirements that apply to ECAs to 

ships in internal waters. 

We also note the application of these 

standards to internal waters should not 

disturb reasonable expectations or 

impose a significant burden on industry. 

It has always been presumed in our 

analyses supporting the ECA proposal 

and this rule, and is the customary 

practice in the North Sea and Baltic Sea 

SECAs, that vessels will continue to 

comply with the emissions standards 

anytime they operate on the landward 

side of the ECA boundary, including in 

a country’s internal waters. We are not 

aware of anyone ever suggesting that a 

vessel complying with ECA standards 

would increase its emissions while it 

remains in port or other body of water 

that is part of or connected to an ECA. 

We do not believe that vessels would 

generally choose to switch to higher 

sulfur fuels or choose to turn off Tier III 

control strategies in internal waters. In 

most cases, ocean-going vessels only 

operate in internal waters for short 

periods of time while entering and 

leaving ports. Switching to high sulfur 

fuel or turning off and on NOX control 

strategies could be time consuming and 

may not be justified by the limited 

operational cost savings. 

We are finalizing regulatory text to 

codify Annex VI global requirements 

and clarify application of Annex VI ECA 

requirements to ships in U.S. internal 

waters. Specifically, the regulatory text 

includes the APPS requirements for 

vessels to comply with Annex VI global 

requirements in our internal waters. The 

regulatory text also clarifies that vessels 

operating in U.S. internal waters, 

shoreward of an ECA, that can be 

accessed by ocean-going vessels must 

meet Annex VI ECA requirements. This 

includes ports and internal waters such 

as the Great Lakes. In the regulatory text 

we refer to the internal waters in which 

we are applying the ECA requirements 

as the ‘‘ECA associated area.’’ The 

regulatory text will apply the ECA 

requirements for these internal waters 

beginning the same time the ECA takes 

effect under Annex VI. 

Application of the ECA requirements 

under APPS to our internal waters does 

not replace but rather augments our 

Clean Air Act standards. The Clean Air 

Act exhaust emission and fuel standards 

apply regardless of the APPS provisions, 

except to the extent that any of the new 

CAA provisions refer to the ECA 

boundaries. 

We received extensive comments on 

the economic and safety impacts of 

applying the ECA engine and fuel 

requirements to vessels that operate on 

the Great Lakes. The Summary and 

Analysis of Comments for this rule 

includes a discussion of the economic 

impacts of applying the ECA engine and 

fuel requirements to vessels that operate 

on the Great Lakes. In addition, EPA 

will perform a study and issue a report 

evaluating the economic impact of the 

final rule on Great Lakes carriers. We 

will work with Great Lakes stakeholders 

in conducting the study and expect to 

complete the report in summer 2010. 

In addition to recommending the 

above-mentioned study, Conference 

Report 111–316 accompanying HR 2996, 

the Department of Interior, 

Environment, and Related Agencies 

Appropriations Act, 2010, suggests that 

EPA should include two waiver 

provisions for Great Lakes carriers in 

this final rule. Based on this statement 


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and concerns that have been raised by 

the Great Lakes shipping industry, we 

are finalizing a new provision to address 

certain vessels operating exclusively on 

the Great Lakes (hereinafter, ‘‘Great 

Lakes vessels’’). Specifically, we are 

finalizing a provision that provides for 

relief in the event of serious economic 

hardship. This economic hardship 

provision allows Great Lakes shippers to 

petition EPA for a temporary exemption 

from the 2015 fuel sulfur standards. The 

shipper must show that despite taking 

all reasonable business, technical, and 

economic steps to comply with the fuel 

sulfur requirements, the burden of 

compliance costs would create a serious 

economic hardship for the company. 

The Agency will evaluate each 

application on a case-by-case basis. Our 

experience to date shows that detailed 

technical and financial information 

from the companies seeking relief has 

been necessary to fully evaluate whether 

a hardship situation exists. As such, we 

may request additional information as 

needed. Typically, because of EPA’s 

comprehensive evaluation of both 

financial and technical information, 

action on hardship applications can take 

approximately six months. Because of 

this, applications for an economic 

hardship waiver must be submitted to 

EPA by January 1, 2014. As is our 

historic practice with fuel waivers, if we 

approve a delay in meeting the fuel 

sulfur requirements, we expect to 

impose appropriate conditions to: (1) 

Ensure the shipper is making its best 

effort; and (2) minimize any loss of 

emissions benefits from the program. 

In the Conference Report, Congress 

also indicated that EPA should provide 

a waiver for the requirement for the use 

of 1.0 percent fuel sulfur (10,000 ppm) 

standard if residual fuel meeting that 

standard is not available on the Great 

Lakes. In response to this statement and 

comments from the Lake Carriers 

Association, we are creating a provision 

that will ensure that operators on the 

Great Lakes will be able to buy marine 

residual fuels if compliant 10,000 ppm 

S fuel is not available. Under this 

provision, if marine residual fuel 

meeting the 10,000 ppm S standard is 

not available, it will not be a violation 

of our standards for vessel operators to 

bunker and use marine residual fuel 

with sulfur content above 10,000 ppm S 

provided the fuel they do purchase is 

the lowest sulfur marine residual fuel 

available at the port. We believe this 

market based approach will provide a 

significant incentive to fuel suppliers to 

provide 10,000 ppm S fuel, while giving 

Great Lakes shippers confidence that 

marine residual fuel will be available for 

their use during the 10,000 ppm S fuel 

program. 

Finally, some commenters raised 

technical and safety issues associated 

with operating Great Lakes steamships 

on distillate fuel. Great Lakes 

steamships operate in fresh water and 

therefore have very long lives. Many of 

the boilers used on these vessels were 

manufactured and constructed in the 

1940s and 1950s and were designed 

specifically to operate on heavy fuel 

oils. Due to these technical issues, we 

considered a number of options for how 

to address these vessels. However, 

Congress placed a prohibition on EPA’s 

use of funds in this fiscal year to issue 

a final rule that includes fuel sulfur 

standards applicable to existing 

steamships that operate exclusively 

within the Great Lakes. Therefore, we 

are excluding Great Lakes steamships 

from the fuel sulfur requirements. For 

the purpose of this exclusion, Great 

Lakes steamships means vessels, 

operating exclusively on the Great Lakes 

and Saint Lawrence Seaway, whose 

primary propulsion is a steam turbine or 

steam reciprocating engine. In addition, 

these steamships must have been in 

service on the Great Lakes prior to 

October 30, 2009. This does not include 

diesel propulsion Category 3 vessels 

with auxiliary boilers. 

Totem Ocean Trailer Express (TOTE) 

raised similar concerns for the small 

number of steamships operating along 

the U.S. coasts. As these vessels do not 

operate exclusively within U.S. internal 

waters, they fall under the U.S. 

Government’s (primarily EPA and Coast 

Guard’s) implementation of the ECA 

provisions of Annex VI. The 

requirements of the Annex VI ECA fuel 

sulfur limits apply to all vessels and 

have no exemptions for steamships. It is 

not within the scope of this rulemaking 

to amend the requirements of the 

MARPOL Annex VI treaty. However, 

through TOTE’s comments and followup conversations with ship owners, we 

agree that special challenges exist for 

the use of lower sulfur fuel in 

steamships. Therefore, we will continue 

to work on this issue with the United 

States Coast Guard and other members 

of the U.S. Delegation to IMO as well as 

other interested stakeholders including 

the affected steamship operators. We are 

committed to resolving this issue before 

the end of 2011, well in advance of 

January 2015 when the 0.1 percent fuel 

sulfur standard will enter into force. 

(6) Exemptions and Exclusions 

Under MARPOL Annex VI and APPS, 

certain vessels are excluded from some 

or all of the requirements. Consistent 

with Annex VI and APPS, the 

regulations in 1043 will exclude public 

vessels and engines intended to be used 

solely for emergencies. For the purpose 

of this provision, the term ‘‘public 

vessels’’ includes all warships and naval 

auxiliary vessels, as well as any other 

vessels owned or operated by a 

sovereign country engaged in 

noncommercial service. Consistent with 

the provisions in APPS, we are not 

applying the Annex VI requirements to 

U.S.-flagged public vessels (or foreign 

public vessels excluded by their flag 

states). It should be noted, however, that 

not all public vessels are exempt from 

our Clean Air Act engine and fuel 

requirements. Only public vessels 

covered by a national security 

exemption under § 94.908 or § 1042.635 

are exempt from the Clean Air Act 

program. 

The category of emergency engines 

includes engines that power equipment 

such as pumps that are intended to be 

used solely for emergencies and engines 

installed in lifeboats intended to be 

used solely in emergencies. It should be 

noted that the emergency engine 

provisions in the Annex and part 1043 

are similar but not identical to the 

emergency engine provisions in our 

Clean Air Act program or the process of 

obtaining our CAA exemptions. In 

particular, the emergency engine 

exemption from the CAA requirements 

applies only with respect to the catalystbased Tier 4 standards. 

We are exempting from the MARPOL 

Annex VI NOX standards engines 

installed on vessels registered or flagged 

in the United States provided the vessel 

remains within the EEZ of the United 

States. These engines will still be 

required to meet stringent emission 

standards since they are covered by our 

Clean Air Act program. In addition, the 

fuels used by these vessels are also 

covered by our Clean Air Act program, 

which has more stringent fuel 

requirements than Annex VI. Therefore, 

as long as the operators of these 

domestic vessels comply with these 

more stringent Clean Air Act fuel 

requirements, they will be deemed to be 

in compliance with the Annex VI 

requirements. The combination of these 

proposed provisions will mean that a 

fishing vessel that operates out of a U.S. 

port and that never leaves U.S. waters 

will not be required to have an EIAPP 

for all engines above 130 kW, a record 

book of engine parameters and a 

technical file for each engines, and 

vessels over 400 gross tons will not be 

required to maintain bunker delivery 

notes (vessels under 400 gross tons are 

not required by Regulation 18 of 

MARPOL Annex VI to have bunker 

delivery notes). Instead, the engines on 


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that vessel will be required to be in 

compliance with our marine diesel 

engine standards and be required to 

comply with the manufacturer’s 

requirements with regard to the proper 

fueling of those engines. We are also 

explicitly precluding these engines from 

being certified to use residual fuel if 

they are exempt from the part 1043 

requirements. Thus, these engines will 

be required to always use cleaner fuels 

than are required by Annex VI. U.S. 

vessels that operate or may operate in 

waters that are under the jurisdiction of 

another country are not exempt from 

these provisions, and the owner of any 

such vessel may be required by that 

country to show compliance with 

Annex VI. Therefore, the owner should 

be sure to maintain the appropriate 

paperwork for that engine and have the 

appropriate engine certification. It 

should be noted that engines that must 

show compliance with the Annex VI 

standards are not exempt from EPA’s 

standards for Category 1 or Category 2 

engines. 

Finally, spark-ignition, nonreciprocating engines, and engines that 

do not use liquid fuel are not included 

in Regulation 13 of the Annex VI 

program and therefore they will not be 

covered by the proposed APPS 

regulations with respect to NOX

emissions. However, the MARPOL 

Annex VI fuel requirements do apply for 

these vessels. These engines are 

generally subject to separate Clean Air 

Act fuel requirements and/or emission 

standards that effectively require the use 

of low sulfur fuels, either directly or 

indirectly. 

C. Changes to the Requirements Specific 

to Engines Below 30 Liters per Cylinder 

The amendments to MARPOL Annex 

VI were adopted in October of 2008, 

after we finalized our Clean Air Act Tier 

3 and Tier 4 standards for Category 1 

and Category 2 engines (May 6, 2008, 73 

FR 25097). While these two programs 

are very similar, there are a few 

differences between them with regard to 

their engine requirements. We are 

adopting some changes to our CAA 

program to facilitate compliance with 

both programs. In addition, some of the 

provisions described in Section VI.D 

may also apply to Category 1 and 

Category 2 marine diesel engines, 

regarding non-diesel engines and 

technical amendments to our current 

program. 

(1) MARPOL Annex VI and EPA’s 

Standards for Category 1 and Category 2 

Engines 

Our existing regulations include an 

exemption for Category 1 and Category 

2 engines on certain migratory vessels. 

This allowance is limited to vessels that 

are operated primarily outside of the 

United States, and that obtain and 

maintain SOLAS certification and 

appropriate EIAPP certification 

demonstrating compliance with Annex 

VI. We are making some minor 

modifications to this allowance to 

reflect the new Annex VI standards. 

We are also revising § 1042.650 to add 

exemption provisions for Category 1 and 

Category 2 auxiliary engines on vessels 

with Category 3 propulsion engines. 

These auxiliary engines would be 

exempt from the part 1042 standards, 

but would still be required to comply 

with the Annex VI standards. In 

addition, engines that would have been 

subject to the Tier 4 standards of part 

1042 would be required to conform to 

the Tier III NOX requirements, 

irrespective of whether they would be 

required to comply under Annex VI. For 

example, this would affect 2015 

Category 2 engines with a maximum 

engine power of 3000 kW installed on 

a 2015 vessel since such an engine 

would be subject to the Tier 4 standards 

under § 1042.101, but would have only 

been subject to the Tier II standards 

under Annex VI. 

Given the MARPOL Annex VI and 

CAA NOX requirements are comparable, 

with slightly different phase-in dates 

and cut-offs, we believe this approach 

will be a less burdensome 

implementation approach over 

transitioning years, and will not have a 

meaningful impact on emission 

reductions. In the absence of this 

exemption, manufacturers would have 

been required to certify special auxiliary 

engines that met both Annex VI and 

1042 requirements for a U.S. market that 

could be as small as one engine per 

year. By allowing manufacturers to meet 

only the Annex VI requirements, they 

would be able to produce a single 

international engine and spread the 

administrative costs over many more 

engines. It is important to note that we 

are not extending this exemption to 

vessels powered by smaller engines 

because these factors cannot be 

presumed for such vessels. 

(2) On/Off Technology for Category 1 

and 2 Engines 

As described in Section VI.A.3 above, 

we proposed to allow the use of 

auxiliary emission control devices 

(AECDs) that would allow modulation 

of emission control equipment on 

Category 3 engines outside of specific 

geographic areas. These AECDs would 

be subject to certain restrictions: (1) The 

AECD would be available for the Tier 3 

standards only; (2) the AECD would 

modulate emission controls only while 

operating in areas where emissions 

could reasonably be expected to not 

adversely affect U.S. air quality; and (3) 

an engine equipped with an AECD must 

also be equipped with a NOX emission 

monitoring device. 

We are expanding our proposed 

allowance for ocean-going vessels with 

Category 3 propulsion engines to also 

include Category 1 and Category 2 

engines to provide auxiliary power. We 

are not allowing this option for U.S. 

vessels with Category 1 or Category 2 

propulsion engines. 

D. Other Regulatory Issues 

In addition to the changes described 

in Sections VI.A and VI.C, we are also 

finalizing changes that apply to marine 

engines in general, and/or to other types 

of engines. 

(1) Non-Diesel Engines 

Most of the preceding discussions 

have focused on conventional diesel 

engines using either diesel fuel or 

residual fuels. It is important to 

highlight two other types of engines 

being affected by this proposal: engines 

using other fuels and gas turbine 

engines. 

(a) Engines Not Using Diesel Fuel 

For all categories of marine engines, 

our existing standards apply to all 

engines meeting the definition of 

compression-ignition, regardless of the 

fuel type. For example, compressionignition Category 3 engines that burn 

natural gas are subject to our Tier 1 

standards and will be subject to our 

finalized Tier 2 and Tier 3 standards. 

We are continuing to apply this 

approach for all marine engines subject 

to our standards. 

The testing regulations in part 1065 

include test fuel specifications for diesel 

fuel, residual fuel, and natural gas (as 

well as for gasoline and liquefied 

petroleum gas, which would not 

typically be used in a compressionignition engine). To certify an engine for 

a different fuel type, a manufacturer will 

need to obtain EPA approval to use an 

alternate fuel which it recommends for 

testing. All other aspects of certification 

will be the same. 

(b) Gas Turbine Engines 

Gas turbine engines are internal 

combustion engines that can operate 

using a variety of fuels (such as diesel 

fuel or natural gas) but do not operate 

on a compression-ignition or other 

reciprocating engine cycle. Power is 

extracted from the combustion gas using 

a rotating turbine rather than 

reciprocating pistons. The primary type 


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of U.S.-flagged vessels that use gas 

turbine engines are naval combat ships. 

While a small number have been used 

in commercial ships, we are not aware 

of any current sales for commercial 

applications. They can range in size 

from those equivalent in power to midsize Category 1 engines to those that 

produce the same power as Category 3 

engines. None of these engines have 

been subject to our current standards 

because they do not meet the definition 

of compression-ignition engines in our 

existing regulations. 

To date, this omission has not been a 

concern because only a small number of 

turbine-powered vessels have been 

produced and nearly all of them would 

have been eligible for a national security 

exemption. However, we were 

concerned that this exclusion may 

become a loophole in the future for 

operators hoping to avoid using engines 

with advanced catalytic emission 

controls. To a lesser degree, we also had 

concerns about the possibility of other 

non-reciprocating engines being 

excluded. We are closing this potential 

loophole by revising the regulations to 

treat new gas turbine engines (as well as 

other non-reciprocating engines) the 

same as compression-ignition engines 

and to apply our standards for new 

Category 1 and Category 2 engines 

(including NOX, HC, CO, and PM 

standards) to gas turbine engines. 

Several commenters objected to 

finalizing this requirement. They argued 

primarily that this would not align with 

MARPOL. They also asserted that the 

proposed requirements would not pass 

a cost/benefit analysis and that turbines 

cannot be tested under the procedures 

of 40 CFR part 1065. However, they did 

not provide any information about costs, 

benefits, or test procedures. As 

described in the RIA and the Summary 

and Analysis of Comments Document, 

we continue to believe the requirements 

are feasible and appropriate. As 

described below, we are finalizing these 

requirements largely as proposed. The 

primary revision being made is to delay 

them until the Tier 4 timeframe to 

provide turbine manufacturers 

additional lead time. 

To incorporate this approach in our 

marine emission control program, we 

are changing our definitions of Category 

1 and Category 2 to include gas turbine 

engines. Since turbine engines have no 

cylinders, we are adopting a conversion 

convention to apply the regulatory 

provisions that depend on a specified 

value for per-cylinder displacement. 

This convention is intended to apply 

the standards based on equivalent 

power ratings, to the extent possible. 

Specifically, we are redefining ‘‘Category 

1’’ to include gas turbines with rated 

power up to 2250 kW and redefining 

‘‘Category 2’’ to include all gas turbines 

with higher power ratings. This means 

we will not consider any gas turbines as 

‘‘Category 3’’ engines. The largest gas 

turbine engines will be considered to be 

Category 2 engines, even those that had 

rated power more typical of Category 3 

diesel engines. We are adopting this 

approach primarily because our 

Category 3 standards vary with engine 

speed, and are specified based on a 

speed range typical of diesel engines. 

These formulas do not make sense for 

gas turbine engines since they have 

much higher engine speeds. 

We are aware that some companies 

are manufacturing new highperformance recreational vessels using 

gas turbine engines. In at least some 

cases, the engines are modified from 

surplus military aircraft engines. We 

have not yet determined whether such 

recreational engines should be held to 

the same standards as conventional 

diesel engines. It is also important to 

note that under our current regulations, 

diesel engines meeting the definition of 

‘‘recreational marine engine’’ in 

§ 1042.901 are not subject to catalyst 

forcing standards. This approach was 

applied because of factors such as the 

usage patterns for recreational diesel 

engines. We believe these same factors 

to apply for recreational gas turbine 

engines. Thus, we are not as concerned 

about a potential gas turbine loophole 

for recreational engines as for 

commercial engines. We also do not 

have enough information at this time to 

know how feasible it would be for small 

gas turbine engine manufacturers to 

comply with the standards for 

recreational diesel engines, or to 

accurately assess the environmental 

impact of these vessels. Nevertheless, it 

is clear that the environmental impact of 

such small numbers of these engines 

cannot be large. Thus, at this time, we 

are not applying this regulatory change 

to recreational gas turbine engines (i.e., 

that is gas turbine engines installed on 

recreational vessels). We will continue 

to investigate these engines and may 

subject them to standards in the future. 

Our diesel engine program contains a 

national security exemption that 

automatically exempts vessels ‘‘used or 

owned by an agency of the Federal 

government responsible for national 

defense, where the vessel has armor, 

permanently attached weaponry, 

specialized electronic warfare systems, 

unique stealth performance 

requirements, and/or unique combat 

maneuverability requirements.’’ Since it 

is not our intent to prohibit naval 

vessels from using turbine engines, we 

are revising this provision to 

automatically exempt military vessels 

owned by an agency of the Federal 

government responsible for national 

defense powered by gas turbine engines. 

We are confident that gas turbine 

engines could use the same type of 

aftertreatment as is projected for diesel 

engines. The basic reactions through 

which SCR reduces NOX emissions can 

occur under a wide range of conditions, 

and exhaust from gas turbine engines is 

fundamentally similar to exhaust from 

diesel engines. Viewed another way, 

however, this requirement can be 

considered to be feasible based on the 

fact that the only circumstance in which 

a vessel would actually need a gas 

turbine engine would be for military 

purposes where our national security 

exemption provisions will apply. For all 

other vessels, it is entirely feasible for 

the vessel to be powered by a diesel 

engine. In fact, that is what is being 

done today. 

This program for gas turbine engines 

will apply to freshly manufactured 

engines only. We are not applying our 

marine remanufacture program to gas 

turbine engines. Because there are so 

few engines in the fleet, it is not 

possible to know what common 

rebuilding process are or whether and 

how those practices would return an 

existing engine to as-new condition. We 

may review this approach in the future 

if there is an increase in the number of 

gas turbines in the fleet. 

Finally, it is important to address 

some confusion expressed by the 

commenters about our definitions. We 

agree that it would be incorrect to 

actually define turbine engines as 

reciprocating or compression ignition, 

which is what the commenters thought 

we had proposed. However, we did not 

propose to define turbines to be 

reciprocating or compression-ignition 

engines. The commenters misread 

§ 1042.1(f), which states that certain 

marine engines ‘‘are subject to all the 

requirements of this part even if they do 

not meet the definition of ‘compressionignition’ in § 1042.901.’’ This provision 

subjects marine gas turbine engines to 

the requirements of part 1042, but it 

explicitly recognizes that they do not 

meet the definition of compressionignition in § 1042.901. The confusion 

seems to arise from the statement that 

these engines ‘‘are deemed to be 

compression-ignition engines for the 

purposes of this subchapter.’’ This 

statement is merely a regulatory 

convention that means the part applies 

to turbines as if they did meet the 

definition. 


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112See ‘‘Technical Amendments to EPA 

Regulations,’’ EPA memorandum from Alan Stout, 

in the docket for this rule, Docket No.: EPA–HQ– 

OAR–2007–0121. 

113These total estimated costs are slightly 

different than those reported in the ECA proposal, 

because the ECA proposal did not include costs 

associated with the Annex VI existing engine 

program, Tier II, or the costs associated with 

existing vessel modifications that may be required 

to accommodate the use of lower sulfur fuel. 

Further, the cost totals presented in the ECA 

package included Canadian cost estimates. 

(2) Technical Amendments 

The finalized regulations include 

technical amendments to our motor 

vehicle and nonroad engine regulations. 

These changes are generally corrections 

and clarifications. A large number of 

these changes are the removal of 

obsolete highway engine text that 

applied only for past model years. Many 

others are changes to the text of part 

1042 to make it more consistent with 

the language of our other recently 

corrected nonroad parts. The last large 

category of changes includes those 

related to the test procedures in part 

1065. See the memorandum in the 

docket entitled ‘‘Technical Amendments 

to EPA Regulations’’ for a full 

description of these changes.112

E. U.S. Vessels Enrolled in the Maritime 

Security Program 

The U.S. Department of 

Transportation Maritime Administration 

(MARAD) oversees the Maritime 

Security Program (MSP) established by 

the Maritime Security Act of 1996 and 

reauthorized by the Maritime Security 

Act of 2003 (MSA). The MSA requires 

that the Secretary of Transportation, in 

consultation with the Secretary of 

Defense, establish a fleet of active, 

commercially viable and militarily 

useful vessels to meet national defense 

and other security requirements and 

maintain a U.S. presence in 

international commercial shipping. The 

fleet consists of privately-owned, U.S.- 

flagged vessels known as the Maritime 

Security Fleet (MSF). 46 U.S.C. 53102 

outlines that vessels complying with 

applicable international agreements and 

associated guidelines are eligible for a 

certificate of inspection from Coast 

Guard, and thus inclusion in the MSF. 

The requirements of the MSP may 

have created confusion for owners of 

non-U.S.-flagged vessels regarding their 

obligation to also comply with EPA’s 

domestic marine diesel engine emission 

standards at the time they re-flag for 

inclusion in the MSF. We want to 

remind vessel owners that the MSA 

does not preempt the Clean Air Act or 

alleviate their obligation to comply with 

EPA’s marine diesel engine program, or 

any other EPA requirements that apply 

to marine vessels. As is clear from our 

past rulemakings, it has always been our 

intent that each U.S.-flagged vessel must 

comply with all of EPA’s domestic 

standards, regardless of whether the 

vessel was flagged in the U.S. upon 

original delivery into service. 

We are revising the regulations to 

clarify these requirements and, as noted 

earlier, to provide exemptions for 

auxiliary engines on Category 3. First, 

we are revising § 1042.1 to clarify that 

our regulations apply for all U.S.-flagged 

vessels. In conjunction with this, we are 

revising the definitions of ‘‘model year’’ 

and ‘‘new marine engine’’ to clarify that 

our marine engine program applies to 

all U.S.-flagged vessels regardless of 

where that vessels is built or operated, 

and how the regulations apply for 

vessels that are re-flagged to be U.S. 

vessels. 

We are clarifying that engines on 

foreign vessels that vessels become ‘‘new 

marine engines’’ under part 1042 at the 

point at which they are reflagged. As 

new marine engines, we would expect 

them to be covered by valid certificates 

and/or exemptions prior to being placed 

into service. If engines on U.S.-flagged 

vessels are not covered by valid 

certificates and/or exemptions when 

they first enter U.S. waters, they would 

be subject to all of the prohibitions of 

part 1068.101. The operator would be in 

violation of the prohibition against 

introduction of an uncertified new 

engine into U.S. commerce. 

Some of the revisions being finalized 

are intended to simplify the transition 

from part 94 to part 1042. Under the 

revised regulations, part 1042 becomes 

the default regulatory part for 

compression-ignition marine engines. 

Section 1043.1 specifies that such 

marine engines are subject to part 1042 

unless they are certified under part 94. 

In addition, § 1042.1(c) specifies that the 

definition of ‘‘new marine engine’’ in 

§ 1042.901 applies for engines certified 

under part 94. This is important because 

our standards and prohibitions apply for 

engines meeting the definition of ‘‘new 

marine engine’’. Thus, to determine 

whether an uncertified marine engine is 

subject to our standards and 

prohibitions, you must determine 

whether it meets any of the criteria of 

the definition of ‘‘new marine engine’’ in 

§ 1042.901. 

Each ‘‘new marine engine’’, is subject 

to standards based on its model year. 

The revised definition of ‘‘model year’’ 

specifies that engines on re-flagged 

vessels would generally be subject to the 

standards that would have applied in 

the year they were originally 

manufactured. If the engine has a model 

year before the years the part 94 

standards first applied, it would not be 

subject to any standards. If the engine 

has a later model year but one that is 

before the years the part 1042 standards 

apply, it would be subject to the 

standards of part 94. According to 

§ 1042.1(c), if the engine is certified to 

these part 94 standards, it is not 

required to comply with the 

requirements of part 1042. 

To further smooth this transition, we 

are finalizing a new interim provision in 

§ 1042.145(i). This provision is intended 

to apply for vessel operators that were 

not aware that their vessels were 

required to comply with our regulations. 

Once this amendment takes effect, it 

will allow them to operate in U.S. 

waters until July 1, 2010 without 

certificates or exemptions for their 

engines. After that, it will be a violation 

of 40 CFR 1068.101 to operate in U.S. 

waters with uncertified engines if those 

engines are subject to our standards. 

Operation of such vessels in U.S. waters 

on or after July 1, 2010 is deemed to be 

introduction into U.S. commerce of a 

new marine engine. 

VII. Costs and Economic Impacts 

In this section, we present the 

projected cost impacts and cost 

effectiveness of the coordinated 

emission control strategy for large 

marine vessels with a per cylinder 

displacement greater than 30 Liters per 

cylinder. We also present our analysis of 

the economic impacts of the 

coordinated strategy, which consists of 

the estimated social costs of the program 

and how those costs will likely be 

shared across stakeholders. The 

projected benefits and benefit-cost 

analysis of the coordinated strategy are 

presented in Section VIII. 

We estimate the costs of the 

coordinated strategy to be about $1.85 

billion in 2020, increasing to $3.11 

billion in 2030.113 Of the 2020 costs, 

nearly 89 percent or $1.64 billion are 

attributable to the fuel sulfur provisions. 

The total operational costs are estimated 

to be $1.82 billion in 2020. The costs to 

apply engine controls to U.S.-flagged 

vessels are expected to be $31.9 million 

in 2020, increasing to $47.4 million in 

2030 as more ships are built to comply 

with Clean Air Act (CAA) Tier 3 NOX

limits. All costs are presented in 2006 

U.S. dollars. 

When attributed by pollutant, at a net 

present value of 3 percent from 2010 

through 2040, the NOX controls are 

expected to cost about $510 per ton of 

NOX reduced, SOX controls are expected 

to cost about $930 per ton of SOX

reduced, and the PM controls are 


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expected to cost about $7,950 per ton of 

PM reduced ($500, $920, and $7,850 per 

ton of NOX, SOX, and PM respectively, 

at a net present value of 7 percent over 

the same period). These costs are 

comparable to our other recently 

adopted mobile source programs, and 

are one of the most cost-effective 

programs in terms of NOX and PM when 

compared to recent mobile and 

stationary programs. The coordinated 

strategy also provides very cost-effective 

SOX reductions comparable to the 

Heavy-Duty Nonroad diesel rulemaking. 

The social costs of the program are 

estimated to be approximately $3.1 

billion in 2030. The impact of these 

costs on society is estimated to be 

minimal. For example, we estimate the 

cost of shipping a 20-foot container on 

the Pacific route, with 1,700 nm of 

operation in the ECA, would increase by 

about $18, or less than 3 percent. 

Similarly, the price of a seven-day 

Alaska cruise that operates mainly in 

the ECA is expected to increase by about 

$7 per day. 

The estimated costs presented in this 

section are for the entire coordinated 

strategy, including those requirements 

that are the subject of this action and 

those that are associated with the 

proposed ECA designation. Table VII–1 

sets out the different components of the 

coordinated strategy for 2020. The costs 

of the coordinated strategy consist of the 

costs associated with the MARPOL 

Annex VI global standards that are 

operational through APPS, some of 

which we are also adding to our CAA 

emission control program for U.S. 

vessels (Tier 2 and Tier 3 NOX emission 

control hardware for U.S. vessels; 

operating costs for the Tier 2 NOX

requirements; controls for existing 

vessels; certain compliance 

requirements). Also included are the 

costs associated with complying with 

the engine standards and low sulfur fuel 

limits in U.S. internal waters (Tier 3 

operating costs; fuel sulfur hardware 

and operating costs). 

Note that, with regard to hardware 

costs, the coordinated strategy includes 

the entire cost for new U.S. vessels to 

comply with the Tier 3 NOX standards 

and fuel limits, even though some of the 

benefits from using these emission 

control systems will occur outside the 

United States. Conversely, we do not 

include any new vessel Tier 3 or fuel 

hardware costs for foreign vessels that 

operate in U.S. waters even though a 

significant share of the benefits of the 

coordinated strategy will arise from 

foreign vessels that comply with the 

engine and fuel sulfur limits while 

operating within the U.S., ECA and 

internal waters. 

The regulatory changes finalized for 

Category 1 and 2 engines are not 

included in this cost analysis as they are 

intended to be compliance flexibilities 

and not result in increased compliance 

costs. Similarly, the technical 

amendments finalized for other engines 

will not have significant economic 

impacts and are therefore not addressed 

here. Finally, to provide for a 

representative comparison between 

costs and benefits of the program, the 

cost analysis presented here assumes 

that all vessels currently using residual 

fuel will operate on distillate fuel in an 

ECA, including Great Lakes steamships. 

As noted in earlier chapters, Great Lakes 

steamships have been excluded from the 

final fuel sulfur standards. This change 

is not expected to have a significant 

impact on the estimated costs or 

benefits of the rule as those vessels are 

not a large part of the national 

inventory. 

TABLE VII–1—COSTS ASSOCIATED WITH THE U.S. COORDINATED STRATEGY AND CANADIAN ECA 

[Estimated Costs for 2020, $2006] 

Program element U.S. coordinated 

strategy 

Canadian ECA 

Hardware—T2 (variable costs; fixed costs 

applied in 2010).

U.S. vessels ................................................. $3,310,000 ..................... NA—not part of ECA. 

Foreign Vessels ........................................... N/A—global std .............. NA—not part of ECA. 

Hardware—T3 (variable costs; fixed costs 

recovered in the year in which they 

occur: 2011–15).

U.S. vessels (variable costs; fixed costs recovered in the year in which they occur: 

2011–15).

$28,700,000 ................... $100,000,000. 

Foreign vessels: 30% of vessels making 

75% of entrances to U.S. ports a.

$296,700,000.

Foreign vessels: 70% of vessels making 

25% of entrances to U.S. ports a.

$692,200,000.

Hardware—Fuel ........................................... U.S. vessels (new vessel costs) .................. $804,000 ........................ $10,000,000. 

Foreign vessels (new vessel costs) ............. $23,600,000.

Operating—T2 (inside full inventory modeling domain).U.S. vessels ................................................. $5,630,000 ..................... NA—not part of ECA. 

Foreign vessels ............................................ $32,900,000 ................... NA—not part of ECA. 

Operating—T3 (inside relevant part of affected waterways).U.S. vessels ................................................. $15,800,000 ................... $30,000,000. 

Foreign vessels ............................................ $127,000,000.

Operating—Fuel (inside relevant part of affected waterways).U.S. vessels ................................................. $210,000,000 ................. $260,000,000. 

Foreign vessels ............................................ $1,430,000,000.

Existing vessels—engine costs (all U.S. 

vessels 1990–99 retrofit during first 5 

years of program, 2011–15).

U.S. vessels ................................................. $0 ................................... NA—not part of ECA. 

Foreign vessels ............................................ N/A—global std .............. NA—not part of ECA. 

Existing vessels—vessel fuel switching 

costs (all U.S. vessels 1999–90 retrofit 

during first 5 years of program, 2011–15).

U.S. vessels ................................................. $0 ................................... Canada did not provide. 

Foreign vessels ............................................ $0 ................................... Canada did not provide. 

The estimated costs presented in this 

section are for the Federal program as a 

whole. We do not estimate costs on a 

regional or owner-specific basis. We 

received several comments from owners 

of vessels operating on the Great Lakes 


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114Research Triangle Institute, 2009. ‘‘Global 

Trade and Fuels Assessment—Future Trends and 

Effects of Designating Requiring Clean Fuels in the 

Marine Sector’’. Prepared for U.S. Environmental 

Protection Agency. Research Triangle Park, NC. 

115 In this analysis, the U.S. included the lower 

48 contiguous States and southeastern Alaska. 

116Research Triangle Institute, 2009. ‘‘Global 

Trade and Fuels Assessment—Future Trends and 

Effects of Designating Requiring Clean Fuels in the 

Marine Sector’’. Prepared for U.S. Environmental 

Protection Agency. Research Triangle Park, NC. 

117Note that distillate fuel has a higher energy 

content, on a per ton basis, than residual fuel. As 

such, there is an offsetting cost savings, on a per 

metric ton basis, for switching to distillate fuel. 

Based on a 5 percent higher energy content for 

distillate, the net equivalent cost increase is 

estimated as $123 for each metric ton of residual 

fuel that is being replaced by distillate fuel. 

contending that the impact of the 

proposed control program on their 

operations is unique, and that the 

economic impacts of the program on 

these operators should be estimated 

separately. As explained in Section VI 

of this preamble and in more detail in 

the Summary and Analysis of 

Comments prepared for this final rule, 

we are providing various regulatory 

flexibilities for operators that may have 

difficulty complying with the 

requirements of this rule. In addition, as 

part of EPA’s appropriation bill (Pub. L. 

111–88), Congress recommended that 

EPA perform a study to evaluate the 

economic impact of the final rule on 

Great Lakes carriers, with a final report 

due in the summer of 2010. We will be 

soliciting input from affected entities as 

we prepare that report. 

A. Estimated Fuel Costs 

The coordinated strategy includes fuel 

sulfur limits which are included in this 

cost analysis. Prior to this final rule, all 

distillate fuels produced at refineries in 

the U.S. had a sulfur limitation of 15 

ppm. The coordinated strategy does not 

impose additional costs for refiners in 

the U.S. and actually allows additional 

flexibility. Specifically, we are allowing 

distillate fuel to have up to 1,000 ppm 

sulfur for use in Category 3 vessels. The 

fuel requirements will impose a cost to 

the ship owners. This section presents 

estimates of the cost of compliance with 

the 1,000 ppm sulfur limit in the U.S. 

waterways. 

Distillate fuel will likely be used to 

meet the 1,000 ppm fuel sulfur limit, 

beginning in 2015. As such, the primary 

cost of the fuel sulfur limit for ship 

owners will be that associated with 

switching from heavy fuel oil to highercost distillate fuel. Some engines 

already operate on distillate fuel and 

will not be affected by fuel switching 

costs. However, distillate fuel costs may 

be affected by the need to further refine 

the distillate fuel to meet the 1,000 ppm 

sulfur limit. 

To investigate these effects, studies 

were performed on the impact of a 

North American ECA on global fuel 

production and costs, to inform the 

application for such ECA.114 These 

studies were performed prior to the ECA 

being defined; thus, we picked a 

maximum distance boundary to ensure 

the fuel volumes used for the cost 

analysis would be larger than required 

by the program. Specifically, we used 

the total fuel consumption in the U.S. 

and Canada exclusive economic 

zones.115 The studies are relevant to this 

regulation as well, since they estimate 

the cost of 1,000 ppm sulfur fuel for 

Category 3 vessels operating in U.S. 

waterways. 

To assess the effect on the refining 

industry of the imposition of a 1,000 

ppm sulfur limit on fuels, we needed to 

first understand and characterize the 

fuels market. Research Triangle Institute 

(RTI) was contracted to conduct a fuels 

study using an activity-based economic 

approach. The study established 

baseline bunker fuel demand, projected 

a growth rate for bunker fuel demand, 

and established future bunker fuel 

demand volumes.116 These volumes 

then became the input to the World Oil 

Refining Logistics and Demand 

(WORLD) model to evaluate the effect of 

the coordinated strategy on fuel cost. 

The WORLD model was run by Ensys 

Energy & Systems, the owner and 

developer of the refinery model. The 

WORLD model is the only such model 

currently developed for this purpose 

and was developed by a team of 

international petroleum consultants. It 

has been widely used by industries, 

government agencies, and Organization 

of the Petroleum Exporting Countries 

(OPEC) over the past 13 years, including 

the Cross Government/Industry 

Scientific Group of Experts, established 

to evaluate the effects of the different 

fuel options proposed under the 

revision of MARPOL Annex VI. The 

model incorporates crude sources, 

global regions, refinery operations, and 

world economics. The results of the 

WORLD model have been comparable to 

other independent predictions of global 

fuel, air pollutant emissions and 

economic predictions. 

The WORLD model was run for 2020, 

in which the control case included a 

fuel sulfur level of 1,000 ppm in the 

U.S. The baseline case was modeled as 

‘‘business as usual’’ in which ships 

continue to use the same fuel as today. 

Because of the recent increases and 

fluctuations in oil prices, we had 

additional WORLD model runs 

conducted. For these runs, we used new 

reference case and high oil price 

estimates that were recently released by 

the U.S. Energy Information 

Administration (EIA). In addition to 

increased oil price estimates, the 

updated model accounts for increases in 

natural gas costs, capital costs for 

refinery upgrades, and product 

distribution costs. 

Because only a small portion of global 

marine fuel is consumed in the ECA, the 

overall impact on global fuel production 

is small. Global fuel use in 2020 by 

ships is projected to be 500 million 

metric tonnes/yr. Of this amount, 90 

million metric tonnes of fuel is used for 

U.S./Canadian trade, or about 18 

percent of total global fuel use. In the 

proposed ECA, less than 20 million 

metric tonnes of fuel will be consumed 

in 2020, which is less than 4 percent of 

total global marine fuel use. Of the 

amount of fuel to be consumed in the 

proposed ECA in 2020, about 4 million 

metric tonnes of distillate will be 

consumed in the Business as Usual 

(BAU) case, which is about 20 percent 

of the amount of total fuel to be 

consumed in the proposed ECA. 

There are two main components to 

projected increased marine fuel cost 

associated with the ECA. The first 

component results from shifting from 

operation on residual fuel to operation 

on higher cost distillate fuel. This is the 

dominant cost component. However, 

there is also a small cost associated with 

desulfurizing the distillate to meet the 

1,000 ppm sulfur standard. Based on the 

WORLD modeling, the average increase 

in costs associated with switching from 

marine residual to distillate will be $145 

per metric tonne of fuel consumed. Due 

to the differences in energy density 

between the two fuels, this translates to 

a cost increase of $123 for each metric 

tonne of residual fuel replaced by 

distillate fuel.117 This is the cost 

increase that will be borne by the 

shipping companies purchasing the 

fuel. Of this amount, $6 per metric 

tonne is the increase in costs associated 

with distillate desulfurization. 

Table VII–2 summarizes the fuel cost 

estimates with and without an ECA. In 

the baseline case, fuel volumes for 

operation are 18% marine gas oil 

(MGO), 7% marine diesel oil (MDO), 

and 75% IFO. Weighted average 

baseline distillate fuel cost is $462/ 

tonne. In the ECA, all fuel volumes are 

modeled as MGO, at $468/tonne. 


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118 ICF International, ‘‘Costs of Emission 

Reduction Technologies for Category 3 Marine 

Engines,’’ prepared for the U.S. Environmental 

Protection Agency, December 2008. EPA Report 

Number: EPA–420–R–09–008. 

TABLE VII–2—ESTIMATE MARINE FUEL

COSTS

Fuel Units Baseline ECA 

MGO ... $/bbl .... $ 61 .75 $ 62 .23 

$/tonne 464 468 

MDO .... $/bbl .... 61 .89 62 .95 

$/tonne 458 466 

IFO ...... $/bbl .... 49 .87 49 .63 

$/tonne 322 321 

The increased cost of distillate 

desulfurization is due both to additional 

coking and hydrotreating capacities at 

refineries. Cokers crack residual blends 

in IFO bunker fuel into distillates, using 

heat and residence time to make the 

conversion. The process also produces 

useful byproducts such as petroleum 

coke and off gas. The WORLD model 

did not use hydrocracking technology to 

convert residual fuels into distillates for 

either the reference or high price crude 

cases. Because of the higher capital and 

operating costs of hydrocrackers, the 

WORLD model favored the use of 

coking units. As such, the WORLD 

model assumed that cokers would 

convert the residual blendstocks in 

Intermediate Fuel Oil grades to 

distillates. The model added coking 

processes to refineries located in the 

U.S. and, to a lesser extent, to refiner 

regions outside of the U.S. Specifically, 

the model added one additional coking 

unit with a capacity of 30 thousand 

barrels per stream day (KBPSD), and one 

to two hydrocracking units representing 

50 and 80 KBPSD additional capacity. 

The WORLD model also added new 

conventional distillate hydrotreating 

capacity to lower the sulfur levels for 

the marine distillate fuel, in addition to 

the existing slack distillate 

hydrotreating capacity that existed in 

refiner regions for these fuels. In 

addition, the model used lighter crudes 

and adjusted operating parameters in 

refineries. This had the effect of 

increasing the projected production of 

lower sulfur distillate fuels in lieu of 

adding distillate hydrotreating capacity. 

The model elected to use lower sulfur 

crudes and used operational 

adjustments. Higher capital and 

operating costs of new units under the 

high-priced crude scenario favored use 

of existing refinery capacity made 

available from lower global refiner 

utilizations. 

B. Estimated Engine Costs 

To quantify the cost impacts 

associated with the coordinated 

strategy, we estimated the hardware and 

operational costs to U.S.-flagged ships, 

as well as affected foreign-flagged ships. 

The hardware costs included in the total 

cost of the coordinated strategy are only 

applied to U.S.-flagged vessels, and 

include those associated with the CAA 

Tier 2 and Tier 3 NOX standards, the 

Annex VI existing engine program, and 

the use of lower sulfur fuel. Tier 2 

hardware costs consist of changes to the 

engine block and the migration from 

mechanical fuel injection to common 

rail fuel injection systems. Tier 3 

hardware costs include engine 

modifications, the migration from 

mechanical fuel injection to common 

rail fuel injection systems, and the 

installation of Selective Catalytic 

Reduction (SCR). Hardware costs 

associated with the use of lower sulfur 

fuel are from applying additional tanks 

and equipment to enable a vessel to 

switch from residual fuel to lower sulfur 

fuel. These equipment costs were 

applied to those new vessels that may 

need additional hardware, and also 

include the estimated cost of retrofitting 

the portion of the fleet that may require 

additional hardware to accommodate 

the use of lower sulfur fuel in 2015. The 

hardware costs also include a per engine 

cost of $10,000 associated with the 

requirement to test each production 

engine (§ 1042.302). These are the sole 

engine hardware costs specifically 

attributable to our CAA rule. 

The operational costs were applied to 

both U.S.- and foreign-flagged vessels 

and include additional operational costs 

associated with the applicable NOX

limits and the use of lower sulfur fuel. 

The operational costs for NOX controls 

consist of the additional fuel required 

due to an estimated two percent fuel 

penalty associated with the use of 

technologies to meet CAA Tier 2 and 

global Tier II NOX standards, and the 

use of urea for ships equipped with an 

SCR unit to meet CAA Tier 3 and global 

Tier III NOX standards. The operational 

costs associated with the use of lower 

sulfur fuel include both the differential 

cost of using lower sulfur fuel that 

meets ECA standards instead of using 

marine distillate fuel, and the 

differential cost of using lower sulfur 

fuel that meets ECA standards instead of 

using residual fuel. 

To assess the potential cost impacts, 

we must understand (1) the makeup of 

the fleet of ships expected to visit the 

U.S. when these requirements go into 

effect, (2) the emission reduction 

technologies expected to be used, and 

(3) the cost of these technologies. 

Chapter 5 of the RIA presents this 

analysis in greater detail. The total 

engine and vessel costs associated with 

the coordinated strategy are based on a 

cost per unit value applied to the 

number of affected vessels. Operational 

costs are based on fuel consumption 

values determined in the inventory 

analysis (Section 5.2). This section 

discusses a brief overview of the 

methodology used to develop the 

hardware and operational costs, and the 

methodology used to develop a fleet of 

future vessels to which these hardware 

and engineering costs were applied. 

(1) Methodology 

To estimate the hardware costs to 

ships that may be affected by the 

coordinated strategy, we used an 

approach similar to that used to 

estimate the emissions inventory. 

Specifically, the same inputs were used 

to develop a fleet of ships by ship type 

and engine type that may be expected to 

visit U.S. ports through the year 2040. 

In order to determine the cost of 

applying emission reduction technology 

on a per vessel basis, ICF International 

was contracted by the U.S. EPA to 

conduct a cost study of the various 

compliance strategies expected to be 

used to meet the new NOX standards 

and fuel sulfur requirements.118 ICF was 

instructed to develop cost estimates 

covering a range of vessel types and 

sizes, which could be scaled according 

to engine speed and power to arrive at 

an estimated cost per vessel. The costs 

developed for these engine 

configurations were used to develop a 

$/kW value that could be applied to any 

slow or medium speed engine. Using 

the average propulsion power by ship 

type presented in the inventory 

analysis, the per-vessel hardware costs 

were then applied to the estimated 

number of applicable vessels built after 

the standards take effect. 

(a) Hardware Costs 

The hardware cost estimates include 

variable costs (components, assembly, 

and the associated markup) and fixed 

costs (tooling, research and 

development, redesign efforts, and 

certification). Hardware costs associated 

with the Annex VI existing engine 

standards were applied to the portion of 

existing U.S.-flagged vessels built 

between 1990 and 1999 expected to be 

subject to these standards in 2011 when 

the standards go into effect (engines 

with a per-cylinder displacement of at 

least 90 liters and a power output of 

over 5,000 kW. These costs were 

applied over a five-year period 

beginning in 2011 where 20 percent of 

the total subject fleet was estimated to 

undergo service each year. The existing 

engine program fixed costs were phased 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 22943 

119 In order to separate slow speed engines from 

medium speed engines where that information was 

not explicitly available, 2-stroke engines were 

assumed to be slow speed, where 4-stroke engines 

were assumed to be medium speed. 120http://www.sea-web.com. 

in over a five-year period beginning in 

2010 and applied on a per-vessel basis. 

Hardware costs associated with the 

CAA Tier 2 program were applied to all 

new U.S.-flagged vessels beginning in 

the year 2011 when the standards take 

effect. The fixed costs associated with 

Tier 2 standards are expected to be 

incurred over a five-year period; 

however, as the Tier 2 standards take 

effect in 2011, it was assumed that 

manufacturers are nearing the end of 

their research and development. In 

order to capture all of these costs, all 

fixed costs that would have been 

incurred during that five-year phase-in 

period were applied in the year 2010. 

Hardware costs associated with Tier 3 

were estimated for U.S. vessels and 

were applied as of 2016. The fixed costs 

associated with Tier 3 were phased in 

over a five-year period beginning in 

2011. 

Hardware costs associated with the 

use of lower sulfur fuel are estimated 

separately for both new and existing 

vessels that may require additional 

hardware to accommodate the use of 

lower sulfur fuel. The fuel sulfur control 

related hardware costs for new vessels 

begin to apply in 2015, while all retrofit 

costs are expected to be incurred by 

2015 and as such are applied in this 

year. The fixed costs for both new and 

existing vessels that may require 

additional hardware to accommodate 

the use of lower sulfur fuel are applied 

on a per-vessel basis and are phased in 

over a five year period beginning as of 

2010. 

(b) Operational Costs 

The operational costs estimated here 

are composed of three parts: (1) The 

estimated increase in fuel consumption 

expected to occur with the use of Tier 

II technologies on U.S.- and foreignflagged vessels, (2) the differential cost 

of using lower sulfur fuel applicable for 

both U.S.- and foreign-flagged vessels, 

and (3) the use of urea with SCR as a 

Tier III NOX emission reduction 

technology on both U.S.- and foreignflagged vessels. The fuel consumption 

values associated with Tier II and Tier 

III standards were determined in the 

inventory analysis (see Chapter 3 of the 

RIA), with an estimated Tier II fuel 

consumption penalty of 2 percent (see 

Chapter 4 of the RIA). The two percent 

fuel penalty estimate is based on the use 

of modifications to the fuel delivery 

system to achieve Tier II NOX

reductions, and does not reflect the 

possibility that there may be other 

technologies available to manufacturers 

that could offset this fuel penalty. 

Additionally, Tier III will provide the 

opportunity to re-optimize engines for 

fuel economy when using 

aftertreatment, such as SCR, to provide 

NOX reductions similar to the 

compliance strategy for some heavyduty truck manufacturers using urea 

SCR to meet our 2010 truck standard. 

The differential cost of using lower 

sulfur fuel is discussed above in Section 

VII.A of this preamble. The estimated 

urea cost associated with the use of Tier 

III SCR is derived from a urea dosage 

rate that is 7.5 percent of the fuel 

consumption rate. 

Operating costs per vessel vary 

depending on what year the vessel was 

built, e.g., vessels built as of 2016 will 

incur operating costs associated with 

the use of urea necessary when using 

SCR as a Tier III NOX emission control 

technology, while vessels built prior to 

2016 do not use urea but will incur 

operating costs associated with the 

differential cost of using lower sulfur 

fuel. Further, we have assumed vessels 

built as of 2011 that meet Tier II 

standards will incur a 2 percent fuel 

consumption penalty; see Table 5–31 of 

the RIA for further details on fuel costs 

and fuel volumes. In addition, vessels 

built as of 2016 that meet Tier III NOX

standards while traveling in the 

regulated U.S. waterways are still 

required to at least meet Tier II NOX

standards outside of an ECA and will 

continue to incur the associated fuel 

penalty. Therefore, an estimated fleet 

had to be developed over a range of 

years, and provide a breakout of ships 

by age in each year. 

(2) Fleet Development 

There are currently no available 

estimates of the number of ships that 

may visit U.S. ports in the future or 

comprehensive engine sales predictions. 

Therefore, to develop the costs 

associated with the coordinated 

strategy, an approximation of the 

number of ships by age and engine type 

that may visit U.S. ports in the future 

was constructed. To characterize the 

fleet of ships visiting U.S. ports, we 

used U.S. port call data collected in 

2002 for the inventory port analysis (see 

Chapter 3 of the RIA) which included 

only vessels with C3 engines where the 

engine size and type was identified.119

We used this data with the growth rates 

developed in the inventory analysis to 

estimate how many ships, by ship type 

and engine type, would visit U.S. ports 

in future years. Due to the long life of 

these vessels, and the fact that there has 

been no significant event that would 

have changed the composition of the 

world fleet since this baseline data was 

taken, it is reasonable to use 2002 data 

as the basis for modeling the future fleet 

upon which to base hardware cost 

estimates. An analysis is presented in 

Section 5.1.2.2 of Chapter 5 of the RIA 

which confirms the reasonableness of 

this assumption using 2007 MARAD 

data. 

The ship type information gathered 

from this baseline data, for the purposes 

of both this analysis and the inventory, 

was categorized into one of the 

following ship types: Auto Carrier, Bulk 

Carrier, Container, General Cargo, 

Miscellaneous, Passenger, Refrigerated 

Cargo (Reefer), Roll-On Roll-Off (RoRo), 

and Tankers. Average engine and vessel 

characteristics were developed from the 

baseline data, and these values were 

used to represent the characteristics of 

new vessels used in this cost analysis 

(see Chapter 3 of the RIA). Estimated 

future fleets were developed by ship 

type and engine type through the year 

2040 for both new and existing vessels 

and both U.S.- and foreign-flagged 

vessels. Hardware costs were applied on 

a per-vessel basis. 

Although most ships primarily 

operate on residual fuel, they typically 

carry some amount of distillate fuel as 

well. Switching to the use of lower 

sulfur distillate fuel is the compliance 

strategy assumed here to be used by 

both new and existing ships in 2015 

when the new lower sulfur fuel 

standards go into effect. To estimate the 

potential cost of this compliance 

strategy, we evaluated the distillate 

storage capacity of the current existing 

fleet to estimate how many ships may 

require additional hardware to 

accommodate the use of lower sulfur 

fuel. We performed this analysis on the 

entire global fleet listed in Lloyd’s 

database as of 2008.120 Of the nearly 

43,000 vessels listed, approximately 

20,000 vessels had provided Lloyds 

with fuel tankage information, cruise 

speed, and propulsion engine power 

data. Using this information, we were 

able to estimate how far each vessel 

could travel on its existing distillate 

carrying capacity. 

In order to determine if the current 

distillate capacity of a particular ship 

was sufficient to call on a U.S. 

coordinated strategy without requiring 

additional hardware, we evaluated 

whether or not each ship could travel 

1,140 nm, or the distance between the 

Port of Los Angeles and the Port of 

Tacoma. This distance was selected 

because it represents one of the longer 

trips a ship could travel without 


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stopping at another port, and should 

overestimate the number of vessels that 

would require such a modification. The 

resulting percentages of ships estimated 

to require a retrofit were then applied to 

the number of existing ships in the 2015 

fleet to estimate the total cost of this 

compliance strategy for existing ships 

built prior to 2015. The same 

percentages were also applied to all new 

ships built as of 2015 to determine the 

number of ships that may require 

additional hardware and estimate the 

cost of this compliance strategy for new 

vessels. 

(3) NOX Reduction Technologies 

(a) Tier 2 

Most engine manufacturers are 

expected to be able to meet Tier 2 NOX

standards using engine modifications. 

This cost estimate includes the 

hardware costs associated with the use 

of retarded fuel injection timing, higher 

compression ratios, and better fuel 

distribution. There are no variable costs 

associated with the engine 

modifications as the changes are not 

expected to require any additional 

hardware. Some engines may also be 

equipped with common-rail fuel 

systems instead of mechanical fuel 

injection to meet Tier 2 NOX standards. 

It is expected that approximately 75 

percent of SSD and 30 percent of MSD 

engines will get this modification for 

Tier 2. The Tier 2 hardware costs 

developed here include the costs of the 

migration of some engines to commonrail fuel systems. It was also estimated 

that these technologies may increase 

fuel consumption by up to 2 percent; 

this fuel penalty is included in the Tier 

2 operational costs. Tier 2 hardware 

costs included in the total estimated 

cost of the coordinated strategy are only 

associated with U.S.-flagged vessels; 

operational costs are applied to both 

U.S.- and foreign-flagged vessels. 

(b) Tier 3 

Tier 3 NOX standards are 

approximately 80 percent below Tier 1 

NOX standards, and are likely to require 

exhaust aftertreatment such as SCR. ICF 

performed a detailed cost analysis for 

the U.S. EPA that included surveying 

engine and emission control technology 

manufacturers regarding these advanced 

technology strategies and their potential 

costs. Tier 3 NOX standards are 

projected to be met through the use of 

SCR systems. While other technologies 

such as EGR or those that include 

introduction of water into the 

combustion chamber either through 

fumigation, fuel emulsions, or direct 

water injection may also enable Tier 3 

compliance, we assume they will only 

be selected if they are less costly than 

SCR. Therefore, we have based this 

analysis on the exclusive use of SCR. 

(c) Engine Modifications 

In addition to SCR, it is expected that 

manufacturers will also use compound 

or two-stage turbocharging as well as 

electronic valving to enhance 

performance and emission reductions to 

meet Tier 3 NOX standards. Engine 

modifications to meet Tier 3 emission 

levels will include a higher percentage 

of common-rail fuel injection coupled 

with two-stage turbocharging and 

electronic valving. Engine 

manufacturers estimate that nearly all 

SSD and 80 percent of MSD engines will 

use common-rail fuel injection. Two 

stage turbocharging will most likely be 

used on least 70 percent of all engines 

required to meet Tier 3 emission levels. 

Electronically (hydraulically) actuated 

intake and exhaust valves for MSD and 

electronically actuated exhaust valves 

for SSD are necessary to accommodate 

two-stage turbocharging. Additionally, 

the remaining SSD engines still using 

mechanical injection (approximately 25 

percent mechanically controlled, and 75 

percent electronically controlled) are 

expected to migrate to common rail for 

Tier 3, while an additional 40 percent 

of MSD engines are expected to receive 

common rail totaling approximately 80 

percent of all MSD engines. The engine 

modification variable costs were applied 

to all new U.S.-flagged vessels equipped 

with either SSD or MSD engines. Costs 

to foreign-flagged vessel expected to 

visit U.S. ports are presented as a 

separate analysis in Chapter 5 of the 

RIA, and are not included in the total 

estimated cost of the coordinated 

strategy. 

(4) SOX/PM Emission Reduction 

Technology 

In addition to Tier 3 NOX standards, 

the IMO ECA requirements also include 

lower fuel sulfur limits that will result 

in reductions in SOX and PM. Category 

3 marine engines typically operate on 

heavy fuel oil with a sulfur content of 

2.7 percent, therefore significant SOX

and PM reductions will be achieved 

using distillate fuels with a sulfur 

content of 0.1 percent. This cost 

analysis is based on the assumption that 

vessel operators will operate their 

engines using lower sulfur fuel in the 

U.S. coordinated strategy waterways. 

We believe fuel switching will be the 

primary compliance approach; fuel 

scrubbers would be used in the event 

that the operator expected to realize a 

cost savings and are not considered in 

this analysis. In some cases, additional 

capacity and equipment to 

accommodate the use of lower sulfur 

fuel may need to be installed on a 

vessel. The potential costs due to these 

additional modifications applied to new 

ships as well as retrofits to any existing 

ships are discussed here, and these 

hardware costs are included as part of 

the total cost of this coordinated 

program. 

Although most ships operate on heavy 

fuel oil, they typically carry small 

amounts of distillate fuel. Some vessel 

modifications and new operating 

practices may be necessary to use lower 

sulfur distillate fuels on vessels 

designed to operate primarily on 

residual fuel. Installation and use of a 

fuel cooler, associated piping, and 

viscosity meters to the fuel treatment 

system may be required to ensure 

viscosity matches between the fuel and 

injection system design. While there are 

many existing ships that already have 

the capacity to operate on both heavy 

fuel oil and distillate fuel and have 

separate fuel tank systems to support 

each type of fuel, some ships may not 

have sufficient onboard storage 

capacity. If a new or segregated tank is 

desired, additional equipment for fuel 

delivery and control of these systems 

may be required. 

(5) NOX and SOX Emission Reduction 

Technology Costs 

(a) NOX Emission Reduction 

Technology 

The costs associated with SCR 

include variable and fixed costs. SCR 

hardware costs include the reactor, 

dosage pump, urea injectors, piping, 

bypass valve, an acoustic horn or a 

cleaning probe, the control unit and 

wiring, and the urea tank (the size of the 

tank is based on 250 hours of normal 

operation when the ship is operating in 

the regulated U.S. waterways and the 

SCR system is activated.) The size of the 

tank is dependent on the frequency with 

which the individual ship owner prefers 

to fill the urea tank. The methodology 

used here to estimate the capacity of the 

SCR systems is based on the power 

rating of the propulsion engines only. 

Auxiliary engine power represents 

about 20 percent of total installed power 

on a vessel; however, it would be 

unusual to operate both propulsion and 

auxiliary engines at 100 percent load. 

Typically, ships operate under full 

propulsion power only while at sea 

when the SCR is not operating; when 

nearing ports, the auxiliary engine is 

operating at high loads while the 

propulsion engine is operating at very 

low loads. 


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121http://www.iicl.org, Institute of International 

Container Lessors. 

122 Kristensen, Hans Otto Holmegaard, 

‘‘Preliminary Ship Design of Container Ships, Bulk 

Carriers, Tankers, and Ro-Ro Ships. Assessment of 

Environmental Impact from Sea-Borne Transport 

Compared with Landbased Transport,’’ March, 

2008. 

123http://people.hofstra.edu/geotrans/eng/ch2en/ 

conc2en/maritimefreightrates.html. 

124http://moneycentral.msn.com/investor/ 

invsub/results/hilite.asp?Symbol=SSW. 

125Based on a container ship carrying nearly 

9,000 TEUs traveling from Hong Kong to the Port 

of Los Angeles (approximately 6,400 nm) with a 

cruise speed of 25 nm/hr, the round trip time is 

nearly 21 days and this trip could be made roughly 

16 times per year. 

In this analysis, we determined the 

average number of hours a ship would 

spend calling on a U.S. port: If the call 

was straight in and straight out at 200 

nm, the average time spent was slightly 

over 35 hours. If the distance travelled 

was substantial, such as from the Port of 

Los Angeles to the Port of Tacoma, or 

1140 nm, the average time spent 

travelling was approximately 75 hours. 

Therefore, the size of the tanks and 

corresponding $/kW values estimated 

here to carry enough urea for 250 hours 

of continuous operation may be an 

overestimate. Based on 250 hours of 

operation, a range of urea tank sizes 

from 20 m3 to approximately 256 m3

was determined for the six different 

engine configurations used in this 

analysis. 

To understand what impacts this may 

have on the cargo hauling capacity of 

the ship, we looked at the ISO standard 

containers used today. Currently, over 

two-thirds of the containers in use today 

are 40 feet long, total slightly over 77 m3

and are the equivalent of two TEU.121

The urea tank sizes estimated here 

reflect a cargo equivalence of 0.5–2 

TEUs, based on a capacity sufficient for 

250 hours of operation. The TEU 

capacity of container ships, for example, 

continues to increase and can be as high 

as 13,000 TEUs.122 Based on a rate of 

approximately $1,300 per TEU to ship a 

container from Asia to the U.S., a net 

profit margin of 10%, and an average of 

16 trips per year, the estimated cost due 

to displaced cargo to call on a U.S./ 

Canada ECA may be $2,100.123 124 125

The cost analysis presented here does 

not include displaced cargo due to the 

variability of tank sizes owners choose 

to install. 

To estimate the SCR hardware costs 

associated with newly built ships, we 

needed to generate an equation in terms 

of $/kW that could be applied to other 

engine sizes. Therefore, the $/kW values 

representing the hardware costs 

estimated for the six different engine 

types and sizes used in this analysis was 

developed using a curve fit for both SSD 

and MSD engines. The resulting $/kW 

values range from $40–$80 per kW for 

MSD, and $40–$70 for SSD. These costs 

were then applied based on the 

characteristics of the average ship types 

described in the inventory section of the 

RIA (see Chapter 3) to the representative 

portion of the future fleet in order to 

estimate the total costs associated with 

this program. Table VII–3 presents the 

estimated costs of this technology as 

applied to different ship and engine 

types representing the average ship 

characteristics discussed in Section 

VII.A.2. 

(b) Lower Sulfur Fuel Hardware Costs 

This cost analysis is based on the use 

of switching to lower sulfur fuel to meet 

the fuel sulfur standards. The costs 

presented here may be incurred by some 

existing and some newly built ships if 

additional fuel tank equipment is 

required to facilitate the use of lower 

sulfur fuel. Based on existing vessel 

fleet data, we estimate that 

approximately one-third of existing 

vessels may need additional equipment 

installed to accommodate additional 

lower sulfur fuel storage capacity 

beyond that installed on comparable 

new ships. In order to include any costs 

that may be incurred on new vessels 

that choose to add additional lower 

sulfur fuel capacity, we also estimated 

that one-third of new vessels may 

require additional hardware. Separate 

$/kW values were developed for new 

and existing vessels as the existing 

vessel retrofit would likely require more 

labor to complete installation. 

The size of the tank is dependent on 

the frequency with which the individual 

ship owner prefers to fill the lower 

sulfur fuel tank. The size of the tanks 

and corresponding $/kW value 

estimated here will carry capacity 

sufficient for 250 hours of propulsion 

and auxiliary engine operation. This is 

most likely an overestimate of the 

amount of lower sulfur fuel a ship 

owner would need to carry, resulting in 

an overestimate of the total cost to 

existing and new vessels. The tank sizes 

based on 250 hours of operation and 

based on the six different engine 

configuration used in this analysis range 

from 240 m3 to nearly 2,000 m3. This 

would be the equivalent of 6–50 TEUs. 

This cost analysis does not reflect other 

design options such as partitioning of a 

residual fuel tank to allow for lower 

sulfur fuel capacity which would reduce 

the amount of additional space required, 

nor does this analysis reflect the 

possibility that some ships may have 

already been designed to carry smaller 

amounts of distillate fuel in separate 

tanks for purposes other than 

continuous propulsion. The $/kW value 

hardware cost values for the six data 

points corresponding to the six different 

engine types and sizes used in this 

analysis are $2–7 for SSD and $3–8 for 

MSD. A curve fit was determined for the 

slow-speed engine as well as for the 

medium speed engines to determine a 

$/kW value for each engine type. Table 

VII–3 presents the estimated costs of the 

technologies used to meet the different 

standards as applied to different ship 

and engine types representing the 

average ship characteristics discussed in 

Section VII.A.2. The estimated hardware 

costs of retrofitting existing U.S.-flagged 

vessels that may require additional 

hardware to accommodate the use of 

lower sulfur fuel is estimated to be 

$10.4 million in 2015. 

TABLE VII–3—ESTIMATED VARIABLE COSTS OF EMISSION CONTROL TECHNOLOGY ON A PER-SHIP BASIS—BY SHIP TYPE

AND ENGINE TYPE a

Ship type Engine speed 

Average propulsion power 

(kW) 

MFI to 

common rail 

EFI to 

common rail 

Tier 3 (SCR 

and engine 

modifications) 

Lower sulfur 

fuel hardware— 

new vessels 

Lower sulfur 

fuel hardware— 

existing vessels 

Auto Carrier ..... MSD ............... 9640 $80,500 $30,400 $566,000 $42,300 $56,400 

Bulk Carrier ...... MSD ............... 6360 67,200 24,600 479,000 36,900 48,500 

Container ......... MSD ............... 13878 92,300 35,400 678,000 49,200 66,600 

General Cargo MSD ............... 5159 60,400 21,700 448,000 34,900 45,600 

Passenger ........ MSD ............... 23762 109,600 42,800 939,000 65,400 90,400 

Reefer .............. MSD ............... 7360 71,900 26,600 506,000 38,500 50,900 

RoRo ................ MSD ............... 8561 76,700 28,700 538,000 40,500 53,800 

Tanker .............. MSD ............... 6697 68,800 25,300 488,000 37,400 49,300 


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TABLE VII–3—ESTIMATED VARIABLE COSTS OF EMISSION CONTROL TECHNOLOGY ON A PER-SHIP BASIS—BY SHIP TYPE

AND ENGINE TYPE a—Continued 

Ship type Engine speed 

Average propulsion power 

(kW) 

MFI to 

common rail 

EFI to 

common rail 

Tier 3 (SCR 

and engine 

modifications) 

Lower sulfur 

fuel hardware— 

new vessels 

Lower sulfur 

fuel hardware— 

existing vessels 

Misc. ................. MSD ............... 9405 79,800 30,000 560,000 41,900 55,800 

Auto Carrier ..... SSD ............... 11298 152,400 55,500 819,000 48,000 64,800 

Bulk Carrier ...... SSD ............... 8434 132,900 48,400 669,000 42,700 57,700 

Container ......... SSD ............... 27454 211,600 77,200 1,521,000 63,900 86,700 

General Cargo SSD ............... 7718 127,000 46,200 630,000 41,100 55,500 

Passenger ........ SSD ............... 23595 201,500 73,500 1,374,000 61,200 83,000 

Reefer .............. SSD ............... 10449 147,200 53,600 776,000 46,500 62,900 

RoRo ................ SSD ............... 15702 174,300 63,500 1,034,000 53,900 72,900 

Tanker .............. SSD ............... 9755 142,600 51,900 739,000 45,300 61,200 

Misc. ................. SSD ............... 4659 93,300 33,900 50,000 32,000 43,100 

aThe values presented in Table VII–3 are provided only to show what the estimated costs would be for a range of vessel types given average 

characteristics (such as DWT, total main, and total auxiliary power) for both SSD and MSD engine types. Not all vessels will require all of these 

technologies; for example, it is estimated that only 30 percent of MSD will get common-rail fuel injection systems for Tier II.

(6) Total Costs Associated With the 

Coordinated Strategy 

The total hardware costs associated 

with the coordinated strategy were 

estimated using the number of new 

ships by ship type and engine type 

entering the fleet each year. Table VII– 

4 presents the total hardware costs to 

U.S.-flagged vessels associated with the 

coordinated strategy. These costs consist 

of the variable and fixed hardware costs 

associated with the Annex VI existing 

engine program, Tier 2 and Tier 3 

standards, and additional components 

that may be required to accommodate 

the use of lower sulfur fuel on both new 

and existing vessels. This table also 

presents the total estimated operational 

costs associated with the coordinated 

strategy. These costs consist of the 2 

percent fuel consumption penalty 

associated with Tier 2 (Annex VI Tier 

II), the use of urea on vessels equipped 

with SCR systems, and the differential 

cost of using lower sulfur fuel; these 

costs are incurred by both U.S.- and 

foreign-flagged vessels. The total 

estimated cost of the coordinated 

strategy is $3.41 billion in 2030. The 

total costs from 2010 through 2040 are 

estimated to be $42.9 billion at a 3 

percent discount rate or $22.1 at a 7 

percent discount rate. 

TABLE VII–4—TOTAL HARDWARE AND OPERATIONAL COSTS ASSOCIATED WITH THE COORDINATED STRATEGY

[Thousands of $] 

Year 

Total hardware 

costs for existing engines 

Total new engine hardware 

costs 

Total vessel 

hardware costs 

Total operating costs Total costs associated with 

the coordinated 

strategy U.S. flag Foreign flag 

2010 ............................................. $9,400 $319 $166 $0 $0 $485 

2011 ............................................. 161,000 3,580 173 173 1,130 5,060 

2012 ............................................. 153,000 3,700 179 841 5,590 10,300 

2013 ............................................. 145,000 3,830 186 32,400 213,000 249,000 

2014 ............................................. 137,000 3,960 192 34,400 226,000 265,000 

2015 ............................................. 131,000 4,100 11,100 180,000 1,190,000 1,390,000 

2016 ............................................. 0 27,300 691 189,000 1,250,000 1,470,000 

2017 ............................................. 0 28,500 717 199,000 1,330,000 1,560,000 

2018 ............................................. 0 29,600 745 210,000 1,410,000 1,650,000 

2019 ............................................. 0 30,700 773 221,000 1,500,000 1,750,000 

2020 ............................................. 0 31,900 803 233,000 1,590,000 1,860,000 

2021 ............................................. 0 33,200 834 246,000 1,680,000 1,960,000 

2022 ............................................. 0 34,600 866 258,000 1,770,000 2,060,000 

2023 ............................................. 0 35,900 899 272,000 1,880,000 2,190,000 

2024 ............................................. 0 37,400 934 286,000 1,980,000 2,300,000 

2025 ............................................. 0 38,800 970 300,000 2,090,000 2,430,000 

2026 ............................................. 0 40,400 1,010 315,000 2,200,000 2,560,000 

2027 ............................................. 0 42,100 1,050 330,000 2,310,000 2,680,000 

2028 ............................................. 0 43,700 1,090 345,000 2,430,000 2,820,000 

2029 ............................................. 0 45,500 1,130 362,000 2,550,000 2,960,000 

2030 ............................................. 0 47,400 1,180 378,000 2,680,000 3,110,000 

2031 ............................................. 0 49,300 1,220 395,000 2,810,000 3,260,000 

2032 ............................................. 0 51,300 1,270 413,000 2,950,000 3,420,000 

2033 ............................................. 0 53,400 1,320 431,000 3,080,000 3,570,000 

2034 ............................................. 0 55,500 1,370 451,000 3,240,000 3,750,000 

2035 ............................................. 0 57,900 1,430 471,000 3,390,000 3,920,000 

2036 ............................................. 0 60,200 1,490 494,000 3,560,000 4,120,000 

2037 ............................................. 0 62,800 1,540 517,000 3,740,000 4,320,000 

2038 ............................................. 0 65,300 1,610 541,000 3,930,000 4,540,000 

2039 ............................................. 0 68,000 1,670 566,000 4,110,000 4,750,000 

2040 ............................................. 0 70,800 1,740 591,000 4,310,000 4,970,000 

NPV @ 3% ................................... 677,000 663,000 26,500 5,260,000 36,900,000 42,900,000 


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TABLE VII–4—TOTAL HARDWARE AND OPERATIONAL COSTS ASSOCIATED WITH THE COORDINATED STRATEGY— 

Continued 

[Thousands of $] 

Year 

Total hardware 

costs for existing engines 

Total new engine hardware 

costs 

Total vessel 

hardware costs 

Total operating costs Total costs associated with 

the coordinated 

strategy U.S. flag Foreign flag 

NPV @ 7% ................................... 610,000 346,000 16,900 2,730,000 19,000,000 22,100,000 

C. Cost Effectiveness 

One tool that can be used to assess the 

value of the coordinated strategy is the 

engineering costs incurred per ton of 

emissions reduced. This analysis 

involves a comparison of our program to 

other measures that have been or could 

be implemented. As summarized in this 

section, the coordinated strategy 

represents a highly cost effective mobile 

source control program for reducing 

NOX, PM and SOX emissions. 

We have estimated the cost per ton 

based on the net present value of 3 

percent and 7 percent of all hardware 

costs incurred by U.S.-flagged vessels, 

all operational costs incurred by both 

U.S. and foreign-flagged vessels, and all 

emission reductions generated from the 

year 2010 through the year 2040. The 

baseline case for these estimated 

reductions is the existing set of engine 

standards for C3 marine diesel engines 

and fuel sulfur limits. Table VII–5 

shows the annual emissions reductions 

associated with the coordinated 

strategy; these annual tons are 

undiscounted. A description of the 

methodology used to estimate these 

annual reductions can be found in 

Section II of this preamble and Chapter 

3 of the RIA. 

TABLE VII–5—ESTIMATED EMISSIONS REDUCTIONS ASSOCIATED WITH THE COORDINATED STRATEGY

[Short tons] 

Calendar year 

Reductions (tons) 

NOX SOX PM 

2010 ........................................................................................................................... 47,000 0 0 

2011 ........................................................................................................................... 54,000 0 0 

2012 ........................................................................................................................... 70,000 0 0 

2013 ........................................................................................................................... 88,000 390,000 48,400 

2014 ........................................................................................................................... 105,000 406,000 50,400 

2015 ........................................................................................................................... 123,000 641,000 68,000 

2016 ........................................................................................................................... 150,000 668,000 70,800 

2017 ........................................................................................................................... 209,000 695,000 73,700 

2018 ........................................................................................................................... 279,000 724,000 76,800 

2019 ........................................................................................................................... 349,000 755,000 80,000 

2020 ........................................................................................................................... 409,000 877,000 94,100 

2021 ........................................................................................................................... 488,000 916,000 98,200 

2022 ........................................................................................................................... 547,000 954,000 102,000 

2023 ........................................................................................................................... 634,000 995,000 107,000 

2024 ........................................................................................................................... 714,000 1,040,000 111,000 

2025 ........................................................................................................................... 790,000 1,080,000 116,000 

2026 ........................................................................................................................... 866,000 1,130,000 121,000 

2027 ........................................................................................................................... 938,000 1,170,000 126,000 

2028 ........................................................................................................................... 1,020,000 1,220,000 131,000 

2029 ........................................................................................................................... 1,100,000 1,280,000 137,000 

2030 ........................................................................................................................... 1,180,000 1,330,000 143,000 

2031 ........................................................................................................................... 1,260,000 1,390,000 149,000 

2032 ........................................................................................................................... 1,330,000 1,450,000 155,000 

2033 ........................................................................................................................... 1,410,000 1,510,000 162,000 

2034 ........................................................................................................................... 1,500,000 1,580,000 169,000 

2035 ........................................................................................................................... 1,590,000 1,650,000 177,000 

2036 ........................................................................................................................... 1,690,000 1,720,000 184,000 

2037 ........................................................................................................................... 1,810,000 1,800,000 193,000 

2038 ........................................................................................................................... 1,920,000 1,880,000 201,000 

2039 ........................................................................................................................... 2,020,000 1,970,000 210,000 

2040 ........................................................................................................................... 2,130,000 2,050,000 220,000 

NPV at 3% ................................................................................................................. 14,400,000 19,100,000 2,100,000 

NPV at 7% ................................................................................................................. 6,920,000 10,100,000 1,090,000 

The net estimated reductions by 

pollutant, using a net present value of 

3 percent from 2010 through 2040 are 

14.4 million tons of NOX, 19.1 million 

tons of SOX, and 2.1 million tons of PM 

(6.9 million, 10.1 million, and 1.1 

million tons of NOX, SOX, and PM, 

respectively, at a net present value of 7 

percent over the same period.) 

Using the above cost and emission 

reduction estimates, we estimated the 

lifetime (2010 through 2040) cost per 

ton of pollutant reduced. For this 

analysis, all of the hardware costs 

associated with the Annex VI existing 

engine program and Tier 2 and Tier 3 

NOX standards as well as the 

operational costs associated with the 


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126The costs totals reported in this FRM are 

slightly different than those reported in the ECA 

proposal. This is because the ECA proposal did not 

include costs associated with the Annex VI existing 

engine program, Tier II, or the costs associated with 

existing vessel modifications that may be required 

to accommodate the use of lower sulfur fuel. 

Further, the cost totals presented in the ECA 

package included Canadian cost estimates. 

global Tier II and Tier III standards were 

attributed to NOX reductions. The costs 

associated with lower sulfur fuel 

operational costs as applied to all 

vessels visiting U.S. ports and the 

hardware costs associated with 

accommodating the use of lower sulfur 

fuel on U.S.-flagged vessels were 

associated with SOX and PM reductions. 

In this analysis, half of the costs 

associated with the use of lower sulfur 

fuel were allocated to PM reductions 

and half to SOX, reductions, because the 

costs incurred to reduce SOX emissions 

directly reduce emissions of PM as well. 

Using this allocation of costs and the 

emission reductions shown in Table 

VII–5 we can estimate the lifetime cost 

per ton reduced associated with each 

pollutant. These results are shown in 

Table VII–6. Using a net present value 

of 3 percent, the discounted lifetime 

cost per ton of pollutant reduced is $510 

for NOX, $930 for SOX, and $7,950 for 

PM ($500, $920, and $7,850 per ton of 

NOX, SOX, and PM, respectively, at a 

net present value of 7 percent.) As 

shown in Table VII–6, these estimated 

discounted lifetime costs are similar to 

the annual long-term (2030) cost per ton 

of pollutant reduced. 

TABLE VII–6—COORDINATED STRATEGY ESTIMATED AGGREGATE DISCOUNTED LIFETIME COST PER TON (2010–2040) 

AND LONG-TERM ANNUAL COST PER TON (2030) a

Pollutant 

2010 thru 2040 discounted lifetime cost per 

ton at 3% 

2010 thru 2040 discounted lifetime cost per 

ton at 7% 

Long-term cost per ton 

(for 2030) 

NOX .............................................................................................. $510 $500 $520 

SOX .............................................................................................. 930 920 940 

PM ................................................................................................ 7,950 7,850 8,760 

aThe $/ton numbers presented here vary from those presented in the ECA proposal due to the net present value of the annualized reductions 

being applied from 2015–2020, and the use of metric tonnes rather than of short tons. Note that these costs are in 2006 U.S. dollars. 

These results for the coordinated 

strategy compare favorably to other air 

emissions control programs. Table VII– 

7 compares the coordinated strategy to 

other air programs. This comparison 

shows that the coordinated strategy will 

provide a cost-effective strategy for 

generating substantial NOX, SOX, and 

PM reductions from Category 3 vessels. 

The results presented in Table VII–7 are 

lifetime costs per ton discounted at a net 

present value of 3 percent, with the 

exception of the stationary source 

program and locomotive/marine 

retrofits, for which annualized costs are 

presented. While results at a net present 

value of 7 percent are not presented, the 

results would be similar. Specifically, 

the coordinated strategy falls within the 

range of values for other recent 

programs. 

TABLE VII–7—ESTIMATED $/TON FOR THE COORDINATED STRATEGY COMPARED TO PREVIOUS MOBILE SOURCE

PROGRAMS FOR NOX, SOX, AND PM10

Source category a, Implementation 

date NOX cost/ton SOX cost/ton PM10 cost/ton 

Category 3 Marine Compression Ignition Engine Coordinated 

Strategy FRM, 2009.

2011 510 930 7,950. 

Nonroad Small Spark-Ignition Engines ....................................

73 FR 59034, October 8, 2008 ................................................

2010 b,c 330–1,200 

Stationary Diesel (CI) Engines ................................................

71 FR 39154, July 11, 2006 ....................................................

2006 580–20,000 ............................ 3,500–42,000. 

Locomotives and C1/C2 Marine (Both New and Retrofits) .....

73 FR 25097, May 6, 2008 ......................................................

2015 b 730 ............................ 8,400 (New). 

45,000 (Retrofit). 

Heavy Duty Nonroad Diesel Engines ......................................

69 FR 38957, June 29, 2004 ...................................................

2015 b 1,100 780 13,000. 

Heavy Duty Onroad Diesel Engines ........................................

66 FR 5001, January 18, 2001 ................................................

2010 b 2,200 5,800 14,000. 

Notes: 

aTable presents aggregate program-wide cost/ton over 30 years, discounted at a 3 percent NPV, except for Stationary CI Engines and Locomotive/Marine retrofits, for which annualized costs of control for individual sources are presented. All figures are in 2006 U.S. dollars per short 

ton. b Includes NOX plus non-methane hydrocarbons (NMHC). NMHC are also ozone precursors, thus some rules set combined NOX+NMHC emissions standards. NMHC are a small fraction of NOX so aggregate cost/ton comparisons are still reasonable. c Low end of range represents costs for marine engines with credit for fuel savings, high end of range represents costs for other nonroad SI 

engines without credit for fuel savings. 

D. Economic Impact Analysis 

This section contains our analysis of 

the expected economic impacts of our 

coordinated strategy on the markets for 

Category 3 marine diesel engines, 

vessels using these engines, and the U.S. 

marine transportation service sector. We 

briefly describe our methodology and 

present our estimated expected 

economic impacts. 

The total estimated social costs of the 

coordinated strategy in 2030 are 

equivalent to the estimated engineering 

compliance costs of the program, at 

approximately $3.1 billion.126 As 

explained below, these costs are 

expected to accrue initially to the 

owners and operators of affected vessels 

when they purchase engines, vessels, 

and fuel. These owners and operators 

are expected to pass their increased 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 22949 

127Stopford describes these markets as 

competitive. See Stopford, Martin. Maritime 

Economics, 3rd Edition (Routledge, 2009), Chapter 

4. 

128Tirole, Jean. The Theory of Industrial 

Organization (1989). MIT Press. See pages 223–224. 

costs on to the entities that purchase 

international marine transportation 

services, in the form of higher freight 

rates. Ultimately, these social costs are 

expected to be borne by the final 

consumers of goods transported by 

affected vessels in the form of slightly 

higher prices for those goods. 

We estimate that compliance with the 

coordinated strategy would increase the 

price of a new vessel by 0.5 to 2 percent, 

depending on the vessel type. The price 

impact of the coordinated strategy on 

the marine transportation services sector 

would vary, depending on the route and 

the amount of time spent in waterways 

covered by the engine and fuel controls 

(the U.S. ECA and U.S. internal waters 

covered by the coordinated strategy). 

For example, we estimate that the cost 

of operating a ship in liner service 

between Singapore, Seattle, and Los 

Angeles/Long Beach, which includes 

about 1,700 nm of operation in 

waterways covered by the coordinated 

strategy, would increase by about 3 

percent. For a container ship, this 

represents a price increase of about $18 

per container (3 percent price increase), 

assuming the total increase in operating 

costs is passed on to the purchaser of 

the marine transportation services. The 

per passenger price of a seven-day 

Alaska cruise on a vessel operating 

entirely within waterways covered by 

the coordinated strategy is expected to 

increase by about $7 per day, again 

assuming that the total increase in 

operating costs is passed on to the 

passengers of the vessel. Ships that 

spend less time in covered areas would 

experience relatively smaller increases 

in their operating costs, and the impacts 

on their freight prices is expected to be 

smaller. 

It should be noted that this economic 

analysis holds all other aspects of the 

market constant except for the elements 

of the coordinated strategy. It does not 

attempt to predict future market 

equilibrium conditions, particularly 

with respect to how excess capacity in 

today’s market due to the current 

economic downturn will be absorbed. 

This approach is appropriate because 

the goal of an economic impact analysis 

is to explore the impacts of a specific 

program; allowing changes in other 

market conditions would confuse the 

impacts due to the regulatory program. 

The remainder of this section 

provides information on the 

methodology we used to estimate these 

economic impacts and the results of our 

analysis. A more detailed discussion 

can be found in Chapter 7 of the RIA 

prepared for this rule. 

(1) What Is the Purpose of an Economic 

Impact Analysis? 

In general, the purpose of an 

Economic Impact Analysis (EIA) is to 

provide information about the potential 

economic consequences of a regulatory 

action, such as the coordinated strategy 

to reduce emissions from Category 3 

vessels. Such an analysis consists of 

estimating the social costs of a 

regulatory program and the distribution 

of these costs across stakeholders. The 

estimated social costs can then be 

compared with the estimated social 

benefits as presented elsewhere in this 

preamble. 

In an economic impact analysis, 

social costs are the value of the goods 

and services lost by society resulting 

from (a) the use of resources to comply 

with and implement a regulation and (b) 

reductions in output. There are two 

parts to the analysis. In the market 

analysis, we estimate how prices and 

quantities of goods directly affected by 

the emission control program can be 

expected to change once the program 

goes into effect. In the economic welfare 

analysis, we look at the total social costs 

associated with the program and their 

distribution across key stakeholders. 

(2) How Did We Estimate the Economic 

Impacts of the Coordinated Strategy? 

Our analysis of the economic impacts 

of the coordinated strategy is based on 

the application of basic microeconomic 

theory. In this analysis, we use a 

competitive market model approach in 

which the interaction between supply 

and demand determines equilibrium 

market prices and quantities. The 

competitive model approach is 

appropriate for the vessel building and 

transportation service markets because 

in each of those markets there are many 

producers and consumers are not 

constrained to use one producer over 

the others.127

We also use a competitive market 

structure for the Category 3 engine 

market. This market is characterized by 

a small number of manufacturers (2 

companies comprising about 60 percent 

of the market, with two others having a 

notable share), which suggests that this 

limited number of manufacturers may 

have certain market power. However, an 

important characteristic of the market 

suggests this market may nevertheless 

be competitive. Specifically while the 

primary engine companies design and 

patent Category 3 marine diesel engines, 

they manufacture only key components 

and not the actual engine itself. Engines 

are manufactured through licensing 

agreements with shipyards or other 

companies. Licensees pay a fixed cost to 

the primary engine manufacturers for 

using their designs and brands. Engine 

prices are then set by the licensees, 

sometimes as part of the price of a 

completed vessel, and there is 

competition among these firms to 

manufacturer engines and vessels. 

Nevertheless, to estimate the 

maximum economic impact of the 

program, we can examine how the 

results of this economic impact analysis 

would change if we assumed an 

imperfectly competitive market 

structure. In markets with a small 

number of producers, it is not 

uncommon for manufacturers to 

exercise market power to obtain prices 

above their costs, thereby securing 

greater profits. In this case, market 

prices would be expected to increase by 

more than the compliance costs of the 

regulatory program, although the 

magnitude of the increase would be 

limited by the existing dynamics of the 

market (i.e., the current difference 

between the actual market price and the 

competitive market price). This impact 

is discussed in more detail in Section 

VII.D.5, below. The higher price impact 

from imperfect competition would be 

transmitted to the vessel and marine 

transportation markets. However, even 

in this case, the price impacts of this 

rule on the Category 3 engine market are 

not expected to be large given the price 

increases estimated for the competitive 

case, described below. This is because 

the compliance costs for engine program 

are relatively small compared to the 

price of a vessel. 

Finally, the existence of only a small 

number of firms in a market does not 

mean that the market necessarily 

behaves noncompetitively. In the 

Bertrand competition model, firms 

compete with each other by choosing a 

lower price.128 When they compete 

repeatedly, the market price is expected 

to approximate the price that would 

occur in a perfectly competitive market. 

In this case, the two primarily engine 

producers compete against each other 

and against the smaller producers in the 

market. They also compete to sell the 

same or similar engines in the landbased electrical power generating 

market, where they face many more 

competitors. 

In a competitive structure model, we 

use the relationships between supply 

and demand to simulate how markets 

can be expected to respond to increases 


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22950 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

129Harrould-Koleib, Ellycia. Shipping Impacts on 

Climate: A Source with Solutions. Oceana, July 

2008. A copy of this report can be found at 

http://www.oceana.org/fileadmin/oceana/uploads/ 

Climate_Change/Oceana_Shipping_Report.pdf. 

130Stopford, Martin. Maritime Economics, 3rd 

Edition. Routledge, 2009. p. 163. 

in production costs that occur as a result 

of the new emission control program. 

We use the laws of supply and demand 

to construct a model to estimate the 

social costs of the program and identify 

how those costs will be shared across 

the markets and, thus, across 

stakeholders. The relevant concepts are 

summarized below and are presented in 

greater detail in Chapter 7 of the RIA. 

Before the implementation of a 

control program, a competitive market is 

assumed to be in equilibrium, with 

producers producing the amount of a 

good that consumers desire to purchase 

at the market price. The implementation 

of a control program results in an 

increase in production costs by the 

amount of the compliance costs. This 

generates a ‘‘shock’’ to the initial 

equilibrium market conditions (a change 

in supply). Producers of affected 

products will try to pass some or all of 

the increased production costs on to the 

consumers of these goods through price 

increases, without changing the quantity 

produced. In response to the price 

increases, consumers will decrease the 

quantity they buy of the affected good 

(a change in the quantity demanded). 

This creates surplus production at the 

new price. Producers will react to the 

decrease in quantity demanded by 

reducing the quantity they produce, and 

they will be willing to sell the 

remaining production at a lower price 

that does not cover the full amount of 

the compliance costs. Consumers will 

then react to this new price. These 

interactions continue until the surplus 

production is removed and a new 

market equilibrium price and quantity 

combination is achieved. 

The amount of the compliance costs 

that will be borne by stakeholders is 

ultimately limited by the price 

sensitivity of consumers and producers 

in the relevant markets, represented by 

the price elasticities of demand and 

supply for each market. An ‘‘inelastic’’ 

price elasticity (less than one) means 

that supply or demand is not very 

responsive to price changes (a one 

percent change in price leads to less 

than one percent change in quantity). 

An ‘‘elastic’’ price elasticity (more than 

one) means that supply or demand is 

sensitive to price changes (a one percent 

change in price leads to more than one 

percent change in quantity). A price 

elasticity of one is unit elastic, meaning 

there is a one-to-one correspondence 

between a percent change in price and 

percent change in quantity. 

On the production side, price 

elasticity of supply depends on the time 

available to adjust production in 

response to a change in price, how easy 

it is to store goods, and the cost of 

increasing (or decreasing) output. In this 

analysis, we assume the supply for 

engines, vessels, and marine 

transportation services is elastic: an 

increase in the market price of an 

engine, vessel or freight rates will lead 

producers to want to produce more, 

while a decrease will lead them to 

produce less (this is the classic upwardsloping supply curve). It would be 

difficult to estimate the slope of the 

supply curve for each of these markets 

given the global nature of the sector and, 

as explained in Chapter 7 of the RIA it 

is not necessary to have estimated 

supply elasticities for this analysis due 

to the assumption of nearly perfectly 

inelastic demand for the marine 

transportation sector. However, we can 

make some observations about the 

supply elasticities based on the nature 

of each sector. For the marine 

transportation sector, it is reasonable to 

assume a supply elasticity equal to or 

greater than one because the amount of 

transportation services provided can 

easily be adjusted due to a change in 

price in most cases (e.g., move more or 

fewer containers or passengers) 

especially if the market can carry a 

certain amount of excess capacity. For 

the new Category 3 engine market the 

supply elasticity is also likely to be 

greater than one. These engines are 

often used in other land-based 

industries, notably in power plants, 

which provide a market to 

accommodate production fluctuations 

as manufacturers adjust their output for 

the marine market. The supply elasticity 

for the vessel construction market, on 

the other hand, is upward sloping but 

the slope (supply elasticity) may be less 

than or equal to one depending on the 

vessel type. This would be expected 

since it may be harder to adjust 

production and/or store output if the 

price drops, or rapidly increase 

production if the price increases. 

Because of the nature of this industry, 

it may not be possible to easily switch 

production to other goods, or to stop or 

start production of new vessels. 

On the consumption side, we assume 

that the demand for engines is a 

function of the demand for vessels, 

which is a function of the demand for 

international shipping (demand for 

engines and vessels is derived from the 

demand for marine transportation 

services). This makes intuitive sense: 

Category 3 engine and vessel 

manufacturers would not be expected to 

build an engine or vessel unless there is 

a purchaser, and purchasers will want a 

new vessel/engine only if there is a need 

for one to supply marine transportation 

services. Deriving the price elasticity of 

demand for the vessel and engine 

markets from the international shipping 

market is an important feature of this 

analysis because it provides a link 

between the product markets. 

In this analysis, the price elasticity of 

demand for marine transportation 

services, and therefore for vessels and 

Category 3 engines, is assumed to be 

nearly perfectly inelastic (the demand 

for marine transportation services will 

remain the same for all price changes). 

This stems from the fact that for most 

goods, there are no reasonable 

alternative shipping modes. In most 

cases, transportation by rail or truck is 

not feasible, and transportation by 

aircraft is too expensive. Approximately 

90 percent of world trade by tonnage is 

moved by ship, and ships provide the 

most efficient method to transport these 

goods on a tonne-mile basis.129 Stopford 

notes that ‘‘shippers need the cargo and, 

until they have time to make alternative 

arrangements, must ship it regardless of 

cost * * *. The fact that freight 

generally accounts for only a small 

portion of material costs reinforces this 

argument.’’ 130 A nearly perfectly 

inelastic price elasticity of demand for 

marine transportation services means 

that virtually all of the compliance costs 

can be expected to be passed on to the 

consumers of marine transportation 

services, with no change in output for 

engine producers, ship builders, or 

owners and operators of ships engaged 

in international trade. Section VII.D.5, 

below, provides a discussion of the 

impact of relaxing of the nearly perfect 

demand elasticity for marine 

transportation services in general, and 

for the cruise industry specifically. 

Relaxing this assumption is not 

expected to change the estimated total 

social costs of the program, which are 

limited by the engineering compliance 

costs. However, it would change the 

way those costs are shared among 

stakeholders. 

Finally, with regard to the fuel 

markets, the impacts of the coordinated 

strategy on fuel costs were assessed 

using the World Oil Refining Logistics 

and Demand (WORLD) model, as run by 

Ensys Energy & Systems, the owner and 

developer of the refinery model. As 

described in Chapter 5 of the RIA, the 

WORLD model is the only such model 

currently developed for this purpose, 

and was developed by a team of 

international petroleum consultants. It 


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131The MARPOL amendments include Tier II and 

Tier III NOX standards that apply to all vessels, 

including foreign vessels. While the analysis does 

not include hardware costs for the MARPOL Tier 

II and Tier III standards for foreign vessels because 

foreign vessels operate anywhere in the world, it is 

appropriate to include the operating costs for these 

foreign vessels while they are operating in our 

inventory modeling domain. This is because foreign 

vessels complying with the Tier II and Tier III 

standards will have a direct beneficial impact on 

U.S. air quality, and if we consider the benefits of 

these standards we should also consider their costs. 

has been widely used by industries, 

government agencies, and OPEC over 

the past 13 years, including the Cross 

Government/Industry Scientific Group 

of Experts, established to evaluate the 

effects of the different fuel options 

proposed under the revision of 

MARPOL Annex VI. The model 

incorporates crude sources, global 

regions, refinery operations, and world 

economics, as well as assumptions 

about how these markets respond to 

regulatory programs. The results of the 

WORLD model have been shown to be 

comparable to other independent 

predictions of global fuel, air pollutant 

emissions and economic predictions. 

WORLD is a comprehensive, bottomup model of the global oil downstream 

that includes crude and noncrude 

supplies; refining operations and 

investments; crude, products, and 

intermediates trading and transport; and 

product blending/quality and demand. 

Its detailed simulations are capable of 

estimating how the global system can be 

expected to operate under a wide range 

of different circumstances, generating 

model outputs such as price effects and 

projections of refinery operations and 

investments. 

This analysis of the economic impacts 

of the coordinated strategy relies on the 

estimated engineering compliance costs 

for engines and fuels described in 

Sections VII.A (fuels) and VII.B 

(engines) above. These costs include 

hardware costs for new U.S. vessels to 

comply with the Tier 2 and Tier 3 

engine standards, and for existing U.S. 

vessels to comply with the MARPOL 

Annex VI requirements for existing 

engines. There are also hardware costs 

for fuel switching equipment on new 

and existing U.S. vessels to comply with 

the 1,000 ppm fuel sulfur limit; the cost 

analysis assumes that 32 percent of all 

vessels require fuel switching 

equipment to be added (new vessels) or 

retrofit (existing vessels). Also included 

are expected increases in operating costs 

for U.S. and foreign vessels operating in 

the inventory modeling domain (the 

waterways covered by the engine and 

fuel controls, i.e., the U.S. ECA and U.S. 

internal waters covered by the 

coordinated strategy.131 These increased 

operating costs include changes in fuel 

consumption rates, increases in fuel 

costs, and the use of urea for engines 

equipped with SCR, as well as a small 

increase in operating costs for operation 

outside the waterways affected by the 

coordinated strategy due to the fuel 

price impacts of the program. 

(3) What Are the Estimated Market 

Impacts of the Coordinated Strategy? 

(a) What Are the Estimated Engine and 

Vessel Market Impacts of the 

Coordinated Strategy? 

The estimated market impacts for 

engines and vessels are based on the 

variable costs associated with the engine 

and vessel compliance programs; fixed 

costs are not included in the market 

analysis. This is appropriate because in 

a competitive market the industry 

supply curve is generally based on the 

market’s marginal cost curve; fixed costs 

do not influence production decisions at 

the margin. Therefore, the market 

analysis for a competitive market is 

based on variable costs only. 

The assumption of nearly perfectly 

inelastic demand for marine 

transportation services means that the 

quantity of these services purchased is 

not expected to change as a result of 

costs of complying with the 

requirements of the coordinated 

strategy. As a result, the demand for 

vessels and engines would also not 

change compared to the no-control 

scenario, and the quantities produced 

would remain the same. 

The assumption of nearly perfectly 

inelastic demand for marine 

transportation services also means the 

price impacts of the coordinated 

strategy on new engines and vessels 

would be equivalent to the variable 

engineering compliance costs. Estimated 

price impacts for a sample of enginevessel combinations are set out in Table 

VII–8 for medium speed engines, and 

Table VII–9 for slow speed engines. 

These are the estimated price impacts 

associated with the Tier 3 engine 

standards on a vessel that will switch 

fuels to comply with the fuel sulfur 

requirements while operating in the 

waterways covered by the engine and 

fuel controls. Because there is no phasein for the standards, the estimated price 

impacts are the same for all years, 

beginning in 2016. 

TABLE VII–8—SUMMARY OF ESTIMATED MARKET IMPACTS—MEDIUM SPEED TIER 3 ENGINES AND VESSELS

[$2006] a

Ship type 

Average 

propulsion 

power 

New vessel engine price impact 

(new tier 3 

engine price impact) b

New vessel fuel 

switching equipment price 

impact c

New vessel total 

price 

impact 

Auto Carrier ............................................................................................. 9,600 $573,200 $42,300 $615,500 

Bulk Carrier .............................................................................................. 6,400 483,500 36,900 520,400 

Container ................................................................................................. 13,900 687,800 49,200 736,000 

General Cargo ......................................................................................... 5,200 450,300 34,900 475,200 

Passenger ................................................................................................ 23,800 952,500 65,400 1,107,900 

Reefer ...................................................................................................... 7,400 511,000 38,500 549,500 

RoRo ........................................................................................................ 8,600 543,800 40,500 584,300 

Tanker ...................................................................................................... 6,700 492,800 37,400 530,200 

Misc. ......................................................................................................... 9,400 566,800 41,900 608,700 

Notes: 

aThe new vessel engine price impacts listed here do not include a per engine cost of $10,000 for engines installed on U.S. vessels to comply 

with the proposed production testing requirement (§ 1042.302). b Medium speed engine price impacts are estimated from the cost information presented in Chapter 5 of the RIA using the following formula: 

(10%*($/SHIP_MECH→CR)) + (30%*($/SHIP_ELEC→CR)) + (T3 ENGINE MODS) + (T3SCR)). cAssumes 32 percent of new vessels would require the fuel switching equipment. 


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22952 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

TABLE VII–9—SUMMARY OF ESTIMATED MARKET IMPACTS—SLOW SPEED TIER 3 ENGINES AND VESSELS ($2006) a

Ship type 

Average 

propulsion 

power 

New vessel engine price impact 

(new tier 3 

engine price 

impact) b

New vessel fuel 

switching equipment price 

impact c

New vessel total 

price impact 

Auto Carrier ............................................................................................. 11,300 $825,000 $48,000 $873,000 

Bulk Carrier .............................................................................................. 8,400 672,600 42,700 715,300 

Container ................................................................................................. 27,500 1,533,100 63,900 1,597,000 

General Cargo ......................................................................................... 7,700 632,900 41,000 673,900 

Passenger ................................................................................................ 23,600 1,385,300 61,200 1,446,500 

Reefer ...................................................................................................... 10,400 781,000 46,500 827,500 

RoRo ........................................................................................................ 15,700 1,042,100 53,900 1,096,000 

Tanker ...................................................................................................... 9,800 744,200 45,300 789,500 

Misc. ......................................................................................................... 4,700 453,600 32,000 485,600 

Notes: 

aThe new vessel engine price impacts listed here do not include a per engine cost of $10,000 for engines installed on U.S. vessels to comply 

with the proposed production testing requirement (§ 1042.302). bSlow speed engine price impacts are estimated from the cost information presented in Chapter 5 using the following formula: (5%*($/ 

SHIP_MECH→CR)) + (15%*($/SHIP_ELEC→CR)) + (T3 ENGINE MODS) + (T3 SCR)). cAssumes 32 percent of new vessels would require the fuel switching equipment. 

The estimated price impacts for Tier 

2 vessels would be substantially lower, 

given the technology that will be used 

to meet the Tier 2 standards is much 

less expensive. The cost of complying 

with the Tier 2 standards ranges from 

about $56,000 to $100,000 for a medium 

speed engine, and from about $130,000 

to $250,000 for a slow speed engine (see 

discussion in Chapter 7 of the RIA). 

Again, because the standards do not 

phase in, the estimated price impacts 

are the same for all years the Tier 2 

standards are required, 2011 through 

2015. 

These estimated price impacts for Tier 

2 and Tier 3 vessels are small when 

compared to the price of a new vessel. 

A selection of new vessel prices is 

provided in Table VII–10; these range 

from about $40 million to $480 million. 

The program price increases range from 

about $600,000 to $1.5 million. A price 

increase of $600,000 to comply with the 

Tier 3 standards and fuel switching 

requirements would be an increase of 

approximately 2 percent for a $40 

million vessel. The largest vessel price 

increase noted above for a Tier 3 

passenger vessel is about $1.5 million; 

this is a price increase of less than 1 

percent for a $478 million passenger 

vessel. Independent of the nearlyperfect inelasticity of demand, price 

increases of this magnitude would be 

expected to have little, if any, effect on 

the sales of new vessels, all other 

economic conditions held constant. 

TABLE VII–10—NEWBUILD VESSEL PRICE BY SHIP TYPE AND SIZE, SELECTED VESSELS

[Millions, $2008] 

Vessel type Vessel size 

category Size range (mean) (DWT) Newbuild 

Bulk Carrier ........................................................................... Handy ............................................. 10,095–39,990 (27,593) $56.00 

Handymax ...................................... 40,009–54,881 (47,616) 79.00 

Panamax ........................................ 55,000–78,932 (69,691) 97.00 

Capesize ........................................ 80,000–364,767 (157,804) 175.00 

Container ............................................................................... Feeder ............................................ 1,000–13,966 (9,053) 38.00 

Intermediate ................................... 14,003–36,937 (24,775) 70.00 

Panamax ........................................ 37,042–54,700 (45,104) 130.00 

Post Panamax ................................ 55,238–84,900 (67,216) 165.00 

Gas carrier ............................................................................ Midsize ........................................... 1,001–34,800 (7,048) 79.70 

LGC ................................................ 35,760–59,421 (50,796) 37.50 

VLGC ............................................. 62,510–122,079 (77,898) 207.70 

General cargo ....................................................................... Coastal Small ................................. 1,000–9,999 (3,789) 33.00 

Coastal Large ................................. 10,000–24,912 (15,673) 43.00 

Handy ............................................. 25,082–37,865 (29,869) 52.00 

Panamax ........................................ 41,600–49,370 (44,511) 58.00 

Passenger ............................................................................. All ................................................... 1,000–19,189 (6,010) 478.40 

Reefer .................................................................................... All ................................................... 1,000–19,126 (6,561) 17.30 

Ro-Ro .................................................................................... All ................................................... 1,000–19,126 (7,819) 41.20 

Tanker ................................................................................... Coastal ........................................... 1,000–23,853 (7,118) 20.80 

Handymax ...................................... 25,000–39,999 (34,422) 59.00 

Panamax ........................................ 40,000–75,992 (52,300) 63.00 

AFRAmax ....................................... 76,000–117,153 (103,112) 77.00 

Suezmax ........................................ 121,109–167,294 (153,445) 95.00 


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132Stopford, Martin, Maritime Economics, 3rd 

Edition. Routledge, 2009. Page 519. 

TABLE VII–10—NEWBUILD VESSEL PRICE BY SHIP TYPE AND SIZE, SELECTED VESSELS—Continued 

[Millions, $2008] 

Vessel type Vessel size 

category Size range (mean) (DWT) Newbuild 

VLCC .............................................. 180,377–319,994 (294,475) 154.00 

Sources: Lloyd’s Shipping Economist (2008), Informa (2008), Lloyd’s Sea-Web (2008). 

(b) What Are the Estimated Fuel Market 

Impacts of the Coordinated Strategy? 

The market impacts for the fuel 

markets were estimated through the 

modeling performed to estimate the fuel 

compliance costs for the coordinated 

strategy. In the WORLD model, the total 

quantity of fuel used is held constant, 

which is consistent with the assumption 

that the demand for international 

shipping transportation would not be 

expected to change due to the lack of 

transportation alternatives. 

The expected price impacts of the 

coordinated strategy are set out in Table 

VII–11. Note that on a mass basis, less 

distillate than residual fuel is needed to 

go the same distance (5 percent less). 

The prices in Table VII–11 are adjusted 

for this impact. 

Table VII–11 shows that the 

coordinated strategy is expected to 

result in a small increase in the price of 

marine distillate fuel, about 1.3 percent. 

The price of residual fuel is expected to 

decrease slightly, by less than one 

percent, due to a reduction in demand 

for that fuel. 

TABLE VII–11—SUMMARY OF ESTIMATED MARKET IMPACTS—FUEL MARKETS

Fuel Units Baseline 

price 

Control 

price 

Adjusted for 

energy density % change 

Distillate .................................................................................................... $/tonne $462 $468 N/A +1.3% 

Residual ................................................................................................... $/tonne $322 $321 N/A ¥0.3% 

Fuel Switching .......................................................................................... $/tonne $322 $468 $444 +38.9%a

Notes: 

aEnergy adjusted value. 

Because of the need to shift from 

residual fuel to distillate fuel for ships 

while operating in the waterways 

covered by the engine and fuel controls 

(the U.S. ECA and U.S. internal waters 

covered by the coordinated strategy), 

ship owners are expected to see an 

increase in their total cost of fuel. This 

increase is because distillate fuel is 

more expensive than residual fuel. 

Factoring in the higher energy content 

of distillate fuel relative to residual fuel, 

the fuel cost increase would be about 39 

percent. 

(c) What Are the Estimated Marine 

Transportation Market Impacts of the 

Coordinated Strategy? 

We used the above information to 

estimate the impacts on the prices of 

marine transportation services. This 

analysis, which is presented in Chapter 

7 of the RIA, is limited to the impacts 

of increases in operating costs due to the 

fuel and emission requirements of the 

coordinated strategy. Operating costs 

would increase due to the increase in 

the price of fuel, the need to switch to 

fuel with a sulfur content not to exceed 

1,000 ppm while operating in the 

waterways covered by the engine and 

fuel controls, and due to the need to 

dose the aftertreatment system with urea 

to meet the Tier 3 standards. Table VII– 

12 summarizes these price impacts for 

selected transportation markets. Table 

VII–12 also lists the vessel and engine 

parameters that were used in the 

calculations. 

TABLE VII–12—SUMMARY OF IMPACTS OF OPERATIONAL FUEL/UREA COST INCREASES

Vessel type Vessel and engine 

parameters Operational price increases 

Container .................................................................

North Pacific Circle Route .......................................

36,540 kW .............................................

50,814 DWT 

$17.53/TEU. 

Bulk Carrier ..............................................................

North Pacific Circle Route .......................................

3,825 kW ...............................................

16,600 DWT 

$0.56/tonne. 

Cruise Liner .............................................................

(Alaska) ....................................................................

31,500 kW .............................................

226,000 DWT 

1,886 passengers 

$6.60/per passenger per day. 

This information suggests that the 

increase in marine transportation 

service prices would be small, both 

absolutely and when compared to the 

price charged by the ship owner per 

unit transported and are estimated to be 

about $18 per TEU on the North Pacific 

Circle Route and $0.56 per tonne for 

bulk cargo on the North Pacific Circle 

Route. Stopford notes that the price of 

transporting a 20 foot container between 

the UK and Canada is estimated to be 

about $1,500; of that, $700 is the cost of 

the ocean freight; the rest is for port, 

terminal, and other charges.132 Thus, a 

price increase of about $18 represents 

an increase of less than 3 percent of 

ocean freight cost, and about one 

percent of transportation cost. Similarly, 

the price of a 7-day Alaska cruise varies 


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133The costs totals reported in this FRM are 

slightly different than those reported in the ECA 

proposal. This is because the ECA proposal did not 

include costs associated with the Annex VI existing 

engine program, Tier II, or the costs associated with 

existing vessel modifications that may be required 

to accommodate the use of lower sulfur fuel. 

Further, the cost totals presented in the ECA 

package included Canadian cost estimates. 

134Census Bureau’s Foreign Trade Division, U.S. 

Waterborne Foreign Trade by U.S. Custom Districts, 

as reported by the Maritime Administration at 

http://www.marad.dot.gov/library_landing_page/

data_and_statistics/Data_and_Statistics.htm, 

accessed April 9, 2009. 

135U.S. Census Bureau, Industry Statistics 

Sampler, NAICS 48311, Deep sea, coastal, and Great 

Lakes transportation, at http://www.census.gov/ 

econ/census02/data/industry/E48311.HTM, 

assessed on April 9, 2009. 

from $100 to $400 per night or more. In 

that case, a price increase of about $7 

per night would be a 1.5 percent to 

about 6 percent increase. 

(4) What Are the Estimated Social Costs 

of the Coordinated Strategy and How 

Are They Expected To Be Distributed 

Across Stakeholders? 

The total social costs of the 

coordinated strategy are based on both 

fixed and variable costs. Fixed costs are 

a cost to society: They displace other 

product development activities that may 

improve the quality or performance of 

engines and vessels. In this economic 

impact analysis, fixed costs are 

accounted for in the year in which they 

occur, with the fixed costs associated 

with the Tier 2 engine standards 

accounted for in 2010 and the fixed 

costs associated with the Tier 3 engine 

standards and the fuel sulfur controls 

for vessels operating on the waterways 

covered by the coordinated strategy are 

accounted for in the five-year period 

beginning prior to their effective dates. 

The estimated social costs of the 

coordinated strategy for all years are 

presented in Table VII–4. For 2030, the 

social costs are estimated to be about 

$3.1 billion.133 For the reasons 

described above and explained more 

fully in the RIA, these costs are 

expected to be borne fully by consumers 

of marine transportation services. 

These social costs are small when 

compared to the total value of U.S. 

waterborne foreign trade. In 2007, 

waterborne trade for government and 

non-government shipments by vessel 

into and out of U.S. foreign trade zones, 

the 50 States, the District of Columbia, 

and Puerto Rico was about $1.4 trillion. 

Of that, about $1 trillion was for 

imports.134

If only U.S. vessels are considered, 

the social costs of the coordinated 

strategy in 2030 would be about $427.5 

million. Again, these social costs are 

small when compared to the annual 

revenue for this sector. In 2002, the 

annual revenue for this sector was about 

$19.8 billion.135

(5) Sensitivity Analyses 

In this section we briefly discuss the 

impact of relaxing several of the 

assumptions used in our economic 

impact analysis for the coordinated 

strategy, including the assumption of 

nearly perfectly inelastic demand for 

marine transportation services, nearly 

perfectly inelastic demand for cruise 

services, and a competitive market 

structure for the Category 3 marine 

diesel engine market. Each of these 

cases is examined more fully in Chapter 

7 of the RIA for this rule. 

To examine the impact of the 

assumption of nearly perfectly inelastic 

demand elasticity for marine 

transportation services, we would 

determine a discrete value for that 

elasticity and then create a computer 

model to model the effects of the 

coordinated strategy. It would be 

difficult to develop such an elasticity 

using available industry information. 

Therefore, this alternative analysis relies 

on the price elasticities we developed 

for our 2008 rulemaking that set 

technology-forcing standards for 

Category 1 and Category 2 engines (73 

FR 25098, May 6, 2008). Although these 

price elasticities of demand and supply 

were developed using data for United 

States markets only, they reflect 

behavioral reactions to price changes if 

alternative modes of transportation were 

available. While they are not specific to 

the global marine transportation market, 

they are useful to provide an idea of the 

change in results that could be expected 

if the demand elasticity for marine 

transportation is not nearly perfectly 

inelastic. 

The values used for the behavioral 

parameters for the Category 1 and 2 

markets are provided in Table VII–13. In 

this case, the demand for marine 

transportation services is estimated to 

be somewhat inelastic: A one percent 

increase in price will result in a 0.5 

percent decrease in demand. 

TABLE VII–13—BEHAVIORAL PARAMETERS USED IN LOCOMOTIVE/MARINE ECONOMIC IMPACT MODEL

Sector Market Demand elasticity Source Supply elasticity Source 

Marine ............... Marine Transportation 

Services.

¥0.5 (inelastic) ......... Literature estimate ..... 0.6 (inelastic) ............. Literature estimate. 

Commercial Vessels a ... Derived ...................... N/A ............................ 2.3 (elastic) ................ Econometric estimate. 

Engines ......................... Derived ...................... N/A ............................ 3.8 (elastic) ................ Econometric estimate. 

Notes: 

a Commercial vessels include tug/tow/pushboats, ferries, cargo vessels, crew/supply boats, and other commercial vessels. 

In general, relaxing the condition of 

nearly perfectly inelastic demand 

elasticity would result in the 

compliance costs of the coordinated 

strategy being shared by consumers and 

suppliers. The distribution of 

compliance costs from our earlier rule 

are presented in Table VII–14. While the 

emission control requirements and the 

compliance cost structure of the 

coordinated strategy are somewhat 

different, these results give an idea of 

how costs would be shared if the 

assumption of nearly perfectly inelastic 

price elasticity of demand for the 

transportation services market in the 

ocean-going marine sector were relaxed. 


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136EPA420–02–022, Final Regulatory Support 

Document: Control of Emissions from Unregulated 

Nonroad Engines, Chapter 9. A copy of this 

document is available at http://www.epa.gov/otaq/ 

regs/nonroad/2002/r02022j.pdf. 

137Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. 

Calle, D. Krewski, K. Ito, and G.D. Thurston (2002). 

Lung Cancer, Cardiopulmonary Mortality, and 

Long-term Exposure to Fine Particulate Air 

Pollution. Journal of the American Medical 

Association, 287, 1132–1141. 138Bell, M.L., et al. (2004). Ozone and short-term 

mortality in 95 U.S. urban communities, 1987– 

2000. Journal of the American Medical Association, 

292(19), 2372–2378. 139Laden, F., J. Schwartz, F.E. Speizer, and D.W. 

Dockery (2006). Reduction in Fine Particulate Air 

Pollution and Mortality. American Journal of 

Respiratory and Critical Care Medicine. 173, 667– 

672. 140Levy, J.I., S.M. Chemerynski, and J.A. Sarnat 

(2005). Ozone exposure and mortality: an empiric 

Continued 

TABLE VII–14—DISTRIBUTION OF SOCIAL COSTS AMONG STAKEHOLDER GROUPS—CATEGORY 1 AND CATEGORY 2 

ENGINE PROGRAM

Stakeholder group 2020 

(percent) 

2030 

(percent) 

Marine engine producers ................................................................................................................................. 0.8 0.5 

Marine vessel producers ................................................................................................................................. 10.7 3.8 

Recreational and fishing vessel consumers .................................................................................................... 8.4 4.1 

Marine transportation service providers .......................................................................................................... 36.4 41.5 

Marine transportation service consumers ....................................................................................................... 43.8 50.0 

Total .......................................................................................................................................................... 100.0 100.0 

With regard to cruise transportation, 

commenters remarked that demand is 

not nearly perfectly inelastic. Cruises 

are a recreational good, and if the price 

of a cruise increases, consumers will 

choose to spend their recreational 

budgets on other activities. 

The same analysis described above 

would also apply in this particular 

sector of the marine transportation 

market. In this case, the share of the 

compliance costs that will be borne by 

the cruise industry suppliers will 

depend on the magnitude of the demand 

elasticity. If the price elasticity of 

demand is larger (in absolute value) 

than the price elasticity of supply, ship 

owners will bear a larger share of the 

costs of the program; if the price 

elasticity of demand is smaller (in 

absolute value) than the price elasticity 

of supply, consumers will bear a larger 

share of the program. 

In our 2002 recreational vehicle rule, 

we estimated the demand elasticity for 

inboard cruisers to be about ¥1.4 and 

the supply elasticity to be about 1.6.136

Using these values as a proxy for cruise 

ship demand and supply, this suggests 

that the compliance costs will be shared 

among passengers and operators roughly 

evenly. 

As described in Section 7.3 of the 

RIA, the compliance costs associated 

with the coordinated strategy are 

expected to be small compared to the 

daily costs of a cruise, at about $7 per 

night. Overall, total engine and vessel 

costs are expected to increase about one 

percent and operating costs increasing 

between 1.5 and 6 percent. These 

increases are within the range of historic 

variations in bunker fuel prices. So, 

although relaxing the assumption of 

nearly perfectly elastic demand 

elasticity for cruises means the burden 

of the coordinated strategy would be 

shared between cruise ship operators 

and cruise ship passengers, those costs, 

and therefore the expected price 

increases, are expected to be small 

compared to the price of a cruise. 

Finally, this Economic Impact 

Analysis assumes that the market 

structure for the Category 3 marine 

diesel engine market is competitive. As 

explained above, this assumption is 

reasonable even though there are few 

producers in this market. If, in fact, this 

market is noncompetitive and behaves 

more like an oligopoly, then the results 

of the analysis would be somewhat 

different. Specifically, oligopolistic 

producers can set the market price at a 

level higher than the competitive market 

price, capturing larger profits than 

would otherwise be the case. However, 

this price premium would already be 

reflected in the prices of Category 3 

marine diesel engines. What would 

change in the analysis is the magnitude 

of the compliance costs passed on to 

consumers of these engines (vessel 

builders and the transportation services 

market), which would be higher than 

the compliance costs. This effect is 

discussed in Chapter 7 of the RIA. 

VIII. Benefits 

This section presents our analysis of 

the health and environmental benefits 

that will occur as a result of EPA’s 

coordinated strategy to address 

emissions from Category 3 engines and 

ocean-going vessels throughout the 

period from initial implementation 

through 2030. We provide estimated 

benefits for the entire coordinated 

strategy, including the Annex VI Tier 2 

NOX requirements and the ECA controls 

that will be mandatory for U.S. and 

foreign vessels through the Act to 

Prevent Pollution from Ships. However, 

unlike the cost analysis, this benefits 

analysis does not allocate benefits 

between the components of the program 

(the requirements in this rule and the 

requirements that would apply through 

MARPOL Annex VI and ECA 

implementation). This is because the 

benefits of the coordinated strategy will 

be fully realized only when the U.S. 

ECA is in place and both U.S. and 

foreign vessel are required to use lower 

sulfur fuel and operate their Tier 3 NOX

controls while in the designated area, 

and therefore it makes more sense to 

consider the benefits of the coordinated 

strategy as a whole. 

The components of the coordinated 

strategy will apply stringent NOX and 

SOX standards to virtually all vessels 

that affect U.S. air quality, and impacts 

on human health and welfare will be 

substantial. As presented in Section II, 

the coordinated strategy is expected to 

provide very large reductions in direct 

PM, NOX, SOX, and toxic compounds, 

both in the near term and in the long 

term. Emissions of NOX (a precursor to 

ozone formation and secondarilyformed PM2.5), SOX (a precursor to 

secondarily-formed PM2.5) and directlyemitted PM2.5 contribute to ambient 

concentrations of PM2.5 and ozone. 

Exposure to ozone and PM2.5 is linked 

to adverse human health impacts such 

as premature deaths as well as other 

important public health and 

environmental effects. 

Using the most conservative 

premature mortality estimates (Pope et 

al., 2002 for PM2.5 and Bell et al., 2004 

for ozone),137 138 we estimate that 

implementation of the coordinated 

strategy will reduce approximately 

12,000 premature mortalities in 2030 

and yield approximately $110 billion in 

total benefits. The upper end of the 

premature mortality estimates (Laden et 

al., 2006 for PM2.5 and Levy et al., 2005 

for ozone) 139 140 increases avoided 


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bayes metaregression analysis. Epidemiology. 16(4), 

458–68. 

141U.S. Environmental Protection Agency (2006). 

Final Regulatory Impact Analysis (RIA) for the 

Proposed National Ambient Air Quality Standards 

for Particulate Matter. Prepared by: Office of Air 

and Radiation. Retrieved March 26, 2009 at http:// 

www.epa.gov/ttn/ecas/ria.html. 

142U.S. Environmental Protection Agency (2008). 

Final Ozone NAAQS Regulatory Impact Analysis. 

Prepared by: Office of Air and Radiation, Office of 

Air Quality Planning and Standards. Retrieved 

March 26, 2009 at http://www.epa.gov/ttn/ecas/ 

ria.html. 

143 Information on BenMAP, including 

downloads of the software, can be found at http:// 

www.epa.gov/ttn/ecas/benmodels.html. 

144Mrozek, J.R., and L.O. Taylor (2002). What 

Determines the Value of Life? A Meta-Analysis. 

Journal of Policy Analysis and Management 

21(2):253–270. 

145 Viscusi, V.K., and J.E. Aldy (2003). The Value 

of a Statistical Life: A Critical Review of Market 

Estimates Throughout the World. Journal of Risk 

and Uncertainty 27(1):5–76. 

146 In this analysis, we adjust the VSL to account 

for a different currency year (2006$) and to account 

for income growth to 2020 and 2030. After applying 

these adjustments to the $5.5 million value, the VSL 

is $7.7m in 2020 and $7.9 in 2030. 

147 Kochi, I., B. Hubbell, and R. Kramer 2006. An 

Empirical Bayes Approach to Combining Estimates 

of the Value of Statistical Life for Environmental 

Policy Analysis. Environmental and Resource 

Economics. 34: 385–406. 

148U.S. Environmental Protection Agency (U.S. 

EPA). 2007. SAB Advisory on EPA’s Issues in 

Valuing Mortality Risk Reduction. http:// 

yosemite.epa.gov/sab/sabproduct.nsf/ 

4128007E7876B8F0852573760058A978/$File/sab08-001.pdf. 

149 In the (draft) update of the Economic 

Guidelines, EPA retained the VSL endorsed by the 

SAB with the understanding that further updates to 

the mortality risk valuation guidance would be 

forthcoming in the near future. Therefore, this 

report does not represent final agency policy. The 

2000 guidelines can be downloaded here: http:// 

yosemite.epa.gov/ee/epa/eed.nsf/webpages/ 

Guidelines.html, and the draft updated version 

(2008) of the guidelines can be downloaded here: 

http://yosemite.epa.gov/ee/epa/eerm.nsf/ 

vwRepNumLookup/EE-0516?OpenDocument. 

150 In this analysis, we adjust the VSL to account 

for a different currency year (2006$) and to account 

for income growth to 2020 and 2030. After applying 

these adjustments to the $6.3 million value, the VSL 

is $8.9m in 2020 and $9.1m in 2030. 

premature mortalities to approximately 

31,000 in 2030 and yields 

approximately $270 billion in total 

benefits. Thus, even taking the most 

conservative premature mortality 

assumptions, the health impacts of the 

coordinated strategy presented in this 

rule are clearly substantial. 

A. Overview 

We base our analysis on peerreviewed studies of air quality and 

human health effects (see U.S. EPA, 

2006 and U.S. EPA, 2008).141 142 These 

methods are described in more detail in 

the RIA that accompanies this action. To 

model the ozone and PM air quality 

impacts of the CAA standards and 

requirements and the ECA designation, 

we used the Community Multiscale Air 

Quality (CMAQ) model (see Section II). 

The modeled ambient air quality data 

serves as an input to the Environmental 

Benefits Mapping and Analysis Program 

(BenMAP).143 BenMAP is a computer 

program developed by the U.S. EPA that 

integrates a number of the modeling 

elements used in previous analyses (e.g., 

interpolation functions, population 

projections, health impact functions, 

valuation functions, analysis and 

pooling methods) to translate modeled 

air concentration estimates into health 

effects incidence estimates and 

monetized benefits estimates. 

The range of total ozone- and PMrelated benefits associated with the 

coordinated strategy to control ship 

emissions is presented in Table VIII–1. 

We present total benefits based on the 

PM- and ozone-related premature 

mortality function used. The benefits 

ranges therefore reflect the addition of 

each estimate of ozone-related 

premature mortality (each with its own 

row in Table VIII–1) to estimates of PMrelated premature mortality. These 

estimates represent EPA’s preferred 

approach to characterizing the best 

estimate of benefits associated with the 

coordinated strategy. As is the nature of 

Regulatory Impact Analyses (RIAs), the 

assumptions and methods used to 

estimate air quality benefits evolve to 

reflect the Agency’s most current 

interpretation of the scientific and 

economic literature. This analysis, 

therefore, incorporates a number of 

important changes from recent RIAs 

released by the Office of Transportation 

and Air Quality (OTAQ): 

• The 2030 air quality modeling of 

the final coordinated strategy reflects air 

quality impacts associated with an ECA 

boundary distance of 200 nm with 

global controls (set through IMO) 

beyond the ECA boundary. For the 

proposal, however, the air quality 

modeling reflected impacts associated 

with an ECA boundary distance of 100 

nm with global controls beyond. To 

estimate the 2030 benefits associated 

with a 200 nm ECA boundary in the 

proposal, we transferred the 

relationship between modeled impacts 

between 100 nm and 200 nm ECA 

boundaries observed in 2020. For each 

health endpoint and associated 

valuation, we calculated a ratio based 

on the national-level estimate for the 

200 nm and 100 nm scenario and 

applied that to the related 2030 100 nm 

estimate. For the final RIA, we 

estimated benefits based on the actual 

2030 200 nm air quality modeling 

results. The net effect of this change 

results in a small decrease in 2030 

benefits compared to the proposal. 

• For a period of time (2004–2008), 

the Office of Air and Radiation (OAR) 

valued mortality risk reductions using a 

value of statistical life (VSL) estimate 

derived from a limited analysis of some 

of the available studies. OAR arrived at 

a VSL using a range of $1 million to $10 

million (2000$) consistent with two 

meta-analyses of the wage-risk 

literature. The $1 million value 

represented the lower end of the 

interquartile range from the Mrozek and 

Taylor (2002) 144 meta-analysis of 33 

studies and $10 million represented the 

upper end of the interquartile range 

from the Viscusi and Aldy (2003) 145

meta-analysis of 46 studies. The mean 

estimate of $5.5 million (2000$) 146 was 

also consistent with the mean VSL of 

$5.4 million estimated in the Kochi et 

al. (2006) 147 meta-analysis. However, 

the Agency neither changed its official 

guidance on the use of VSL in rulemakings nor subjected the interim 

estimate to a scientific peer-review 

process through the Science Advisory 

Board (SAB) or other peer-review group. 

During this time, the Agency 

continued work to update its guidance 

on valuing mortality risk reductions, 

including commissioning a report from 

meta-analytic experts to evaluate 

methodological questions raised by EPA 

and the SAB on combining estimates 

from the various data sources. In 

addition, the Agency consulted several 

times with the Science Advisory Board 

Environmental Economics Advisory 

Committee (SAB–EEAC) on the issue. 

With input from the meta-analytic 

experts, the SAB–EEAC advised the 

Agency to update its guidance using 

specific, appropriate meta-analytic 

techniques to combine estimates from 

unique data sources and different 

studies, including those using different 

methodologies (i.e., wage-risk and stated 

preference) (U.S. EPA–SAB, 2007).148

Until updated guidance is available, 

the Agency determined that a single, 

peer-reviewed estimate applied 

consistently best reflects the SAB–EEAC 

advice it has received. Therefore, the 

Agency has decided to apply the VSL 

that was vetted and endorsed by the 

SAB in the Guidelines for Preparing 

Economic Analyses (U.S. EPA, 2000) 

while the Agency continues its efforts to 

update its guidance on this issue.149

This approach calculates a mean value 

across VSL estimates derived from 26 

labor market and contingent valuation 

studies published between 1974 and 

1991. The mean VSL across these 

studies is $6.3 million (2000$).150

The Agency is committed to using 

scientifically sound, appropriately 


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151U.S. Environmental Protection Agency (U.S. 

EPA). Integrated Science Assessment for Particulate 

Matter (External Review Draft). National Center for 

Environmental Assessment, Research Triangle Park, 

NC. EPA/600/R–08/139. December. Available on 

the Internet at http://cfpub.epa.gov/ncea/cfm/

recordisplay.cfm?deid=201805. 

152U.S. Environmental Protection Agency (U.S. 

EPA). Integrated Science Assessment for Particulate 

Matter (Second External Review Draft). National 

Center for Environmental Assessment, Research 

Triangle Park, NC. EPA/600/R–08/139B. July. 

Available on the Internet at http://cfint.rtpnc.epa.

gov/ncea/prod/recordisplay.cfm?deid=210586. 

153U.S. Environmental Protection Agency— 

Science Advisory Board (U.S. EPA–SAB). Review of 

EPA’s Integrated Science Assessment for Particulate 

Matter (First External Review Draft, December 

2008). EPA–COUNCIL–09–008. May. Available on 

the Internet at http://yosemite.epa.gov/sab/

SABPRODUCT.NSF/81e39f4c09954fcb85256ead

006be86e/73ACCA834AB44A10852575BD

0064346B/$File/EPA-CASAC-09-008-unsigned.pdf. 

154U.S. Environmental Protection Agency— 

Science Advisory Board (U.S. EPA–SAB). 

Consultation on EPA’s Particulate Matter National 

Ambient Air Quality Standards: Scope and Methods 

Plan for Health Risk and Exposure Assessment. 

EPA–COUNCIL–09–009. May. Available on the 

Internet at http://yosemite.epa.gov/sab/

SABPRODUCT.NSF/81e39f4c09954fcb85256ead

006be86e/723FE644C5D758DF852575BD00763A32/

$File/EPA-CASAC-09-009-unsigned.pdf. 

155 It is important to note that uncertainty 

regarding the shape of the concentration-response 

function is conceptually distinct from an assumed 

threshold. An assumed threshold (below which 

there are no health effects) is a discontinuity, which 

is a specific example of non-linearity. 

156The final PM ISA, which will have undergone 

the full agency scientific review process, is 

scheduled to be completed in late December 2009. 

157 In the proposed Portland Cement RIA, EPA 

solicited comment on the use of the no-threshold 

model for benefits analysis within the preamble of 

that proposed rule. The comment period for the 

Portland Cement proposed NESHAP closed on 

September 4, 2009 (Docket ID No. EPA–HQ–OAR– 

2002–0051 available at http://www.regulations.gov). 

EPA is currently reviewing those comments. U.S. 

Environmental Protection Agency. (2009). 

Regulatory Impact Analysis: National Emission 

Standards for Hazardous Air Pollutants from the 

Portland Cement Manufacturing Industry. Office of 

Air and Radiation. Retrieved on May 4, 2009, from 

http://www.epa.gov/ttn/ecas/regdata/RIAs/ 

portlandcementria_4-20-09.pdf. 

158Roman, Henry A., Walker, Katherine D., 

Walsh, Tyra L., Conner, Lisa, Richmond, Harvey M., 

Hubbell, Bryan J., and Kinney, Patrick L.. (2008). 

Expert Judgment Assessment of the Mortality 

Impact of Changes in Ambient Fine Particulate 

Matter in the U.S. Environ. Sci. Technol., 42, 7, 

2268–2274. 

159Bell, M.L., et al. (2004). Ozone and short-term 

mortality in 95 U.S. urban communities, 1987– 

2000. Jama, 2004. 292(19): p. 2372–8. 

160Huang, Y.; Dominici, F.; Bell, M.L. (2005). 

Bayesian hierarchical distributed lag models for 

summer ozone exposure and cardio-respiratory 

mortality. Environmetrics 16: 547–562. 

161Schwartz, J. (2005). How sensitive is the 

association between ozone and daily deaths to 

control for temperature? Am. J. Respir. Crit. Care 

Med. 171: 627–631. 

162U.S. EPA (2007). Review of the National 

Ambient Air Quality Standards for Ozone, Policy 

Assessment of Scientific and Technical 

Information. OAQPS Staff Paper. EPA–452/R–07– 

003. This document is available in Docket EPA– 

HQ–OAR–2003–0190. Retrieved on April 10, 2009, 

from http:www.epa.gov/ttn/naaqs/standards/ozone/ 

s_o3_cr_sp.html. 

163CASAC (2007). Clean Air Scientific Advisory 

Committee’s (CASAC) Review of the Agency’s Final 

Ozone Staff Paper. EPA–CASAC–07–002. March 26. 

164Bell, M.L., F. Dominici, and J.M. Samet (2005). 

A meta-analysis of time-series studies of ozone and 

mortality with comparison to the national 

morbidity, mortality, and air pollution study. 

Epidemiology, 16(4): p. 436–45. 

165 Ito, K., S.F. De Leon, and M. Lippmann (2005). 

Associations between ozone and daily mortality: 

analysis and meta-analysis. Epidemiology. 16(4): p. 

446–57. 

166Levy, J.I., S.M. Chemerynski, and J.A. Sarnat 

(2005). Ozone exposure and mortality: an empiric 

bayes metaregression analysis. Epidemiology. 16(4): 

p. 458–68. 

167National Research Council (NRC), 2008. 

Estimating Mortality Risk Reduction and Economic 

Continued 

reviewed evidence in valuing mortality 

risk reductions and has made significant 

progress in responding to the SAB– 

EEAC’s specific recommendations. The 

Agency anticipates presenting results 

from this effort to the SAB–EEAC in 

Winter 2009/2010 and that draft 

guidance will be available shortly 

thereafter. 

• In recent analyses, OTAQ has 

estimated PM2.5-related benefits 

assuming that a threshold exists in the 

PM-related concentration-response 

functions (at 10 μg/m3) below which 

there are no associations between 

exposure to PM2.5 and health impacts. 

EPA strives to use the best available 

science to support our benefits analyses, 

and we recognize that interpretation of 

the science regarding air pollution and 

health is dynamic and evolving. Based 

on our review of the body of scientific 

literature, EPA applied the no-threshold 

model in this analysis. EPA’s draft 

Integrated Science Assessment,151 152

which was recently reviewed by EPA’s 

Clean Air Scientific Advisory 

Committee,153 154 concluded that the 

scientific literature consistently finds 

that a no-threshold log-linear model 

most adequately portrays the PMmortality concentration-response 

relationship while recognizing potential 

uncertainty about the exact shape of the 

concentration-response function.155

Although this document does not 

represent final agency policy that has 

undergone the full agency scientific 

review process, it provides a basis for 

reconsidering the application of 

thresholds in PM2.5 concentrationresponse functions used in EPA’s 

RIAs.156 It is important to note that 

while CASAC provides advice regarding 

the science associated with setting the 

National Ambient Air Quality 

Standards, typically other scientific 

advisory bodies provide specific advice 

regarding benefits analysis.157 Please see 

Section 6.4.1.3 of the RIA that 

accompanies this preamble for more 

discussion of the treatment of 

thresholds in this analysis. 

• For the coordinated strategy, we 

rely on two empirical (epidemiological) 

studies of the relationship between 

ambient PM2.5 and premature mortality 

(the extended analyses of the Harvard 

Six Cities study by Laden et al (2006) 

and the American Cancer Society (ACS) 

cohort by Pope et al (2002)) to anchor 

our benefits analysis, though we also 

present the PM2.5-related premature 

mortality benefits associated with the 

estimates supplied by the expert 

elicitation as a sensitivity analysis. This 

approach was recently adopted in the 

proposed Portland Cement MACT RIA. 

Since 2006, EPA has calculated benefits 

based on these two empirical studies 

and derived the range of benefits, 

including the minimum and maximum 

results, from an expert elicitation of the 

relationship between exposure to PM2.5

and premature mortality (Roman et al., 

2008).158 Using alternate relationships 

between PM2.5 and premature mortality 

supplied by experts, higher and lower 

benefits estimates are plausible, but 

most of the expert-based estimates have 

fallen between the two epidemiologybased estimates (Roman et al., 2008). 

Assuming no threshold in the 

empirically-derived premature mortality 

concentration response functions used 

in the analysis of the coordinated 

strategy, only one expert falls below the 

empirically-derived range while two of 

the experts are above this range (see 

Tables 6–5 and 6–6 in the RIA that 

accompanies this preamble). Please refer 

to the proposed Portland Cement MACT 

RIA for more information about the 

preferred approach and the evolution of 

the treatment of threshold assumptions 

within EPA’s regulatory analyses. 

• The range of ozone benefits 

associated with the coordinated strategy 

is estimated based on risk reductions 

derived from several sources of ozonerelated mortality effect estimates. This 

analysis presents six alternative 

estimates for the association based upon 

different functions reported in the 

scientific literature. We use three multicity studies,159 160 161 including the Bell, 

2004 National Morbidity, Mortality, and 

Air Pollution Study (NMMAPS) that 

was used as the primary basis for the 

risk analysis in the ozone Staff Paper 162

and reviewed by the Clean Air Science 

Advisory Committee (CASAC).163 We 

also use three studies that synthesize 

ozone mortality data across a large 

number of individual studies.164 165 166

This approach is consistent with 

recommendations provided by the NRC 

in their ozone mortality report (NRC, 

2008),167 ‘‘The committee recommends 


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Benefits from Controlling Ozone Air Pollution. The 

National Academies Press: Washington, DC. 

that the greatest emphasis be placed on 

estimates from new systematic multicity 

analyses that use national databases of 

air pollution and mortality, such as in 

the NMMAPS, without excluding 

consideration of meta-analyses of 

previously published studies.’’ The NRC 

goes on to note that there are 

uncertainties within each study that are 

not fully captured by this range of 

estimates. 

TABLE VIII–1—ESTIMATED 2030 MONETIZED PM- AND OZONE-RELATED HEALTH BENEFITS OF A COORDINATED U.S. 

STRATEGY TO CONTROL SHIP EMISSIONS a

2030 Total Ozone and PM Benefits—PM Mortality Derived from American Cancer Society Analysis and Six-Cities Analysis a

Premature ozone mortality function Reference 

Total benefits 

(billions, 2006$, 

3% discount 

rate) c d

Total benefits 

(billions, 2006$, 

7% discount 

rate) c d

Multi-city analyses .................................................... Bell et al., 2004 ........................................................ 110–260 99–240 

Huang et al., 2005 .................................................... 110–260 100–240 

Schwartz, 2005 ......................................................... 110–260 100–240 

Meta-analyses .......................................................... Bell et al., 2005 ........................................................ 110–260 100–240 

Ito et al., 2005 .......................................................... 110–270 110–240 

Levy et al., 2005 ....................................................... 110–270 110–240 

Notes: 

a Total includes premature mortality-related and morbidity-related ozone and PM2.5 benefits. Range was developed by adding the estimate 

from the ozone premature mortality function to the estimate of PM2.5-related premature mortality derived from either the ACS study (Pope et al., 

2002) or the Six-Cities study (Laden et al., 2006). b Note that total benefits presented here do not include a number of unquantified benefits categories. A detailed listing of unquantified health 

and welfare effects is provided in Table VIII–2. c Results reflect the use of both a 3 and 7 percent discount rate, as recommended by EPA’s Guidelines for Preparing Economic Analyses and 

OMB Circular A–4. Results are rounded to two significant digits for ease of presentation and computation. 

The benefits in Table VIII–1 include 

all of the human health impacts we are 

able to quantify and monetize at this 

time. However, the full complement of 

human health and welfare effects 

associated with PM and ozone remain 

unquantified because of current 

limitations in methods or available data. 

We have not quantified a number of 

known or suspected health effects 

linked with ozone and PM for which 

appropriate health impact functions are 

not available or which do not provide 

easily interpretable outcomes (i.e., 

changes in heart rate variability). 

Additionally, we are unable to quantify 

a number of known welfare effects, 

including reduced acid and particulate 

deposition damage to cultural 

monuments and other materials, and 

environmental benefits due to 

reductions of impacts of eutrophication 

in coastal areas. These are listed in 

Table VIII–2. As a result, the health 

benefits quantified in this section are 

likely underestimates of the total 

benefits attributable to the 

implementation of the coordinated 

strategy to control ship emissions. 

TABLE VIII–2—UNQUANTIFIED AND NON-MONETIZED POTENTIAL EFFECTS OF A COORDINATED U.S. STRATEGY TO

CONTROL SHIP EMISSIONS

Pollutant/effects Effects not included in analysis—Changes in 

Ozone Health a ...................................................................................... Chronic respiratory damage.b

Premature aging of the lungs.b

Non-asthma respiratory emergency room visits. 

Exposure to UVb (+/¥).e

Ozone Welfare ...................................................................................... Yields for 

— commercial forests. 

— some fruits and vegetables. 

— non-commercial crops. 

Damage to urban ornamental plants. 

Impacts on recreational demand from damaged forest aesthetics. 

Ecosystem functions. 

Exposure to UVb (+/¥).e

PM Health c ........................................................................................... Premature mortality—short term exposures.d

Low birth weight. 

Pulmonary function. 

Chronic respiratory diseases other than chronic bronchitis. 

Non-asthma respiratory emergency room visits. 

Exposure to UVb (+/¥).e

PM Welfare ........................................................................................... Residential and recreational visibility in non-Class I areas. 

Soiling and materials damage. 

Damage to ecosystem functions. 

Exposure to UVb (+/¥).e

Nitrogen and Sulfate Deposition Welfare ............................................. Commercial forests due to acidic sulfate and nitrate deposition. 

Commercial freshwater fishing due to acidic deposition. 

Recreation in terrestrial ecosystems due to acidic deposition. 


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TABLE VIII–2—UNQUANTIFIED AND NON-MONETIZED POTENTIAL EFFECTS OF A COORDINATED U.S. STRATEGY TO

CONTROL SHIP EMISSIONS—Continued 

Pollutant/effects Effects not included in analysis—Changes in 

Existence values for currently healthy ecosystems. 

Commercial fishing, agriculture, and forests due to nitrogen. deposition. 

Recreation in estuarine ecosystems due to nitrogen. deposition. 

Ecosystem functions. 

Passive fertilization. 

CO Health ............................................................................................. Behavioral effects. 

HC/Toxics Health f ................................................................................. Cancer (benzene, 1,3-butadiene, formaldehyde, acetaldehyde). 

Anemia (benzene). 

Disruption of production of blood components (benzene). 

Reduction in the number of blood platelets (benzene). 

Excessive bone marrow formation (benzene). 

Depression of lymphocyte counts (benzene). 

Reproductive and developmental effects (1,3-butadiene). 

Irritation of eyes and mucus membranes (formaldehyde). 

Respiratory irritation (formaldehyde). 

Asthma attacks in asthmatics (formaldehyde). 

Asthma-like symptoms in non-asthmatics (formaldehyde). 

Irritation of the eyes, skin, and respiratory tract (acetaldehyde). 

Upper respiratory tract irritation and congestion (acrolein). 

HC/Toxics Welfare ................................................................................ Direct toxic effects to animals. 

Bioaccumulation in the food chain. 

Damage to ecosystem function. 

Odor. 

Notes: 

aThe public health impact of biological responses such as increased airway responsiveness to stimuli, inflammation in the lung, acute inflammation and respiratory cell damage, and increased susceptibility to respiratory infection are likely partially represented by our quantified 

endpoints. bThe public health impact of effects such as chronic respiratory damage and premature aging of the lungs may be partially represented by 

quantified endpoints such as hospital admissions or premature mortality, but a number of other related health impacts, such as doctor visits and 

decreased athletic performance, remain unquantified. c In addition to primary economic endpoints, there are a number of biological responses that have been associated with PM health effects including morphological changes and altered host defense mechanisms. The public health impact of these biological responses may be partly represented by our quantified endpoints. dWhile some of the effects of short-term exposures are likely to be captured in the estimates, there may be premature mortality due to shortterm exposure to PM not captured in the cohort studies used in this analysis. However, the PM mortality results derived from the expert 

elicitation do take into account premature mortality effects of short term exposures. e May result in benefits or disbenefits. 

f Many of the key hydrocarbons related to this rule are also hazardous air pollutants listed in the CAA. 

B. Quantified Human Health Impacts 

Tables VIII–3 and VIII–4 present the 

annual PM2.5 and ozone health impacts 

in the 48 contiguous U.S. States 

associated with the coordinated strategy 

for both 2020 and 2030. For each 

endpoint presented in Tables VIII–3 and 

VIII–4, we provide both the mean 

estimate and the 90% confidence 

interval. 

Using EPA’s preferred estimates, 

based on the ACS and Six-Cities studies 

and no threshold assumption in the 

model of mortality, we estimate that the 

coordinated strategy will result in 

between 5,300 and 14,000 cases of 

avoided PM2.5-related premature deaths 

annually in 2020 and between 12,000 

and 30,000 avoided premature deaths 

annually in 2030. As a sensitivity 

analysis, when the range of expert 

opinion is used, we estimate between 

1,900 and 18,000 fewer premature 

mortalities in 2020 and between 4,300 

and 40,000 fewer premature mortalities 

in 2030 (see Tables 6–5 and 6–6 in the 

RIA that accompanies this rule). 

For ozone-related premature 

mortality, we estimate a range of 

between 61 to 280 fewer premature 

mortalities as a result of the coordinated 

strategy in 2020 and between 210 to 920 

in 2030. The increase in annual benefits 

from 2020 to 2030 reflects additional 

emission reductions from coordinated 

strategy, as well as increases in total 

population and the average age (and 

thus baseline mortality risk) of the 

population. 

TABLE VIII–3—ESTIMATED PM2.5-RELATED HEALTH IMPACTS ASSOCIATED WITH A COORDINATED U.S. STRATEGY TO

CONTROL SHIP EMISSIONS a

Health effect 

2020 Annual reduction in 

ship-related 

incidence 

(5th–95th percentile) 

2030 Annual reduction in 

ship-related 

incidence 

(5th–95th percentile) 

Premature Mortality—Derived from epidemiology literature b

Adult, age 30+, ACS Cohort Study (Pope et al., 2002) ............................................ 5,300 .................................

(2,100–8,500) ...................

12,000 

(4,700–19,000) 

Adult, age 25+, Six-Cities Study (Laden et al., 2006) ............................................... 14,000 ...............................

(7,400–20,000) .................

30,000 

(17,000–44,000) 


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TABLE VIII–3—ESTIMATED PM2.5-RELATED HEALTH IMPACTS ASSOCIATED WITH A COORDINATED U.S. STRATEGY TO

CONTROL SHIP EMISSIONS a—Continued 

Health effect 

2020 Annual reduction in 

ship-related 

incidence 

(5th–95th percentile) 

2030 Annual reduction in 

ship-related 

incidence 

(5th–95th percentile) 

Infant, age <1 year (Woodruff et al., 1997) ............................................................... 20 ......................................

(0–55) ...............................

34 

(0–93) 

Chronic bronchitis (adult, age 26 and over) ..................................................................... 3,800 .................................

(700–6,900) ......................

8,100 

(1,500–14,000) 

Non-fatal myocardial infarction (adult, age 18 and over) ................................................. 8,800 .................................

(3,200–14,000) .................

20,000 

(7,600–33,000) 

Hospital admissions—respiratory (all ages) c .................................................................... 1,200 .................................

(590–1,800) ......................

2,700 

(1,300–4,000) 

Hospital admissions—cardiovascular (adults, age >18) d ................................................. 2,700 .................................

(2,000–3,200) ...................

6,600 

(4,700–7,700) 

Emergency room visits for asthma (age 18 years and younger) ..................................... 3,500 .................................

(2,000–4,900) ...................

7,300 

(4,300–10,000) 

Acute bronchitis (children, age 8–12) ............................................................................... 8,500 .................................

(0–17,000) ........................

17,000 

(0–35,000) 

Lower respiratory symptoms (children, age 7–14) ........................................................... 100,000 .............................

(49,000–150,000) .............

210,000 

(100,000–310,000) 

Upper respiratory symptoms (asthmatic children, age 9–18) ........................................... 77,000 ...............................

(24,000–130,000) .............

160,000 

(50,000–270,000) 

Asthma exacerbation (asthmatic children, age 6–18) ...................................................... 95,000 ...............................

(10,000–260,000) .............

200,000 

(22,000–550,000) 

Work loss days .................................................................................................................. 720,000 .............................

(630,000–810,000) ...........

1,400,000 

(1,300,000–1,600,000) 

Minor restricted activity days (adults, age 18–65) ............................................................ 4,300,000 ..........................

(3,600,000–4,900,000) .....

8,500,000 

(7,200,000–9,800,000) 

Notes: 

a Incidence is rounded to two significant digits. Estimates represent incidence within the 48 contiguous United States. 

bPM-related adult mortality based upon the American Cancer Society (ACS) Cohort Study (Pope et al., 2002) and the Six-Cities Study (Laden 

et al., 2006). Note that these are two alternative estimates of adult mortality and should not be summed. PM-related infant mortality based upon 

a study by Woodruff, Grillo, and Schoendorf, (1997). [Woodruff, T.J., J. Grillo, and K.C. Schoendorf. 1997. ‘‘The Relationship Between Selected 

Causes of Postneonatal Infant Mortality and Particulate Air Pollution in the United States.’’ Environmental Health Perspectives 105(6):608–612.] c Respiratory hospital admissions for PM include admissions for chronic obstructive pulmonary disease (COPD), pneumonia and asthma. d Cardiovascular hospital admissions for PM include total cardiovascular and subcategories for ischemic heart disease, dysrhythmias, and 

heart failure. 

TABLE VIII–4—ESTIMATED OZONE-RELATED HEALTH IMPACTS ASSOCIATED WITH A COORDINATED U.S. STRATEGY TO

CONTROL SHIP EMISSIONS a

Health effect 

2020 Annual reduction in 

ship-related 

incidence 

(5th–95th percentile) 

2030 Annual reduction in 

ship-related 

incidence 

(5th–95th percentile) 

Premature Mortality, All ages b

Multi-City Analyses 

Bell et al. (2004)—Non-accidental ............................................................................. 61 ......................................

(23–98) .............................

210 

(70–340) 

Huang et al. (2005)—Cardiopulmonary ..................................................................... 100 ....................................

(43–160) ...........................

350 

(130–570) 

Schwartz (2005)—Non-accidental ............................................................................. 93 ......................................

(34–150) ...........................

320 

(100–530) 

Meta-analyses: 

Bell et al. (2005)—All cause ...................................................................................... 200 ....................................

(100–290) .........................

660 

(320–1,000) 

Ito et al. (2005)—Non-accidental ............................................................................... 270 ....................................

(170–370) .........................

920 

(560–1,300) 

Levy et al. (2005)—All cause ..................................................................................... 280 ....................................

(200–360) .........................

920 

(640–1,200) 

Hospital admissions—respiratory causes (adult, 65 and older) c ..................................... 470 ....................................

(46–830) ...........................

1,900 

(120–3,300) 

Hospital admissions—respiratory causes (children, under 2) .......................................... 380 ....................................

(180–590) .........................

1,200 

(490–1,900) 

Emergency room visit for asthma (all ages) ..................................................................... 210 ....................................

(0–550) .............................

690 

(0–1,800) 

Minor restricted activity days (adults, age 18–65) ............................................................ 360,000 .............................

(160,000–570,000) ...........

1,100,000 

(430,000–1,700,000) 


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TABLE VIII–4—ESTIMATED OZONE-RELATED HEALTH IMPACTS ASSOCIATED WITH A COORDINATED U.S. STRATEGY TO

CONTROL SHIP EMISSIONS a—Continued 

Health effect 

2020 Annual reduction in 

ship-related 

incidence 

(5th–95th percentile) 

2030 Annual reduction in 

ship-related 

incidence 

(5th–95th percentile) 

School absence days ........................................................................................................ 130,000 .............................

(51,000–190,000) .............

420,000 

(150,000–630,000) 

Notes: 

a Incidence is rounded to two significant digits. Estimates represent incidence within the 48 contiguous U.S. 

bEstimates of ozone-related premature mortality are based upon incidence estimates derived from several alternative studies: Bell et al. 

(2004); Huang et al. (2005); Schwartz (2005); Bell et al. (2005); Ito et al. (2005); Levy et al. (2005). The estimates of ozone-related premature 

mortality should therefore not be summed. c Respiratory hospital admissions for ozone include admissions for all respiratory causes and subcategories for COPD and pneumonia. 

C. Monetized Benefits 

Table VIII–5 presents the estimated 

monetary value of reductions in the 

incidence of ozone and PM2.5-related 

health effects. All monetized estimates 

are stated in 2006$. These estimates 

account for growth in real gross 

domestic product (GDP) per capita 

between the present and the years 2020 

and 2030. As the tables indicate, total 

benefits are driven primarily by the 

reduction in premature fatalities each 

year. 

Our estimate of total monetized 

benefits in 2020 for the coordinated 

strategy, using the ACS and Six-Cities 

PM mortality studies and the range of 

ozone mortality assumptions, is 

between $47 billion and $110 billion, 

assuming a 3 percent discount rate, or 

between $42 billion and $100 billion, 

assuming a 7 percent discount rate. In 

2030, we estimate the monetized 

benefits to be between $110 billion and 

$270 billion, assuming a 3 percent 

discount rate, or between $99 billion 

and $240 billion, assuming a 7 percent 

discount rate. The monetized benefit 

associated with reductions in the risk of 

both ozone- and PM2.5-related 

premature mortality ranges between 90 

to 98 percent of total monetized health 

benefits, in part because we are unable 

to quantify a number of benefits 

categories (see Table VIII–2). These 

unquantified benefits may be 

substantial, although their magnitude is 

highly uncertain. 

TABLE VIII–5—ESTIMATED MONETARY VALUE IN REDUCTIONS IN INCIDENCE OF HEALTH AND WELFARE EFFECTS

[in millions of 2006$] a b

2020 2030 

PM2.5-related health effect Estimated mean value of reductions 

(5th and 95th percentile) 

Premature Mortality—Derived from 

Epidemiology Studies c d.

Adult, age 30+ —ACS study (Pope 

et al., 2002).

3% discount rate ............................ $43,000 ($5,000¥$110,000) ...... $99,000 ($12,000¥$260,000) 

7% discount rate ............................ $38,000 ($4,500¥$100,000) ...... $89,000 ($11,000¥$230,000) 

Adult, age 25+ —six-cities study 

(Laden et al., 2006).

3% discount rate ............................ $110,000 ($14,000¥$270,000) .. $250,000 ($33,000¥$630,000) 

7% discount rate ............................ $98,000 ($13,000¥$250,000) .... $230,000 ($30,000¥$570,000) 

Infant mortality, <1 year—(Woodruff et al. 1997).$180 ($0¥$670) ......................... $310 ($0¥$1,200) 

Chronic bronchitis (adults, 26 and over) $1,900 ($140¥$6,500) ............... $4,100 ($320¥$14,000) 

Non-fatal acute myocardial infarctions 

3% discount rate ................................................................................... $960 ($170¥$2,300) .................. $2,700 ($460¥$6,700) 

7% discount rate ................................................................................... $930 ($160¥$2,300) .................. $2,600 ($430¥$6,600) 

Hospital admissions for respiratory causes ................................................. $17 ($8.4¥$25) .......................... $39 ($19¥$57) 

Hospital admissions for cardiovascular causes .......................................... $76 ($48¥$110) ......................... $180 ($120¥$250) 

Emergency room visits for asthma .............................................................. $1.3 ($0.70¥$1.9) ...................... $2.7 ($1.5¥$4.1) 

Acute bronchitis (children, age 8–12) .......................................................... $0.63 ($0¥$1.6) ......................... $1.3 ($0¥$3.2) 

Lower respiratory symptoms (children, 7–14) ............................................. $2.0 ($0.75¥$3.7) ...................... $4.1 ($1.6¥$7.6) 

Upper respiratory symptoms (asthma, 9–11) .............................................. $2.4 ($0.65¥$5.3) ...................... $5.0 ($1.4¥$11) 

Asthma exacerbations ................................................................................. $5.1 ($0.51¥$15) ....................... $11 ($1.1¥$32) 

Work loss days ............................................................................................ $110 ($94¥$120) ....................... $220 ($190¥$250) 

Minor restricted-activity days (MRADs) ....................................................... $270 ($150¥$390) ..................... $540 ($310¥$780) 

Ozone-related Health Effect 

Premature mortality, all ages—derived from multi-city analyses.Bell et al., 2004 .............................. $540 ($63¥$1,400) .................... $1,800 ($210¥$4,900) 

Huang et al., 2005 .......................... $910 ($110¥$2,300) .................. $3,100 ($360¥$8,200) 

Schwartz, 2005 ............................... $830 ($94¥$2,200) .................... $2,800 ($310¥$7,600) 


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168National Research Council (NRC). 2008. 

Estimating Mortality Risk Reduction and Economic 

Benefits from Controlling Ozone Air Pollution. The 

National Academies Press: Washington, DC. 

TABLE VIII–5—ESTIMATED MONETARY VALUE IN REDUCTIONS IN INCIDENCE OF HEALTH AND WELFARE EFFECTS— 

Continued 

[in millions of 2006$] a b

2020 2030 

Premature mortality, all ages—derived from meta-analyses.Bell et al., 2005 .............................. $1,700 ($220¥$4,400) ............... $5,800 ($740¥$15,000) 

Ito et al., 2005 ................................ $2,400 ($330¥$5,900) ............... $8,200 ($1,100¥$20,000) 

Levy et al., 2005 ............................. $2,400 ($340¥$5,900) ............... $8,200 ($1,100¥$20,000) 

Hospital admissions—respiratory causes (adult, 65 and older) .................. $11 ($1.1¥$20) .......................... $45 ($2.8¥$79) 

Hospital admissions—respiratory causes (children, under 2) ..................... $3.8 ($1.8¥$5.9) ........................ $12 ($4.9¥$19) 

Emergency room visit for asthma (all ages) ............................................... $0.08 ($0.03¥$0.20) .................. $0.25 ($0¥$0.63) 

Minor restricted activity days (adults, age 18–65) ...................................... $23 ($9.8¥$41) .......................... $69 ($25¥$120) 

School absence days .................................................................................. $12 ($4.6¥$17) .......................... $37 ($13¥$57) 

Notes: 

a Monetary benefits are rounded to two significant digits for ease of presentation and computation. PM and ozone benefits are nationwide. b Monetary benefits adjusted to account for growth in real GDP per capita between 1990 and the analysis year (2020 or 2030). 

cValuation assumes discounting over the SAB recommended 20-year segmented lag structure. Results reflect the use of 3 percent and 7 percent discount rates consistent with EPA and OMB guidelines for preparing economic analyses. 

D. What Are the Limitations of the 

Benefits Analysis? 

Every benefit-cost analysis examining 

the potential effects of a change in 

environmental protection requirements 

is limited to some extent by data gaps, 

limitations in model capabilities (such 

as geographic coverage), and 

uncertainties in the underlying 

scientific and economic studies used to 

configure the benefit and cost models. 

Limitations of the scientific literature 

often result in the inability to estimate 

quantitative changes in health and 

environmental effects, such as potential 

increases in premature mortality 

associated with increased exposure to 

carbon monoxide. Deficiencies in the 

economics literature often result in the 

inability to assign economic values even 

to those health and environmental 

outcomes which can be quantified. 

These general uncertainties in the 

underlying scientific and economics 

literature, which can lead to valuations 

that are higher or lower, are discussed 

in detail in the RIA and its supporting 

references. Key uncertainties that have a 

bearing on the results of the benefit-cost 

analysis of the coordinated strategy 

include the following: 

• The exclusion of potentially 

significant and unquantified benefit 

categories (such as health, odor, and 

ecological benefits of reduction in air 

toxics, ozone, and PM); 

• Errors in measurement and 

projection for variables such as 

population growth; 

• Uncertainties in the estimation of 

future year emissions inventories and 

air quality; 

• Uncertainty in the estimated 

relationships of health and welfare 

effects to changes in pollutant 

concentrations including the shape of 

the C–R function, the size of the effect 

estimates, and the relative toxicity of the 

many components of the PM mixture; 

• Uncertainties in exposure 

estimation; and 

• Uncertainties associated with the 

effect of potential future actions to limit 

emissions. 

As Table VIII–5 indicates, total 

benefits are driven primarily by the 

reduction in premature mortalities each 

year. Some key assumptions underlying 

the premature mortality estimates 

include the following, which may also 

contribute to uncertainty: 

• Inhalation of fine particles is 

causally associated with premature 

death at concentrations near those 

experienced by most Americans on a 

daily basis. Although biological 

mechanisms for this effect have not yet 

been completely established, the weight 

of the available epidemiological, 

toxicological, and experimental 

evidence supports an assumption of 

causality. The impacts of including a 

probabilistic representation of causality 

were explored in the expert elicitationbased results of the PM NAAQS RIA. 

• All fine particles, regardless of their 

chemical composition, are equally 

potent in causing premature mortality. 

This is an important assumption, 

because PM produced via transported 

precursors emitted from marine engines 

may differ significantly from PM 

precursors released from electric 

generating units and other industrial 

sources. However, no clear scientific 

grounds exist for supporting differential 

effects estimates by particle type. 

• The C–R function for fine particles 

is approximately linear within the range 

of ambient concentrations under 

consideration. Thus, the estimates 

include health benefits from reducing 

fine particles in areas with varied 

concentrations of PM, including both 

regions that may be in attainment with 

PM2.5 standards and those that are at 

risk of not meeting the standards. 

• There is uncertainty in the 

magnitude of the association between 

ozone and premature mortality. The 

range of ozone benefits associated with 

the coordinated strategy is estimated 

based on the risk of several sources of 

ozone-related mortality effect estimates. 

In a recent report on the estimation of 

ozone-related premature mortality 

published by the National Research 

Council, a panel of experts and 

reviewers concluded that short-term 

exposure to ambient ozone is likely to 

contribute to premature deaths and that 

ozone-related mortality should be 

included in estimates of the health 

benefits of reducing ozone exposure.168

EPA has requested advice from the 

National Academy of Sciences on how 

best to quantify uncertainty in the 

relationship between ozone exposure 

and premature mortality in the context 

of quantifying benefits. 

Emissions and air quality modeling 

decisions are made early in the 

analytical process. For this reason, the 

emission control scenarios used in the 

air quality and benefits modeling are 

slightly different than the coordinated 

strategy. The discrepancies impact the 

benefits analysis in two ways: 

• The air quality modeling used for 

the 2020 scenario is based on inventory 

estimates that were modeled using 

incorrect boundary information. We 

believe the impact of this difference, 

while modest, likely leads to a small 

underestimate of the benefits that are 

presented in this section. The correct 

boundary information was used for the 


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169National Research Council (NRC). 2002. 

Estimating the Public Health Benefits of Proposed 

Air Pollution Regulations. The National Academies 

Press: Washington, DC. 

170U.S. Environmental Protection Agency. 

October 2006. Final Regulatory Impact Analysis 

(RIA) for the Proposed National Ambient Air 

Quality Standards for Particulate Matter. Prepared 

by: Office of Air and Radiation. Available at http:// 

www.epa.gov/ttn/ecas/ria.html. 

2030 scenario. Please refer to the 

Chapter 3 of the RIA for more 

information on the emissions excluded 

from the health impacts analysis. 

• The 2020 air quality modeling 

scenarios do not include emission 

reductions associated with the 

implementation of global controls (set 

through IMO) beyond the assumed ECA 

boundary of 200 nautical miles (nm). 

Again, while we expect the impact of 

this difference is modest, the omission 

of these additional emission reductions 

likely leads to a small underestimate of 

the 2020 benefits presented in this 

section. The 2030 air quality modeling 

scenario did include emission 

reductions associated with global 

controls beyond the assumed ECA 

boundary of 200 nm. 

Despite the uncertainties described 

above, we believe this analysis provides 

a conservative estimate of the estimated 

economic benefits of the standards in 

future years because of the exclusion of 

potentially significant benefit categories 

that are not quantifiable at this time. 

Acknowledging benefits omissions and 

uncertainties, we present a best estimate 

of the total benefits based on our 

interpretation of the best available 

scientific literature and methods 

supported by EPA’s technical peer 

review panel, the Science Advisory 

Board’s Health Effects Subcommittee 

(SAB–HES). The National Academies of 

Science (NRC, 2002) has also reviewed 

EPA’s methodology for analyzing the 

health benefits of measures taken to 

reduce air pollution. EPA addressed 

many of these comments in the analysis 

of the final PM NAAQS.169 170 This 

analysis incorporates this most recent 

work to the extent possible. 

E. Comparison of Costs and Benefits 

This section presents the cost-benefit 

comparison related to the expected 

impacts of our coordinated strategy for 

ocean-going vessels. In estimating the 

net benefits of the coordinated strategy, 

the appropriate cost measure is ‘social 

costs.’ Social costs represent the welfare 

costs of a rule to society and do not 

consider transfer payments (such as 

taxes) that are simply redistributions of 

wealth. For this analysis, we estimate 

that the social costs of the coordinated 

program are equivalent to the estimated 

compliance costs of the program. While 

vessel owners and operators will see 

their costs increase by the amount of 

those compliance costs, they are 

expected to pass them on in their 

entirety to consumers of marine 

transportation services in the form of 

increased freight rates. Ultimately, these 

costs will be borne by the final 

consumers of goods transported by 

ocean-going vessels in the form of 

higher prices for those goods. The social 

benefits of the coordinated strategy are 

represented by the monetized value of 

health and welfare improvements 

experienced by the U.S. population. 

Table VIII–6 contains the estimated 

social costs and the estimated 

monetized benefits of the coordinated 

strategy. 

The results in Table VIII–6 suggest 

that the 2020 monetized benefits of the 

coordinated strategy are greater than the 

expected costs. Specifically, the annual 

benefits of the total program will range 

between $47 to $110 billion annually in 

2020 using a three percent discount rate, 

or between $42 to $100 billion assuming 

a 7 percent discount rate, compared to 

estimated social costs of approximately 

$1.9 billion in that same year. These 

benefits are expected to increase to 

between $110 and $270 billion annually 

in 2030 using a three percent discount 

rate, or between $99 and $240 billion 

assuming a 7 percent discount rate, 

while the social costs are estimated to 

be approximately $3.1 billion. Though 

there are a number of health and 

environmental effects associated with 

the coordinated strategy that we are 

unable to quantify or monetize (see 

Table VIII–2), the benefits of the 

coordinated strategy far outweigh the 

projected costs. 

Using a conservative benefits 

estimate, the 2020 benefits outweigh the 

costs by a factor of 22. Using the upper 

end of the benefits range, the benefits 

could outweigh the costs by a factor of 

58. Likewise, in 2030 benefits outweigh 

the costs by at least a factor of 32 and 

could be as much as a factor of 87. Thus, 

even taking the most conservative 

benefits assumptions, benefits of the 

coordinated strategy clearly outweigh 

the costs. 

TABLE VIII–6—SUMMARY OF ANNUAL BENEFITS AND COSTS ASSOCIATED WITH A COORDINATED U.S. STRATEGY TO

CONTROL SHIP EMISSIONS a

[Millions of 2006 dollars] 

Description 2020 2030 

Total Estimated Costs b ............................................................................................................ $1,900 ........................... $3,100. 

Total Estimated Health Benefits: cdef

3-percent discount rate ..................................................................................................... $47,000 to $110,000 ..... $110,000 to $270,000. 

7-percent discount rate ..................................................................................................... $42,000 to $100,000 ..... $99,000 to $240,000. 

Annual Net Benefits (Total Benefits—Total Costs): 

3-percent discount rate ..................................................................................................... $45,000 to $110,000 ..... $110,000 to $270,000. 

7-percent discount rate ..................................................................................................... $40,000 to $98,000 ....... $96,000 to $240,000. 

Notes: 

aAll estimates represent annual benefits and costs anticipated for the years 2020 and 2030. Totals are rounded to two significant digits and 

may not sum due to rounding. bThe calculation of annual costs does not require amortization of costs over time. Therefore, the estimates of annual cost do not include a discount rate or rate of return assumption (see Chapter 7 of the RIA). In Chapter 7, however, we use both a 3-percent and 7-percent social discount rate to calculate the net present value of total social costs consistent with EPA and OMB guidelines for preparing economic analyses. cTotal includes ozone and PM2.5 benefits. Range was developed by adding the estimate from the Bell et al., 2005 ozone premature mortality 

function to PM2.5-related premature mortality derived from the ACS (Pope et al., 2002) and Six-Cities (Laden et al., 2006) studies. dAnnual benefits analysis results reflect the use of a 3-percent and 7-percent discount rate in the valuation of premature mortality and nonfatal 

myocardial infarctions, consistent with EPA and OMB guidelines for preparing economic analyses. eValuation of premature mortality based on long-term PM exposure assumes discounting over the SAB recommended 20-year segmented lag 

structure described in the Regulatory Impact Analysis for the Final Clean Air Interstate Rule (March 2005). f Not all possible benefits or disbenefits are quantified and monetized in this analysis. Potential benefit categories that have not been quantified 

and monetized are listed in Table VIII–2. 


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IX. Public Participation 

Two public hearings were held to 

provide interested parties the 

opportunity to present data, views, or 

arguments concerning the proposed 

rule; the first hearing was held in New 

York, NY on August 4, 2009, and the 

second in Long Beach, CA on August 6, 

2009. The public was invited to submit 

written comments on the proposed rule 

during the formal comment period, 

which ended on September 28, 2009. 

EPA received 126 comments, and a 

detailed summary and response to these 

comments can be found in the Summary 

and Analysis of Comments document in 

the docket (Docket ID EPA–HQ–OAR– 

2007–0121). 

EPA received a number of comments 

on the value that a voluntary 

verification program would provide as 

well as comments on how best to 

implement such a program. The 

proposed program is discussed in 

Chapter 9 of the RIA. EPA is still 

reviewing these comments and is not 

taking any action today with regard to 

such a program. We will continue to 

evaluate the potential for such a 

program and will work in an open 

process with stakeholders should we 

conclude that such a program is 

appropriate. 

EPA also received a number of 

comments on the technical challenges of 

operating steamships on lower sulfur 

fuel. In response, we are not taking final 

action today to apply the ECA fuel 

sulfur requirements to Great Lakes 

steamships in service prior to January 1, 

2009. We will continue to study these 

technical issues and address these 

vessels in a future action, if appropriate. 

This rule includes several technical 

amendments unrelated to Category 3 

marine diesel engines. Two of these 

have generated a significant degree of 

interest from commenters. First, we 

raised for discussion a variety of 

temporary changes to the bonding 

requirements for nonroad spark-ignition 

engines below 19 kW (Small SI engines) 

based on feedback received by 

manufacturers and surety agents. We 

learned over the last several months that 

manufacturers have been struggling to 

obtain a bond for 2010, as required 

under § 1054.690. It seemed that the 

bond values specified in the regulation 

were in some cases preventing surety 

agents and manufacturers from reaching 

agreeable terms. While we were 

considering these changes, we learned 

that one manufacturer in the United 

States and nine manufacturers from 

China were able to establish a bond 

policy. We expect to continue to 

monitor implementation experiences 

with respect to the bonding provision, 

but we believe it is no longer necessary 

to adopt the interim regulatory 

provisions we were considering. We are 

proceeding with one adjustment to the 

bonding provisions. We believe it is 

appropriate to set a maximum value of 

$10 million for any bond that is 

required under § 1054.690. Setting this 

value the same as the maximum level of 

fixed assets that we require to be 

exempted from getting a bond would 

allow for a logical correlation regarding 

the liability for manufacturers that are 

exempt from the bonding requirement 

and those that are not. Nevertheless, we 

believe it is appropriate to adopt this 

change for a three-year transition 

period. At that point, we would either 

change the regulation to adopt some 

permanent cap on bond values or let the 

regulation revert to the original 

provisions with no maximum value. 

We communicated our intent to make 

these bonding-related changes to those 

that commented on the bonding 

provisions when we first adopted them, 

including the Outdoor Power 

Equipment Institute, the Engine 

Manufacturers Association, and the 

California Air Resources Board. The 

Outdoor Power Equipment Institute and 

the Engine Manufacturers Association 

objected to the change, arguing that the 

reduced bond requirement would be 

insufficient to recover penalties for 

noncompliance in most cases. Based on 

these comments and on the fact that 

several companies have established 

bond policies, we have decided not to 

make these changes in this rulemaking. 

We may choose to pursue these or other 

long-term adjustments to the bonding 

regulations based on our experiences 

over the next several months, but we 

would do that in the context of a new 

rulemaking, which would include 

ample opportunity for comment and 

collaboration. In the meantime, we 

anticipate that small businesses may 

continue to have difficulty establishing 

a bond. If this is the case, we would be 

ready to consider an application for 

hardship under the provisions of 

§ 1054.635. Small businesses applying 

for relief under this provision would 

need to provide us with enough 

information to be able to act on their 

request. In any hardship approval, we 

would likely first consider the same 

kinds of relief reflected in the interim 

regulation changes we were considering. 

In particular, we could reduce the 

specified bond amount to preserve a 

measure of protection that is more 

carefully calibrated for very small sales 

volumes. We could also consider a 

manufacturer to be exempted from 

getting a bond based on a good 

compliance history of less than ten 

years. 

The proposed rule also included new 

regulatory provisions to clarify what we 

would consider acceptable inventory 

and stockpiling practices for engine and 

vehicle manufacturers relative to the 

new emission standards for heavy-duty 

highway engines that take effect in 2010 

and later model years. We have received 

extensive input in the comments, 

including concerns about how to define 

and potentially apply certain terms such 

as ‘‘normal inventory’’ and ‘‘production’’ 

practices given the dynamics of today’s 

market and placed in the context of the 

timing of this final rule, and how such 

terms might be used by the Agency to 

determine whether inappropriate 

stockpiling has occurred. Based on this, 

we have decided to defer codification of 

the stockpiling prohibition until a later 

rulemaking. In the meantime, we plan to 

implement the 2010 standards based on 

the Agency’s existing stockpiling 

guidance and to monitor engine and 

vehicle manufacturers in order to ensure 

that no circumventions of the Clean Air 

Act have occurred. 

X. Statutory and Executive Order 

Reviews 

As explained in Section I.A, the 

program we are finalizing is part of a 

coordinated strategy to address 

emissions from ocean-going vessels. 

That coordinated strategy includes, 

among other actions, the combination 

the global Tier 2 NOX standards 

included in the amendments to Annex 

VI and the ECA Tier 3 NOX limits and 

fuel sulfur limits that will apply when 

the U.S. coasts are designated as an ECA 

through an additional amendment to 

Annex VI. These engine and fuel 

standards will be enforceable for all 

vessels, U.S. and foreign, operating in 

the United States through the Act to 

Prevent Pollution from Ships. Because 

the coordinated strategy in its entirety is 

economically significant (see cost 

analysis in Section V), the components 

we are adopting in this rule (engine 

controls for Category 3 engines on U.S. 

vessels under our Clean Air Act 

program, as required by section 213 of 

the Act that are identical to the 

MARPOL Annex VI NOX limits; limits 

on hydrocarbon and carbon monoxide 

emissions for Category 3 engines; PM 

measurement requirement; changes to 

our Clean Air Act diesel fuel program to 

allow production and sale of ECAcompliant fuel; changes to our emission 

control program for smaller marine 

diesel engines to harmonize with the 

Annex VI NOX requirements, for U.S. 

vessels that operate internationally) may 


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also be considered to be economically 

significant. 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order (EO) 12866 

(58 FR 51735, October 4, 1993), this 

action is a ‘‘significant regulatory action’’ 

because it raises novel legal or policy 

issues due to the international nature of 

the use of Category 3 marine diesel 

engines. Accordingly, EPA submitted 

this action to the Office of Management 

and Budget (OMB) for review under EO 

12866 and any changes made in 

response to OMB recommendations 

have been documented in the docket for 

this action. 

In addition, EPA prepared an analysis 

of the potential costs and benefits 

associated with our coordinated strategy 

for controlling emissions from oceangoing vessels. While the costs of the 

coordinated strategy are ‘‘significant,’’ 

the largest part of these costs are related 

to compliance with MARPOL Annex VI, 

which applies independently of this 

final rule. The costs of the requirements 

we are adopting in this rule are 

minimal. This analysis is contained in 

the Regulatory Impact Analysis that was 

prepared, and is available in the docket 

for this rulemaking and at the docket 

Internet address listed under ADDRESSES

above. 

B. Paperwork Reduction Act 

The information collection 

requirements in this rule will be 

submitted for approval to the Office of 

Management and Budget (OMB) under 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. The information collection 

requirements are not enforceable until 

OMB approves them. 

Section 208(a) of the Clean Air Act 

requires that manufacturers provide 

information the Administrator may 

reasonably require to determine 

compliance with the regulations; 

submission of the information is 

therefore mandatory. We will consider 

confidential all information meeting the 

requirements of section 208(c) of the 

Clean Air Act. Recordkeeping and 

reporting requirements for 

manufacturers would be pursuant to the 

authority of section 208 of the Clean Air 

Act. 

The data we require in this action is 

necessary to comply with Title II of the 

Clean Air Act, as amended in 1990. The 

Act directs us to adopt regulations for 

nonroad engines if we determine those 

engines contribute significantly to air 

pollution in the U.S. Now that we have 

made this determination, the Act directs 

us to set emission standards for any 

category of nonroad engines that 

contribute to air quality nonattainment 

in two or more areas in the U.S. We can 

only meet the requirements of the Act 

by collecting data from the regulated 

industry. Also, we will only have an 

effective program if we know that these 

engines maintain their certified 

emission level throughout their 

operating lives. 

The burden for certification testing is 

generally based on conducting two 

engine tests for each engine family, then 

using that test data for several years. 

The manufacturer’s application for 

certification involves an extensive effort 

the first year, followed by relatively 

little effort in subsequent years. We 

estimate that manufacturers will 

conduct new certification testing every 

five years; the costs have been estimated 

on an annual average basis. In addition 

to testing, manufacturers must prepare 

the application for certification and 

maintain appropriate records. The 

burden for production-line testing is 

based on an industry-wide calculation. 

Rebuilders, including operators of 

marine vessels with Category 3 engines, 

must keep records as needed to show 

that rebuilt engines continue to meet 

emission standards, consistent with the 

manufacturer’s original design. In 

addition, owners and operators of 

marine vessels with Category 3 engines 

must record information about their 

location when rebuilding engines or 

making other adjustments and send 

minimal annual notification to EPA to 

show that engine maintenance and 

adjustments have not caused engines to 

be noncompliant. In total, we estimate 

that 12 engine manufacturers and 200 

engine rebuilders will together face an 

estimated compliance burden of 3,012 

hours per year, which corresponds with 

annual costs of $191,759 per year. 

Burden is defined at 5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. EPA 

will amend the table in 40 CFR part 9 

to add OMB control number associated 

with the new regulations in 40 CFR part 

1043 once those are approved. 

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 this rule on small entities, small 

entity is defined as: (1) A small business 

that is primarily engaged in 

manufacture of large diesel marine 

engines as defined by NAICS code 

333618 with 1,000 or fewer employees 

(based on Small Business 

Administration size standards) or a 

small business primarily engaged in 

shipbuilding and repairing as defined 

by NAICS code 336611 with 1,000 or 

fewer employees (based on Small 

Business Administration size 

standards); (2) a small business that is 

primarily engaged in freight or 

passenger transportation, either on the 

Great Lakes or in coastal areas as 

defined by NAICS codes 483113 and 

483114 with 500 or fewer employees 

(based on Small Business 

Administration size standards); (3) 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 (4) 

a small organization that is any not-forprofit 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. 

Since publication of the proposed 

rulemaking, we have learned that the 

small entities directly regulated by this 

final rule include shipping companies 

that use fuel subject to the requirements 

in this rulemaking. We have identified 

four small U.S. companies that are 

operating Category 3 engines that 

currently burn residual fuel, and have 

estimated the compliance burden for 

each of these four small companies 

based on available information about 

the companies and their vessels. Our 

analysis indicates that two companies 

will have an estimated compliance 

burden representing less than 1 percent 

of their operating revenues, one 

company will have an estimated 

compliance burden representing 

between 1 and 3 percent of their 

operating revenues, and one company 

will have an estimated compliance 

burden representing slightly over 6 

percent of their operating revenues. 

Although this final rule will not have 

a significant economic impact on a 

substantial number of small entities, 

EPA nonetheless has tried to reduce the 

impact of this rule by adopting 

provisions to reduce the regulatory 


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burden for these companies. For 

example, if we would apply the fuel 

requirements to steamships, a total of 

five small businesses would have an 

estimated compliance burden 

representing over 1 percent of their 

operating revenues, with the values for 

some companies reaching 20 percent or 

higher. However, we have decided to 

adopt provisions allowing us to waive 

the fuel-related requirements for these 

companies if it can be demonstrated that 

a compliant residual fuel is not 

available, or that the compliance burden 

will jeopardize the solvency of the 

company. This analysis also does not 

include cost savings from increased 

durability and reliability or decreased 

maintenance that occurs when using 

distillate fuel instead of residual fuel. 

Our estimated burden for these 

companies therefore overestimates the 

costs these companies will actually face 

when complying with the rule. 

Additionally, in some areas, we 

consider port areas to be internal waters 

even though they are directly accessed 

by vessels that operate in coastal and 

international service on the oceans 

(such as Puget Sound). We believe it 

would not be realistic to expect 

companies operating such vessels to use 

distillate fuel as they approach U.S. 

ports and then convert the engines to 

operate on residual fuel for that portion 

of their operation that is considered 

internal waters. Since it would take 

about an hour of operation to transition 

back to the residual fuel, we believe this 

would not be commonly practiced 

whether or not fuel requirements apply 

in internal waters. Nevertheless, we 

have analyzed this scenario for potential 

small business impacts. We found that 

one U.S. small business with coastal 

operations would be affected by this 

rule, but that they will have costs 

representing less than one percent of 

their revenues. As a result, we have 

concluded that all small businesses that 

own or operate these coastal vessels will 

see no significant economic impact in 

complying with this rule. 

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. While the costs of the 

coordinated strategy exceed the $100 

million per year threshold for the 

private sector, the costs of the 

components of that strategy that are the 

subject of this rule are less than $100 

million per year, as explained in Section 

VII. Therefore, this action is not subject 

to the requirements of Sections 202 or 

205 of the UMRA. This action 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. 

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 will 

be implemented at the Federal level and 

impose compliance obligations only on 

private industry. Thus, Executive Order 

13132 does not apply to this rule. 

Although Section 6 of Executive 

Order 13132 does not apply to this rule, 

EPA did consult with representatives of 

various State and local governments in 

developing this rule. EPA consulted 

with representatives from the National 

Association of Clean Air Agencies 

(NACAA, formerly STAPPA/ALAPCO), 

the Northeast States for Coordinated Air 

Use Management (NESCAUM), and the 

California Air Resources Board (CARB). 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, EPA 

specifically solicited comment on the 

action from State and local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have Tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). The rule will be implemented at 

the Federal level and impose 

compliance costs only on manufacturers 

of marine engines and marine vessels. 

Tribal governments will be affected only 

to the extent they purchase and use the 

regulated engines and vehicles. Thus, 

Executive Order 13175 does not apply 

to this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

This action is not subject to EO 13045 

(62 FR 19885, April 23, 1997) because 

it is not economically significant as 

defined in EO 12866, and because the 

Agency does not believe the 

environmental health or safety risks 

addressed by this action present a 

disproportionate risk to children. This 

action’s health and risk assessments are 

contained in Section II.A and Section 

VIII in this document and in Chapter 2 

of the RIA, which has been placed in the 

public docket under Docket ID number 

EPA–HQ–OAR–2007–0121. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

Executive Order 13211, ‘‘Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use’’ (66 FR 28355 (May 

22, 2001)), requires EPA to prepare and 

submit a Statement of Energy Effects to 

the Administrator of the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, for 

certain actions identified as ‘‘significant 

energy actions.’’ Section 4(b) of 

Executive Order 13211 defines 

‘‘significant energy actions’’ as ‘‘any 

action by an agency (normally 

published in the Federal Register) that 

promulgates or is expected to lead to the 

promulgation of a final rule or 

regulation, including notices of inquiry, 

advance notices of proposed 

rulemaking, and notices of proposed 

rulemaking: (1)(i) That is a significant 

regulatory action under Executive Order 

12866 or any successor order, and (ii) is 

likely to have a significant adverse effect 

on the supply, distribution, or use of 

energy; or (2) that is designated by the 

Administrator of the Office of 

Information and Regulatory Affairs as a 

significant energy action.’’ We have 

prepared a Statement of Energy Effects 

for this action as follows. 

This rule’s potential effects on energy 

supply, distribution, or use have been 

analyzed and are discussed in detail in 

Section 4.6 of the RIA. In summary, 

while we project that this rule would 

result in an energy effect that exceeds 

the 10,000 barrel per day change in 

crude oil production threshold noted in 

E.O. 13211, this rule does not 

significantly affect the energy use, 

production, or distribution beyond what 

is required by Annex VI of the 

International Convention for the 

Prevention of Pollution from Ships. 

I. National Technology Transfer 

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 doing 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 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 22967 

171 ICF International. December 1, 2008. 

Estimation of diesel particulate matter 

concentration isopleths near selected harbor areas 

with revised emissions (revised). Memorandum to 

EPA under Work Assignment Number 1–9, Contract 

Number EP–C–06–094. This memo is available in 

Docket EPA–HQ–OAR–2007–0121. 

172 ICF International. December 10, 2008. 

Estimation of diesel particulate matter population 

exposure near selected harbor areas with revised 

harbor emissions (revised). Memorandum to EPA 

under Work Assignment Number 2–9, Contract 

Number EP–C–06–094. This memo is available in 

Docket EPA–HQ–OAR–2007–0121. 

173The emissions inventories used as inputs for 

the analyses are not official estimates and likely 

underestimate overall emissions because they are 

not inclusive of all emission sources at the 

individual ports in the sample. 

174The Agency selected a representative sample 

from the top 150 U.S. ports including coastal, 

inland and Great Lake ports. 

bodies. The NTTAA directs EPA to 

provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

The rulemaking involves technical 

standards. Therefore, the Agency 

conducted a search to identify 

potentially applicable voluntary 

consensus standards. The only test 

procedures outside of EPA that are 

written for Category 3 marine diesel 

engines are in the NOX Technical Code 

as part of MARPOL Annex VI. These 

test procedures have been adopted by 

the International Maritime Organization 

under the auspices of the United 

Nations. As such, they are not 

technically voluntary consensus 

standards. We have adopted test 

procedure specifications for Category 3 

marine diesel engines in 40 CFR part 

1042, which rely on the EPA test 

procedures in 40 CFR part 1065. We 

have written the part 1065 test 

procedures to apply broadly to all sizes 

and types of engines. We have 

coordinated these efforts with a wide 

range of manufacturers from every 

industry over nearly the last ten years. 

As a result of this effort, we have 

reached a point that the test procedures 

have been very widely referenced and 

adopted for use in various countries and 

for various applications. We believe that 

part 1065 is the best path toward global 

harmonization of emission test 

procedures for highway, nonroad, and 

stationary engines. Nevertheless, we 

have included a provision allowing 

manufacturers to rely on the procedures 

specified in the NOX Technical Code. 

We believe this appropriately maintains 

part 1065 as the primary path for 

adopting standardized and harmonized 

test procedures, without precluding the 

possibility of testing according to the 

other widely accepted protocol for 

testing Category 3 marine diesel 

engines. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 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 

increases the level of environmental 

protection for all affected populations 

without having any disproportionately 

high and adverse human health or 

environmental effects on any 

population, including any minority or 

low-income population. 

Together, this final rule which 

addresses emissions from domesticflagged vessels and the joint U.S./ 

Canada ECA application to the IMO 

which addresses emissions from 

foreign-flagged vessels (referred to as the 

‘‘coordinated strategy’’) will achieve 

significant reductions of various 

emissions from Category 3 marine diesel 

engines, including NOX, SOX, and direct 

PM. Exposure to these pollutants raises 

concerns regarding environmental 

health for the U.S. population in general 

including the minority populations and 

low-income populations that are the 

focus of the environmental justice 

executive order. 

The emission reductions from the 

new standards in the coordinated 

strategy will have large beneficial effects 

on communities in proximity to port, 

harbor, and waterway locations, 

including low-income and minority 

communities. In addition to exhaust 

emission standards for freshly 

manufactured and remanufactured 

engines, the coordinated strategy will 

further reduce emissions from regulated 

engines that directly impact low-income 

and minority communities. 

EPA recently updated its initial 

screening-level analysis of selected 

marine port areas to better understand 

the populations, including minority and 

low-income populations, that are 

exposed to diesel PM emission sources 

from these facilities.171 172 This 

screening-level analysis is an inexact 

tool and should only be considered for 

illustrative purposes to help understand 

potential impacts. The analysis 

included all emission sources as well as 

ocean-going marine diesel engines, and 

focused on a representative selection of 

national marine ports (45 ports 

total).173 174 Considering only oceangoing marine engine diesel PM 

emissions, the results indicate that 6.5 

million people are exposed to ambient 

diesel PM levels that are 2.0 μg/m3 and 

0.2 μg/m3 above levels found in areas 

further from these facilities. This 

population includes a disproportionate 

number of low-income households, 

African-Americans, and Hispanics. The 

results from all emission sources show 

that nearly 18 million people are 

exposed to higher levels of diesel PM 

from all sources at the marine port areas 

than urban background levels. Because 

those living in the vicinity of marine 

ports are more likely to be low-income 

households and minority residents, 

these populations would receive a 

significant benefit from the combined 

coordinated strategy. See Section VIII of 

this preamble and Chapter 6 of the RIA 

for a discussion on the benefits of this 

rule, including the benefits to minority 

and low-income communities. 

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). This rule 

will be effective June 29, 2010. 

XI. Statutory Provisions and Legal 

Authority 

Statutory authority for the controls in 

this final rule can be found in sections 

203–209, 211, 213 (which specifically 

authorizes controls on emissions from 

nonroad engines and vehicles), 216, and 

301 of the Clean Air Act (CAA), 42 

U.S.C. 7414, 7522, 7523, 7424, 7525, 

7541, 7542, 7543, 7545, 7547, 7550, and 

7601. 


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22968 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

List of Subjects 

40 CFR Part 80 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Confidential 

business information, Diesel fuel, Fuel 

additives, Imports, Labeling, Penalties, 

Reporting and recordkeeping 

requirements. 

40 CFR Part 85 

Confidential business information, 

Imports, Labeling, Motor vehicle 

pollution, Reporting and recordkeeping 

requirements, Research, Warranties. 

40 CFR Part 86 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Reporting and 

recordkeeping requirements, Motor 

vehicle. 

40 CFR Part 94 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Confidential 

business information, Imports, 

Incorporation by reference, Labeling, 

Penalties, Vessels, Reporting and 

recordkeeping requirements, 

Warranties. 

40 CFR Part 1027 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Imports, 

Reporting and recordkeeping 

requirements. 

40 CFR Part 1033 

Environmental protection, 

Administrative practice and procedure, 

Confidential business information, 

Incorporation by reference, Labeling, 

Penalties, Railroads, Reporting and 

recordkeeping requirements. 

40 CFR Part 1039 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Confidential 

business information, Imports, 

Incorporation by reference, Labeling, 

Penalties, Reporting and recordkeeping 

requirements, Warranties. 

40 CFR Part 1042 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Confidential 

business information, Imports, 

Incorporation by reference, Labeling, 

Penalties, Vessels, Reporting and 

recordkeeping requirements, 

Warranties. 

40 CFR Part 1043 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Imports, 

Incorporation by reference, Vessels, 

Reporting and recordkeeping 

requirements. 

40 CFR Parts 1045, 1048, 1051, 1054, 

and 1060 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Confidential 

business information, Imports, 

Incorporation by reference, Labeling, 

Penalties, Reporting and recordkeeping 

requirements, Warranties. 

40 CFR Parts 1065 

Environmental protection, 

Administrative practice and procedure, 

Incorporation by reference, Reporting 

and recordkeeping requirements, 

Research. 

40 CFR Part 1068 

Environmental protection, 

Administrative practice and procedure, 

Confidential business information, 

Imports, Incorporation by reference, 

Motor vehicle pollution, Penalties, 

Reporting and recordkeeping 

requirements, Warranties. 

Dated: December 18, 2009. 

Lisa P. Jackson, 

Administrator. 

■ For the reasons set out in the 

preamble, title 40, chapter I of the Code 

of Federal Regulations is amended as set 

forth below. 

PART 80—REGULATION OF FUEL 

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. 

■ 2. Section 80.2 is amended as follows: 

■ a. By revising paragraph (ccc). 

■ b. By revising paragraph (nnn). 

■ c. By adding paragraph (ttt). 

■ d. By adding paragraph (uuu). 

§ 80.2 Definitions. 

* * * * * 

(ccc) Heating Oil means any #1, #2, or 

non-petroleum diesel blend that is sold 

for use in furnaces, boilers, and similar 

applications and which is commonly or 

commercially known or sold as heating 

oil, fuel oil, and similar trade names, 

and that is not jet fuel, kerosene, or 

MVNRLM diesel fuel. 

* * * * * 

(nnn) Nonroad, locomotive, or marine 

(NRLM) diesel fuel means any diesel 

fuel or other distillate fuel that is used, 

intended for use, or made available for 

use, as a fuel in any nonroad diesel 

engines, including locomotive and 

marine diesel engines, except the 

following: Distillate fuel with a T90 at 

or above 700 °F that is used only in 

Category 2 and 3 marine engines is not 

NRLM diesel fuel, and ECA marine fuel 

is not NRLM diesel fuel (note that fuel 

that conforms to the requirements of 

NRLM diesel fuel is excluded from the 

definition of ‘‘ECA marine fuel’’ in this 

section without regard to its actual use). 

Use the distillation test method 

specified in 40 CFR 1065.1010 to 

determine the T90 of the fuel. NR diesel 

fuel and LM diesel fuel are 

subcategories of NRLM diesel fuel. 

(1) Any diesel fuel that is sold for use 

in stationary engines that are required to 

meet the requirements of § 80.510(a) 

and/or (b), when such provisions are 

applicable to nonroad engines, shall be 

considered NRLM diesel fuel. 

(2) [Reserved] 

* * * * * 

(ttt) ECA marine fuel is diesel, 

distillate, or residual fuel that meets the 

criteria of paragraph (ttt)(1) of this 

section, but not the criteria of paragraph 

(ttt)(2) of this section. 

(1) All diesel, distillate, or residual 

fuel used, intended for use, or made 

available for use in Category 3 marine 

vessels while the vessels are operating 

within an Emission Control Area (ECA) 

is ECA marine fuel, unless it meets the 

criteria of paragraph (ttt)(2) of this 

section. 

(2) ECA marine fuel does not include 

any of the following fuel: 

(i) Fuel that is allowed by 40 CFR part 

1043 to exceed the fuel sulfur limits for 

operation in an ECA (such as fuel used 

by excluded vessels or vessels equipped 

with equivalent emission controls in 

conformance with 40 CFR 1043.55). 

(ii) Fuel that conforms fully to the 

requirements of this part for NRLM 

diesel fuel (including being designated 

as NRLM). 

(iii) Fuel used, or made available for 

use, in any diesel engines not installed 

on a Category 3 marine vessel. 

(uuu) Category 3 marine vessels, for 

the purposes of this part 80, are vessels 

that are propelled by engines meeting 

the definition of ‘‘Category 3’’ in 40 CFR 

part 1042.901. 

Subpart I—Motor Vehicle Diesel Fuel; 

Nonroad, Locomotive, and Marine 

Diesel Fuel; and ECA Marine Fuel 

■ 3. The heading for subpart I is revised 

as set forth above. 

■ 4. Section 80.501 is amended as 

follows: 

■ a. By revising paragraph (a)(5). 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 22969 

■ b. By revising paragraph (a)(6). 

■ c. By adding paragraph (a)(7). 

§ 80.501 What fuel is subject to the 

provisions of this subpart? 

(a) * * * 

(5) ECA marine fuel. 

(6) Other distillate fuels. 

(7) Motor oil that is used as or 

intended for use as fuel in diesel motor 

vehicles or nonroad diesel engines or is 

blended with diesel fuel for use in 

diesel motor vehicles or nonroad diesel 

engines, including locomotive and 

marine diesel engines, at any 

downstream location. 

* * * * * 

■ 5. Section 80.502 is amended as 

follows: 

■ a. By revising paragraph (a). 

■ b. By revising paragraph (b) 

introductory text and paragraph (b)(1) 

introductory text. 

■ c. By revising paragraph (c). 

■ d. By revising paragraph (d) 

introductory text. 

■ e. By adding paragraph (g). 

■ f. By adding paragraph (h). 

§ 80.502 What definitions apply for 

purposes of this subpart? 

* * * * * 

(a) Entity means any refiner, importer, 

distributor, retailer or wholesalepurchaser consumer of any distillate 

fuel (or other product subject to the 

requirements of this subpart I). 

(b) Facility means any place, or series 

of places, where an entity produces, 

imports, or maintains custody of any 

distillate fuel (or other product subject 

to the requirements of this subpart I) 

from the time it is received to the time 

custody is transferred to another entity, 

except as described in paragraphs (b)(1) 

through (4) of this section: 

(1) Where an entity maintains custody 

of a batch of diesel fuel (or other 

product subject to the requirements of 

this subpart I) from one place in the 

distribution system to another place 

(e.g., from a pipeline to a terminal), all 

owned by the same entity, both places 

combined are considered to be one 

single aggregated facility, except where 

an entity chooses to treat components of 

such an aggregated facility as separate 

facilities. The choice made to treat these 

places as separate facilities may not be 

changed by the entity during any 

applicable compliance period. Except as 

specified in paragraph (b)(2) of this 

section, where compliance requirements 

depend upon facility-type, the entire 

facility must comply with the 

requirements that apply to its 

components as follows: 

* * * * * 

(c) Truck loading terminal means any 

facility that dyes NRLM diesel fuel or 

ECA marine fuel, pays taxes on motor 

vehicle diesel fuel per IRS code (26 CFR 

part 48), or adds a fuel marker pursuant 

to § 80.510 to heating oil and delivers 

diesel fuel or heating oil into trucks for 

delivery to retail or ultimate consumer 

locations. 

(d) Batch means a quantity of diesel 

fuel (or other product subject to the 

requirements of this subpart I) which is 

homogeneous with regard to those 

properties that are specified for 

MVNRLM diesel fuel or ECA marine 

fuel under this subpart I, has the same 

designation under this subpart I (if 

applicable), and whose custody is 

transferred from one facility to another 

facility. 

* * * * * 

(g) Emission Control Area. An 

Emission Control Area (ECA), for the 

purposes of this subpart, means the 

‘‘ECA’’ as defined in 40 CFR 1043.20 as 

well as ‘‘ECA associated area’’ as defined 

in 40 CFR 1043.20. 

(h) Marine diesel engine. For the 

purposes of this subpart I only, marine 

diesel engine means a diesel engine 

installed on a Category 1 (C1) or 

Category 2 (C2) marine vessel. 

■ 6. Section 80.510 is amended as 

follows: 

■ a. By revising the section heading. 

■ b. By revising paragraph (f) 

introductory text and adding paragraph 

(f)(6). 

■ c. By revising paragraph (g)(1). 

■ d. By adding paragraph (k). 

§ 80.510 What are the standards and 

marker requirements for NRLM diesel fuel 

and ECA marine fuel? 

* * * * * 

(f) Marking provisions. From June 1, 

2012 through May 31, 2014: 

* * * * * 

(6) Marker solvent yellow 124 shall 

not be used in any MVNRLM or heating 

oil after May 31, 2014. 

(g) * * * 

(1) Northeast/Mid-Atlantic Area, 

which includes the following States and 

counties, through May 31, 2014: North 

Carolina, Virginia, Maryland, Delaware, 

New Jersey, Connecticut, Rhode Island, 

Massachusetts, Vermont, New 

Hampshire, Maine, Washington DC, 

New York (except for the counties of 

Chautauqua, Cattaraugus, and 

Allegany), Pennsylvania (except for the 

counties of Erie, Warren, McKean, 

Potter, Cameron, Elk, Jefferson, Clarion, 

Forest, Venango, Mercer, Crawford, 

Lawrence, Beaver, Washington, and 

Greene), and the eight eastern-most 

counties of West Virginia (Jefferson, 

Berkeley, Morgan, Hampshire, Mineral, 

Hardy, Grant, and Pendleton). 

* * * * * 

(k) Beginning June 1, 2014. All ECA 

marine fuel is subject to a maximum 

per-gallon sulfur content of 1,000 ppm. 

■ 7. Section 80.511 is amended as 

follows: 

■ a. By revising the section heading. 

■ b. By revising paragraph (a). 

■ c. By revising paragraphs (b)(4) and 

(b)(9). 

■ d. By adding paragraph (b)(10). 

§ 80.511 What are the per-gallon and 

marker requirements that apply to NRLM 

diesel fuel, ECA marine fuel, and heating oil 

downstream of the refiner or importer? 

(a) Applicable dates for marker 

requirements. Beginning June 1, 2006, 

all NRLM diesel fuel and ECA marine 

fuel shall contain less than 0.10 

milligrams per liter of the marker 

solvent yellow 124, except for LM diesel 

fuel subject to the marking requirements 

of § 80.510(e). 

(b) * * * 

(4) Except as provided in paragraphs 

(b)(5) through (8) of this section, the pergallon sulfur standard of § 80.510(c) 

shall apply to all NRLM diesel fuel 

beginning August 1, 2014, for all 

downstream locations other than retail 

outlets or wholesale 

purchaser-consumer facilities, shall 

apply to all NRLM diesel fuel beginning 

October 1, 2014 for retail outlets and 

wholesale purchaser-consumer 

facilities, and shall apply to all NRLM 

diesel fuel beginning December 1, 2014, 

for all locations. 

* * * * * 

(9) The per-gallon sulfur standard of 

§ 80.510(k) shall apply to all ECA 

marine fuel beginning August 1, 2014, 

for all downstream locations other than 

retail outlets or wholesale purchaserconsumer facilities, shall apply to all 

ECA marine fuel beginning October 1, 

2014, for retail outlets and wholesale 

purchaser-consumer facilities, and shall 

apply to all ECA marine fuel beginning 

December 1, 2014, for all locations. 

(10) For the purposes of this section, 

distributors that have their own fuel 

storage tanks and deliver only to 

ultimate consumers shall be treated the 

same as retailers and their facilities 

treated the same as retail outlets. 

■ 8. Section 80.513 is amended by 

revising paragraph (e) to read as follows: 

§ 80.513 What provisions apply to 

transmix processing facilities? 

* * * * * 

(e) From June 1, 2014 and beyond, 

NRLM diesel fuel produced by a 

transmix processor is subject to the 

standards of § 80.510(c). 

■ 9. Section 80.525 is amended by 

revising paragraphs (b) and (d) to read 

as follows: 


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22970 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

§ 80.525 What requirements apply to 

kerosene blenders? 

* * * * * 

(b) Kerosene blenders are not subject 

to the requirements of this subpart 

applicable to refiners of diesel fuel, but 

are subject to the requirements and 

prohibitions applicable to downstream 

parties. 

* * * * * 

(d) Kerosene that a kerosene blender 

adds or intends to add to diesel fuel 

subject to the 15 ppm sulfur content 

standard must meet the 15 ppm sulfur 

content standard, and either of the 

following requirements: 

(1) The product transfer document 

received by the kerosene blender 

indicates that the kerosene is diesel fuel 

that complies with the 15 ppm sulfur 

content standard. 

(2) The kerosene blender has test 

results indicating the kerosene complies 

with the 15 ppm sulfur standard. 

■ 10. Section 80.551 is amended by 

revising paragraph (f) to read as follows: 

§ 80.551 How does a refiner obtain 

approval as a small refiner under this 

subpart? 

* * * * * 

(f) Approval of small refiner status for 

refiners who apply under § 80.550(d) 

will be based on all information 

submitted under paragraph (c) of this 

section, except as provided in 

§ 80.550(e). 

* * * * * 

■ 11. Section 80.561 is amended by 

revising the section heading to read as 

follows: 

§ 80.561 How can a refiner or importer 

seek temporary relief from the requirements 

of this subpart in case of extreme 

unforeseen circumstances? 

* * * * * 

■ 12. Section 80.570 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 80.570 What labeling requirements apply 

to retailers and wholesale purchaserconsumers of diesel fuel beginning June 1, 

2006? 

(a) From June 1, 2006 through 

November 30, 2010, any retailer or 

wholesale purchaser-consumer who 

sells, dispenses, or offers for sale or 

dispensing, motor vehicle diesel fuel 

subject to the 15 ppm sulfur standard of 

§ 80.520(a)(1), must affix the following 

conspicuous and legible label, in block 

letters of no less than 24-point bold 

type, and printed in a color contrasting 

with the background, to each pump 

stand: 

ULTRA-LOW SULFUR HIGHWAY 

DIESEL FUEL (15 ppm Sulfur 

Maximum) 

Required for use in all model year 

2007 and later highway diesel vehicles 

and engines. 

Recommended for use in all diesel 

vehicles and engines. 

(b) From June 1, 2006, through 

November 30, 2010, any retailer or 

wholesale purchaser-consumer who 

sells, dispenses, or offers for sale or 

dispensing, motor vehicle diesel fuel 

subject to the 500 ppm sulfur standard 

of § 80.520(c), must prominently and 

conspicuously display in the immediate 

area of each pump stand from which 

motor vehicle fuel subject to the 500 

ppm sulfur standard is offered for sale 

or dispensing, the following legible 

label, in block letters of no less than 24- 

point bold type, printed in a color 

contrasting with the background: 

LOW SULFUR HIGHWAY DIESEL 

FUEL (500 ppm Sulfur Maximum) 

WARNING 

Federal law prohibits use in model 

year 2007 and later highway vehicles 

and engines. 

Its use may damage these vehicles and 

engines. 

* * * * * 

■ 13. Section 80.571 is amended by 

revising paragraphs (b) and (d) to read 

as follows: 

§ 80.571 What labeling requirements apply 

to retailers and wholesale purchaserconsumers of NRLM diesel fuel or heating 

oil beginning June 1, 2007? 

* * * * * 

(b) From June 1, 2007, through 

September 30, 2010, for pumps 

dispensing NRLM diesel fuel meeting 

the 500 ppm sulfur standard of 

§ 80.510(a): 

LOW SULFUR NON-HIGHWAY DIESEL 

FUEL (500 ppm Sulfur Maximum) 

WARNING 

Federal Law prohibits use in highway 

vehicles or engines. 

* * * * * 

(d) From June 1, 2007, and beyond, 

for pumps dispensing non-motor 

vehicle diesel fuel for use other than in 

nonroad, locomotive, or marine engines, 

such as for use as heating oil: 

HEATING OIL (May Exceed 500 ppm 

Sulfur) 

WARNING 

Federal law prohibits use in highway 

vehicles or engines, or in nonroad, 

locomotive, or marine diesel engines. 

Its use may damage these diesel 

engines. 

* * * * * 

■ 14. Section 80.572 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 80.572 What labeling requirements apply 

to retailers and wholesale purchaserconsumers of NR and NRLM diesel fuel and 

heating oil beginning June 1, 2010? 

* * * * * 

(a) From June 1, 2010, through 

September 31, 2014, any retailer or 

wholesale purchaser-consumer who 

sells, dispenses, or offers for sale or 

dispensing, motor vehicle diesel fuel 

subject to the 15 ppm sulfur standard of 

§ 80.520(a)(1), must affix the following 

conspicuous and legible label, in block 

letters of no less than 24-point bold 

type, and printed in a color contrasting 

with the background, to each pump 

stand: 

ULTRA-LOW SULFUR HIGHWAY 

DIESEL FUEL (15 ppm Sulfur 

Maximum) 

Required for use in all highway diesel 

vehicles and engines. 

Recommended for use in all diesel 

vehicles and engines. 

(b) From June 1, 2010, through 

September 30, 2012, for pumps 

dispensing NR diesel fuel subject to the 

15 ppm sulfur standard of § 80.510(b): 

ULTRA-LOW SULFUR NON-HIGHWAY 

DIESEL FUEL (15 ppm Sulfur 

Maximum) 

Required for use in all model year 

2011 and later nonroad diesel engines. 

Recommended for use in all other 

non-highway diesel engines. 

WARNING 

Federal law prohibits use in highway 

vehicles or engines. 

* * * * * 

■ 15. Section 80.573 is amended by 

revising paragraph (a) to read as follows: 

§ 80.573 What labeling requirements apply 

to retailers and wholesale purchaserconsumers of NRLM diesel fuel and heating 

oil beginning June 1, 2012? 

* * * * * 

(a) From June 1, 2012, through 

September 30, 2014, for pumps 

dispensing NRLM diesel fuel subject to 

the 15 ppm sulfur standard of 

§ 80.510(c): 

ULTRA-LOW SULFUR NON-HIGHWAY 

DIESEL FUEL (15 ppm Sulfur 

Maximum) 

Required for use in all model year 

2011 and later nonroad diesel engines. 

Recommended for use in all other 

non-highway diesel engines. 


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WARNING 

Federal law prohibits use in highway 

vehicles or engines. 

* * * * * 

■ 16. Section 80.574 is revised to read 

as follows: 

§ 80.574 What labeling requirements apply 

to retailers and wholesale purchaserconsumers of ECA marine fuel beginning 

June 1, 2014? 

(a) Any retailer or wholesale 

purchaser-consumer who sells, 

dispenses, or offers for sale or 

dispensing ECA marine fuel must 

prominently and conspicuously display 

in the immediate area of each pump 

stand from which ECA marine fuel is 

offered for sale or dispensing, one of the 

following legible labels, as applicable, 

in block letters of no less than 24-point 

bold type, printed in a color contrasting 

with the background: 

(1) From June 1, 2014, and beyond, for 

pumps dispensing ECA marine fuel 

subject to the 1,000 ppm sulfur standard 

of § 80.510(k): 

1,000 ppm SULFUR ECA MARINE 

FUEL (1,000 ppm Sulfur Maximum) 

For use in Category 3 (C3) marine 

vessels only. 

WARNING 

Federal law prohibits use in any 

engine that is not installed on a C3 

marine vessel; use of fuel oil with a 

sulfur content greater than 1,000 ppm in 

an ECA is prohibited except as allowed 

by 40 CFR Part 1043. 

(2) The labels required by paragraph 

(a)(1) of this section must be placed on 

the vertical surface of each pump 

housing and on each side that has gallon 

and price meters. The labels shall be on 

the upper two-thirds of the pump, in a 

location where they are clearly visible. 

(b) Alternative labels to those 

specified in paragraph (a) of this section 

may be used as approved by EPA. 

(1) For U.S. Mail: U.S. EPA, Attn: 

Diesel Sulfur Alternative Label Request, 

6406J, 1200 Pennsylvania Avenue, NW., 

Washington, DC 20460. 

(2) For overnight or courier services: 

U.S. EPA, Attn: Diesel Sulfur 

Alternative Label Request, 6406J, 1310 L 

Street, NW., 6th Floor, Washington, DC 

20005. (202) 343–9038. 

■ 17. Section 80.580 is amended by 

adding paragraphs (b)(1) and (c)(1) to 

read as follows: 

§ 80.580 What are the sampling and 

testing methods for sulfur? 

* * * * * 

(b) * * * 

(1) For ECA marine fuel subject to the 

1,000 ppm sulfur standard of 

§ 80.510(k), sulfur content may be 

determined using ASTM D2622 

(incorporated by reference, see 

paragraph (e) of this section). 

* * * * * 

(c) * * * 

(1) Options for testing sulfur content 

of 1,000 ppm diesel fuel. (i) For ECA 

marine fuel subject to the 1,000 ppm 

sulfur standard of § 80.510(k), sulfur 

content may be determined using ASTM 

D4294, ASTM D5453, or ASTM D6920 

(all incorporated by reference, see 

paragraph (e) of this section), provided 

that the refiner or importer test result is 

correlated with the appropriate method 

specified in paragraph (b)(1) of this 

section; or 

(ii) For ECA marine fuel subject to the 

1,000 ppm sulfur standard of 

§ 80.510(k), sulfur content may be 

determined using any test method 

approved under § 80.585. 

* * * * * 

■ 18. Section 80.581 is amended by 

revising the section heading and 

paragraphs (a) and (c)(1) to read as 

follows: 

§ 80.581 What are the batch testing and 

sample retention requirements for motor 

vehicle diesel fuel, NRLM diesel fuel, and 

ECA marine fuel? 

(a) Beginning on June 1, 2006 (or 

earlier pursuant to § 80.531), for motor 

vehicle diesel fuel, and beginning June 

1, 2010 (or earlier pursuant to § 80.535), 

for NRLM diesel fuel, and beginning 

June 1, 2014, for ECA marine fuel, each 

refiner and importer shall collect a 

representative sample from each batch 

of motor vehicle or NRLM diesel fuel 

produced or imported and subject to the 

15 ppm sulfur content standard, or ECA 

marine fuel subject to the 1,000 ppm 

sulfur content standard. Batch, for the 

purposes of this section, means batch as 

defined under § 80.2 but without the 

reference to transfer of custody from one 

facility to another facility. 

* * * * * 

(c)(1) Any refiner who produces 

motor vehicle, NRLM diesel fuel, or 

ECA marine fuel using computercontrolled in-line blending equipment, 

including the use of an on-line analyzer 

test method that is approved under the 

provisions of § 80.580, and who, 

subsequent to the production of the 

diesel fuel batch tests a composited 

sample of the batch under the 

provisions of § 80.580 for purposes of 

designation and reporting, is exempt 

from the requirement of paragraph (b) of 

this section to obtain the test result 

required under this section prior to the 

diesel fuel leaving the refinery, 

provided that the refiner obtains 

approval from EPA. The requirement of 

this paragraph (c)(1) that the in-line 

blending equipment must include an 

on-line analyzer test method that is 

approved under the provisions of 

§ 80.580 is effective beginning June 1, 

2006. 

* * * * * 

■ 19. Section 80.583 is amended by 

revising the section heading to read as 

follows: 

§ 80.583 What alternative sampling and 

testing requirements apply to importers 

who transport motor vehicle diesel fuel, 

NRLM diesel fuel, or ECA marine fuel by 

truck or rail car? 

* * * * * 

■ 20. Section 80.584 is amended by 

revising the section heading and adding 

paragraphs (a)(3) and (b)(3) to read as 

follows: 

§ 80.584 What are the precision and 

accuracy criteria for approval of test 

methods for determining the sulfur content 

of motor vehicle diesel fuel, NRLM diesel 

fuel, and ECA marine fuel? 

(a) * * * 

(3) For ECA marine fuel subject to the 

1,000 ppm sulfur standard of 

§ 80.510(k), of a standard deviation less 

than 18.07 ppm, computed from the 

results of a minimum of 20 repeat tests 

made over 20 days on samples taken 

from a single homogeneous 

commercially available diesel fuel with 

a sulfur content in the range of 700– 

1,000 ppm. The 20 results must be a 

series of tests with a sequential record 

of the analyses and no omissions. A 

laboratory facility may exclude a given 

sample or test result only if the 

exclusion is for a valid reason under 

good laboratory practices and it 

maintains records regarding the sample 

and test results and the reason for 

excluding them. 

(b) * * * 

(3) For ECA marine fuel subject to the 

1,000 ppm sulfur standard of 

§ 80.510(k): 

(i) The arithmetic average of a 

continuous series of at least 10 tests 

performed on a commercially available 

gravimetric sulfur standard in the range 

of 300–400 ppm sulfur shall not differ 

from the ARV of that standard by more 

than 13.55 ppm sulfur; 

(ii) The arithmetic average of a 

continuous series of at least 10 tests 

performed on a commercially available 

gravimetric sulfur standard in the range 

of 900–1,000 ppm sulfur shall not differ 

from the ARV of that standard by more 

than 13.55 ppm sulfur; and 

(iii) In applying the tests of 

paragraphs (b)(3)(i) and (ii) of this 

section, individual test results shall be 


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compensated for any known chemical 

interferences. 

■ 21. Section 80.585 is amended by 

revising the section heading and 

paragraphs (e)(2) and (e)(4) to read as 

follows: 

§ 80.585 What is the process for approval 

of a test method for determining the sulfur 

content of diesel or ECA marine fuel? 

* * * * * 

(e) * * * 

(2) Follow paragraph 7.3.1 of ASTM D 

6299–02 to check standards using a 

reference material at least monthly or 

following any major change to the 

laboratory equipment or test procedure. 

Any deviation from the accepted 

reference value of a check standard 

greater than 1.44 ppm (for diesel fuel 

subject to the 15 ppm sulfur standard), 

19.36 ppm (for diesel fuel subject to the 

500 ppm sulfur standard), or 36.14 ppm 

(for ECA marine fuel subject to the 1,000 

ppm sulfur standard must be 

investigated. 

* * * * * 

(4) Upon discovery of any quality 

control testing violation of paragraph A 

1.5.1.3 or A 1.5.2.1 of ASTM D 6299– 

02, or any check standard deviation 

greater than 1.44 ppm (for diesel fuel 

subject to the 15 ppm sulfur standard), 

19.36 ppm (for diesel fuel subject to the 

500 ppm sulfur standard), or 36.14 ppm 

(for ECA marine fuel subject to the 1,000 

ppm sulfur standard), conduct an 

investigation into the cause of such 

violation or deviation and, after 

restoring method performance to 

statistical control, retest retained 

samples from batches originally tested 

since the last satisfactory quality control 

material or check standard testing 

occasion. 

■ 22. Section 80.590 is amended as 

follows: 

■ a. By revising the section heading. 

■ b. By revising paragraphs (a) 

introductory text, (a)(5), (a)(6) 

introductory text, and (a)(6)(ii). 

■ c. By adding paragraph (a)(7)(vii). 

■ d. By redesignating paragraphs (e) 

through (i) as paragraphs (f) through (j), 

respectively. 

■ e. By adding a new paragraph (e). 

§ 80.590 What are the product transfer 

document requirements for motor vehicle 

diesel fuel, NRLM diesel fuel, heating oil, 

ECA marine fuel, and other distillates? 

(a) This paragraph (a) applies on each 

occasion that any person transfers 

custody or title to MVNRLM diesel fuel, 

heating oil, or ECA marine fuel 

(including distillates used or intended 

to be used as MVNRLM diesel fuel, 

heating oil, or ECA marine fuel) except 

when such fuel is dispensed into motor 

vehicles or nonroad equipment, 

locomotives, marine diesel engines or 

C3 vessels. Note that 40 CFR part 1043 

specifies requirements for documenting 

fuel transfers to certain marine vessels. 

For all fuel transfers subject to this 

paragraph (a), the transferor must 

provide to the transferee documents 

which include the following 

information: 

* * * * * 

(5) For transfers of MVNRLM diesel 

fuel or ECA marine fuel (beginning June 

1, 2014), the sulfur content standard the 

transferor represents the fuel to meet. 

(6) Beginning June 1, 2006, when an 

entity, from a facility at any point in the 

distribution system, transfers custody of 

a distillate or residual fuel designated 

under § 80.598, the following 

information must also be included: 

* * * * * 

(ii) An accurate and clear statement of 

the applicable designation and/or 

classification under § 80.598(a) and (b), 

for example, ‘‘500 ppm sulfur NRLM 

diesel fuel’’, or ‘‘jet fuel’’; and whether 

the fuel is dyed or undyed, and for 

heating oil, whether marked or 

unmarked where applicable. 

(7) * * * 

(vii) ECA marine fuel. For ECA 

marine fuel produced or imported 

beginning June 1, 2014, ‘‘1,000 ppm 

sulfur (maximum) ECA marine fuel. For 

use in Category 3 marine vessels only. 

Not for use in engines not installed on 

C3 marine vessels.’’ 

* * * * * 

(e) Beginning June 1, 2014, for ECA 

marine fuel only (except for transfers to 

truck carriers, retailers or wholesale 

purchaser-consumers), product codes 

may be used to convey the information 

required under this section if such 

codes are clearly understood by each 

transferee. ‘‘1000’’ must appear clearly 

on the product transfer document, and 

may be contained in the product code. 

If the designation is included in the 

code, codes used to convey the 

statement in paragraph (a)(7)(vii) of this 

section must contain the number 

‘‘1000’’. If another letter, number, or 

symbol is being used to convey the 

statement in paragraph (a)(7)(vii) of this 

section, it must be clearly defined and 

denoted on the product transfer 

document. 

* * * * * 

■ 23. Section 80.593 is amended by 

revising the introductory text to read as 

follows: 

§ 80.593 What are the reporting 

requirements for refiners and importers of 

motor vehicle diesel fuel subject to 

temporary refiner relief standards? 

Beginning with 2006, or the first 

compliance period during which credits 

are generated under § 80.531(b) or (c), 

whichever is earlier, any refiner or 

importer who produces or imports 

motor vehicle diesel fuel subject to the 

500 ppm sulfur standard under 

§ 80.520(c), or any refiner or importer 

who generates, uses, obtains, or 

transfers credits under §§ 80.530 

through 80.532, and continuing for each 

year thereafter, must submit to EPA 

annual reports that contain the 

information required in this section, and 

such other information as EPA may 

require: 

* * * * * 

■ 24. Section 80.597 is amended by 

revising paragraphs (c), (d), (e), and (f) 

and adding paragraph (g) to read as 

follows: 

§ 80.597 What are the registration 

requirements? 

* * * * * 

(c) Registration for ECA marine fuel. 

Refiners and importers that intend to 

produce or supply ECA marine fuel 

beginning June 1, 2014, must provide 

EPA the information under § 80.76 no 

later than December 31, 2012, if such 

information has not been previously 

provided under the provisions of this 

part. In addition, for each import 

facility, the same identifying 

information as required for each refinery 

under § 80.76(c) must be provided. 

(d) Entity registration. (1) Except as 

prescribed in paragraph (d)(6) of this 

section, each entity as defined in 

§ 80.502 that intends to deliver or 

receive custody of any of the following 

fuels from June 1, 2006 through May 31, 

2010, must register with EPA by 

December 31, 2005, or six months prior 

to commencement of producing, 

importing, or distributing any distillate 

listed in paragraphs (d)(1)(i) through 

(d)(1)(iii) of this section: 

(i) Fuel designated as 500 ppm sulfur 

MVNRLM diesel fuel under § 80.598 on 

which taxes have not been assessed 

pursuant to IRS code (26 CFR part 48). 

(ii) Fuel designated as 15 ppm sulfur 

MVNRLM diesel fuel under § 80.598 on 

which taxes have not been assessed 

pursuant to IRS code (26 CFR part 48). 

(iii) Fuel designated as NRLM diesel 

fuel under § 80.598 that is undyed 

pursuant to § 80.520. 

(iv) Fuel designated as California 

Diesel fuel under § 80.598 on which 

taxes have not been assessed and red 

dye has not been added (if required) 

pursuant to IRS code (26 CFR part 48) 


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and that is delivered by pipeline to a 

terminal outside of the State of 

California pursuant to the provisions of 

§ 80.617(b). 

(2) Except as prescribed in paragraph 

(d)(6) of this section, each entity as 

defined in § 80.502 that intends to 

deliver or receive custody of any of the 

following fuels from June 1, 2007, 

through May 31, 2014, must register 

with EPA by December 31, 2005, or six 

months prior to commencement of 

producing, importing, or distributing 

any distillate listed in paragraph (d)(1) 

of this section: 

(i) Fuel designated as 500 ppm sulfur 

MVNRLM diesel fuel under § 80.598 on 

which taxes have not been assessed 

pursuant to IRS code (26 CFR part 48). 

(ii) Fuel designated as NRLM diesel 

fuel under § 80.598 that is undyed 

pursuant to § 80.520. 

(iii) Fuel designated as heating oil 

under § 80.598 that is unmarked 

pursuant to § 80.510(d) through (f). 

(iv) Fuel designated as LM diesel fuel 

under § 80.598(a)(2)(iii) that is 

unmarked pursuant to § 80.510(e). 

(3) Except as prescribed in paragraph 

(d)(6) of this section, each entity as 

defined in § 80.502 that intends to 

deliver or receive custody of any of the 

following fuels beginning June 1, 2014, 

must register with EPA by December 31, 

2012, or prior to commencement of 

producing, importing, or distributing 

any distillate or residual fuel listed in 

this paragraph (d): 

(i) Fuel designated as 1,000 ppm 

sulfur ECA marine fuel under § 80.598. 

(ii) [Reserved] 

(4) Registration shall be on forms 

prescribed by the Administrator, and 

shall include the name, business 

address, contact name, telephone 

number, e-mail address, and type of 

production, importation, or distribution 

activity or activities engaged in by the 

entity. 

(5) Registration shall include the 

information required under paragraph 

(e) of this section for each facility 

owned or operated by the entity that 

delivers or receives custody of a fuel 

described in paragraphs (d)(1) through 

(3) of this section. 

(6) Exceptions for Excluded Liquids. 

An entity that would otherwise be 

required to register pursuant to the 

requirements of paragraphs (d)(1) 

through (3) of this section is exempted 

from the registration requirements 

under this section provided that: 

(i) The only diesel fuel or heating oil 

that the entity delivers or receives on 

which taxes have not been assessed or 

which is not received dyed pursuant to 

IRS code 26 CFR part 48 is an excluded 

liquid as defined pursuant to IRS code 

26 CFR 48.4081–1(b). 

(ii) The entity does not transfer the 

excluded liquid to a facility which 

delivers or receives diesel fuel other 

than an excluded liquid on which taxes 

have not been assessed pursuant to IRS 

code (26 CFR part 48). 

(e) Facility registration. (1) List for 

each separate facility of an entity 

required to register under paragraph (d) 

of this section, the facility name, 

physical location, contact name, 

telephone number, e-mail address and 

type of facility. For facilities that are 

aggregated under § 80.502, provide 

information regarding the nature and 

location of each of the components. If 

aggregation is changed for any 

subsequent compliance period, the 

entity must provide notice to EPA prior 

to the beginning of such compliance 

period. 

(2) If facility records are kept off-site, 

list the off-site storage facility name, 

physical location, contact name, and 

telephone number. 

(3) Mobile facilities: (i) A description 

shall be provided in the registration 

detailing the types of mobile vessels that 

will likely be included and the nature 

of the operations. 

(ii) Entities may combine all mobile 

operations into one facility; or may split 

the operations by vessel, region, route, 

waterway, etc. and register separate 

mobile facilities for each. 

(iii) The specific vessels need not be 

identified in the registration, however 

information regarding specific vessel 

contracts shall be maintained by each 

registered entity for its mobile facilities, 

pursuant to § 80.602(d). 

(f) Changes to registration 

information. Any company or entity 

shall submit updated registration 

information to the Administrator within 

30 days of any occasion when the 

registration information previously 

supplied for an entity, or any of its 

registered facilities, becomes incomplete 

or inaccurate. 

(g) Issuance of registration numbers. 

EPA will supply a registration number 

to each entity and a facility registration 

number to each of an entity’s facilities 

that is identified, which shall be used in 

all reports to the Administrator. 

■ 25. Section 80.598 is amended as 

follows: 

■ a. By revising paragraphs (a)(2)(i)(A) 

through (F). 

■ b. By adding paragraph (a)(2)(i)(H). 

■ c. By revising paragraph (a)(2)(v) 

introductory text. 

■ d. By adding paragraph (a)(3)(xv). 

■ e. By revising paragraphs (b)(4)(i), 

(b)(4)(ii), (b)(7)(i), (b)(7)(ii), (b)(8), 

(b)(9)(ii), (b)(9)(viii), and (b)(9)(x) 

introductory text. 

§ 80.598 What are the designation 

requirements for refiners, importers, and 

distributors? 

(a) * * * 

(2) * * * 

(i) * * * 

(A) Motor vehicle, nonroad, 

locomotive or marine (MVNRLM) diesel 

fuel. 

(B) Heating oil. 

(C) Jet fuel. 

(D) Kerosene. 

(E) No. 4 fuel. 

(F) Distillate fuel for export only. 

* * * * * 

(H) ECA marine fuel. This designation 

may be used beginning June 1, 2014, 

and fuel designated as such is subject to 

the restrictions in paragraph (a)(3)(xv) of 

this section. 

* * * * * 

(v) From June 1, 2006, through May 

31, 2010, any batch designated as motor 

vehicle diesel fuel must also be 

designated according to one of the 

following distillation classifications that 

most accurately represents the fuel: 

* * * * * 

(3) * * * 

(xv) Beginning June 1, 2014, any fuel 

designated as ECA marine fuel will be 

subject to all the following restrictions: 

(A) Such fuel may not exceed a sulfur 

level of 1,000 ppm. 

(B) Such fuel may only be produced, 

distributed, sold, and purchased for use 

in C3 marine vessels. 

(b) * * * 

(4) * * * 

(i) #1D 500 ppm sulfur motor vehicle 

diesel fuel. 

(ii) #2D 500 ppm sulfur motor vehicle 

diesel fuel. 

* * * * * 

(7) * * * 

(i) 500 ppm sulfur NRLM diesel fuel. 

(ii) Heating oil. 

* * * * * 

(8) Beginning June 1, 2014, whenever 

custody of a batch of distillate or 

residual fuel (other than jet fuel, 

kerosene, No. 4 fuel, fuel for export, fuel 

intended for use outside an ECA, or fuel 

otherwise allowed to be used under 40 

CFR part 1043) having a sulfur content 

greater than 15 ppm is transferred to 

another facility, the entity transferring 

custody must accurately and clearly 

designate the batch as one of the 

following and specify its volume: 

(i) ECA marine fuel. 

(ii) Heating oil. 

(iii) Exempt distillate fuels such as 

fuels that are covered by a national 

security exemption under § 80.606, fuels 


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that are used for purposes of research 

and development pursuant to § 80.607, 

and fuels used in the U.S. Territories 

pursuant to § 80.608 (including 

additional identifying information). 

(9) * * * 

(ii) Until June 1, 2014, any distillate 

fuel containing greater than or equal to 

0.10 milligrams per liter of marker 

solvent yellow 124 required under 

§ 80.510(d), (e), or (f) must be designated 

as heating oil except that from June 1, 

2010, through September 30, 2012, it 

may also be designated as LM diesel 

fuel as specified under § 80.510(e). 

* * * * * 

(viii) For facilities in areas other than 

those specified in § 80.510(g)(1) and (2), 

batches or portions of batches of 

unmarked distillate received designated 

as heating oil may be re-designated as 

NRLM or LM diesel fuel only if all the 

following restrictions are met: 

(A) From June 1, 2007, through May 

31, 2010, for any compliance period, the 

volume of high sulfur NRLM diesel fuel 

delivered from a facility cannot be 

greater than the volume received, unless 

the volume of heating oil delivered from 

the facility is also greater than the 

volume it received by an equal or 

greater proportion, as calculated in 

§ 80.599(c)(2). 

(B) From June 1, 2010, through May 

31, 2014, for any compliance period, the 

volume of fuel designated as heating oil 

delivered from a facility cannot be less 

than the volume of fuel designated as 

heating oil received, as calculated in 

§ 80.599(c)(4). 

* * * * * 

(x) Notwithstanding the provisions of 

paragraphs (b)(5) and (8) of this section, 

beginning October 1, 2007: 

* * * * * 

■ 26. Section 80.599 is amended as 

follows: 

■ a. By revising paragraph (a)(1). 

■ b. By removing and reserving 

paragraph (a)(2). 

■ c. By revising paragraph (e)(4). 

§ 80.599 How do I calculate volume 

balances for designation purposes? 

(a) * * * 

(1) The annual compliance periods 

are shown in the following table: 

Beginning date of 

annual compliance 

period 

Ending date of annual 

compliance period 

June 1, 2006 ............. May 31, 2007. 

June 1, 2007 ............. June 30, 2008. 

July 1, 2008 .............. June 30, 2009. 

July 1, 2009 .............. May 31, 2010. 

June 1, 2010 ............. June 30, 2011. 

July 1, 2011 .............. May 31, 2012. 

June 1, 2012 ............. June 30, 2013. 

July 1, 2013 .............. May 31, 2014. 

(2) [Reserved] 

* * * * * 

(e) * * * 

(4) The following calculation may be 

used to account for wintertime blending 

of kerosene and the blending of nonpetroleum diesel: 

#2MV500O≤ #2MV500I + #2MV500P ¥ 

#2MV500INVCHG + 0.2 * (#1MV15I + 

#2MV15I + NPMV15I) 

Where: 

#1MV15I = the total volume of fuel received 

during the compliance period that is 

designated as #1D 15 ppm sulfur motor 

vehicle diesel fuel. Any motor vehicle 

diesel fuel produced by or imported into 

the facility shall not be included in this 

volume. 

NPMV15I = the total volume of fuel received 

during the compliance period that is 

designated as NP15 ppm sulfur motor 

vehicle diesel fuel. Any motor vehicle 

diesel fuel produced by or imported into 

the facility shall not be included in this 

volume. 

#1MV15P = the total volume of fuel produced 

by or imported into the facility during 

the compliance period that was 

designated as #1D 15 ppm sulfur motor 

vehicle diesel fuel when it was 

delivered. 

* * * * * 

■ 27. Section 80.600 is amended as 

follows: 

■ a. By revising paragraphs (a)(5) and 

(a)(12). 

■ b. By revising paragraphs (b)(1)(v)(A) 

and (B). 

■ c. By revising paragraph (b)(3). 

■ d. By revising paragraph (i). 

■ e. By revising paragraphs (o)(1) and 

(o)(2). 

§ 80.600 What records must be kept for 

purposes of the designate and track 

provisions? 

(a) * * * 

(5) Any refiner or importer shall 

maintain the records specified in 

paragraphs (a)(6) through (10) of this 

section for each batch of distillate or 

residual fuel that it transfers custody of 

and designates from June 1, 2014, and 

later as any of the following categories: 

(i) Heating oil. 

(ii) ECA marine fuel. 

* * * * * 

(12) Records must be maintained that 

demonstrate compliance with a refiner’s 

compliance plan required under 

§ 80.554, for distillate fuel designated as 

high sulfur NRLM diesel fuel and 

delivered from June 1, 2007 through 

May 31, 2010, for distillate fuel 

designated as 500 ppm sulfur NR diesel 

fuel and delivered from June 1, 2010, 

through May 31, 2012, and for distillate 

fuel designated as 500 ppm sulfur 

NRLM diesel fuel and delivered from 

June 1, 2012, through May 31, 2014, in 

the areas specified in § 80.510(g)(2). 

* * * * * 

(b) * * * 

(1) * * * 

(v) For each facility that receives fuel 

designated as heating oil, records for 

each batch of distillate or residual fuel 

with any of the following designations 

for which custody is received or 

delivered as well as any batches 

produced from June 1, 2014, and 

beyond: 

(A) 1,000 ppm sulfur ECA marine 

fuel. 

(B) Heating oil. 

* * * * * 

(3) Records that clearly and accurately 

identify the total volume in gallons of 

each designated fuel identified under 

paragraph (b)(1) of this section 

transferred over each of the compliance 

periods, and over the periods from June 

1, 2006 to the end of each compliance 

period. The records shall be maintained 

separately for each fuel designated 

under paragraph (b)(1) of this section, 

and for each EPA entity and facility 

registration number from whom the fuel 

was received or to whom it was 

delivered. For batches of fuel received 

from facilities without an EPA facility 

registration number: 

(i) Any batches of fuel received 

marked pursuant to § 80.510(d) or (f) 

shall be deemed to be designated as 

heating oil. 

(ii) Any batches of fuel received 

marked pursuant to § 80.510(e) shall be 

deemed to be designated as heating oil 

or LM diesel fuel. 

(iii) Any batches of fuel received on 

which taxes have been paid pursuant to 

Section 4082 of the Internal Revenue 

Code (26 CFR 48.4082) shall be deemed 

to be designated as motor vehicle diesel 

fuel. 

(iv) Any 500 ppm sulfur diesel fuel 

dyed pursuant to § 80.520(b) and not 

marked pursuant to § 80.510(d) or (f) 

shall be deemed to be designated as 

NRLM diesel fuel. 

(v) Any diesel fuel with less than or 

equal to 500 ppm sulfur which is dyed 

pursuant to § 80.520(b) and not marked 

pursuant to § 80.510(e) shall be deemed 

to be NR diesel fuel. 

(vi) Beginning June 1, 2014, any 

batches of fuel with greater than 15 ppm 

sulfur, but less than or equal to 1,000 

ppm sulfur, and not designated as 

heating oil shall be deemed to be 1,000 

ppm ECA marine fuel. 

* * * * * 

(i) Additional records that must be 

kept by mobile facilities. Any registered 

mobile facility must keep records of all 

contracts from any contracted 


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components (e.g., tank truck, barge, 

marine tanker, rail car, etc.) in each of 

its registered mobile facilities. 

* * * * * 

(o) * * * 

(1) Any aggregated facility consisting 

of a refinery and truck loading terminal 

shall maintain records of all the 

following information for each batch of 

distillate fuel (and/or residual fuel with 

a sulfur level of 1,000 ppm or less that 

is intended for use in an ECA) produced 

by the refinery and sent over the 

aggregated facility’s truck loading 

terminal rack: 

(i) The batch volume. 

(ii) The batch number, assigned under 

the batch numbering procedures under 

§§ 80.65(d)(3) and 80.502(d)(1). 

(iii) The date of production. 

(iv) A record designating the batch as 

distillate or residual fuel meeting the 

500 ppm, 15 ppm, or 1,000 ppm ECA 

marine sulfur standard. 

(v) A record indicating the volumes 

that were either taxed, dyed, or dyed 

and marked. 

(2) Volume reports for all distillate 

fuel (and/or residual fuel with a sulfur 

level of 1,000 ppm or less that is 

intended for use in an ECA) from 

external sources (i.e., from another 

refiner or importer), as described in 

§ 80.601(f)(2), sent over the aggregated 

facility’s truck rack. 

■ 28. Section 80.601 is amended by 

revising paragraph (b)(3)(x) to read as 

follows: 

§ 80.601 What are the reporting 

requirements for purposes of the designate 

and track provisions? 

* * * * * 

(b) * * * 

(3) * * * 

(x) Beginning with the report due 

August 31, 2011, and ending with the 

report due August 31, 2012, the volume 

balance under §§ 80.598(b)(9)(ix) and 

80.599(d)(2). 

* * * * * 

■ 29. Section 80.602 is amended as 

follows: 

■ a. By revising the section heading. 

■ b. By revising paragraphs (a) 

introductory text, (a)(2) introductory 

text, and (a)(3). 

■ c. By revising paragraphs (b) 

introductory text, (b)(4)(i), and (b)(4)(ii). 

■ d. By revising paragraphs (g)(1) and 

(g)(2). 

§ 80.602 What records must be kept by 

entities in the NRLM diesel fuel, ECA marine 

fuel, and diesel fuel additive production, 

importation, and distribution systems? 

(a) Records that must be kept by 

parties in the NRLM diesel fuel, ECA 

marine fuel and diesel fuel additive 

production, importation, and 

distribution systems. Beginning June 1, 

2007, or June 1, 2006, if that is the first 

period credits are generated under 

§ 80.535, any person who produces, 

imports, sells, offers for sale, dispenses, 

distributes, supplies, offers for supply, 

stores, or transports nonroad, 

locomotive or marine diesel fuel, or 

ECA marine fuel (beginning June 1, 

2014) subject to the provisions of this 

subpart, must keep all the following 

records: 

* * * * * 

(2) For any sampling and testing for 

sulfur content for a batch of NRLM 

diesel fuel produced or imported and 

subject to the 15 ppm sulfur standard or 

any sampling and testing for sulfur 

content as part of a quality assurance 

testing program, and any sampling and 

testing for cetane index, aromatics 

content, marker solvent yellow 124 

content or dye solvent red 164 content 

of NRLM diesel fuel, ECA marine fuel, 

NRLM diesel fuel additives or heating 

oil: 

* * * * * 

(3) The actions the party has taken, if 

any, to stop the sale or distribution of 

any NRLM diesel fuel or ECA marine 

fuel found not to be in compliance with 

the sulfur standards specified in this 

subpart, and the actions the party has 

taken, if any, to identify the cause of any 

noncompliance and prevent future 

instances of noncompliance. 

(b) Additional records to be kept by 

refiners and importers of NRLM diesel 

fuel and ECA marine fuel. Beginning 

June 1, 2007, or June 1, 2006, pursuant 

to the provisions of §§ 80.535 or 

80.554(d) (or June 1, 2014, pursuant to 

the provisions of § 80.510(k)), any 

refiner producing distillate or residual 

fuel subject to a sulfur standard under 

§§ 80.510, 80.513, 80.536, 80.554, 

80.560, or 80.561, for each of its 

refineries, and any importer importing 

such fuel separately for each facility, 

shall keep records that include the 

following information for each batch of 

NRLM diesel fuel, ECA marine fuel, or 

heating oil produced or imported: 

* * * * * 

(4) * * * 

(i) NRLM diesel fuel, NR diesel fuel, 

LM diesel fuel, ECA marine fuel, or 

heating oil, as applicable. 

(ii) Meeting the 500 ppm sulfur 

standard of § 80.510(a), the 15 ppm 

sulfur standard of § 80.510(b) and (c), 

the 1,000 ppm sulfur standard of 

§ 80.510(k), or other applicable 

standard. 

* * * * * 

(g) * * * 

(1) All the following information for 

each batch of distillate fuel (or residual 

fuel with a sulfur level of 1,000 ppm or 

less if such fuel is intended for use in 

an ECA) produced by the refinery and 

sent over the aggregated facility’s truck 

rack: 

(i) The batch volume. 

(ii) The batch number, assigned under 

the batch numbering procedures under 

§§ 80.65(d)(3) and 80.502(d)(1). 

(iii) The date of production. 

(iv) A record designating the batch as 

one of the following: 

(A) NRLM diesel fuel, NR diesel fuel, 

LM diesel fuel, ECA marine fuel, or 

heating oil, as applicable. 

(B) Meeting the 500 ppm sulfur 

standard of § 80.510(a), the 15 ppm 

sulfur standard of § 80.510(b) and (c), 

the 1,000 ppm sulfur standard of 

§ 80.510(k), or other applicable 

standard. 

(C) Dyed or undyed with visible 

evidence of solvent red 164. 

(D) Marked or unmarked with solvent 

yellow 124. 

(2) Hand-off reports for all distillate 

fuel (or residual fuel with a sulfur level 

of 1,000 ppm or less if such fuel is 

intended for use in an ECA) from 

external sources (i.e., from another 

refiner or importer), as described in 

§ 80.601(f)(2). 

■ 30. Section 80.606 is amended as 

follows: 

■ a. By revising the section heading. 

■ b. By revising paragraph (a) 

introductory text and paragraph (a)(1). 

■ c. By revising paragraph (b). 

■ d. By adding paragraph (c). 

§ 80.606 What national security exemption 

applies to fuels covered under this 

subpart? 

(a) The standards of all the fuels listed 

in paragraph (b) of this section do not 

apply to fuel that is produced, imported, 

sold, offered for sale, supplied, offered 

for supply, stored, dispensed, or 

transported for use in any of the 

following: 

(1) Tactical military motor vehicles or 

tactical military nonroad engines, 

vehicles or equipment, including 

locomotive and marine, having an EPA 

national security exemption from the 

motor vehicle emission standards under 

40 CFR 85.1708, or from the nonroad 

engine emission standards under 40 

CFR part 89, 92, 94, 1042, or 1068. 

* * * * * 

(b) The exempt fuel must meet any of 

the following: 

(1) The motor vehicle diesel fuel 

standards of § 80.520(a)(1), (a)(2), and 

(c). 

(2) The nonroad, locomotive, and 

marine diesel fuel standards of 

§ 80.510(a), (b), and (c). 


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(3) The 1,000 ppm ECA marine fuel 

standards of § 80.510(k). 

(c) The exempt fuel must meet all the 

following conditions: 

(1) It must be accompanied by 

product transfer documents as required 

under § 80.590. 

(2) It must be segregated from nonexempt MVNRLM diesel fuel and ECA 

marine fuel at all points in the 

distribution system. 

(3) It must be dispensed from a fuel 

pump stand, fueling truck or tank that 

is labeled with the appropriate 

designation of the fuel, such as ‘‘JP–5’’ or 

‘‘JP–8’’. 

(4) It may not be used in any motor 

vehicles or nonroad engines, equipment 

or vehicles, including locomotive and 

marine, other than the vehicles, engines, 

and equipment referred to in paragraph 

(a) of this section. 

■ 31. Section 80.607 is amended as 

follows: 

■ a. By revising the section heading. 

■ b. By revising paragraph (a). 

■ c. By revising paragraphs (c)(3)(iv) 

and (c)(4). 

■ d. By revising paragraphs (d)(2), 

(d)(3), and (d)(4). 

■ e. By revising paragraph (e)(1). 

■ f. By revising paragraph (f). 

§ 80.607 What are the requirements for 

obtaining an exemption for diesel fuel or 

ECA marine fuel used for research, 

development or testing purposes? 

(a) Written request for a research and 

development exemption. Any person 

may receive an exemption from the 

provisions of this subpart for diesel fuel 

or ECA marine fuel used for research, 

development, or testing purposes by 

submitting the information listed in 

paragraph (c) of this section to: Director, 

Transportation and Regional Programs 

Division (6406J), U.S. Environmental 

Protection Agency, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460 

(postal mail); or Director, Transportation 

and Regional Programs Division, U.S. 

Environmental Protection Agency, 1310 

L Street, NW., 6th floor, Washington, DC 

20005 (express mail/courier); and 

Director, Air Enforcement Division 

(2242A), U.S. Environmental Protection 

Agency, Ariel Rios Building, 1200 

Pennsylvania Avenue, NW., 

Washington, DC 20460. 

* * * * * 

(c) * * * 

(3) * * * 

(iv) The quantity of fuel which does 

not comply with the requirements of 

§§ 80.520 and 80.521 for motor vehicle 

diesel fuel, or § 80.510 for NRLM diesel 

fuel or ECA marine fuel. 

(4) With regard to control, a 

demonstration that the program affords 

EPA a monitoring capability, including 

all the following: 

(i) The site(s) of the program 

(including facility name, street address, 

city, county, State, and zip code). 

(ii) The manner in which information 

on vehicles and engines used in the 

program will be recorded and made 

available to the Administrator upon 

request. 

(iii) The manner in which information 

on the fuel used in the program 

(including quantity, fuel properties, 

name, address, telephone number and 

contact person of the supplier, and the 

date received from the supplier), will be 

recorded and made available to the 

Administrator upon request. 

(iv) The manner in which the party 

will ensure that the research and 

development fuel will be segregated 

from motor vehicle diesel fuel, NRLM 

diesel fuel, or ECA marine fuel, as 

applicable, and how fuel pumps will be 

labeled to ensure proper use of the 

research and development fuel. 

(v) The name, address, telephone 

number and title of the person(s) in the 

organization requesting an exemption 

from whom further information on the 

application may be obtained. 

(vi) The name, address, telephone 

number and title of the person(s) in the 

organization requesting an exemption 

who is responsible for recording and 

making available the information 

specified in this paragraph (c), and the 

location where such information will be 

maintained. 

(d) * * * 

(2) The research and development 

fuel must be designated by the refiner or 

supplier, as applicable, as research and 

development fuel. 

(3) The research and development 

fuel must be kept segregated from nonexempt MVNRLM diesel fuel and ECA 

marine fuel at all points in the 

distribution system. 

(4) The research and development 

fuel must not be sold, distributed, 

offered for sale or distribution, 

dispensed, supplied, offered for supply, 

transported to or from, or stored by a 

fuel retail outlet, or by a wholesale 

purchaser-consumer facility, unless the 

wholesale purchaser-consumer facility 

is associated with the research and 

development program that uses the fuel. 

* * * * * 

(e) * * * 

(1) The volume of fuel subject to the 

approval shall not exceed the estimated 

amount under paragraph (c)(3)(iv) of 

this section, unless EPA grants a greater 

amount in writing. 

* * * * * 

(f) Effects of exemption. Motor vehicle 

diesel fuel, NRLM diesel fuel, or ECA 

marine fuel that is subject to a research 

and development exemption under this 

section is exempt from other provisions 

of this subpart provided that the fuel is 

used in a manner that complies with the 

purpose of the program under paragraph 

(c) of this section and the requirements 

of this section. 

* * * * * 

■ 32. Section 80.608 is revised to read 

as follows: 

§ 80.608 What requirements apply to 

diesel fuel and ECA marine fuel for use in 

the Territories? 

The sulfur standards of § 80.520(a)(1) 

and (c) related to motor vehicle diesel 

fuel, of § 80.510(a), (b), and (c) related 

to NRLM diesel fuel, and of § 80.510(k) 

related to ECA marine fuel, do not apply 

to fuel that is produced, imported, sold, 

offered for sale, supplied, offered for 

supply, stored, dispensed, or 

transported for use in the Territories of 

Guam, American Samoa or the 

Commonwealth of the Northern Mariana 

Islands, provided that such diesel fuel is 

all the following: 

(a) Designated by the refiner or 

importer as high sulfur diesel fuel only 

for use in Guam, American Samoa, or 

the Commonwealth of the Northern 

Mariana Islands. 

(b) Used only in Guam, American 

Samoa, or the Commonwealth of the 

Northern Mariana Islands. 

(c) Accompanied by documentation 

that complies with the product transfer 

document requirements of 

§ 80.590(b)(1). 

(d) Segregated from non-exempt 

MVNRLM diesel fuel and/or nonexempt ECA marine fuel at all points in 

the distribution system from the point 

the fuel is designated as exempt fuel 

only for use in Guam, American Samoa, 

or the Commonwealth of the Northern 

Mariana Islands, while the exempt fuel 

is in the United States (or the United 

States Emission Control Area) but 

outside these Territories. 

■ 33. Section 80.610 is amended as 

follows: 

■ a. By revising paragraph (a)(1). 

■ b. By revising paragraph (b). 

■ c. By revising paragraph (c). 

■ d. By revising paragraphs (e)(3)(iii) 

and (e)(4)(iii) and adding paragraph 

(e)(6). 

■ e. By revising paragraph (g). 

§ 80.610 What acts are prohibited under 

the diesel fuel sulfur program? 

* * * * * 

(a) * * * 

(1) Produce, import, sell, offer for sale, 

dispense, supply, offer for supply, store 

or transport motor vehicle diesel fuel, 


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NRLM diesel fuel, ECA marine fuel or 

heating oil that does not comply with 

the applicable standards, dye, marking 

or any other product requirements 

under this subpart I and 40 CFR part 69, 

except as allowed by 40 CFR part 1043 

for ECA marine fuel. 

* * * * * 

(b) Designation and volume balance 

violation. Produce, import, sell, offer for 

sale, dispense, supply, offer for supply, 

store or transport motor vehicle diesel, 

NRLM diesel fuel, ECA marine fuel, 

heating oil or other fuel that does not 

comply with the applicable designation 

or volume balance requirements under 

§§ 80.598 and 80.599. 

(c) Additive violation. (1) Produce, 

import, sell, offer for sale, dispense, 

supply, offer for supply, store or 

transport any fuel additive for use at a 

downstream location that does not 

comply with the applicable 

requirements of § 80.521. 

(2) Blend or permit the blending into 

motor vehicle diesel fuel, NRLM diesel 

fuel, or ECA marine fuel at a 

downstream location, or use, or permit 

the use, in motor vehicle diesel fuel, 

NRLM diesel fuel, or ECA marine fuel, 

of any additive that does not comply 

with the applicable requirements of 

§ 80.521. 

* * * * * 

(e) * * * 

(3) * * * 

(iii) This prohibition begins December 

1, 2014, in all other areas. 

(4) * * * 

(iii) This prohibition begins December 

1, 2014, in all other areas. 

* * * * * 

(6) Beginning January 1, 2015, 

introduce (or permit the introduction of) 

any fuel with a sulfur content greater 

than 1,000 ppm for use in a Category 3 

marine vessel within an ECA, except as 

allowed by 40 CFR part 1043. This 

prohibition is in addition to other 

prohibitions in this section. 

* * * * * 

(g) Cause violating fuel or additive to 

be in the distribution system. Cause 

motor vehicle diesel fuel, NRLM diesel 

fuel, or ECA marine fuel to be in the 

diesel fuel distribution system which 

does not comply with the applicable 

standard, dye or marker requirements or 

the product segregation requirements of 

this subpart I, or cause any fuel additive 

to be in the fuel additive distribution 

system which does not comply with the 

applicable sulfur standards under 

§ 80.521. 

■ 34. Section 80.612 is amended by 

revising paragraph (b) introductory text 

to read as follows: 

§ 80.612 Who is liable for violations of this 

subpart? 

* * * * * 

(b) Persons liable for failure to comply 

with other provisions of this subpart. 

Any person who: 

* * * * * 

■ 35. Section 80.613 is amended by 

revising paragraph (a)(1)(iv) 

introductory text to read as follows: 

§ 80.613 What defenses apply to persons 

deemed liable for a violation of a prohibited 

act under this subpart? 

(a) * * * 

(1) * * * 

(iv) For refiners and importers of 

diesel fuel subject to the 15 ppm sulfur 

standard under § 80.510(b) or (c) or 

§ 80.520(a)(1), the 500 ppm sulfur 

standard under § 80.510(a) or 

§ 80.520(c), and/or the 1,000 ppm sulfur 

standard under § 80.510(k), test results 

that— 

* * * * * 

■ 36. Section 80.615 is amended by 

revising paragraphs (b)(2) and (b)(4) to 

read as follows: 

§ 80.615 What penalties apply under this 

subpart? 

* * * * * 

(b) * * * 

(2) Any person liable under 

§ 80.612(a)(2) for causing motor vehicle 

diesel fuel, NRLM diesel fuel, ECA 

marine fuel, heating oil, or other 

distillate fuel to be in the distribution 

system which does not comply with an 

applicable standard or requirement of 

this subpart I, except as allowed under 

40 CFR part 1043, is subject to a 

separate day of violation for each and 

every day that the noncomplying fuel 

remains any place in the diesel fuel 

distribution system. 

* * * * * 

(4) For purposes of this paragraph (b): 

(i) The length of time the motor 

vehicle diesel fuel, NRLM diesel fuel, 

ECA marine fuel, heating oil, or other 

distillate fuel in question remained in 

the diesel fuel distribution system is 

deemed to be 25 days, except as further 

specified in paragraph (b)(4)(ii) of this 

section. 

(ii) The length of time is deemed not 

to be 25 days if a person subject to 

liability demonstrates by reasonably 

specific showings, by direct or 

circumstantial evidence, that the noncomplying motor vehicle, NR diesel 

fuel, NRLM diesel fuel, ECA marine 

fuel, heating oil, or distillate fuel 

remained in the distribution system for 

fewer than or more than 25 days. 

* * * * * 

PART 85—CONTROL OF AIR 

POLLUTION FROM MOBILE SOURCES 

■ 37. The authority citation for part 85 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart R—[Amended] 

■ 38. Section 85.1703 is amended by 

revising the section heading and 

paragraph (a) introductory text to read 

as follows: 

§ 85.1703 Definition of motor vehicle. 

(a) For the purpose of determining the 

applicability of section 216(2), a vehicle 

which is self-propelled and capable of 

transporting a person or persons or any 

material or any permanently or 

temporarily affixed apparatus shall be 

deemed a motor vehicle, unless any one 

or more of the criteria set forth below 

are met, in which case the vehicle shall 

be deemed not a motor vehicle: 

* * * * * 

■ 39. A new § 85.1715 is added to 

subpart R to read as follows: 

§ 85.1715 Aircraft meeting the definition of 

motor vehicle. 

This section applies for aircraft 

meeting the definition of motor vehicle 

in § 85.1703. 

(a) For the purpose of this section, 

aircraft means any vehicle capable of 

sustained air travel above treetop 

heights. 

(b) The standards, requirements, and 

prohibitions of 40 CFR part 86 do not 

apply for aircraft or aircraft engines. 

Standards apply separately to certain 

aircraft engines, as described in 40 CFR 

part 87. 

PART 86—CONTROL OF EMISSIONS 

FROM NEW AND IN-USE HIGHWAY 

VEHICLES AND ENGINES 

■ 40. The authority citation for part 86 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

§§ 86.000–15, 86.000–21, 86000–23, 86.000– 

25, 86.001–1, 86.087–38, 86.090–8, 86.091– 

10, 86.094–1. 86.094–15, 86.094–17, 86.094– 

23, 86.094–9, 86.096–9, 86.096–10, 86.096– 

11, 86.096–14, 86.096–23, 86.098–7, 86.098– 

8, 86.098–11, 86.098–15, 86.098–17, 86.098– 

21, 86.098–22, 86.099–1, and 86.099–30 

[Removed] 

■ 41. Subpart A is amended by 

removing the following sections: 

86.000–15, 86.000–21, 86.000–23, 

86.000–25, 86.001–1, 86.087–38, 

86.090–8, 86.091–10, 86.094–1, 86.094– 

15, 86.094–17, 86.094–23, 86.094–9, 

86.096–9, 86.096–10, 86.096–11, 


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86.096–14, 86.096–23, 86.098–7, 

86.098–8, 86.098–11, 86.098–15, 

86.098–17, 86.098–21, 86.098–22, 

86.099–1, 86.099–30. 

§ 86.000–28—[Amended] 

■ 42. Section 86.000–28 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraph (a)(3). 

■ c. By removing paragraph (a)(4)(i) 

introductory text. 

■ d. By removing and reserving 

paragraphs (a)(4)(i)(A) through 

(a)(4)(i)(B)(2)(i). 

■ e. By removing paragraphs 

(a)(4)(i)(B)(2)(iii) through (a)(4)(i)(D)(2). 

■ f. By removing and reserving 

paragraph (a)(4)(ii)(B). 

■ g. By removing paragraphs (a)(4)(ii)(C) 

and (a)(4)(iv) and (v). 

■ h. By removing and reserving 

paragraphs (a)(5) and (a)(6). 

■ i. By removing paragraph (a)(7)(i) 

introductory text. 

■ j. By removing and reserving 

paragraphs (a)(7)(ii) through (b)(4)(i). 

■ k. By removing paragraphs (b)(7) 

through (h). 

■ 43. Section 86.008–10 is amended by 

revising paragraph (a)(2) to read as 

follows: 

§ 86.008–10 Emission standards for 2008 

and later model year Otto-cycle heavy-duty 

engines and vehicles. 

* * * * * 

(a) * * * 

(2) The standards set forth in 

paragraph (a)(1) of this section refer to 

the exhaust emitted over the operating 

schedule set forth in paragraph (f)(1) of 

Appendix I to this part, and measured 

and calculated in accordance with the 

procedures set forth in subpart N or P 

of this part: 

(i) Perform the test interval set forth 

in paragraph (f)(1) of Appendix I of this 

part with a cold-start according to 40 

CFR part 1065, subpart F. This is the 

cold-start test interval. 

(ii) Shut down the engine after 

completing the test interval and allow 

20 minutes to elapse. This is the hot 

soak. 

(iii) Repeat the test interval. This is 

the hot-start test interval. 

(iv) Calculate the total emission mass 

of each constituent, m, and the total 

work, W, over each test interval 

according to 40 CFR 1065.650. 

(v) Determine your engine’s brakespecific emissions using the following 

calculation, which weights the 

emissions from the cold-start and hotstart test intervals: 

brake-specific emissions - hot-start

-

= m m + ⋅

W

cold start

cold sta

6

rt + ⋅ 6 Whot-start

* * * * * 

■ 44. Section 86.010–38 is amended by 

revising paragraphs (j) introductory text 

and (j)(15)(i) introductory text to read as 

follows: 

§ 86.010–38 Maintenance instructions. 

* * * * * 

(j) The following provisions describe 

requirements related to emission control 

diagnostic service information for 

heavy-duty engines used in vehicles 

over 14,000 pounds gross vehicle weight 

(GVW): 

* * * * * 

(15) * * * 

(i) By July 1, 2013, manufacturers 

shall make available for sale to the 

persons specified in paragraph (j)(3)(i) 

of this section their own manufacturerspecific diagnostic tools at a fair and 

reasonable cost. These tools shall also 

be made available in a timely fashion 

either through the manufacturer Web 

site or through a manufacturerdesignated intermediary. Upon 

Administrator approval, manufacturers 

will not be required to make available 

manufacturer-specific tools with 

reconfiguration capabilities if they can 

demonstrate to the satisfaction of the 

Administrator that these tools are not 

essential to the completion of an 

emissions-related repair, such as 

recalibration. As a condition of 

purchase, manufacturers may request 

that the purchaser take all necessary 

training offered by the engine 

manufacturer. Any required training 

materials and classes must comply with 

the following: 

* * * * * 

§ 86.091–7 [Amended] 

■ 45. Section 86.091–7 is amended by 

removing paragraph (a)(3) and removing 

and reserving paragraphs (c)(3) and 

(d)(2). 

§ 86.094–7 [Amended] 

■ 46. Section 86.094–7 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (a) introductory text through 

(a)(2). 

■ c. By removing and reserving 

paragraphs (b) through (c)(2), (c)(4) 

through (d)(1)(v), (d)(3) through (g), and 

(h)(1). 

■ d. By removing paragraphs (h)(6) and 

(i). 

§ 86.094–14 [Amended] 

■ 47. Section 86.094–14 is amended as 

follows: 

■ a. By removing paragraph 

(c)(7)(i)(C)(4). 

■ b. By removing and reserving 

paragraph (c)(11)(ii)(B)(1). 

■ c. By removing paragraphs 

(c)(11)(ii)(B)(16) through (18). 

■ d. By removing and reserving 

paragraphs (c)(11)(ii)(C) and 

(c)(11)(ii)(D)(1) through (6) 

§ 86.094–21 [Amended] 

■ 48. Section 86.094–21 is amended by 

removing and reserving paragraph 

(b)(6). 

§ 86.094–22 [Amended] 

■ 49. Section 86.094–22 is amended by 

removing and reserving paragraph 

(d)(1). 

§ 86.094–26 [Amended] 

■ 50. Section 86.094–26 is amended as 

follows: 

■ a. By removing and reserving 

paragraph (a)(2). 

■ b. By removing the text of paragraph 

(a)(3) introductory text and the (a)(3)(i) 

paragraph heading. 

■ c. By removing and reserving 

paragraphs (a)(3)(i)(A), (a)(3)(i)(C), 

(a)(3)(ii)(C), and (a)(4)(i)(C). 

■ d. By removing paragraph (a)(6)(iii). 

■ e. By removing and reserving 

paragraphs (a)(9)(ii) and (b)(2)(i) and (ii). 

■ f. By removing paragraphs (b)(2)(iv) 

and (b)(4)(i)(C), and (D). 

■ g. By removing and reserving 

paragraphs (b)(4)(ii), (c), and (d)(2)(ii). 

§ 86.094–28 [Amended] 

■ 51. Section 86.094–28 is amended as 

follows: 

■ a. By removing and reserving 

paragraphs (a)(1) and (2). 

■ b. By removing the text of paragraphs 

(a)(4) introductory text and (a)(4)(i) 

introductory text. 

■ c. By removing and reserving 

paragraph (a)(4)(i)(B)(2)(ii). 


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■ d. By removing paragraph (a)(4)(i)(C). 

■ e. By removing and reserving 

paragraph (a)(4)(ii) and(iii). 

■ f. By removing paragraph (a)(4)(v). 

■ g. By removing paragraph and 

reserving (a)(7) introductory text. 

■ h. By removing and reserving 

paragraphs (a)(7)(i), (b)(1) and (2), and 

(b)(4)(ii). 

■ i. By removing paragraphs (b)(4)(iii) 

and (iv), (b)(5) through (8), and (c) and 

(d). 

§ 86.094–30 [Amended] 

■ 52. Section 86.094–30 is amended as 

follows: 

■ a. By removing and reserving 

paragraphs (a)(3) and (a)(4)(i) and (ii). 

■ b. By removing and reserving 

paragraph (a)(4)(iv) introductory text. 

■ c. By removing and reserving 

paragraphs (a)(10), (11), (13), 

(b)(1)(ii)(B), (b)(1)(ii)(D), and (b)(2). 

■ d. By removing and reserving 

paragraph (b)(4)(ii) introductory text. 

■ e. By removing and reserving 

paragraph (b)(4)(ii)(B). 

■ f. By removing paragraphs (b)(4)(iii) 

and (iv) and (f). 

§ 86.095–14 [Amended] 

■ 53. Section 86.095–14 is amended by 

removing the introductory text and 

removing and reserving paragraphs (a) 

through (c)(11)(ii)(B)(15) and 

(c)(11)(ii)(D)(7) through (c)(15). 

§ 86.095–23 [Amended] 

■ 54. Section 86.095–23 is amended as 

follows: 

■ a. By removing and reserving 

paragraphs (a) and (b). 

■ b. By removing and reserving 

paragraph (c)(2). 

■ c. By removing and reserving 

paragraphs (d) and (e). 

■ d. By removing and reserving 

paragraphs (h) through (k). 

§ 86.095–26 [Amended] 

■ 55. Section 86.095–26 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (a) through (b)(4)(i)(C) and 

(b)(4)(ii)(C). 

■ c. By removing paragraphs (b)(4)(iii) 

through (d). 

§ 86.095–30 [Amended] 

■ 56. Section 86.095–30 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (a)(1) through (a)(3) and 

(a)(4)(i) through (iii). 

■ c. By removing paragraphs 

(a)(4)(iv)(A) through (C). 

■ d. By removing and reserving 

paragraphs (a)(5) through (12). 

■ e. By removing paragraph (a)(14). 

■ f. By removing and reserving 

paragraph (b). 

■ g. By removing paragraphs (c) through 

(f). 

§ 86.095–35 [Amended] 

■ 57. Section 86.095–35 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (a)(2) introductory text 

through (a)(2)(iii)(C). 

■ c. By removing and reserving 

paragraph (c). 

§ 86.096–7 [Amended] 

■ 58. Section 86.096–7 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (a) through (h)(5). 

■ c. By removing the heading for 

paragraph (h)(6) introductory text and 

removing and reserving paragraph 

(h)(6)(i). 

■ d. By removing paragraph (h)(7)(vii). 

§ 86.096–8 [Amended] 

■ 59. Section 86.096–8 is amended as 

follows: 

■ a. By removing paragraph (a)(1)(iii). 

■ b. By removing and reserving 

paragraph (a)(2). 

■ c. By removing paragraph (a)(3). 

■ d. By removing and reserving 

paragraphs (b) introductory text through 

(b)(4). 

§ 86.096–21 [Amended] 

■ 60. Section 86.096–21 is amended by 

removing the introductory text and 

removing and reserving paragraphs (a) 

through (j). 

§ 86.096–24 [Amended] 

■ 61. Section 86.096–24 is amended as 

follows: 

■ a. By removing and reserving 

paragraphs (a)(5) through (7), (b)(1)(i) 

and (ii), and (b)(1)(vii). 

■ b. By removing and reserving 

paragraphs (b)(1)(viii) introductory text 

and (b)(1)(viii)(A). 

■ c. By removing and reserving 

paragraph (f). 

■ d. By removing paragraph (g)(3). 

§ 86.096–26 [Amended] 

■ 62. Section 86.096–26 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (a) and (b). 

■ c. By removing and reserving 

paragraphs (c)(1) through (c)(3). 

■ d. By removing paragraph (d). 

§ 86.096–30 [Amended] 

■ 63. Section 86.096–30 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (a)(1) through (14). 

■ c. By removing paragraphs (a)(19) 

through (24). 

■ d. By removing and reserving 

paragraph (b). 

■ e. By removing paragraphs (c) through 

(f). 

§ 86.097–9 [Amended] 

■ 64. Section 86.097–9 is amended as 

follows: 

■ a. By removing paragraph (a)(1)(iv). 

■ b. By removing and reserving 

paragraph (a)(2). 

■ c. By removing paragraph (a)(3). 

■ d. By removing and reserving 

paragraphs (b) and (d) through (f). 

§ 86.098–10 [Amended] 

■ 65. Section 86.098–10 is amended by 

removing and reserving paragraph (b). 

§ 86.098–23 [Amended] 

■ 66. Section 86.098–23 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (b)(2), (c), and (d)(2). 

■ c. By removing paragraph (d)(3). 

■ d. By removing and reserving 

paragraphs (f) through (g) and (l). 

§ 86.098–24 [Amended] 

■ 67. Section 86.098–24 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing paragraph (a) 

introductory text. 

■ c. By removing and reserving 

paragraphs (a)(1) through (4). 

■ d. By removing paragraph (a)(8) 

through (15). 

■ e. By removing and reserving 

paragraphs (b) introductory text 

and(b)(1) introductory text. 

■ f. By removing and reserving 

paragraphs (b)(1)(i) through (vi) and 

(b)(1)(viii)(B). 

■ g. By removing paragraphs (b)(1)(ix) 

through (xii). 

■ h. By removing and reserving 

paragraph (b)(2). 

■ i. By removing paragraphs (b)(3) and 

(c) through (h). 

§ 86.098–25 [Amended] 

■ 68. Section 86.098–25 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraph (a). 

■ c. By removing and reserving 

paragraph (b) introductory text. 


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■ d. By removing and reserving 

paragraphs (b)(1) through (2). 

■ e. By removing and reserving 

paragraph (b)(3) introductory text 

through (b)(3)(vi)(D). 

■ f. By removing paragraphs (b)(3)(vii), 

(b)(4) through (7), and (c) through (h). 

§ 86.098–26 [Amended] 

■ 69. Section 86.098–26 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (a)(1) and (2). 

■ c. By removing and reserving 

paragraphs (a)(3) introductory text and 

(a)(3)(i)(A) and (B). 

■ d. By removing paragraph (a)(3)(i)(D). 

■ e. By removing and reserving 

paragraph (a)(3)(ii)(A) and (B). 

■ h. By removing paragraphs (a)(3)(ii)(D) 

and (a)(4) through (11). 

■ i. By removing and reserving 

paragraph (b). 

■ j. By removing paragraphs (c) through 

(d). 

§ 86.098–28 [Amended] 

■ 70. Section 86.098–28 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (a)(1) through (a)(3). 

■ c. By removing and reserving 

paragraphs (a)(4)(i) introductory text, 

(a)(4)(i)(A) and (B), and (a)(4)(ii)(A) . 

■ d. By removing and reserving 

paragraphs (a)(4)(iii) and (iv). 

■ f. By removing and reserving 

paragraphs (a)(5) and (6), (a)(7)(i) and 

(ii), and (b). 

■ g. By removing paragraphs (c) through 

(h). 

§ 86.098–30 [Amended] 

■ 71. Section 86.098–30 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraphs (a)(1) through (18), (b)(1), 

and (b)(3). 

■ c. By removing and reserving 

paragraphs (b)(4) introductory text, 

(b)(4)(i), and (b)(4)(ii)(A). 

■ d. By removing paragraphs (b)(5) 

through (f). 

§ 86.099–8 [Amended] 

■ 72. Section 86.099–8 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraph (a)(1) introductory text. 

■ c. By removing and reserving 

paragraphs (a)(1)(i) and (ii), (b)(5), and 

(c). 

■ d. By removing paragraphs (e) through 

(k). 

§ 86.099–9 [Amended] 

■ 73. Section 86.099–9 is amended as 

follows: 

■ a. By removing the introductory text. 

■ b. By removing and reserving 

paragraph (a)(1) introductory text. 

■ c. By removing and reserving 

paragraphs (a)(1)(i) through (iii). 

■ d. By removing paragraph (c) through 

(k). 

Subpart B—[Amended] 

■ 74. Section 86.138–96 is amended by 

revising paragraph (k) to read as follows: 

§ 86.138–96 Hot soak test. 

* * * * * 

(k) For the supplemental two-diurnal 

test sequence (see § 86.130–96), perform 

a hot soak test as described in this 

section, except that the test shall be 

conducted within seven minutes after 

completion of the hot start exhaust test 

and temperatures throughout the hot 

soak measurement period must be 

between 68 ° and 86 °F. This hot soak 

test is followed by two consecutive 

diurnal heat builds, described in 

§ 86.133–96(p). 

* * * * * 

■ 75. Section 86.144–94 is amended by 

revising paragraph (c)(7)(ii) to read as 

follows: 

§ 86.144–94 Calculations; exhaust 

emissions. 

* * * * * 

(c) * * * 

(7) * * * 

(ii) For methanol-fueled vehicles, 

where fuel composition is CxHyOz as 

measured, or calculated, for the fuel 

used: 

DF =

X

x+ y x+ y z

CO HC CO C e e e CH OHe

100 ⋅

+⋅ − ( )

⎛

⎝

⎜

⎜

⎜

⎞

⎠

⎟

⎟

⎟

+ ++ +

2 42

3

3 76

2

.

CHCHOe ( ) ⋅ − 10 4

* * * * * 

Subpart E—[Amended] 

■ 76. Section 86.415–78 is amended by 

revising paragraph (b) to read as follows: 

§ 86.415–78 Production vehicles. 

* * * * * 

(b) Any manufacturer obtaining 

certification shall notify the 

Administrator of the number of vehicles 

of each engine family-engine 

displacement-emission control systemfuel system-transmission type-inertial 

mass category combination produced for 

sale in the United States during the 

preceding year. This report must be 

submitted every year within 45 days 

after the end of the model year. 

* * * * * 

Subpart G—Selective Enforcement 

Auditing of New Light-Duty Vehicles, 

Light-Duty Trucks, and Heavy-Duty 

Vehicles 

■ 77. The heading for subpart G is 

revised as set forth above. 

■ 78. Section 86.601–84 is amended by 

revising the introductory text to read as 

follows: 

§ 86.601–84 Applicability. 

The provisions of this subpart apply 

to light-duty vehicles, light-duty trucks, 

and heavy-duty vehicles. However, 

manufacturers that optionally certify 

heavy-duty vehicles based on chassis 

testing under § 86.1863–07 may choose 

instead to perform selective 

enforcement audits using the 

procedures specified in 40 CFR part 

1068, subpart E. References to ‘‘lightduty vehicle’’ or ‘‘LDT’’ in this subpart 

G shall be deemed to include light-duty 

trucks and heavy-duty vehicles as 

appropriate. 

* * * * * 

■ 79. Subpart K, consisting of § 86.1001, 

is revised to read as follows: 

Subpart K—Selective Enforcement 

Auditing of New Heavy-Duty Engines 

§ 86.1001 Applicability. 

(a) The selective enforcement auditing 

program described in 40 CFR part 1068, 


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subpart E, applies for all heavy-duty 

engines as described in this section. In 

addition, the provisions of 40 CFR 

1068.10 and 1068.20 apply for any 

selective enforcement audits of these 

engines. 

(b) For heavy-duty engines, the 

prescribed test procedure is the Federal 

Test Procedure as described in subparts 

I, N, and P of this part (including 

provisions of 40 CFR part 1065 as 

specified in this part), except that they 

shall not be subject to the test 

procedures specified in §§ 86.1360(b)(2) 

and (f), 86.1370, 86.1372, and 86.1380. 

The Administrator may, on the basis of 

a written application by a manufacturer, 

approve optional test procedures other 

than those in subparts I, N, and P of this 

part for any heavy-duty vehicle which is 

not susceptible to satisfactory testing 

using the procedures in subparts I, N, 

and P of this part. 

Subpart N—[Amended] 

■ 80. Section 86.1305–2010 is amended 

by revising paragraph (h)(2) to read as 

follows: 

§ 86.1305–2010 Introduction; structure of 

subpart. 

* * * * * 

(h) * * * 

(2) Follow the provisions of 40 CFR 

1065.342 to verify the performance of 

any sample dryers in your system. 

Correct your measurements according to 

40 CFR 1065.659, except use the value 

of Kw in § 86.1342–90(i) as the value of 

(1¥xH2Oexh) in Equation 1065.659–1. 

* * * * * 

Subpart T—[Amended] 

■ 81. Section 86.1910 is amended by 

revising paragraph (d) to read as 

follows: 

§ 86.1910 How must I prepare and test my 

in-use engines? 

* * * * * 

(d) You must test the selected engines 

while they remain installed in the 

vehicle. Use portable emission sampling 

equipment and field-testing procedures 

referenced in § 86.1375. Measure 

emissions of THC, NMHC (by any 

method specified in 40 CFR part 1065, 

subpart J), CO, NOX, PM (as 

appropriate), and CO2. Measure or 

determine O2 emissions using good 

engineering judgment. 

* * * * * 

PART 94—CONTROL OF EMISSIONS 

FROM MARINE COMPRESSION– 

IGNITION ENGINES 

■ 82. The authority citation for part 94 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 83. Section 94.1 is amended by 

revising paragraph (b)(3) to read as 

follows: 

§ 94.1 Applicability. 

* * * * * 

(b) * * * 

(3) Marine engines subject to the 

standards of 40 CFR part 1042, and 

marine engines that optionally certify 

(to the Tier 1 or Tier 2 standards) under 

the provisions of 40 CFR part 1042. Note 

that 40 CFR 1042.1 specifies that marine 

compression-ignition engines that are 

not certified under this part are subject 

to 40 CFR part 1042. Such engines may 

also be subject to the standards of this 

part 94. 

* * * * * 

■ 84. Section 94.12 is amended by 

adding paragraph (j) to read as follows: 

§ 94.12 Interim provisions. 

* * * * * 

(j) Transition to new category 

thresholds. Beginning model year 2012, 

engines with maximum engine power at 

or below 3700 kW with per-cylinder 

displacement at or above 5.0 liters and 

below 7.0 liters are Category 1 engines 

subject to 40 CFR part 1042. Similarly, 

beginning model year 2014, engines 

with maximum engine power above 

3700 kW with per-cylinder 

displacement at or above 5.0 liters and 

below 7.0 liters are Category 1 engines 

subject to 40 CFR part 1042. For 

purposes of this paragraph (j), maximum 

engine power has the meaning given in 

40 CFR 1042.901. 

Subpart J—[Amended] 

■ 85. Section 94.904 is amended by 

revising paragraph (a) to read as follows: 

§ 94.904 Exemptions. 

(a) Except as specified otherwise in 

this subpart, the provisions of §§ 94.904 

through 94.913 exempt certain new 

engines from the standards, other 

requirements, and prohibitions of this 

part, except for the requirements of this 

subpart and the requirements of 

§ 94.1104. Additional requirements may 

apply for imported engines; these are 

described in subpart I of this part. 

Engines may also be exempted from the 

standards of this part under the 

provisions of 40 CFR part 1042 or part 

1068. 

* * * * * 

PART 1027—FEES FOR ENGINE, 

VEHICLE, AND EQUIPMENT 

COMPLIANCE PROGRAMS 

■ 86. The authority citation for part 

1027 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

■ 87. Section 1027.101 is amended as 

follows: 

■ a. By revising paragraph (a)(2)(iii). 

■ b. By adding paragraph (a)(4). 

■ c. By revising paragraph (d). 

§ 1027.101 To whom do these 

requirements apply? 

(a) * * * 

(2) * * * 

(iii) Marine compression-ignition 

engines we regulate under 40 CFR part 

94, 1042, or 1043. 

* * * * * 

(4) Portable fuel containers we 

regulate under 40 CFR part 59, subpart 

F. 

* * * * * 

(d) Paragraph (a) of this section 

identifies the parts of the CFR that 

define emission standards and other 

requirements for particular types of 

engines, vehicles, and fuel-system 

components. This part 1027 refers to 

each of these other parts generically as 

the ‘‘standard-setting part.’’ For example, 

40 CFR part 1051 is always the 

standard-setting part for recreational 

vehicles. For some nonroad engines, we 

allow for certification related to 

evaporative emissions separate from 

exhaust emissions. In this case, 40 CFR 

part 1060 is the standard-setting part for 

the equipment or fuel system 

components you produce. 

■ 88. Section 1027.105 is amended by 

revising paragraph (b)(3) to read as 

follows: 

§ 1027.105 How much are the fees? 

* * * * * 

(b) * * * 

(3) The following fees apply for 

nonroad and stationary engines, 

vehicles, equipment, and components: 

Category Certificate type Fee 

(i) Locomotives and locomotive engines ...................................................................... All .............................................................. $826 

(ii) Marine compression-ignition engines and stationary compression-ignition engines with per-cylinder displacement at or above 10 liters.All, including EIAPP .................................. 826 


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Category Certificate type Fee 

(iii) Other nonroad compression-ignition engines and stationary compression-ignition engines with per-cylinder displacement below 10 liters.All .............................................................. 1,822 

(iv) Large SI engines .................................................................................................... All .............................................................. 826 

(v) Stationary spark-ignition engines above 19 kW ..................................................... All .............................................................. 826 

(vi) Marine SI engines and Small SI engines .............................................................. Exhaust only ............................................. 826 

(vii) Stationary spark-ignition engines at or below 19 kW ........................................... Exhaust only ............................................. 826 

(viii) Recreational vehicles ........................................................................................... Exhaust (or combined exhaust and evap) 826 

(ix) Equipment and fuel-system components associated with nonroad and stationary spark-ignition engines, including portable fuel containers.Evap (where separate certification is required).241 

* * * * * 

■ 89. Section 1027.115 is amended by 

revising paragraph (g) to read as follows: 

§ 1027.115 What special provisions apply 

for certification related to nonroad and 

stationary engines? 

* * * * * 

(g) For marine compression-ignition 

engines, if you apply for a Federal 

certificate and an EIAPP certificate for 

the same engine family, a single fee 

applies for the engine family (see 40 

CFR parts 94, 1042, and 1043). 

* * * * * 

■ 89b. Section 1027.150 is amended by 

revising the section heading to read as 

follows and removing the definition of 

‘‘Annex VI.’’ 

§ 1027.150 What definitions apply to this 

part? 

* * * * * 

PART 1033—CONTROL OF EMISSIONS 

FROM LOCOMOTIVES 

■ 90. The authority citation for part 

1033 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 91. Section 1033.15 is amended by 

revising paragraph (a) to read as follows: 

§ 1033.15 Other regulation parts that apply 

for locomotives. 

(a) Part 1065 of this chapter describes 

procedures and equipment 

specifications for testing engines to 

measure exhaust emissions. Subpart F 

of this part 1033 describes how to apply 

the provisions of part 1065 of this 

chapter to test locomotives to determine 

whether they meet the exhaust emission 

standards in this part. 

* * * * * 

■ 92. A new § 1033.30 is added to 

subpart A to read as follows: 

§ 1033.30 Submission of information. 

(a) This part includes various 

requirements to record data or other 

information. Refer to § 1033.925 and 40 

CFR 1068.25 regarding recordkeeping 

requirements. Unless we specify 

otherwise, store these records in any 

format and on any media and keep them 

readily available for one year after you 

send an associated application for 

certification, or one year after you 

generate the data if they do not support 

an application for certification. You 

must promptly send us organized, 

written records in English if we ask for 

them. We may review them at any time. 

(b) The regulations in § 1033.255 and 

40 CFR 1068.101 describe your 

obligation to report truthful and 

complete information and the 

consequences of failing to meet this 

obligation. This includes information 

not related to certification. 

(c) Send all reports and requests for 

approval to the Designated Compliance 

Officer (see § 1033.901). 

(d) Any written information we 

require you to send to or receive from 

another company is deemed to be a 

required record under this section. Such 

records are also deemed to be 

submissions to EPA. We may require 

you to send us these records whether or 

not you are a certificate holder. 

Subpart B—[Amended] 

■ 93. Section 1033.101 is amended by 

revising paragraph (d) to read as 

follows: 

§ 1033.101 Exhaust emission standards. 

* * * * * 

(d) Averaging, banking, and trading. 

You may generate or use emission 

credits under the averaging, banking, 

and trading (ABT) program as described 

in subpart H of this part to comply with 

the NOX and/or PM standards of this 

part. You may also use ABT to comply 

with the Tier 4 HC standards of this part 

as described in paragraph (j) of this 

section. Generating or using emission 

credits requires that you specify a 

family emission limit (FEL) for each 

pollutant you include in the ABT 

program for each engine family. These 

FELs serve as the emission standards for 

the engine family with respect to all 

required testing instead of the standards 

specified in paragraphs (a) and (b) of 

this section. FELs may not be higher 

than the following limits: 

(1) FELs for Tier 0 and Tier 1 

locomotives originally manufactured 

before 2002 may have any value. 

(2) FELs for Tier 1 locomotives 

originally manufactured 2002 through 

2004 may not exceed 9.5 g/bhp-hr for 

NOX emissions or 0.60 g/bhp-hr for PM 

emissions measured over the line-haul 

duty cycle. FELs for these locomotives 

may not exceed 14.4 g/bhp-hr for NOX

emissions or 0.72 g/bhp-hr for PM 

emissions measured over the switch 

duty cycle. 

(3) FELs for Tier 2 and Tier 3 

locomotives may not exceed the Tier 1 

standards of this section. 

(4) FELs for Tier 4 locomotives may 

not exceed the Tier 3 standards of this 

section. 

* * * * * 

■ 94. Section 1033.115 is amended by 

revising paragraph (f) to read as follows: 

§ 1033.115 Other requirements. 

* * * * * 

(f) Defeat devices. You may not equip 

your locomotives with a defeat device. 

A defeat device is an auxiliary emission 

control device (AECD) that reduces the 

effectiveness of emission controls under 

conditions that the locomotive may 

reasonably be expected to encounter 

during normal operation and use. 

(1) This does not apply to AECDs you 

identify in your application for 

certification if any of the following is 

true: 

(i) The conditions of concern were 

substantially included in the applicable 

duty cycle test procedures described in 

subpart F of this part. 

(ii) You show your design is necessary 

to prevent locomotive damage or 

accidents. 

(iii) The reduced effectiveness applies 

only to starting the locomotive. 

(iv) The locomotive emissions when 

the AECD is functioning are at or below 

the notch caps of § 1033.101. 

(2) This does not apply to AECDs 

related to hotel mode that conform to 

the specifications of this paragraph 

(f)(2). This provision is intended for 

AECDs that have the primary function 

of operating the engine at a different 

speed than would be done to generate 


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the same propulsive power when not 

operating in hotel mode. Identify and 

describe these AECDs in your 

application for certification. We may 

allow the AECDs to modify engine 

calibrations where we determine that 

such modifications are environmentally 

beneficial or needed for proper engine 

function. You must obtain preliminary 

approval under § 1033.210 before 

incorporating such modifications. 

Otherwise, you must apply the same 

injection timing and intake air cooling 

strategies in hotel mode and non-hotel 

mode. 

* * * * * 

■ 95. Section 1033.120 is amended by 

revising paragraph (c) to read as follows: 

§ 1033.120 Emission-related warranty 

requirements. 

* * * * * 

(c) Components covered. The 

emission-related warranty covers all 

components whose failure would 

increase a locomotive’s emissions of any 

regulated pollutant. This includes 

components listed in 40 CFR part 1068, 

Appendix I, and components from any 

other system you develop to control 

emissions. The emission-related 

warranty covers the components you 

sell even if another company produces 

the component. Your emission-related 

warranty does not need to cover 

components whose failure would not 

increase a locomotive’s emissions of any 

regulated pollutant. For remanufactured 

locomotives, your emission-related 

warranty is required to cover only those 

parts that you supply or those parts for 

which you specify allowable part 

manufacturers. It does not need to cover 

used parts that are not replaced during 

the remanufacture. 

* * * * * 

■ 95b. Section 1033.150 amended by 

revising paragraph (a)(4) and 

redesignating paragraph (k)(1) as 

paragraph (l) to read as follows: 

§ 1033.150 Interim provisions. 

* * * * * 

(a) * * * 

(4) Estimate costs as follows: 

(i) The cost limits described in 

paragraph (a)(1) of this section are 

specified in terms of 2007 dollars. 

Adjust these values for future years 

according to the following equation: 

Actual Limit = (2007 Limit) × [(0.6000) 

× (Commodity Index) + (0.4000) × 

(Earnings Index)] 

Where: 

2007 Limit = The value specified in 

paragraph (a)(1) of this section ($250,000 

or $125,000). 

Commodity Index = The U.S. Bureau of 

Labor Statistics Producer Price Index for 

Industrial Commodities Less Fuel (Series 

WPU03T15M05) for the month prior to 

the date you submit your application 

divided by 173.1. 

Earnings Index = The U.S. Bureau of Labor 

Statistics Estimated Average Hourly 

Earnings of Production Workers for 

Durable Manufacturing (Series 

CES3100000008) for the month prior to 

the date you submit your application 

divided by 18.26. 

(ii) Calculate all costs in current 

dollars (for the month prior to the date 

you submit your application). Calculate 

fuel costs based on a fuel price adjusted 

by the Association of American 

Railroads’ monthly railroad fuel price 

index (P), which is available at https:// 

www.aar.org//media/AAR/RailCost

Indexes/Index_MonthlyFuelPrices.ashx. 

(Use the value for the column in which 

P equals 539.8 for November 2007.) 

Calculate a new fuel price using the 

following equation: 

Fuel Price = ($2.76 per gallon) × (P/ 

539.8) 

* * * * * 

Subpart C—[Amended] 

■ 96. Section 1033.220 is amended by 

revising the introductory text and 

paragraph (a) to read as follows: 

§ 1033.220 Amending maintenance 

instructions. 

You may amend your emissionrelated maintenance instructions after 

you submit your application for 

certification, as long as the amended 

instructions remain consistent with the 

provisions of § 1033.125. You must send 

the Designated Compliance Officer a 

request to amend your application for 

certification for an engine family if you 

want to change the emission-related 

maintenance instructions in a way that 

could affect emissions. In your request, 

describe the proposed changes to the 

maintenance instructions. If owners/ 

operators follow the original 

maintenance instructions rather than 

the newly specified maintenance, this 

does not allow you to disqualify those 

locomotives from in-use testing or deny 

a warranty claim. 

(a) If you are decreasing or 

eliminating any of the specified 

maintenance, you may distribute the 

new maintenance instructions to your 

customers 30 days after we receive your 

request, unless we disapprove your 

request. This would generally include 

replacing one maintenance step with 

another. We may approve a shorter time 

or waive this requirement. 

* * * * * 

■ 97. Section 1033.225 is amended as 

follows: 

■ a. By revising the introductory text. 

■ b. By revising paragraphs (b) 

introductory text and (b)(2). 

■ c. By revising paragraphs (e) and (f). 

§ 1033.225 Amending applications for 

certification. 

Before we issue you a certificate of 

conformity, you may amend your 

application to include new or modified 

locomotive configurations, subject to the 

provisions of this section. After we have 

issued your certificate of conformity, 

you may send us an amended 

application requesting that we include 

new or modified locomotive 

configurations within the scope of the 

certificate, subject to the provisions of 

this section. You must also amend your 

application if any changes occur with 

respect to any information that is 

included or should be included in your 

application. For example, you must 

amend your application if you 

determine that your actual production 

variation for an adjustable parameter 

exceeds the tolerances specified in your 

application. 

* * * * * 

(b) To amend your application for 

certification, send the relevant 

information to the Designated 

Compliance Officer. 

* * * * * 

(2) Include engineering evaluations or 

data showing that the amended engine 

family complies with all applicable 

requirements. You may do this by 

showing that the original emission-data 

locomotive is still appropriate for 

showing that the amended family 

complies with all applicable 

requirements. 

* * * * * 

(e) For engine families already 

covered by a certificate of conformity, 

you may start producing the new or 

modified locomotive anytime after you 

send us your amended application, 

before we make a decision under 

paragraph (d) of this section. However, 

if we determine that the affected 

locomotives do not meet applicable 

requirements, we will notify you to 

cease production of the locomotives and 

may require you to recall the 

locomotives at no expense to the owner. 

Choosing to produce locomotives under 

this paragraph (e) is deemed to be 

consent to recall all locomotives that we 

determine do not meet applicable 

emission standards or other 

requirements and to remedy the 

nonconformity at no expense to the 

owner. If you do not provide 

information required under paragraph 


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(c) of this section within 30 days after 

we request it, you must stop producing 

the new or modified locomotives. 

(f) You may ask us to approve a 

change to your FEL in certain cases after 

the start of production. The changed 

FEL may not apply to locomotives you 

have already introduced into U.S. 

commerce, except as described in this 

paragraph (f). If we approve a changed 

FEL after the start of production, you 

must include the new FEL on the 

emission control information label for 

all locomotives produced after the 

change. You may ask us to approve a 

change to your FEL in the following 

cases: 

(1) You may ask to raise your FEL for 

your engine family at any time. In your 

request, you must show that you will 

still be able to meet the emission 

standards as specified in subparts B and 

H of this part. If you amend your 

application by submitting new test data 

to include a newly added or modified 

locomotive, as described in paragraph 

(b)(3) of this section, use the appropriate 

FELs with corresponding production 

volumes to calculate emission credits 

for the model year, as described in 

subpart H of this part. In all other 

circumstances, you must use the higher 

FEL for the entire family to calculate 

emission credits under subpart H of this 

part. 

(2) You may ask to lower the FEL for 

your emission family only if you have 

test data from production locomotives 

showing that emissions are below the 

proposed lower FEL. The lower FEL 

applies only to engines or fuel-system 

components you produce after we 

approve the new FEL. Use the 

appropriate FELs with corresponding 

production volumes to calculate 

emission credits for the model year, as 

described in subpart H of this part. 

■ 98. Section 1033.235 is amended by 

revising paragraphs (c) and (d) 

introductory text to read as follows: 

§ 1033.235 Emission testing required for 

certification. 

* * * * * 

(c) We may measure emissions from 

any of your emission-data locomotives 

or other locomotives from the engine 

family. 

(1) We may decide to do the testing 

at your plant or any other facility. If we 

do this, you must deliver the locomotive 

to a test facility we designate. If we do 

the testing at your plant, you must 

schedule it as soon as possible and 

make available the instruments, 

personnel, and equipment we need. 

(2) If we measure emissions from one 

of your locomotives, the results of that 

testing become the official emission 

results for the locomotive. Unless we 

later invalidate these data, we may 

decide not to consider your data in 

determining if your engine family meets 

applicable requirements. 

(3) Before we test one of your 

locomotives, we may set its adjustable 

parameters to any point within the 

adjustable ranges (see § 1033.115(b)). 

(4) Before we test one of your 

locomotives, we may calibrate it within 

normal production tolerances for 

anything we do not consider an 

adjustable parameter. For example, this 

would apply where we determine that 

an engine parameter is not an adjustable 

parameter (as defined in § 1033.901) but 

that it is subject to production 

variability. 

(d) You may ask to use carryover 

emission data from a previous model 

year instead of doing new tests if all the 

following are true: 

* * * * * 

■ 99. Section 1033.240 is amended by 

revising paragraph (a) introductory text 

and paragraph (b) introductory text to 

read as follows: 

§ 1033.240 Demonstrating compliance with 

exhaust emission standards. 

(a) For purposes of certification, your 

engine family is considered in 

compliance with the applicable 

numerical emission standards in 

§ 1033.101 if all emission-data 

locomotives representing that family 

have test results showing official 

emission results and deteriorated 

emission levels at or below these 

standards. 

* * * * * 

(b) Your engine family is deemed not 

to comply if any emission-data 

locomotive representing that family has 

test results showing an official emission 

result or a deteriorated emission level 

for any pollutant that is above an 

applicable emission standard. Use the 

following steps to determine the 

deteriorated emission level for the test 

locomotive: 

* * * * * 

■ 100. Section 1033.255 is amended by 

revising paragraph (b) to read as follows: 

§ 1033.255 EPA decisions. 

* * * * * 

(b) We may deny your application for 

certification if we determine that your 

engine family fails to comply with 

emission standards or other 

requirements of this part or the Clean 

Air Act. We will base our decision on 

all available information. If we deny 

your application, we will explain why 

in writing. 

* * * * * 

Subpart D—[Amended] 

■ 101. Section 1033.325 is amended by 

revising paragraph (d) to read as 

follows: 

§ 1033.325 Maintenance of records; 

submittal of information. 

* * * * * 

(d) Nothing in this section limits our 

authority to require you to establish, 

maintain, keep or submit to us 

information not specified by this 

section. We may also ask you to send 

less information. 

* * * * * 

Subpart F—[Amended] 

■ 102. Section 1033.501 is amended by 

revising paragraph (i) to read as follows: 

§ 1033.501 General provisions. 

* * * * * 

(i) For passenger locomotives that can 

generate hotel power from the main 

propulsion engine, the locomotive must 

comply with the emission standards 

when in non-hotel setting. For hotel 

mode, the locomotive is subject to the 

notch cap provisions of § 1033.101 and 

the defeat device prohibition of 

§ 1033.115. 

■ 103. Section 1033.505 is amended by 

revising paragraph (a) to read as follows: 

§ 1033.505 Ambient conditions. 

* * * * * 

(a) Temperature. (1) Testing may be 

performed with ambient temperatures 

from 15.5 °C (60 °F) to 40.5 °C (105 °F). 

Do not correct emissions for 

temperature effects within this range. 

(2) It is presumed that combustion air 

will be drawn from the ambient air. 

Thus, the ambient temperature limits of 

this paragraph (a) apply for intake air 

upstream of the engine. If you do not 

draw combustion air from the ambient 

air, use good engineering judgment to 

ensure that any temperature difference 

(between the ambient air and 

combustion air) does not cause the 

emission measurement to be 

unrepresentative of in-use emissions. 

(3) If we allow you to perform testing 

at ambient temperatures below 15.5 °C, 

you must correct NOX emissions for 

temperature effects, consistent with 

good engineering judgment. For 

example, if the intake air temperature 

(at the manifold) is lower at the test 

temperature than it would be for 

equivalent operation at an ambient 

temperature of 15.5 °C, you generally 

will need to adjust your measured NOX

emissions to account for the effect of the 

lower intake air temperature. However, 

if you maintain a constant manifold air 


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temperature, you will generally not 

need to correct emissions. 

* * * * * 

■ 104. Section 1033.515 is amended by 

revising the section heading and 

paragraphs (d) and (e) to read as follows: 

§ 1033.515 Discrete-mode steady-state 

emission tests of locomotives and 

locomotive engines. 

* * * * * 

(d) Use one of the following 

approaches for sampling PM emissions 

during discrete-mode steady-state 

testing: 

(1) Engines certified to a PM 

standard/FEL at or above 0.05 g/bhp-hr. 

Use a separate PM filter sample for each 

test mode of the locomotive test cycle 

according to the procedures specified in 

paragraph (a) through (c) of this section. 

You may ask to use a shorter sampling 

period if the total mass expected to be 

collected would cause unacceptably 

high pressure drop across the filter 

before reaching the end of the required 

sampling time. We will not allow 

sampling times shorter than 60 seconds. 

When we conduct locomotive emission 

tests, we will adhere to the time limits 

for each of the numbered modes in 

Table 1 to this section. 

(2) Engines certified to a PM 

standard/FEL below 0.05 g/bhp-hr. (i) 

You may use separate PM filter samples 

for each test mode as described in 

paragraph (d)(1) of this section; 

however, we recommend that you do 

not. The low rate of sample filter 

loading will result in very long 

sampling times and the large number of 

filter samples may induce uncertainty 

stack-up that will lead to unacceptable 

PM measurement accuracy. Instead, we 

recommend that you measure PM 

emissions as specified in paragraph 

(d)(2)(ii) of this section. 

(ii) You may use a single PM filter for 

sampling PM over all of the test modes 

of the locomotive test cycle as specified 

in this paragraph (d)(2). Vary the sample 

time to be proportional to the applicable 

line-haul or switch weighting factors 

specified in § 1033.530 for each mode. 

The minimum sampling time for each 

mode is 400 seconds multiplied by the 

weighting factor. For example, for a 

mode with a weighting factor of 0.030, 

the minimum sampling time is 12.0 

seconds. PM sampling in each mode 

must be proportional to engine exhaust 

flow as specified in 40 CFR part 1065. 

Begin proportional sampling of PM 

emissions at the beginning of each test 

mode as is specified in paragraph (c) of 

this section. End the sampling period 

for each test mode so that sampling 

times are proportional to the weighting 

factors for the applicable duty cycles. If 

necessary, you may extend the time 

limit for each of the test modes beyond 

the sampling times in Table 1 to this 

section to increase the sampled mass of 

PM emissions or to account for proper 

weighting of the PM emission sample 

over the entire cycle, using good 

engineering judgment. 

(e) This paragraph (e) describes how 

to test locomotive engines when not 

installed in a locomotive. Note that the 

test procedures for dynamometer engine 

testing of locomotive engines are 

intended to produce emission 

measurements that are the same as 

emission measurements produced 

during testing of complete locomotives 

using the same engine configuration. 

The following requirements apply for all 

engine tests: 

(1) Specify a second-by-second set of 

engine speed and load points that are 

representative of in-use locomotive 

operation for each of the set-points of 

the locomotive test cycle described in 

Table 1 to this section, including 

transitions from one notch to the next. 

This is your reference cycle for 

validating your cycle. You may ignore 

points between the end of the sampling 

period for one mode and the point at 

which you change the notch setting to 

begin the next mode. 

(2) Keep the temperature of the air 

entering the engine after any charge air 

cooling to within 5 °C of the typical 

intake manifold air temperature when 

the engine is operated in the locomotive 

under similar ambient conditions. 

(3) Proceed as specified in paragraphs 

(a) through (d) of this section for testing 

complete locomotives. 

■ 105. Section 1033.530 is amended by 

revising paragraphs (e) and (h) to read 

as follows: 

§ 1033.530 Duty cycles and calculations. 

* * * * * 

(e) Automated Start-Stop. For a 

locomotive equipped with features that 

shut the engine off after prolonged 

periods of idle, multiply the measured 

idle mass emission rate over the idle 

portion of the applicable test cycles by 

a factor equal to one minus the 

estimated fraction reduction in idling 

time that will result in use from the 

shutdown feature. Do not apply this 

factor to the weighted idle power. 

Application of this adjustment is subject 

to our approval if the fraction reduction 

in idling time that is estimated to result 

from the shutdown feature is greater 

than 25 percent. This paragraph (e) does 

not apply if the locomotive is (or will 

be) covered by a separate certificate for 

idle control. 

* * * * * 

(h) Calculation adjustments for 

energy-saving design features. The 

provisions of this paragraph (h) apply 

for locomotives equipped with new 

energy-saving locomotive design 

features. They do not apply for features 

that only improve the engine’s brakespecific fuel consumption. They also do 

not apply for features that were 

commonly incorporated in locomotives 

before 2008. See paragraph (h)(6) of this 

section for provisions related to 

determining whether certain features are 

considered to have been commonly 

incorporated in locomotives before 

2008. 

(1) Manufacturers/remanufacturers 

choosing to adjust emissions under this 

paragraph (h) must do all of the 

following for certification: 

(i) Describe the energy-saving features 

in your application for certification. 

(ii) Describe in your installation 

instruction and/or maintenance 

instructions all steps necessary to utilize 

the energy-saving features. 

(2) If your design feature will also 

affect the locomotives’ duty cycle, you 

must comply with the requirements of 

paragraph (g) of this section. 

(3) Calculate the energy savings as 

follows: 

(i) Estimate the expected mean in-use 

fuel consumption rate (on a BTU per 

ton-mile basis) with and without the 

energy saving design feature, consistent 

with the specifications of paragraph 

(h)(4) of this section. The energy savings 

is the ratio of fuel consumed from a 

locomotive operating with the new 

feature to fuel consumed from a 

locomotive operating without the 

feature under identical conditions. 

Include an estimate of the 80 percent 

confidence interval for your estimate of 

the mean and other statistical 

parameters we specify. 

(ii) Your estimate must be based on 

in-use operating data, consistent with 

good engineering judgment. Where we 

have previously certified your design 

feature under this paragraph (h), we 

may require you to update your analysis 

based on all new data that are available. 

You must obtain approval before you 

begin collecting operational data for this 

purpose. 

(iii) We may allow you to consider the 

effects of your design feature separately 

for different route types, regions, or 

railroads. We may require that you 

certify these different locomotives in 

different engine families and may 

restrict their use to the specified 

applications. 

(iv) Design your test plan so that the 

operation of the locomotives with and 

without is as similar as possible in all 

material aspects (other than the design 


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feature being evaluated). Correct all data 

for any relevant differences, consistent 

with good engineering judgment. 

(v) Do not include any brake-specific 

energy savings in your calculated 

values. If it is not possible to exclude 

such effects from your data gathering, 

you must correct for these effects, 

consistent with good engineering 

judgment. 

(4) Calculate adjustment factors as 

described in this paragraph (h)(4). If the 

energy savings will apply broadly, 

calculate and apply the adjustment on a 

cycle-weighted basis. Otherwise, 

calculate and apply the adjustment 

separately for each notch. To apply the 

adjustment, multiply the emissions 

(either cycle-weighted or notch-specific, 

as applicable) by the adjustment. Use 

the lower bound of the 80 percent 

confidence interval of the estimate of 

the mean as your estimated energy 

savings rate. We may cap your energy 

savings rate for this paragraph (h)(4) at 

80 percent of the estimate of the mean. 

Calculate the emission adjustment 

factors as: 

AF = 1.000 ¥ (energy savings rate) 

(5) We may require you to collect and 

report data from locomotives we allow 

you to certify under this paragraph (h) 

and to recalculate the adjustment factor 

for future model years based on such 

data. 

(6) Features that are considered to 

have not been commonly incorporated 

in locomotives before 2008 include but 

are not limited to those identified in this 

paragraph (h)(6). 

(i) Electronically controlled 

pneumatic (ECP) brakes, computerized 

throttle management control, and 

advanced hybrid technology were not 

commonly incorporated in locomotives 

before 2008. Manufacturers may claim 

full credit for energy savings that result 

from applying these features to freshly 

manufactured and/or remanufactured 

locomotives. 

(ii) Distributed power systems that 

use radio controls to optimize operation 

of locomotives in the middle and rear of 

a train were commonly incorporated in 

some but not all locomotives in 2008. 

Manufacturers may claim credit for 

incorporating these features into 

locomotives as follows: 

(A) Manufacturers may claim prorated 

credit for incorporating distributed 

power systems in freshly manufactured 

locomotives. Multiply the energy saving 

rate by 0.50 when calculating the 

adjustment factor: 

AF = 1.000¥(energy savings rate) × 

(0.50) 

(B) Manufacturers may claim full 

credit for retrofitting distributed power 

systems in remanufactured locomotives. 

Subpart G—[Amended] 

■ 106. Section 1033.601 is amended by 

revising paragraph (a) to read as follows: 

§ 1033.601 General compliance provisions. 

* * * * * 

(a) Meaning of terms. When used in 

40 CFR part 1068, apply meanings for 

specific terms as follows: 

(1) ‘‘Manufacturer’’ means 

manufacturer and/or remanufacturer. 

(2) ‘‘Date of manufacture’’ means date 

of original manufacture for freshly 

manufactured locomotives and the date 

on which a remanufacture is completed 

for remanufactured engines. 

* * * * * 

■ 107. Section 1033.625 is amended by 

revising paragraphs (a)(1), (b), and (c) to 

read as follows: 

§ 1033.625 Special certification provisions 

for non-locomotive-specific engines. 

* * * * * 

(a) * * * 

(1) Before being installed in the 

locomotive, the engines were covered by 

a certificate of conformity issued under 

40 CFR Part 1039 (or part 89) that is 

effective for the calendar year in which 

the manufacture or remanufacture 

occurs. You may use engines certified 

during the previous years if they were 

subject to the same standards. You may 

not make any modifications to the 

engines unless we approve them. 

* * * * * 

(b) To certify your locomotives by 

design under this section, submit your 

application as specified in § 1033.205, 

with the following exceptions: 

(1) Include the following instead of 

the locomotive test data otherwise 

required by § 1033.205: 

(i) A description of the engines to be 

used, including the name of the engine 

manufacturer and engine family 

identifier for the engines. 

(ii) A brief engineering analysis 

describing how the engine’s emission 

controls will function when installed in 

the locomotive throughout the 

locomotive’s useful life. 

(iii) The emission data submitted 

under 40 CFR part 1039 (or part 89). 

(2) You may separately submit some 

of the information required by 

§ 1033.205, consistent with the 

provisions of § 1033.1(d). For example, 

this may be an appropriate way to 

submit detailed information about 

proprietary engine software. Note that 

this allowance to separately submit 

some of the information required by 

§ 1033.205 is also available for 

applications not submitted under this 

section. 

(c) Locomotives certified under this 

section are subject to all the 

requirements of this part except as 

specified in paragraph (b) of this 

section. The engines used in such 

locomotives are not considered to be 

included in the otherwise applicable 

engines family of 40 CFR part 1039 (or 

part 89). 

* * * * * 

■ 108. A new § 1033.652 is added to 

subpart G to read as follows: 

§ 1033.652 Special provisions for exported 

locomotives. 

(a) Uncertified locomotives. 

Locomotives covered by an export 

exemption under 40 CFR 1068.230 may 

be introduced into U.S. commerce prior 

to being exported, but may not be used 

in any revenue generating service in the 

United States. Locomotives covered by 

this paragraph (a) may not include any 

EPA emission control information label. 

Such locomotives may include emission 

control information labels for the 

country to which they are being 

exported. 

(b) Locomotives covered by exportonly certificates. Locomotives may be 

certified for export under 40 CFR 

1068.230. Such locomotives may be 

introduced into U.S. commerce prior to 

being exported, but may not be used in 

any revenue generating service in the 

United States. 

(c) Locomotives included in a certified 

engine family. Except as specified in 

paragraph (d) of this section, 

locomotives included in a certified 

engine family may be exported without 

restriction. Note that § 1033.705 requires 

that exported locomotives be excluded 

from emission credit calculations in 

certain circumstances. 

(d) Locomotives certified to FELs 

above the standards. The provisions of 

this paragraph (d) apply for locomotive 

configurations included in engine 

families certified to one or more FELs 

above any otherwise applicable 

standard. Individual locomotives that 

will be exported may be excluded from 

an engine family if they are unlabeled. 

For locomotives that were labeled 

during production, you may remove the 

emission control information labels 

prior to export. All unlabeled 

locomotives that will be exported are 

subject to the provisions of paragraph 

(a) of this section. Locomotives that are 

of a configuration included in an engine 

family certified to one of more FELs 

above any otherwise applicable 

standard that include an EPA emission 

control information label when exported 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 22987 

are considered to be part of the engine 

family and must be included in credit 

calculations under § 1033.705. Note that 

this requirement does not apply for 

locomotives that do not have an EPA 

emission control information label, even 

if they have other labels (such as an 

export-only label). 

Subpart H—[Amended] 

■ 109. Section 1033.705 is amended by 

revising paragraph (b) introductory text 

to read as follows: 

§ 1033.705 Calculating emission credits. 

* * * * * 

(b) For each participating engine 

family, calculate positive or negative 

emission credits relative to the 

otherwise applicable emission standard. 

For the end of year report, round the 

sum of emission credits to the nearest 

one hundredth of a megagram (0.01 Mg). 

Round your end of year emission credit 

balance to the nearest megagram (Mg). 

Use consistent units throughout the 

calculation. When useful life is 

expressed in terms of megawatt-hrs, 

calculate credits for each engine family 

from the following equation: 

* * * * * 

■ 110. Section 1033.715 is revised to 

read as follows: 

§ 1033.715 Banking emission credits. 

(a) Banking is the retention of 

emission credits by the manufacturer/ 

remanufacturer generating the emission 

credits (or owner/operator, in the case of 

transferred credits) for use in future 

model years for averaging, trading, or 

transferring. You may use banked 

emission credits only as allowed by 

§ 1033.740. 

(b) You may designate any emission 

credits you plan to bank in the reports 

you submit under § 1033.730 as 

reserved credits. During the model year 

and before the due date for the final 

report, you may designate your reserved 

emission credits for averaging, trading, 

or transferring. 

(c) Reserved credits become actual 

emission credits when you submit your 

final report. However, we may revoke 

these emission credits if we are unable 

to verify them after reviewing your 

reports or auditing your records. 

■ 111. Section 1033.725 is amended by 

revising paragraph (b)(2) to read as 

follows: 

§ 1033.725 Requirements for your 

application for certification. 

* * * * * 

(b) * * * 

(2) Detailed calculations of projected 

emission credits (positive or negative) 

based on projected production volumes. 

We may require you to include similar 

calculations from your other engine 

families to demonstrate that you will be 

able to avoid a negative credit balance 

for the model year. If you project 

negative emission credits for a family, 

state the source of positive emission 

credits you expect to use to offset the 

negative emission credits. 

■ 112. Section 1033.730 is amended by 

revising paragraphs (b)(3) and (b)(5) to 

read as follows: 

§ 1033.730 ABT reports. 

* * * * * 

(b) * * * 

(3) The FEL for each pollutant. If you 

change the FEL after the start of 

production, identify the date that you 

started using the new FEL and/or give 

the engine identification number for the 

first engine covered by the new FEL. In 

this case, identify each applicable FEL 

and calculate the positive or negative 

emission credits as specified in 

§ 1033.225. 

* * * * * 

(5) Rated power for each locomotive 

configuration, and the average 

locomotive power weighted by U.S.- 

directed production volumes for the 

engine family. 

* * * * * 

■ 113. Section 1033.735 is amended by 

revising paragraphs (b), (d), and (e) to 

read as follows: 

§ 1033.735 Required records. 

* * * * * 

(b) Keep the records required by this 

section for at least eight years after the 

due date for the end-of-year report. You 

may not use emission credits for any 

engines if you do not keep all the 

records required under this section. You 

must therefore keep these records to 

continue to bank valid credits. Store 

these records in any format and on any 

media, as long as you can promptly 

send us organized, written records in 

English if we ask for them. You must 

keep these records readily available. We 

may review them at any time. 

* * * * * 

(d) Keep records of the engine 

identification number for each 

locomotive you produce that generates 

or uses emission credits under the ABT 

program. If you change the FEL after the 

start of production, identify the date you 

started using each FEL and the range of 

engine identification numbers 

associated with each FEL. You must 

also be able to identify the purchaser 

and destination for each engine you 

produce. 

(e) We may require you to keep 

additional records or to send us relevant 

information not required by this section 

in accordance with the Clean Air Act. 

Subpart J—[Amended] 

■ 114. Section 1033.901 is amended by 

revising the definitions for ‘‘Carryover’’, 

‘‘Total hydrocarbon equivalent’’, and 

‘‘Useful life’’ and adding a new 

definition for ‘‘Alcohol-fueled 

locomotive’’ in alphabetical order to 

read as follows: 

§ 1033.901 Definitions. 

* * * * * 

Alcohol-fueled locomotive means a 

locomotive with an engine that is 

designed to run using an alcohol fuel. 

For purposes of this definition, alcohol 

fuels do not include fuels with a 

nominal alcohol content below 25 

percent by volume. 

* * * * * 

Carryover means relating to 

certification based on emission data 

generated from an earlier model year as 

described in § 1033.235(d). 

* * * * * 

Total hydrocarbon equivalent has the 

meaning given in 40 CFR 1065.1001. 

This generally means the sum of the 

carbon mass contributions of nonoxygenated hydrocarbons, alcohols and 

aldehydes, or other organic compounds 

that are measured separately as 

contained in a gas sample, expressed as 

exhaust hydrocarbon from petroleumfueled locomotives. The atomic 

hydrogen-to-carbon mass ratio of the 

equivalent hydrocarbon is 1.85:1. 

* * * * * 

Useful life means the period during 

which the locomotive engine is 

designed to properly function in terms 

of reliability and fuel consumption, 

without being remanufactured, specified 

as work output or miles. It is the period 

during which a locomotive is required 

to comply with all applicable emission 

standards. See § 1033.101(g). 

* * * * * 

■ 115. Section 1033.905 is amended by 

adding ‘‘ABT’’, ‘‘AF’’, and U.S.’’ in 

alphabetical order to read as follows: 

§ 1033.925 Symbols, acronyms, and 

abbreviations. 

* * * * * 

ABT averaging, banking, and trading. 

* * * * * 

AF adjustment factor (see § 1033.530). 

* * * * * 

U.S. United States. 

* * * * * 

■ 116. A new § 1033.925 is added to 

subpart J to read as follows: 


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22988 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

§ 1033.925 Reporting and recordkeeping 

requirements. 

Under the Paperwork Reduction Act 

(44 U.S.C. 3501 et seq.), the Office of 

Management and Budget approves the 

reporting and recordkeeping specified 

in the applicable regulations. Failing to 

properly report information and keep 

the records we specify violates 40 CFR 

1068.101(a)(2), which may involve civil 

or criminal penalties. The following 

items illustrate the kind of reporting and 

recordkeeping we require for engines 

regulated under this part: 

(a) We specify the following 

requirements related to engine 

certification in this part 1033: 

(1) In § 1033.150 we state the 

requirements for interim provisions. 

(2) In subpart C of this part we 

identify a wide range of information 

required to certify engines. 

(3) In § 1033.325 we specify certain 

records related to production-line 

testing. 

(4) In subpart G of this part we 

identify several reporting and 

recordkeeping items for making 

demonstrations and getting approval 

related to various special compliance 

provisions. 

(5) In §§ 1033.725, 1033.730, and 

1033.735 we specify certain records 

related to averaging, banking, and 

trading. 

(6) In subpart I of this part we specify 

certain records related to meeting 

requirements for remanufactured 

engines. 

(b) We specify the following 

requirements related to testing in 40 

CFR part 1065: 

(1) In 40 CFR 1065.2 we give an 

overview of principles for reporting 

information. 

(2) In 40 CFR 1065.10 and 1065.12 we 

specify information needs for 

establishing various changes to 

published test procedures. 

(3) In 40 CFR 1065.25 we establish 

basic guidelines for storing test 

information. 

(4) In 40 CFR 1065.695 we identify 

the specific information and data items 

to record when measuring emissions. 

(c) We specify the following 

requirements related to the general 

compliance provisions in 40 CFR part 

1068: 

(1) In 40 CFR 1068.5 we establish a 

process for evaluating good engineering 

judgment related to testing and 

certification. 

(2) In 40 CFR 1068.25 we describe 

general provisions related to sending 

and keeping information. 

(3) In 40 CFR 1068.27 we require 

manufacturers to make engines available 

for our testing or inspection if we make 

such a request. 

(4) In 40 CFR 1068.105 we require 

vessel manufacturers to keep certain 

records related to duplicate labels from 

engine manufacturers. 

(5) In 40 CFR 1068.120 we specify 

recordkeeping related to rebuilding 

engines. 

(6) In 40 CFR part 1068, subpart C, we 

identify several reporting and 

recordkeeping items for making 

demonstrations and getting approval 

related to various exemptions. 

(7) In 40 CFR part 1068, subpart D, we 

identify several reporting and 

recordkeeping items for making 

demonstrations and getting approval 

related to importing engines. 

(8) In 40 CFR 1068.450 and 1068.455 

we specify certain records related to 

testing production-line engines in a 

selective enforcement audit. 

(9) In 40 CFR 1068.501 we specify 

certain records related to investigating 

and reporting emission-related defects. 

(10) In 40 CFR 1068.525 and 1068.530 

we specify certain records related to 

recalling nonconforming engines. 

PART 1039—CONTROL OF EMISSIONS 

FROM NEW AND IN-USE NONROAD 

COMPRESSION-IGNITION ENGINES 

■ 117. The authority citation for part 

1039 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 118. Section 1039.2 is revised to read 

as follows: 

§ 1039.2 Who is responsible for 

compliance? 

The regulations in this part 1039 

contain provisions that affect both 

engine manufacturers and others. 

However, the requirements of this part 

are generally addressed to the engine 

manufacturer. The term ‘‘you’’ generally 

means the engine manufacturer, as 

defined in § 1039.801, especially for 

issues related to certification. 

■ 119. Section 1039.5 is amended by 

revising paragraph (a) to read as follows: 

§ 1039.5 Which engines are excluded from 

this part’s requirements? 

* * * * * 

(a) Locomotive engines. (1) The 

following locomotive engines are not 

subject to the provisions of this part 

1039: 

(i) Engines in locomotives certified 

under 40 CFR part 1033. 

(ii) Engines in locomotives that are 

exempt from the standards of 40 CFR 

part 92 or 1033 pursuant to the 

provisions of 40 CFR part 1033 or 1068 

(except for the provisions of 40 CFR 

1033.150(e)). 

(2) The following locomotive engines 

are subject to the provisions of this part 

1039: 

(i) Engines in locomotives exempt 

from 40 CFR part 1033 pursuant to the 

provisions of 40 CFR 1033.150(e). 

(ii) Locomotive engines excluded 

from the definition of locomotive in 40 

CFR 1033.901. 

* * * * * 

■ 120. Section 1039.15 is amended by 

revising paragraph (a) to read as follows: 

§ 1039.15 Do any other regulation parts 

apply to me? 

(a) Part 1065 of this chapter describes 

procedures and equipment 

specifications for testing engines to 

measure exhaust emissions. Subpart F 

of this part 1039 describes how to apply 

the provisions of part 1065 of this 

chapter to determine whether engines 

meet the exhaust emission standards in 

this part. 

* * * * * 

■ 121. A new § 1039.30 is added to 

subpart A to read as follows: 

§ 1039.30 Submission of information. 

(a) This part includes various 

requirements to record data or other 

information. Refer to § 1039.825 and 40 

CFR 1068.25 regarding recordkeeping 

requirements. Unless we specify 

otherwise, store these records in any 

format and on any media and keep them 

readily available for one year after you 

send an associated application for 

certification, or one year after you 

generate the data if they do not support 

an application for certification. You 

must promptly send us organized, 

written records in English if we ask for 

them. We may review them at any time. 

(b) The regulations in § 1039.255 and 

40 CFR 1068.101 describe your 

obligation to report truthful and 

complete information and the 

consequences of failing to meet this 

obligation. This includes information 

not related to certification. 

(c) Send all reports and requests for 

approval to the Designated Compliance 

Officer (see § 1039.801). 

(d) Any written information we 

require you to send to or receive from 

another company is deemed to be a 

required record under this section. Such 

records are also deemed to be 

submissions to EPA. We may require 

you to send us these records whether or 

not you are a certificate holder. 

Subpart B—[Amended] 

■ 122. Section 1039.104 is amended by 

adding paragraph (h) to read as follows: 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 22989 

§ 1039.104 Are there interim provisions 

that apply only for a limited time? 

* * * * * 

(h) Delayed compliance with labeling 

requirements. Before the 2011 model 

year, you may omit the dates of 

manufacture from the emission control 

information label as specified in 

§ 1039.135(c)(6) if you keep those 

records and provide them to us upon 

request. 

■ 123. Section 1039.120 is amended by 

revising paragraph (c) to read as follows: 

§ 1039.120 What emission-related warranty 

requirements apply to me? 

* * * * * 

(c) Components covered. The 

emission-related warranty covers all 

components whose failure would 

increase an engine’s emissions of any 

regulated pollutant, including 

components listed in 40 CFR part 1068, 

Appendix I, and components from any 

other system you develop to control 

emissions. The emission-related 

warranty covers these components even 

if another company produces the 

component. Your emission-related 

warranty does not need to cover 

components whose failure would not 

increase an engine’s emissions of any 

regulated pollutant. 

* * * * * 

■ 124. Section 1039.125 is amended as 

follows: 

■ a. By revising paragraphs (a)(1)(iii), 

(a)(2)(ii), and (a)(3)(ii). 

■ b. By redesignating paragraph (a)(4) as 

paragraph (a)(6). 

■ c. By adding a new paragraph (a)(4). 

■ d. By adding paragraph (a)(5). 

■ e. By revising paragraphs (c), (d), and 

(g) introductory text to read as follows: 

§ 1039.125 What maintenance instructions 

must I give to buyers? 

* * * * * 

(a) * * * 

(1) * * * 

(iii) You provide the maintenance free 

of charge and clearly say so in your 

maintenance instructions. 

* * * * * 

(2) * * * 

(ii) For the following components, 

including associated sensors and 

actuators, the minimum interval is 3,000 

hours: Fuel injectors, turbochargers, 

catalytic converters, electronic control 

units, EGR systems (including related 

components, but excluding filters and 

coolers), and other add-on components. 

(3) * * * 

(ii) For the following components, 

including associated sensors and 

actuators, the minimum interval is 4,500 

hours: Fuel injectors, turbochargers, 

catalytic converters, electronic control 

units, EGR systems (including related 

components, but excluding filters and 

coolers), and other add-on components. 

(4) For particulate traps, trap 

oxidizers, and components related to 

either of these, scheduled maintenance 

may include cleaning or repair at the 

intervals specified in paragraph (a)(2) or 

(3) of this section, as applicable. 

Scheduled maintenance may include a 

shorter interval for cleaning or repair 

and may also include adjustment or 

replacement, but only if we approve it. 

We will approve your request if you 

provide the maintenance free of charge 

and clearly state this in your 

maintenance instructions, and you 

provide us additional information as 

needed to convince us that the 

maintenance will occur. 

(5) You may ask us to approve a 

maintenance interval shorter than that 

specified in paragraphs (a)(2) and (3) of 

this section under § 1039.210, including 

emission-related components that were 

not in widespread use with nonroad 

compression-ignition engines before 

2011. In your request you must describe 

the proposed maintenance step, 

recommend the maximum feasible 

interval for this maintenance, include 

your rationale with supporting evidence 

to support the need for the maintenance 

at the recommended interval, and 

demonstrate that the maintenance will 

be done at the recommended interval on 

in-use engines. In considering your 

request, we will evaluate the 

information you provide and any other 

available information to establish 

alternate specifications for maintenance 

intervals, if appropriate. We will 

announce any decision we make under 

this paragraph (a)(5) in the Federal 

Register. Anyone may request a hearing 

regarding such a decision (see 

§ 1039.820). 

* * * * * 

(c) Special maintenance. You may 

specify more frequent maintenance to 

address problems related to special 

situations, such as atypical engine 

operation. You must clearly state that 

this additional maintenance is 

associated with the special situation you 

are addressing. We may disapprove your 

maintenance instructions if we 

determine that you have specified 

special maintenance steps to address 

engine operation that is not atypical, or 

that the maintenance is unlikely to 

occur in use. If we determine that 

certain maintenance items do not 

qualify as special maintenance under 

this paragraph (c), you may identify this 

as recommended additional 

maintenance under paragraph (b) of this 

section. 

(d) Noncritical emission-related 

maintenance. Subject to the provisions 

of this paragraph (d), you may schedule 

any amount of emission-related 

inspection or maintenance that is not 

covered by paragraph (a) of this section 

(that is, maintenance that is neither 

explicitly identified as critical emissionrelated maintenance, nor that we 

approve as critical emission-related 

maintenance). Noncritical emissionrelated maintenance generally includes 

maintenance on the components we 

specify in 40 CFR part 1068, Appendix 

I, that is not covered in paragraph (a) of 

this section. You must state in the 

owners manual that these steps are not 

necessary to keep the emission-related 

warranty valid. If operators fail to do 

this maintenance, this does not allow 

you to disqualify those engines from inuse testing or deny a warranty claim. Do 

not take these inspection or 

maintenance steps during service 

accumulation on your emission-data 

engines. 

* * * * * 

(g) Payment for scheduled 

maintenance. Owners are responsible 

for properly maintaining their engines. 

This generally includes paying for 

scheduled maintenance. However, 

manufacturers must pay for scheduled 

maintenance during the useful life if the 

regulations require it or if it meets all 

the following criteria: 

* * * * * 

■ 125. Section 1039.135 is amended by 

revising paragraphs (c)(6) and (c)(8) to 

read as follows: 

§ 1039.135 How must I label and identify 

the engines I produce? 

* * * * * 

(c) * * * 

(6) State the date of manufacture 

[DAY (optional), MONTH, and YEAR]; 

however, you may omit this from the 

label if you stamp, engrave, or otherwise 

permanently identify it elsewhere on 

the engine, in which case you must also 

describe in your application for 

certification where you will identify the 

date on the engine. 

* * * * * 

(8) Identify the emission-control 

system. Use terms and abbreviations as 

described in 40 CFR 1068.45. You may 

omit this information from the label if 

there is not enough room for it and you 

put it in the owners manual instead. 

* * * * * 


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Subpart C—[Amended] 

■ 126. Section 1039.201 is amended by 

adding paragraph (h) to read as follows: 

§ 1039.201 What are the general 

requirements for obtaining a certificate of 

conformity? 

* * * * * 

(h) For engines that become new after 

being placed into service, such as 

engines converted to nonroad use after 

being used in motor vehicles, we may 

specify alternate certification provisions 

consistent with the intent of this part. 

See the definition of ‘‘new nonroad 

engine’’ in § 1039.801. 

■ 127. Section 1039.220 is revised to 

read as follows: 

§ 1039.220 How do I amend the 

maintenance instructions in my 

application? 

You may amend your emissionrelated maintenance instructions after 

you submit your application for 

certification as long as the amended 

instructions remain consistent with the 

provisions of § 1039.125. You must send 

the Designated Compliance Officer a 

written request to amend your 

application for certification for an 

engine family if you want to change the 

emission-related maintenance 

instructions in a way that could affect 

emissions. In your request, describe the 

proposed changes to the maintenance 

instructions. If operators follow the 

original maintenance instructions rather 

than the newly specified maintenance, 

this does not allow you to disqualify 

those engines from in-use testing or 

deny a warranty claim. 

(a) If you are decreasing or 

eliminating any specified maintenance, 

you may distribute the new 

maintenance instructions to your 

customers 30 days after we receive your 

request, unless we disapprove your 

request. This would generally include 

replacing one maintenance step with 

another. We may approve a shorter time 

or waive this requirement. 

(b) If your requested change would 

not decrease the specified maintenance, 

you may distribute the new 

maintenance instructions anytime after 

you send your request. For example, 

this paragraph (b) would cover adding 

instructions to increase the frequency of 

filter changes for engines in severe-duty 

applications. 

(c) You need not request approval if 

you are making only minor corrections 

(such as correcting typographical 

mistakes), clarifying your maintenance 

instructions, or changing instructions 

for maintenance unrelated to emission 

control. We may ask you to send us 

copies of maintenance instructions 

revised under this paragraph (c). 

■ 128. Section 1039.225 is amended by 

revising the section heading, the 

introductory text, and paragraphs (b) 

introductory text, (b)(2), (e), and (f) to 

read as follows: 

§ 1039.225 How do I amend my application 

for certification? 

Before we issue you a certificate of 

conformity, you may amend your 

application to include new or modified 

engine configurations, subject to the 

provisions of this section. After we have 

issued your certificate of conformity, 

you may send us an amended 

application requesting that we include 

new or modified engine configurations 

within the scope of the certificate, 

subject to the provisions of this section. 

You must amend your application if any 

changes occur with respect to any 

information that is included or should 

be included in your application. 

* * * * * 

(b) To amend your application for 

certification, send the relevant 

information to the Designated 

Compliance Officer. 

* * * * * 

(2) Include engineering evaluations or 

data showing that the amended engine 

family complies with all applicable 

requirements. You may do this by 

showing that the original emission-data 

engine is still appropriate for showing 

that the amended family complies with 

all applicable requirements. 

* * * * * 

(e) For engine families already 

covered by a certificate of conformity, 

you may start producing the new or 

modified engine configuration anytime 

after you send us your amended 

application and before we make a 

decision under paragraph (d) of this 

section. However, if we determine that 

the affected engines do not meet 

applicable requirements, we will notify 

you to cease production of the engines 

and may require you to recall the 

engines at no expense to the owner. 

Choosing to produce engines under this 

paragraph (e) is deemed to be consent to 

recall all engines that we determine do 

not meet applicable emission standards 

or other requirements and to remedy the 

nonconformity at no expense to the 

owner. If you do not provide 

information required under paragraph 

(c) of this section within 30 days after 

we request it, you must stop producing 

the new or modified engines. 

(f) You may ask us to approve a 

change to your FEL in certain cases after 

the start of production. The changed 

FEL may not apply to engines you have 

already introduced into U.S. commerce, 

except as described in this paragraph (f). 

If we approve a changed FEL after the 

start of production, you must include 

the new FEL on the emission control 

information label for all engines 

produced after the change. You may ask 

us to approve a change to your FEL in 

the following cases: 

(1) You may ask to raise your FEL for 

your engine family at any time. In your 

request, you must show that you will 

still be able to meet the emission 

standards as specified in subparts B and 

H of this part. If you amend your 

application by submitting new test data 

to include a newly added or modified 

engine, as described in paragraph (b)(3) 

of this section, use the appropriate FELs 

with corresponding production volumes 

to calculate emission credits for the 

model year, as described in subpart H of 

this part. In all other circumstances, you 

must use the higher FEL for the entire 

engine family to calculate emission 

credits under subpart H of this part. 

(2) You may ask to lower the FEL for 

your engine family only if you have test 

data from production engines showing 

that emissions are below the proposed 

lower FEL. The lower FEL applies only 

to engines you produce after we approve 

the new FEL. Use the appropriate FELs 

with corresponding production volumes 

to calculate emission credits for the 

model year, as described in subpart H of 

this part. 

■ 129. Section 1039.230 is amended by 

revising paragraphs (b) and (d) to read 

as follows: 

§ 1039.230 How do I select engine 

families? 

* * * * * 

(b) Group engines in the same engine 

family if they are the same in all the 

following aspects: 

(1) The combustion cycle and fuel. 

(2) The cooling system (water-cooled 

vs. air-cooled). 

(3) Method of air aspiration. 

(4) Method of exhaust aftertreatment 

(for example, catalytic converter or 

particulate trap). 

(5) Combustion chamber design. 

(6) Bore and stroke. 

(7) Cylinder arrangement (such as inline vs. vee configurations). This applies 

for engines with aftertreatment devices 

only. 

(8) Method of control for engine 

operation other than governing (i.e., 

mechanical or electronic). 

(9) Power category. 

(10) Numerical level of the emission 

standards that apply to the engine. 

* * * * * 

(d) In unusual circumstances, you 

may group engines that are not identical 


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with respect to the things listed in 

paragraph (b) of this section in the same 

engine family if you show that their 

emission characteristics during the 

useful life will be similar. 

* * * * * 

■ 130. Section 1039.235 is amended by 

revising the section heading and 

paragraphs (c) and (d) introductory text 

to read as follows: 

§ 1039.235 What testing requirements 

apply for certification? 

* * * * * 

(c) We may measure emissions from 

any of your emission-data engines or 

other engines from the engine family, as 

follows: 

(1) We may decide to do the testing 

at your plant or any other facility. If we 

do this, you must deliver the engine to 

a test facility we designate. The engine 

you provide must include appropriate 

manifolds, aftertreatment devices, 

electronic control units, and other 

emission-related components not 

normally attached directly to the engine 

block. If we do the testing at your plant, 

you must schedule it as soon as possible 

and make available the instruments, 

personnel, and equipment we need. 

(2) If we measure emissions on one of 

your engines, the results of that testing 

become the official emission results for 

the engine. Unless we later invalidate 

these data, we may decide not to 

consider your data in determining if 

your engine family meets applicable 

requirements. 

(3) Before we test one of your engines, 

we may set its adjustable parameters to 

any point within the physically 

adjustable ranges (see § 1039.115(e)). 

(4) Before we test one of your engines, 

we may calibrate it within normal 

production tolerances for anything we 

do not consider an adjustable parameter. 

For example, this would apply for an 

engine parameter that is subject to 

production variability because it is 

adjustable during production, but is not 

considered an adjustable parameter (as 

defined in § 1039.801) because it is 

permanently sealed. 

(d) You may ask to use carryover 

emission data from a previous model 

year instead of doing new tests, but only 

if all the following are true: 

* * * * * 

■ 131. Section 1039.240 is amended by 

revising paragraphs (a), (b), and (c)(1) to 

read as follows: 

§ 1039.240 How do I demonstrate that my 

engine family complies with exhaust 

emission standards? 

(a) For purposes of certification, your 

engine family is considered in 

compliance with the emission standards 

in § 1039.101(a) and (b), § 1039.102(a) 

and (b), § 1039.104, and § 1039.105 if all 

emission-data engines representing that 

family have test results showing official 

emission results and deteriorated 

emission levels at or below these 

standards. This also applies for all test 

points for emission-data engines within 

the family used to establish 

deterioration factors. Note that your 

FELs are considered to be the applicable 

emission standards with which you 

must comply if you participate in the 

ABT program in subpart H of this part. 

(b) Your engine family is deemed not 

to comply if any emission-data engine 

representing that family has test results 

showing an official emission result or a 

deteriorated emission level for any 

pollutant that is above an applicable 

emission standard. Similarly, your 

engine family is deemed not to comply 

if any emission-data engine representing 

that family has test results showing any 

emission level above the applicable notto-exceed emission standard for any 

pollutant. This also applies for all test 

points for emission-data engines within 

the family used to establish 

deterioration factors. 

(c) * * * 

(1) Additive deterioration factor for 

exhaust emissions. Except as specified 

in paragraph (c)(2) of this section, use 

an additive deterioration factor for 

exhaust emissions. An additive 

deterioration factor is the difference 

between exhaust emissions at the end of 

the useful life and exhaust emissions at 

the low-hour test point. In these cases, 

adjust the official emission results for 

each tested engine at the selected test 

point by adding the factor to the 

measured emissions. If the factor is less 

than zero, use zero. Additive 

deterioration factors must be specified 

to one more decimal place than the 

applicable standard. 

* * * * * 

■ 132. Section 1039.245 is amended by 

revising the introductory text to read as 

follows: 

§ 1039.245 How do I determine 

deterioration factors from exhaust 

durability testing? 

This section describes how to 

determine deterioration factors, either 

with an engineering analysis, with preexisting test data, or with new emission 

measurements. Apply these 

deterioration factors to determine 

whether your engines will meet the 

duty-cycle emission standards 

throughout the useful life as described 

in § 1039.240. 

* * * * * 

■ 133. Section 1039.250 is amended by 

revising paragraphs (a) introductory text 

and (c) and removing paragraph (e) to 

read as follows: 

§ 1039.250 What records must I keep and 

what reports must I send to EPA? 

(a) Within 45 days after the end of the 

model year, send the Designated 

Compliance Officer a report describing 

the following information about engines 

you produced during the model year: 

* * * * * 

(c) Keep data from routine emission 

tests (such as test cell temperatures and 

relative humidity readings) for one year 

after we issue the associated certificate 

of conformity. Keep all other 

information specified in this section for 

eight years after we issue your 

certificate. 

* * * * * 

■ 134. Section 1039.255 is amended by 

revising paragraph (b) to read as follows: 

§ 1039.255 What decisions may EPA make 

regarding my certificate of conformity? 

* * * * * 

(b) We may deny your application for 

certification if we determine that your 

engine family fails to comply with 

emission standards or other 

requirements of this part or the Clean 

Air Act. We will base our decision on 

all available information. If we deny 

your application, we will explain why 

in writing. 

* * * * * 

■ 135. Section 1039.510 is amended by 

revising paragraph (b) and adding 

paragraph (c) to read as follows: 

§ 1039.510 Which duty cycles do I use for 

transient testing? 

* * * * * 

(b) The transient test sequence 

consists of an initial run through the 

transient duty cycle from a cold start, 20 

minutes with no engine operation, then 

a final run through the same transient 

duty cycle. Start sampling emissions 

immediately after you start the engine. 

Calculate the official transient emission 

result from the following equation: 


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Official transient emission result cold-start emissio = 0 05 . n ⋅s (g) + 0.95 hot-start emissions (g)

cold-start work

⋅

0 05 . ⋅ (kW ) + 0.95 hot-start work (kW ) ⋅⋅ ⋅ hr hr

(c) Calculate cycle statistics and 

compare with the established criteria as 

specified in 40 CFR 1065.514 to confirm 

that the test is valid. 

Subpart G—[Amended] 

■ 136. Section 1039.605 is amended by 

revising paragraph (d)(3) introductory 

text to read as follows: 

§ 1039.605 What provisions apply to 

engines certified under the motor-vehicle 

program? 

* * * * * 

(d) * * * 

(3) You must show that fewer than 50 

percent of the engine family’s total sales 

in the United States are used in nonroad 

applications. This includes engines 

used in any application without regard 

to which company manufactures the 

vehicle or equipment. Show this as 

follows: 

* * * * * 

■ 137. Section 1039.610 is amended by 

revising paragraph (d)(3) introductory 

text to read as follows: 

§ 1039.610 What provisions apply to 

vehicles certified under the motor-vehicle 

program? 

* * * * * 

(d) * * * 

(3) You must show that fewer than 50 

percent of the engine family’s total sales 

in the United States are used in nonroad 

applications. This includes any type of 

vehicle, without regard to which 

company completes the manufacturing 

of the nonroad equipment. Show this as 

follows: 

* * * * * 

■ 138. Section 1039.627 is amended by 

revising paragraphs (a)(3)(ii) and 

(a)(3)(iii) to read as follows: 

§ 1039.627 What are the incentives for 

equipment manufacturers to use cleaner 

engines? 

* * * * * 

(a) * * * 

(3) * * * 

* * * * * * * 

(ii) 56 ≤ kW < 130 ............. Two engines ....... NOX standards in § 1039.102(e)(1), 

and NMHC standard of 0.19 g/ 

kW-hr, a PM standard of 0.02 g/ 

kW-hr, and a CO standard of 5.0 

g/kW-hr.

Standards in Tables 2 through 7 of 

§ 1039.102 or in § 1039.101.

One engine. 

(iii) 130 ≤ kW < 560 .......... Two engines ....... NOX standards in § 1039.102(e)(2), 

an NMHC standard of 0.19 g/kWhr, a PM standard of 0.02 g/kWhr, and a CO standard of 3.5 g/ 

kW-hr.

Standards in Tables 2 through 7 of 

§ 1039.102 or in § 1039.101.

One engine. 

* * * * * 

Subpart H—[Amended] 

■ 139. Section 1039.705 is amended by 

revising paragraph (b) introductory text 

(before the equation) to read as follows: 

§ 1039.705 How do I generate and 

calculate emission credits? 

* * * * * 

(b) For each participating family, 

calculate positive or negative emission 

credits relative to the otherwise 

applicable emission standard. Calculate 

positive emission credits for a family 

that has an FEL below the standard. 

Calculate negative emission credits for a 

family that has an FEL above the 

standard. Sum your positive and 

negative credits for the model year 

before rounding. Round the sum of 

emission credits to the nearest kilogram 

(kg), using consistent units throughout 

the following equation: 

* * * * * 

■ 140. Section 1039.715 is revised to 

read as follows: 

§ 1039.715 How do I bank emission 

credits? 

(a) Banking is the retention of 

emission credits by the manufacturer 

generating the emission credits for use 

in future model years for averaging or 

trading. 

(b) You may designate any emission 

credits you plan to bank in the reports 

you submit under § 1039.730 as 

reserved credits. During the model year 

and before the due date for the final 

report, you may designate your reserved 

emission credits for averaging or 

trading. 

(c) Reserved credits become actual 

emission credits when you submit your 

final report. However, we may revoke 

these emission credits if we are unable 

to verify them after reviewing your 

reports or auditing your records. 

■ 141. Section 1039.720 is amended by 

revising paragraph (b) to read as follows: 

§ 1039.720 How do I trade emission 

credits? 

* * * * * 

(b) You may trade actual emission 

credits as described in this subpart. You 

may also trade reserved emission 

credits, but we may revoke these 

emission credits based on our review of 

your records or reports or those of the 

company with which you traded 

emission credits. You may trade banked 

credits within an averaging set to any 

certifying manufacturer. 

* * * * * 

■ 142. Section 1039.725 is amended by 

revising paragraph (b)(2) to read as 

follows: 

§ 1039.725 What must I include in my 

application for certification? 

* * * * * 

(b) * * * 

(2) Detailed calculations of projected 

emission credits (positive or negative) 

based on projected production volumes. 

We may require you to include similar 

calculations from your other engine 

families to demonstrate that you will be 

able to avoid a negative credit balance 

for the model year. If you project 

negative emission credits for a family, 

state the source of positive emission 

credits you expect to use to offset the 

negative emission credits. 

■ 143. Section 1039.730 is amended by 

revising paragraphs (b)(3), (b)(4), (b)(5), 

and (f) to read as follows: 


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§ 1039.730 What ABT reports must I send 

to EPA? 

* * * * * 

(b) * * * 

(3) The FEL for each pollutant. If you 

change the FEL after the start of 

production, identify the date that you 

started using the new FEL and/or give 

the engine identification number for the 

first engine covered by the new FEL. In 

this case, identify each applicable FEL 

and calculate the positive or negative 

emission credits as specified in 

§ 1039.225. 

(4) The projected and actual U.S.- 

directed production volumes for the 

model year. If you changed an FEL 

during the model year, identify the 

actual production volume associated 

with each FEL. 

(5) Maximum engine power for each 

engine configuration, and the average 

engine power weighted by U.S.-directed 

production volumes for the engine 

family. 

* * * * * 

(f) Correct errors in your end-of-year 

report or final report as follows: 

(1) You may correct any errors in your 

end-of-year report when you prepare the 

final report, as long as you send us the 

final report by the time it is due. 

(2) If you or we determine within 270 

days after the end of the model year that 

errors mistakenly decreased your 

balance of emission credits, you may 

correct the errors and recalculate the 

balance of emission credits. You may 

not make these corrections for errors 

that are determined more than 270 days 

after the end of the model year. If you 

report a negative balance of emission 

credits, we may disallow corrections 

under this paragraph (f)(2). 

(3) If you or we determine anytime 

that errors mistakenly increased your 

balance of emission credits, you must 

correct the errors and recalculate the 

balance of emission credits. 

■ 144. Section 1039.735 is amended by 

revising paragraphs (b), (d), and (e) to 

read as follows: 

§ 1039.735 What records must I keep? 

* * * * * 

(b) Keep the records required by this 

section for at least eight years after the 

due date for the end-of-year report. You 

may not use emission credits for any 

engines if you do not keep all the 

records required under this section. You 

must therefore keep these records to 

continue to bank valid credits. Store 

these records in any format and on any 

media, as long as you can promptly 

send us organized, written records in 

English if we ask for them. You must 

keep these records readily available. We 

may review them at any time. 

* * * * * 

(d) Keep records of the engine 

identification number for each engine 

you produce that generates or uses 

emission credits under the ABT 

program. You may identify these 

numbers as a range. If you change the 

FEL after the start of production, 

identify the date you started using each 

FEL and the range of engine 

identification numbers associated with 

each FEL. You must also identify the 

purchaser and destination for each 

engine you produce to the extent this 

information is available. 

(e) We may require you to keep 

additional records or to send us relevant 

information not required by this section 

in accordance with the Clean Air Act. 

Subpart I—[Amended] 

■ 145. Section 1039.801 is amended as 

follows: 

■ a. By adding definitions for ‘‘Alcoholfueled engine’’, ‘‘Carryover’’, and ‘‘Date of 

manufacture’’ in alphabetical order. 

■ b. By revising the definitions for 

‘‘Engine configuration’’, ‘‘Model year’’, 

‘‘New nonroad engine’’, ‘‘Total 

hydrocarbon’’, ‘‘Total hydrocarbon 

equivalent’’, and ‘‘Useful life. 

§ 1039.801 What definitions apply to this 

part? 

* * * * * 

Alcohol-fueled engine means an 

engine that is designed to run using an 

alcohol fuel. For purposes of this 

definition, alcohol fuels do not include 

fuels with a nominal alcohol content 

below 25 percent by volume. 

* * * * * 

Carryover means relating to 

certification based on emission data 

generated from an earlier model year as 

described in § 1039.235(d). 

* * * * * 

Date of manufacture has the meaning 

given in 40 CFR 1068.30. 

* * * * * 

Engine configuration means a unique 

combination of engine hardware and 

calibration within an engine family. 

Engines within a single engine 

configuration differ only with respect to 

normal production variability or factors 

unrelated to emissions. 

* * * * * 

Model year means one of the 

following things: 

(1) For freshly manufactured 

equipment and engines (see definition 

of ‘‘new nonroad engine,’’ paragraph (1)), 

model year means one of the following: 

(i) Calendar year. 

(ii) Your annual new model 

production period if it is different than 

the calendar year. This must include 

January 1 of the calendar year for which 

the model year is named. It may not 

begin before January 2 of the previous 

calendar year and it must end by 

December 31 of the named calendar 

year. 

(2) For an engine that is converted to 

a nonroad engine after being placed into 

service as a stationary engine, or being 

certified and placed into service as a 

motor vehicle engine, model year means 

the calendar year in which the engine 

was originally produced. For a motor 

vehicle engine that is converted to be a 

nonroad engine without having been 

certified, model year means the calendar 

year in which the engine becomes a new 

nonroad engine. (See definition of ‘‘new 

nonroad engine,’’ paragraph (2).) 

(3) For a nonroad engine excluded 

under § 1039.5 that is later converted to 

operate in an application that is not 

excluded, model year means the 

calendar year in which the engine was 

originally produced (see definition of 

‘‘new nonroad engine,’’ paragraph (3)). 

(4) For engines that are not freshly 

manufactured but are installed in new 

nonroad equipment, model year means 

the calendar year in which the engine is 

installed in the new nonroad equipment 

(see definition of ‘‘new nonroad engine,’’ 

paragraph (4)). 

(5) For imported engines: 

(i) For imported engines described in 

paragraph (5)(i) of the definition of ‘‘new 

nonroad engine,’’ model year has the 

meaning given in paragraphs (1) through 

(4) of this definition. 

(ii) For imported engines described in 

paragraph (5)(ii) of the definition of 

‘‘new nonroad engine,’’ model year has 

the meaning given in 40 CFR 89.602 for 

independent commercial importers. 

(iii) For imported engines described 

in paragraph (5)(iii) of the definition of 

‘‘new nonroad engine,’’ model year 

means the calendar year in which the 

engine is first assembled in its imported 

configuration, unless specified 

otherwise in this part or in 40 CFR part 

1068. 

* * * * * 

New nonroad engine means any of the 

following things: 

(1) A freshly manufactured nonroad 

engine for which the ultimate purchaser 

has never received the equitable or legal 

title. This kind of engine might 

commonly be thought of as ‘‘brand 

new.’’ In the case of this paragraph (1), 

the engine is new from the time it is 

produced until the ultimate purchaser 

receives the title or the product is 

placed into service, whichever comes 

first. 


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(2) An engine originally manufactured 

as a motor vehicle engine or a stationary 

engine that is later used or intended to 

be used in a piece of nonroad 

equipment. In this case, the engine is no 

longer a motor vehicle or stationary 

engine and becomes a ‘‘new nonroad 

engine.’’ The engine is no longer new 

when it is placed into nonroad service. 

This paragraph (2) applies if a motor 

vehicle engine or a stationary engine is 

installed in nonroad equipment, or if a 

motor vehicle or a piece of stationary 

equipment is modified (or moved) to 

become nonroad equipment. 

(3) A nonroad engine that has been 

previously placed into service in an 

application we exclude under § 1039.5, 

when that engine is installed in a piece 

of equipment that is covered by this part 

1039. The engine is no longer new when 

it is placed into nonroad service covered 

by this part 1039. For example, this 

would apply to marine diesel engine 

that is no longer used in a marine vessel 

but is instead installed in a piece of 

nonroad equipment subject to the 

provisions of this part. 

(4) An engine not covered by 

paragraphs (1) through (3) of this 

definition that is intended to be 

installed in new nonroad equipment. 

This generally includes installation of 

used engines in new equipment. The 

engine is no longer new when the 

ultimate purchaser receives a title for 

the equipment or the product is placed 

into service, whichever comes first. 

(5) An imported nonroad engine, 

subject to the following provisions: 

(i) An imported nonroad engine 

covered by a certificate of conformity 

issued under this part that meets the 

criteria of one or more of paragraphs (1) 

through (4) of this definition, where the 

original engine manufacturer holds the 

certificate, is new as defined by those 

applicable paragraphs. 

(ii) An imported engine covered by a 

certificate of conformity issued under 

this part, where someone other than the 

original engine manufacturer holds the 

certificate (such as when the engine is 

modified after its initial assembly), is a 

new nonroad engine when it is 

imported. It is no longer new when the 

ultimate purchaser receives a title for 

the engine or it is placed into service, 

whichever comes first. 

(iii) An imported nonroad engine that 

is not covered by a certificate of 

conformity issued under this part at the 

time of importation is new, but only if 

it was produced on or after the dates 

shown in the following table. This 

addresses uncertified engines and 

equipment initially placed into service 

that someone seeks to import into the 

United States. Importation of this kind 

of engine (or equipment containing such 

an engine) is generally prohibited by 40 

CFR part 1068. However, the 

importation of such an engine is not 

prohibited if the engine has an earlier 

model year than that identified in the 

following table: 

APPLICABILITY OF EMISSION STANDARDS FOR NONROAD DIESEL ENGINES

Maximum engine power 

Initial date of 

emission standards 

kW < 19 ........................... January 1, 2000. 

19 ≤ kW < 37 ................... January 1, 1999. 

37 ≤ kW < 75 ................... January 1, 1998. 

75 ≤ kW < 130 ................. January 1, 1997. 

130 ≤ kW ≤ 560 ............... January 1, 1996. 

kW > 560 ......................... January 1, 2000. 

* * * * * 

Total hydrocarbon has the meaning 

given in 40 CFR 1065.1001. This 

generally means the combined mass of 

organic compounds measured by the 

specified procedure for measuring total 

hydrocarbon, expressed as a 

hydrocarbon with an atomic hydrogento-carbon ratio of 1.85:1. 

Total hydrocarbon equivalent has the 

meaning given in 40 CFR 1065.1001. 

This generally means the sum of the 

carbon mass contributions of nonoxygenated hydrocarbons, alcohols and 

aldehydes, or other organic compounds 

that are measured separately as 

contained in a gas sample, expressed as 

exhaust hydrocarbon from petroleumfueled engines. The atomic hydrogen-tocarbon ratio of the equivalent 

hydrocarbon is 1.85:1. 

* * * * * 

Useful life means the period during 

which the engine is designed to 

properly function in terms of reliability 

and fuel consumption, without being 

remanufactured, specified as a number 

of hours of operation or calendar years, 

whichever comes first. It is the period 

during which a nonroad engine is 

required to comply with all applicable 

emission standards. See § 1039.101(g). 

* * * * * 

§ 1039.810 [Removed] 

■ 146. Section 1039.810 is removed. 

PART 1042—CONTROL OF EMISSIONS 

FROM NEW AND IN-USE MARINE 

COMPRESSION-IGNITION ENGINES 

AND VESSELS 

■ 147. The authority citation for part 

1042 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 148. Section 1042.1 is revised to read 

as follows: 

§ 1042.1 Applicability. 

Except as provided in this section and 

§ 1042.5, the regulations in this part 

1042 apply for all new compressionignition marine engines (including new 

engines deemed to be compressionignition engines under this section) and 

vessels containing such engines. See 

§ 1042.901 for the definitions of engines 

and vessels considered to be new. 

(a) The emission standards of this part 

1042 for freshly manufactured engines 

apply for new marine engines starting 

with the model years noted in the 

following tables: 

TABLE 1 TO § 1042.1—PART 1042 APPLICABILITY BY MODEL YEAR

Engine category Maximum engine power a Displacement (L/cyl) or application Model year 

Category 1 ................................... kW < 75 ................................................ disp. < 0.9 .................................................................. b 2009 

75 ≤ kW ≤ 3700 .................................... disp. < 0.9 .................................................................. 2012 

0.9 ≤ disp. < 1.2 ......................................................... 2013 

1.2 ≤ disp. < 2.5 ......................................................... 2014 

2.5 ≤ disp. < 3.5 ......................................................... 2013 

3.5 ≤ disp. < 7.0 ......................................................... 2012 


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TABLE 1 TO § 1042.1—PART 1042 APPLICABILITY BY MODEL YEAR—Continued 

Engine category Maximum engine power a Displacement (L/cyl) or application Model year 

kW > 3700 ............................................ disp. < 7.0 .................................................................. 2014 

Category 2 ................................... kW ≤ 3700 ............................................. 7.0 < disp. < 15.0 ....................................................... 2013 

kW > 3700 ............................................ 7.0 ≤ disp. < 15.0 ....................................................... 2014 

All .......................................................... 15 ≤ disp. < 30 ........................................................... 2014 

Category 3 ................................... All .......................................................... disp. ≥ 30 ................................................................... 2011 

aSee § 1042.140, which describes how to determine maximum engine power. bSee Table 1 of § 1042.101 for the first model year in which this part 1042 applies for engines with maximum engine power below 75 kW and 

displacement at or above 0.9 L/cyl. 

(b) New engines with maximum 

engine power below 37 kW and 

originally manufactured and certified 

before the model years identified in 

Table 1 to this section are subject to 

emission standards and requirements of 

40 CFR part 89. The provisions of this 

part 1042 do not apply for such engines 

certified under 40 CFR part 89, except 

as follows beginning June 29, 2010: 

(1) The allowances of this part apply. 

(2) The definitions of ‘‘new marine 

engine’’ and ‘‘model year’’ apply. 

(c) Freshly manufactured engines 

with maximum engine power at or 

above 37 kW and originally 

manufactured and certified before the 

model years identified in Table 1 to this 

section are subject to emission 

standards and requirements of 40 CFR 

part 94. The provisions of this part 1042 

do not apply for such engines certified 

under 40 CFR part 89, except as follows 

beginning June 29, 2010: 

(1) The allowances of this part apply. 

(2) The definitions of ‘‘new marine 

engine’’ and ‘‘model year’’ apply. 

(3) The remanufacturing provisions in 

subpart I of this part may apply for 

remanufactured engines originally 

manufactured in model years before the 

model years identified in Table 1 to this 

section. 

(4) 40 CFR part 94 specifies other 

provisions from this part 1042 that 

apply. 

(d) Engines with model years before 

those specified in Table 1 to this section 

are generally subject to the Tier 1 or Tier 

2 standards of 40 CFR part 94. Such 

engines may be certified to those 

standards under this part 1042. All the 

provisions of this part except the 

emission standards apply to such 

engines if they are certified under this 

part. Note that engines subject to, but 

not certified to, the standards of 40 CFR 

part 94 are subject to the requirements 

and prohibitions of this part and 40 CFR 

part 1068. 

(e) The requirements of subpart I of 

this part apply to remanufactured 

Category 1 and Category 2 engines 

beginning July 7, 2008. 

(f) The marine engines listed in this 

paragraph (f) are subject to all the 

requirements of this part even if they do 

not meet the definition of ‘‘compressionignition’’ in § 1042.901. The following 

engines are deemed to be compressionignition engines for purposes of this 

part: 

(1) Marine engines powered by 

natural gas or other gaseous fuels with 

maximum engine power at or above 250 

kW. Note that gaseous-fueled engines 

with maximum engine power below 250 

kW may or may not meet the definition 

of ‘‘compression-ignition’’ in § 1042.901. 

(2) Marine gas turbine engines. 

(3) Other marine internal combustion 

engines that do not meet the definition 

of ‘‘spark-ignition’’ in § 1042.901. 

(g) Some of the provisions of this part 

may apply for other engines as specified 

in 40 CFR part 1043. 

■ 149. Section 1042.2 is revised to read 

as follows: 

§ 1042.2 Who is responsible for 

compliance? 

The regulations in this part 1042 

contain provisions that affect both 

engine manufacturers and others. 

However, the requirements of this part, 

other than those of subpart I of this part, 

are generally addressed to the engine 

manufacturer for freshly manufactured 

marine engines or other certificate 

holders. The term ‘‘you’’ generally 

means the engine manufacturer, as 

defined in § 1042.901, especially for 

issues related to certification (including 

production-line testing, reporting, etc.). 

■ 150. Section 1042.5 is amended by 

revising paragraph (a) and adding 

paragraph (c) to read as follows: 

§ 1042.5 Exclusions. 

* * * * * 

(a) Foreign vessels. The requirements 

and prohibitions of this part do not 

apply to engines installed on foreign 

vessels, as defined in § 1042.901. Note 

however, that the requirements and 

prohibitions of this part do apply to 

engines installed on any formerly 

foreign vessels that are reflagged as U.S.- 

flagged vessels. 

* * * * * 

(c) Recreational gas turbine engines. 

The requirements and prohibitions of 

this part do not apply to gas turbine 

engines installed on recreational 

vessels, as defined in § 1042.901. 

■ 151. Section 1042.15 is revised to read 

as follows: 

§ 1042.15 Do any other regulation parts 

apply to me? 

(a) Part 1043 of this chapter describes 

requirements related to international 

pollution prevention that apply for 

some of the engines subject to this part. 

(b) The evaporative emission 

requirements of part 1060 of this 

chapter apply to vessels that include 

installed engines fueled with a volatile 

liquid fuel as specified in § 1042.107. 

(Note: Conventional diesel fuel is not 

considered to be a volatile liquid fuel.) 

(c) Part 1065 of this chapter describes 

procedures and equipment 

specifications for testing engines to 

measure exhaust emissions. Subpart F 

of this part 1042 describes how to apply 

the provisions of part 1065 of this 

chapter to determine whether engines 

meet the exhaust emission standards in 

this part. 

(d) The requirements and prohibitions 

of part 1068 of this chapter apply to 

everyone, including anyone who 

manufactures, imports, installs, owns, 

operates, or rebuilds any of the engines 

subject to this part 1042, or vessels 

containing these engines. Part 1068 of 

this chapter describes general 

provisions, including these seven areas: 

(1) Prohibited acts and penalties for 

engine manufacturers, vessel 

manufacturers, and others. 

(2) Rebuilding and other aftermarket 

changes. 

(3) Exclusions and exemptions for 

certain engines. 


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(4) Importing engines. 

(5) Selective enforcement audits of 

your production. 

(6) Defect reporting and recall. 

(7) Procedures for hearings. 

(e) Other parts of this chapter apply 

if referenced in this part. 

■ 152. A new § 1042.30 is added to 

subpart A to read as follows: 

§ 1042.30 Submission of information. 

(a) This part includes various 

requirements to record data or other 

information. Refer to § 1042.925 and 40 

CFR 1068.25 regarding recordkeeping 

requirements. Unless we specify 

otherwise, store these records in any 

format and on any media and keep them 

readily available for one year after you 

send an associated application for 

certification, or one year after you 

generate the data if they do not support 

an application for certification. You 

must promptly send us organized, 

written records in English if we ask for 

them. We may review them at any time. 

(b) The regulations in § 1042.255 and 

40 CFR 1068.101 describe your 

obligation to report truthful and 

complete information and the 

consequences of failing to meet this 

obligation. This includes information 

not related to certification. 

(c) Send all reports and requests for 

approval to the Designated Compliance 

Officer (see § 1042.901). 

(d) Any written information we 

require you to send to or receive from 

another company is deemed to be a 

required record under this section. Such 

records are also deemed to be 

submissions to EPA. We may require 

you to send us these records whether or 

not you are a certificate holder. 

Subpart B—[Amended] 

■ 153. Section 1042.101 is amended by 

revising the section heading, Table 1 in 

paragraph (a)(3), and paragraph 

(d)(1)(iii) to read as follows: 

§ 1042.101 Exhaust emission standards 

for Category 1 engines and Category 2 

engines. 

(a) * * * 

(3) * * * 

BILLING CODE 6560–50–P 


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BILLING CODE 6560–50–C 

* * * * * 

(d) * * * 

(1) * * * 

(iii) Diesel-fueled and all other 

engines not described in paragraph 

(d)(1)(i) or (ii) of this section must 

comply with Tier 3 HC standards based 

on THC emissions and with Tier 4 

standards based on NMHC emissions. 

* * * * * 

■ 154. A new § 1042.104 is added to 

subpart B to read as follows: 

§ 1042.104 Exhaust emission standards 

for Category 3 engines. 

(a) Duty-cycle standards. Exhaust 

emissions from your engines may not 

exceed emission standards, as follows: 

(1) Measure emissions using the test 

procedures described in subpart F of 

this part. Note that while no PM 

standards apply for Category 3 engines, 

PM emissions must be measured for 

certification testing and reported under 

§ 1042.205. Note also that you are not 

required to measure PM emissions for 

other testing. 

(2) NOX standards apply based on the 

engine’s model year and maximum inuse engine speed as shown in the 

following table: 


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TABLE 1 TO § 1042.104—NOX EMISSION STANDARDS FOR CATEGORY 3 ENGINES (G/KW-HR) 

Emission standards Model year 

Maximum in-use engine speed 

Less than 

130 RPM 

130–2000 

RPM a

Over 2000 

RPM 

Tier 1 .............................................................. 2004–2010 b ................................................... 17.0 45.0·n (¥0.20) 9.8 

Tier 2 .............................................................. 2011–2015 ...................................................... 14.4 44.0·n (¥0.23) 7.7 

Tier 3 .............................................................. 2016 and later ................................................ 3.4 9.0·n (¥0.20) 2.0 

a Applicable standards are calculated from n (maximum in-use engine speed, in RPM, as specified in § 1042.140). Round the standards to one 

decimal place. b Tier 1 NOX standards apply as specified in 40 CFR part 94 for engines originally manufactured in model years 2004 through 2010. They are 

shown here only for reference. 

(3) The HC standard for Tier 2 and 

later engines is 2.0 g/kW-hr. This 

standard applies as follows: 

(i) Alcohol-fueled engines must 

comply with HC standards based on 

THCE emissions. 

(ii) Natural gas-fueled engines must 

comply with HC standards based on 

NMHC emissions. 

(iii) Diesel-fueled and all other 

engines not described in paragraph 

(a)(3)(i) or (ii) of this section must 

comply with HC standards based on 

THC emissions. 

(4) The CO standard for Tier 2 and 

later engines is 5.0 g/kW-hr. 

(b) Averaging, banking, and trading. 

Category 3 engines are not eligible for 

participation in the averaging, banking, 

and trading (ABT) program as described 

in subpart H of this part. 

(c) Mode caps. Measured NOX

emissions may not exceed the cap 

specified in this paragraph (c) for any 

applicable duty-cycle test modes with 

power greater than 10 percent maximum 

engine power. Calculate the mode cap 

by multiplying the applicable NOX

standard by 1.5 and rounding to the 

nearest 0.1 g/kW-hr. Note that mode 

caps do not apply for pollutants other 

than NOX and do not apply for any 

modes of operation outside of the 

applicable duty cycles in § 1042.505. 

Category 3 engines are not subject to 

not-to-exceed standards. 

(d) Useful life. Your engines must 

meet the exhaust emission standards of 

this section over their full useful life, 

expressed as a period in years or hours 

of engine operation, whichever comes 

first. 

(1) The minimum useful life value is 

3 years or 10,000 hours of operation. 

(2) Specify a longer useful life in 

hours for an engine family under either 

of two conditions: 

(i) If you design, advertise, or market 

your engine to operate longer than the 

minimum useful life (your 

recommended hours until rebuild 

indicates a longer design life). 

(ii) If your basic mechanical warranty 

is longer than the minimum useful life. 

(e) Applicability for testing. The dutycycle emission standards in this section 

apply to all testing performed according 

to the procedures in § 1042.505, 

including certification, production-line, 

and in-use testing. See paragraph (g) of 

this section for standards that apply for 

certain other test procedures, such as 

some production-line testing. 

(f) Domestic engines. Engines 

installed on vessels excluded from 40 

CFR part 1043 because they operate 

only domestically may not be certified 

for use with residual fuels. 

(g) Alternate installed-engine 

standards. NOX emissions may not 

exceed the standard specified in this 

paragraph (g) for test of engines 

installed on vessels when you are 

unable to operate the engine at the test 

points for the specified duty cycle, and 

you approximate these points consistent 

with the specifications of section 6 of 

Appendix 8 to the NOX Technical Code 

(incorporated by reference in 

§ 1042.910). Calculate the alternate 

installed-engine standard by 

multiplying the applicable NOX

standard by 1.1 and rounding to the 

nearest 0.1 g/kW-hr. 

■ 155. Section 1042.110 is amended by 

revising paragraph (a)(2) and adding 

paragraphs (a)(3) and (d) to read as 

follows: 

§ 1042.110 Recording reductant use and 

other diagnostic functions. 

(a) * * * 

(2) The onboard computer log must 

record in nonvolatile computer memory 

all incidents of engine operation with 

inadequate reductant injection or 

reductant quality. Use good engineering 

judgment to ensure that the operator can 

readily access the information to submit 

the report required by § 1042.660. For 

example, you may meet this 

requirement by documenting the 

incident in a text file that can be 

downloaded or printed by the operator. 

(3) SCR systems must also conform to 

the provisions of paragraph (d) of this 

section if they are equipped with on-off 

controls as allowed under § 1042.115(g). 

* * * * * 

(d) For Category 3 engines equipped 

with on-off NOX controls (as allowed by 

§ 1042.115(g)), you must also equip your 

engine to continuously monitor NOX

concentrations in the exhaust. See 

§ 1042.650 to determine if this 

requirement applies for a given Category 

1 or Category 2 engine. Use good 

engineering judgment to alert operators 

if measured NOX concentrations 

indicate malfunctioning emission 

controls. Record any such operation in 

nonvolatile computer memory. You are 

not required to monitor NOX

concentrations during operation for 

which the emission controls may be 

disabled under § 1042.115(g). For the 

purpose of this paragraph (d), 

‘‘malfunctioning emission controls’’ 

means any condition in which the 

measured NOX concentration exceeds 

the highest value expected when the 

engine is in compliance with the 

installed engine standard of 

§ 1042.104(g). Use good engineering 

judgment to determine these expected 

values during production-line testing of 

the engine using linear interpolation 

between test points and accounting for 

the degree to which the cycle-weighted 

emissions of the engine are below the 

standard. You may also use additional 

intermediate test points measured 

during the production-line test. Note 

that the provisions of paragraph (a) of 

this section also apply for SCR systems 

covered by this paragraph (d). For 

engines subject to both the provisions of 

paragraph (a) of this section and this 

paragraph (d), use good engineering 

judgment to integrate diagnostic features 

to comply with both paragraphs. 

■ 156. Section 1042.115 is amended by 

revising paragraphs (d)(2) introductory 

text, (f) introductory text, and adding 

paragraphs (f)(4) and (g) to read as 

follows: 

§ 1042.115 Other requirements. 

* * * * * 

(d) * * * 


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(2) Category 2 and Category 3 engines 

that have adjustable parameters must 

meet all the requirements of this part for 

any adjustment in the specified 

adjustable range. You must specify in 

your application for certification the 

adjustable range of each adjustable 

parameter on a new engine to— 

* * * * * 

(f) Defeat devices. You may not equip 

your engines with a defeat device. A 

defeat device is an auxiliary emission 

control device that reduces the 

effectiveness of emission controls under 

conditions that the engine may 

reasonably be expected to encounter 

during normal operation and use. (Note 

that this means emission control for 

operation outside of and between the 

official test modes is generally expected 

to be similar to emission control 

demonstrated at the test modes.) This 

does not apply to auxiliary emission 

control devices you identify in your 

application for certification if any of the 

following is true: 

* * * * * 

(4) The engine is a Category 3 engine 

and the AECD conforms to the 

requirements of paragraph (g) of this 

section. See § 1042.650 to determine if 

this allowance applies for a given 

Category 1 or Category 2 engine. 

(g) On-off controls for Category 3 

engines. Manufacturers may equip 

Category 3 engines with features that 

disable Tier 3 NOX emission controls 

subject to the provisions of this 

paragraph (g). See § 1042.650 to 

determine if this allowance applies for 

a given Category 1 or Category 2 engine. 

Where this paragraph (g) applies for a 

Category 1 or Category 2 engine, read 

‘‘Tier 2’’ to mean ‘‘Tier 3’’ and read ‘‘Tier 

3’’ to mean ‘‘Tier 4’’. 

(1) Features that disable Tier 3 

emission controls are considered to be 

AECDs whether or not they meet the 

definition of an AECD. For example, 

manually operated on-off features are 

AECDs under this paragraph (g). The 

features must be identified in your 

application for certification as AECDs. 

For purposes of this paragraph (g), the 

term ‘‘features that disable Tier 3 

emission controls’’ includes (but is not 

limited to) any combination of the 

following that cause the engine’s 

emissions to exceed any Tier 3 emission 

standard: 

(i) Bypassing of exhaust 

aftertreatment. 

(ii) Reducing or eliminating flow of 

reductant to an SCR system. 

(iii) Modulating engine calibration in 

a manner that increases engine-out 

emissions of a regulated pollutant. 

(2) You must demonstrate that the 

AECD will not disable emission controls 

while operating in areas where 

emissions could reasonably be expected 

to adversely affect U.S. air quality. If an 

ECA has been established for U.S. 

waters, this means you must 

demonstrate that the AECD will not 

disable emission control while 

operating in waters within the ECA or 

any ECA associated area. (Note: See the 

regulations in 40 CFR part 1043 for 

requirements related to operation in 

ECAs, including foreign ECAs.) 

Compliance with this paragraph will 

generally require that the AECD 

operation be based on Global 

Positioning System (GPS) inputs. We 

may consider any relevant information 

to determine whether your AECD 

conforms to this paragraph (g). 

(3) The onboard computer log must 

record in nonvolatile computer memory 

all incidents of engine operation with 

the Tier 3 emission controls disabled. 

(4) The engine must comply fully 

with the Tier 2 standards when the Tier 

3 emission controls are disabled. 

■ 157. Section 1042.120 is amended by 

adding paragraph (b)(2) and revising 

paragraph (c) to read as follows: 

§ 1042.120 Emission-related warranty 

requirements. 

* * * * * 

(b) * * * 

(2) For Category 3 engines, your 

emission-related warranty must be valid 

throughout the engine’s full useful life 

as specified in § 1042.104(d). 

* * * * * 

(c) Components covered. The 

emission-related warranty covers all 

components whose failure would 

increase an engine’s emissions of any 

regulated pollutant, including 

components listed in 40 CFR part 1068, 

Appendix I, and components from any 

other system you develop to control 

emissions. The emission-related 

warranty for freshly manufactured 

marine engines covers these 

components even if another company 

produces the component. Your 

emission-related warranty does not need 

to cover components whose failure 

would not increase an engine’s 

emissions of any regulated pollutant. 

For remanufactured engines, your 

emission-related warranty is required to 

cover only those parts that you supply 

or those parts for which you specify 

allowable part manufacturers. It does 

not need to cover used parts that are not 

replaced during the remanufacture. 

* * * * * 

■ 158. Section 1042.125 is amended by 

revising the section heading, 

introductory text, and paragraphs 

(a)(1)(iii) and (d) to read as follows: 

§ 1042.125 Maintenance instructions. 

Give the ultimate purchaser of each 

new engine written instructions for 

properly maintaining and using the 

engine, including the emission control 

system, as described in this section. The 

maintenance instructions also apply to 

service accumulation on your emissiondata engines as described in § 1042.245 

and in 40 CFR part 1065. The 

restrictions specified in paragraphs (a) 

through (e) of this section related to 

allowable maintenance apply only to 

Category 1 and Category 2 engines. 

Manufacturers may specify any 

maintenance for Category 3 engines. 

(a) * * * 

(1) * * * 

(iii) You provide the maintenance free 

of charge and clearly say so in your 

maintenance instructions. 

* * * * * 

(d) Noncritical emission-related 

maintenance. Subject to the provisions 

of this paragraph (d), you may schedule 

any amount of emission-related 

inspection or maintenance that is not 

covered by paragraph (a) of this section 

(that is, maintenance that is neither 

explicitly identified as critical emissionrelated maintenance, nor that we 

approve as critical emission-related 

maintenance). Noncritical emissionrelated maintenance generally includes 

maintenance on the components we 

specify in 40 CFR part 1068, Appendix 

I that is not covered in paragraph (a) of 

this section. You must state in the 

owners manual that these steps are not 

necessary to keep the emission-related 

warranty valid. If operators fail to do 

this maintenance, this does not allow 

you to disqualify those engines from inuse testing or deny a warranty claim. Do 

not take these inspection or 

maintenance steps during service 

accumulation on your emission-data 

engines. 

* * * * * 

■ 159. Section 1042.135 is amended by 

revising paragraphs (c)(5), (c)(8), (c)(9), 

and (c)(11) and adding paragraphs 

(c)(12) and (c)(13) to read as follows: 

§ 1042.135 Labeling. 

* * * * * 

(c) * * * 

(5) State the date of manufacture 

[DAY (optional), MONTH, and YEAR]; 

however, you may omit this from the 

label if you stamp, engrave, or otherwise 

permanently identify it elsewhere on 

the engine, in which case you must also 

describe in your application for 

certification where you will identify the 

date on the engine. 

* * * * * 


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(8) State the useful life for your engine 

family if the applicable useful life is 

based on the provisions of 

§ 1042.101(e)(2) or (3), or 

§ 1042.104(d)(2). 

(9) Identify the emission control 

system. Use terms and abbreviations as 

described in 40 CFR 1068.45. You may 

omit this information from the label if 

there is not enough room for it and you 

put it in the owners manual instead. 

* * * * * 

(11) For a Category 1 or Category 2 

engine that can be modified to operate 

on residual fuel, but has not been 

certified to meet the standards on such 

a fuel, include the statement: ‘‘THIS 

ENGINE IS CERTIFIED FOR 

OPERATION ONLY WITH DIESEL 

FUEL. MODIFYING THE ENGINE TO 

OPERATE ON RESIDUAL OR 

INTERMEDIATE FUEL MAY BE A 

VIOLATION OF FEDERAL LAW 

SUBJECT TO CIVIL PENALTIES.’’ 

(12) For an engine equipped with onoff emissions controls as allowed by 

§ 1042.115, include the statement: 

‘‘THIS ENGINE IS CERTIFIED WITH 

ON-OFF EMISSION CONTROLS. 

OPERATION OF THE ENGINE 

CONTRARY TO 40 CFR 1042.115(g) IS 

A VIOLATION OF FEDERAL LAW 

SUBJECT TO CIVIL PENALTIES.’’ 

(13) For engines intended for 

installation on domestic or public 

vessels, include the following statement: 

‘‘THIS ENGINE DOES NOT COMPLY 

WITH INTERNATIONAL MARINE 

REGULATIONS FOR COMMERCIAL 

VESSELS UNLESS IT IS ALSO 

COVERED BY AN EIAPP 

CERTIFICATE.’’ 

* * * * * 

■ 160. Section 1042.140 is amended by 

revising the section heading and 

introductory text and adding paragraph 

(g) to read as follows: 

§ 1042.140 Maximum engine power, 

displacement, power density, and maximum 

in-use engine speed. 

This section describes how to 

determine the maximum engine power, 

displacement, and power density of an 

engine for the purposes of this part. 

Note that maximum engine power may 

differ from the definition of ‘‘maximum 

test power’’ in § 1042.901. This section 

also specifies how to determine 

maximum in-use engine speed for 

Category 3 engines. 

* * * * * 

(g) Calculate a maximum test speed 

for the nominal power curve as 

specified in 40 CFR 1065.610. This is 

the maximum in-use engine speed used 

for calculating the NOX standard in 

§ 1042.104 for Category 3 engines. 

Alternatively, you may use a lower 

value if engine speed will be limited in 

actual use to that lower value. 

■ 161. Section 1042.145 is amended by 

revising paragraph (a) and the heading 

of paragraph (c) introductory text and 

adding paragraphs (h) and (i) to read as 

follows: 

§ 1042.145 Interim provisions. 

(a) General. The provisions in this 

section apply instead of other 

provisions in this part. This section 

describes when these interim provisions 

expire. Only the provisions of paragraph 

(h) of this section apply for Category 3 

engines. 

* * * * * 

(c) Part 1065 test procedures for 

Category 1 and Category 2 engines. 

* * * 

* * * * * 

(h) The following interim provisions 

apply for Category 3 engines: 

(1) Applicability of Tier 3 standards to 

Category 3 engines operating in Alaska, 

Hawaii, and U.S. territories. (i) Category 

3 engines are not required to comply 

with the Tier 3 NOX standard when 

operating in areas of Guam, American 

Samoa, the Commonwealth of the 

Northern Mariana Islands, Puerto Rico, 

or U.S. Virgin Islands. Category 3 

engines are also not required to comply 

with the Tier 3 NOX standards when 

operating in the waters of the smallest 

Hawaiian islands or in the waters of 

Alaska west of Kodiak. For the purpose 

of this paragraph (h)(1), ‘‘the smallest 

Hawaiian islands’’ includes all Hawaiian 

islands other than Hawaii, Kahoolawe, 

Kauai, Lanai, Maui, Molokai, Niihau, 

and Oahu. Engines must comply fully 

with the appropriate Tier 2 NOX

standard and all other applicable 

requirements when operating in the 

areas identified in this paragraph (h)(1). 

(ii) The provisions of paragraph 

(h)(1)(i) of this section do not apply to 

ships operating in an ECA or an ECA 

associated area. The Tier 3 standards 

apply in full for any area included in an 

ECA or an ECA associated area. 

(2) Part 1065 test procedures. You 

must generally use the test procedures 

specified in subpart F of this part for 

Category 3 engines, including the 

applicable test procedures in 40 CFR 

part 1065. You may use a combination 

of the test procedures specified in this 

part and the test procedures specified in 

40 CFR part 94 before January 1, 2016 

without request. After this date, you 

must use test procedures only as 

specified in subpart F of this part. 

(i) Limitation of 40 CFR 1068.101 

before July 1, 2010. Notwithstanding 

other provisions of this part or 40 CFR 

part 94, for the period June 29, 2010 

through July 1, 2010, it is not a violation 

of 40 CFR 1068.101 to operate in U.S. 

waters uncertified engines installed on 

vessels manufactured outside of the 

United States before June 29, 2010. 

Operation of such vessels in U.S. waters 

on or after July 1, 2010 is deemed to be 

introduction into U.S. commerce of a 

new marine engine. 

Subpart C—[Amended] 

■ 162. Section 1042.201 is amended by 

revising paragraph (h) to read as 

follows: 

§ 1042.201 General requirements for 

obtaining a certificate of conformity. 

* * * * * 

(h) For engines that become new after 

being placed into service, such as 

engines installed on imported vessels, 

we may specify alternate certification 

provisions consistent with the intent of 

this part. See the definition of ‘‘new 

marine engine’’ in § 1042.901. 

■ 163. Section 1042.205 is amended by 

adding paragraph (b)(12) and revising 

paragraphs (i), (o), and (s)(5) to read as 

follows: 

§ 1042.205 Application requirements. 

* * * * * 

(b) * * * 

(12) Include any other information 

required by this part with respect to 

AECDs. For example, see § 1042.115 for 

requirements related to on-off 

technologies. 

* * * * * 

(i) Include the maintenance and 

warranty instructions you will give to 

the ultimate purchaser of each new 

engine (see §§ 1042.120 and 1042.125). 

Describe your plan for meeting warranty 

obligations under § 1042.120. 

* * * * * 

(o) Present emission data for HC, 

NOX, PM, and CO on an emission-data 

engine to show your engines meet 

emission standards as specified in 

§§ 1042.101 or 1042.104. Note that you 

must submit PM data for all engines, 

whether or not a PM standard applies. 

Show emission figures before and after 

applying adjustment factors for 

regeneration and deterioration factors 

for each pollutant and for each engine. 

If we specify more than one grade of any 

fuel type (for example, high-sulfur and 

low-sulfur diesel fuel), you need to 

submit test data only for one grade, 

unless the regulations of this part 

specify otherwise for your engine. 

Include emission results for each mode 

for Category 3 engines or for other 

engines if you do discrete-mode testing 

under § 1042.505. Note that §§ 1042.235 


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and 1042.245 allows you to submit an 

application in certain cases without new 

emission data. 

* * * * * 

(s) * * * 

(5) For Category 2 and Category 3 

engines, propose a range of adjustment 

for each adjustable parameter, as 

described in § 1042.115(d). Include 

information showing why the limits, 

stops, or other means of inhibiting 

adjustment are effective in preventing 

adjustment of parameters on in-use 

engines to settings outside your 

proposed adjustable ranges. 

* * * * * 

■ 164. Section 1042.220 is revised to 

read as follows: 

§ 1042.220 Amending maintenance 

instructions. 

You may amend your emissionrelated maintenance instructions after 

you submit your application for 

certification as long as the amended 

instructions remain consistent with the 

provisions of § 1042.125. You must send 

the Designated Compliance Officer a 

written request to amend your 

application for certification for an 

engine family if you want to change the 

emission-related maintenance 

instructions in a way that could affect 

emissions. In your request, describe the 

proposed changes to the maintenance 

instructions. If operators follow the 

original maintenance instructions rather 

than the newly specified maintenance, 

this does not allow you to disqualify 

those engines from in-use testing or 

deny a warranty claim. 

(a) If you are decreasing or 

eliminating any specified maintenance, 

you may distribute the new 

maintenance instructions to your 

customers 30 days after we receive your 

request, unless we disapprove your 

request. This would generally include 

replacing one maintenance step with 

another. We may approve a shorter time 

or waive this requirement. 

(b) If your requested change would 

not decrease the specified maintenance, 

you may distribute the new 

maintenance instructions anytime after 

you send your request. For example, 

this paragraph (b) would cover adding 

instructions to increase the frequency of 

filter changes for engines in severe-duty 

applications. 

(c) You need not request approval if 

you are making only minor corrections 

(such as correcting typographical 

mistakes), clarifying your maintenance 

instructions, or changing instructions 

for maintenance unrelated to emission 

control. We may ask you to send us 

copies of maintenance instructions 

revised under this paragraph (c). 

■ 165. Section 1042.225 is amended by 

revising the introductory text, 

paragraphs (b) introductory text, (b)(2), 

(e), and (f) to read as follows: 

§ 1042.225 Amending applications for 

certification. 

Before we issue you a certificate of 

conformity, you may amend your 

application to include new or modified 

engine configurations, subject to the 

provisions of this section. After we have 

issued your certificate of conformity, 

you may send us an amended 

application requesting that we include 

new or modified engine configurations 

within the scope of the certificate, 

subject to the provisions of this section. 

You must amend your application if any 

changes occur with respect to any 

information that is included or should 

be included in your application. 

* * * * * 

(b) To amend your application for 

certification as specified in paragraph 

(a) of this section, send the relevant 

information to the Designated 

Compliance Officer. 

* * * * * 

(2) Include engineering evaluations or 

data showing that the amended engine 

family complies with all applicable 

requirements. You may do this by 

showing that the original emission-data 

engine is still appropriate for showing 

that the amended family complies with 

all applicable requirements. 

* * * * * 

(e) For engine families already 

covered by a certificate of conformity, 

you may start producing the new or 

modified engine configuration anytime 

after you send us your amended 

application and before we make a 

decision under paragraph (d) of this 

section. However, if we determine that 

the affected engines do not meet 

applicable requirements, we will notify 

you to cease production of the engines 

and may require you to recall the 

engines at no expense to the owner. 

Choosing to produce engines under this 

paragraph (e) is deemed to be consent to 

recall all engines that we determine do 

not meet applicable emission standards 

or other requirements and to remedy the 

nonconformity at no expense to the 

owner. If you do not provide 

information required under paragraph 

(c) of this section within 30 days after 

we request it, you must stop producing 

the new or modified engines. 

(f) You may ask us to approve a 

change to your FEL in certain cases after 

the start of production. The changed 

FEL may not apply to engines you have 

already introduced into U.S. commerce, 

except as described in this paragraph (f). 

If we approve a changed FEL after the 

start of production, you must include 

the new FEL on the emission control 

information label for all engines 

produced after the change. You may ask 

us to approve a change to your FEL in 

the following cases: 

(1) You may ask to raise your FEL for 

your engine family at any time. In your 

request, you must show that you will 

still be able to meet the emission 

standards as specified in subparts B and 

H of this part. If you amend your 

application by submitting new test data 

to include a newly added or modified 

engine, as described in paragraph (b)(3) 

of this section, use the appropriate FELs 

with corresponding production volumes 

to calculate emission credits for the 

model year, as described in subpart H of 

this part. In all other circumstances, you 

must use the higher FEL for the entire 

family to calculate emission credits 

under subpart H of this part. 

(2) You may ask to lower the FEL for 

your engine family only if you have test 

data from production engines showing 

that emissions are below the proposed 

lower FEL. The lower FEL applies only 

to engines you produce after we approve 

the new FEL. Use the appropriate FELs 

with corresponding production volumes 

to calculate emission credits for the 

model year, as described in subpart H of 

this part. 

■ 166. Section 1042.230 is amended by 

revising paragraphs (a), (b), (f) 

introductory text, and (g) and adding 

paragraph (d) to read as follows: 

§ 1042.230 Engine families. 

(a) For purposes of certification, 

divide your product line into families of 

engines that are expected to have 

similar emission characteristics 

throughout the useful life as described 

in this section. You may not group 

engines in different engine categories in 

the same family. Your engine family is 

limited to a single model year. 

(b) For Category 1 engines, group 

engines in the same engine family if 

they are the same in all the following 

aspects: 

(1) The combustion cycle and the fuel 

with which the engine is intended or 

designed to be operated. 

(2) The cooling system (for example, 

raw-water vs. separate-circuit cooling). 

(3) Method of air aspiration. 

(4) Method of exhaust aftertreatment 

(for example, catalytic converter or 

particulate trap). 

(5) Combustion chamber design. 

(6) Nominal bore and stroke. 

(7) Cylinder arrangement (such as inline vs. vee configurations). This applies 

for engines with aftertreatment devices 

only. 


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(8) Method of control for engine 

operation other than governing (i.e., 

mechanical or electronic). 

(9) Application (commercial or 

recreational). 

(10) Numerical level of the emission 

standards that apply to the engine, 

except as allowed under paragraphs (f) 

and (g) of this section. 

* * * * * 

(d) For Category 3 engines, group 

engines into engine families based on 

the criteria specified in Section 4.3 of 

the NOX Technical Code (incorporated 

by reference in § 1042.910), except as 

allowed in paragraphs (e) and (f) of this 

section. 

* * * * * 

(f) You may group engines that are not 

identical with respect to the things 

listed in paragraph (b), (c), or (d) of this 

section in the same engine family, as 

follows: 

* * * * * 

(g) If you combine engines that are 

subject to different emission standards 

into a single engine family under 

paragraph (f) of this section, you must 

certify the engine family to the more 

stringent set of standards for that model 

year. For Category 3 engine families that 

include a range of maximum in-use 

engine speeds, use the highest value of 

maximum in-use engine speed to 

establish the applicable NOX emission 

standard. 

■ 167. Section 1042.235 is amended by 

revising the section heading, the 

introductory text, and paragraphs (a), 

(c), and (d) introductory text to read as 

follows: 

§ 1042.235 Emission testing related to 

certification. 

This section describes the emission 

testing you must perform to show 

compliance with the emission standards 

in § 1042.101(a) or § 1042.104. See 

§ 1042.205(p) regarding emission testing 

related to the NTE standards. See 

§§ 1042.240 and 1042.245 and 40 CFR 

part 1065, subpart E, regarding service 

accumulation before emission testing. 

See § 1042.655 for special testing 

provisions available for Category 3 

engines subject to Tier 3 standards. 

(a) Select an emission-data engine 

from each engine family for testing. For 

engines at or above 560 kW, you may 

use a development engine that is 

equivalent in design to the engine being 

certified. For Category 3 engines, you 

may use a single-cylinder version of the 

engine. Using good engineering 

judgment, select the engine 

configuration most likely to exceed an 

applicable emission standard over the 

useful life, considering all exhaust 

emission constituents and the range of 

installation options available to vessel 

manufacturers. 

* * * * * 

(c) We may measure emissions from 

any of your emission-data engines or 

other engines from the engine family, as 

follows: 

(1) We may decide to do the testing 

at your plant or any other facility. If we 

do this, you must deliver the engine to 

a test facility we designate. The engine 

you provide must include appropriate 

manifolds, aftertreatment devices, 

electronic control units, and other 

emission-related components not 

normally attached directly to the engine 

block. If we do the testing at your plant, 

you must schedule it as soon as possible 

and make available the instruments, 

personnel, and equipment we need. 

(2) If we measure emissions from one 

of your engines, the results of that 

testing become the official emission 

results for the engine. Unless we later 

invalidate these data, we may decide 

not to consider your data in determining 

if your engine family meets applicable 

requirements. 

(3) Before we test one of your engines, 

we may set its adjustable parameters to 

any point within the specified 

adjustable ranges (see § 1042.115(d)). 

(4) Before we test one of your engines, 

we may calibrate it within normal 

production tolerances for anything we 

do not consider an adjustable parameter. 

For example, this would apply for an 

engine parameter that is subject to 

production variability because it is 

adjustable during production, but is not 

considered an adjustable parameter (as 

defined in § 1042.901) because it is 

permanently sealed. 

(d) You may ask to use carryover 

emission data from a previous model 

year instead of doing new tests, but only 

if all the following are true: 

* * * * * 

■ 168. Section 1042.240 is amended by 

revising paragraphs (a), (b), and (c) 

introductory text and adding paragraphs 

(e) and (f) to read as follows: 

§ 1042.240 Demonstrating compliance with 

exhaust emission standards. 

(a) For purposes of certification, your 

engine family is considered in 

compliance with the emission standards 

in § 1042.101(a) or § 1042.104 if all 

emission-data engines representing that 

family have test results showing official 

emission results and deteriorated 

emission levels at or below these 

standards. This also applies for all test 

points for emission-data engines within 

the family used to establish 

deterioration factors. See paragraph (f) 

of this section for provisions related to 

demonstrating compliance with nonduty-cycle standards, such as NTE 

standards. Note that your FELs are 

considered to be the applicable 

emission standards with which you 

must comply if you participate in the 

ABT program in subpart H of this part. 

(b) Your engine family is deemed not 

to comply if any emission-data engine 

representing that family has test results 

showing an official emission result or a 

deteriorated emission level for any 

pollutant that is above an applicable 

emission standard. Similarly, your 

engine family is deemed not to comply 

if any emission-data engine representing 

that family has test results showing any 

emission level above the applicable notto-exceed emission standard for any 

pollutant. This also applies for all test 

points for emission-data engines within 

the family used to establish 

deterioration factors. 

(c) To compare emission levels from 

the emission-data engine with the 

applicable emission standards, apply 

deterioration factors to the measured 

emission levels for each pollutant. 

Section 1042.245 specifies how to test 

your Category 1 or Category 2 engine to 

develop deterioration factors that 

represent the deterioration expected in 

emissions over your engines’ full useful 

life. See paragraph (e) of this section for 

determining deterioration factors for 

Category 3 engines. Your deterioration 

factors must take into account any 

available data from in-use testing with 

similar engines. Small-volume engine 

manufacturers and post-manufacture 

marinizers may use assigned 

deterioration factors that we establish. 

Apply deterioration factors as follows: 

* * * * * 

(e) For Category 3 engines, determine 

a deterioration factor based on an 

engineering analysis. The engineering 

analysis must describe how the 

measured emission levels from the 

emission-data engine show that engines 

comply with applicable emission 

standards throughout the useful life. 

Include this analysis in your application 

for certification and add a statement that 

all data, analyses, evaluations, and other 

information you used are available for 

our review upon request. 

(f) For NTE standards and mode caps, 

use good engineering judgment to 

demonstrate compliance throughout the 

useful life. You may, but are not 

required to, apply the same 

deterioration factors used to show 

compliance with the applicable dutycycle standards. We will deny your 

application for certification if we 

determine that your test data show that 


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your engines would exceed one or more 

NTE standard or mode cap during their 

useful lives. 

■ 169. Section 1042.245 is amended by 

revising the introductory text and 

paragraph (a) to read as follows: 

§ 1042.245 Deterioration factors. 

This section describes how to 

determine deterioration factors for 

Category 1 and Category 2 engines, 

either with an engineering analysis, 

with pre-existing test data, or with new 

emission measurements. Apply these 

deterioration factors to determine 

whether your engines will meet the 

duty-cycle emission standards 

throughout the useful life as described 

in § 1042.240. This section does not 

apply for Category 3 engines. 

(a) You may ask us to approve 

deterioration factors for an engine 

family with established technology 

based on engineering analysis instead of 

testing. Engines certified to a NOX+HC 

standard or FEL greater than the Tier 3 

NOX+HC standard are considered to rely 

on established technology for control of 

gaseous emissions, except that this does 

not include any engines that use 

exhaust-gas recirculation or 

aftertreatment. In most cases, 

technologies used to meet the Tier 1 and 

Tier 2 emission standards would qualify 

as established technology. We must 

approve your plan to establish a 

deterioration factor under this 

paragraph (a) before you submit your 

application for certification. 

* * * * * 

■ 170. Section 1042.250 is amended by 

revising paragraphs (a) and (c) and 

removing paragraph (e) to read as 

follows: 

§ 1042.250 Recordkeeping and reporting. 

(a) Send the Designated Compliance 

Officer information related to your 

U.S.-directed production volumes as 

described in § 1042.345. In addition, 

within 45 days after the end of the 

model year, you must send us a report 

describing information about engines 

you produced during the model year as 

follows: 

(1) State the total production volume 

for each engine family that is not subject 

to reporting under § 1042.345. 

(2) State the total production volume 

for any engine family for which you 

produce engines after completing the 

reports required in § 1042.345. 

* * * * * 

(c) Keep data from routine emission 

tests (such as test cell temperatures and 

relative humidity readings) for one year 

after we issue the associated certificate 

of conformity. Keep all other 

information specified in this section for 

eight years after we issue your 

certificate. 

* * * * * 

■ 171. Section 1042.255 is amended by 

revising paragraph (b) to read as follows: 

§ 1042.255 EPA decisions. 

* * * * * 

(b) We may deny your application for 

certification if we determine that your 

engine family fails to comply with 

emission standards or other 

requirements of this part or the Clean 

Air Act. We will base our decision on 

all available information. If we deny 

your application, we will explain why 

in writing. 

* * * * * 

Subpart D—[Amended] 

■ 172. Section 1042.301 is amended by 

revising paragraphs (a)(2), (c), (e), and (f) 

to read as follows: 

§ 1042.301 General provisions. 

(a) * * * 

(2) We may exempt Category 1 engine 

families with a projected U.S.-directed 

production volume below 100 engines 

from routine testing under this subpart. 

Request this exemption in your 

application for certification and include 

your basis for projecting a production 

volume below 100 units. We will 

approve your request if we agree that 

you have made good-faith estimates of 

your production volumes. Your 

exemption is approved when we grant 

your certificate. You must promptly 

notify us if your actual production 

exceeds 100 units during the model 

year. If you exceed the production limit 

or if there is evidence of a 

nonconformity, we may require you to 

test production-line engines under this 

subpart, or under 40 CFR part 1068, 

subpart E, even if we have approved an 

exemption under this paragraph (a)(2). 

* * * * * 

(c) Other regulatory provisions 

authorize us to suspend, revoke, or void 

your certificate of conformity, or order 

recalls for engine families, without 

regard to whether they have passed 

these production-line testing 

requirements. The requirements of this 

subpart do not affect our ability to do 

selective enforcement audits, as 

described in 40 CFR part 1068. 

Individual engines in families that pass 

these production-line testing 

requirements must also conform to all 

applicable regulations of this part and 

40 CFR part 1068. 

* * * * * 

(e) If you certify a Category 1 or 

Category 2 engine family with carryover 

emission data, as described in 

§ 1042.235(d), and these equivalent 

engine families consistently pass the 

production-line testing requirements 

over the preceding two-year period, you 

may ask for a reduced testing rate for 

further production-line testing for that 

family. The minimum testing rate is one 

engine per engine family. If we reduce 

your testing rate, we may limit our 

approval to any number of model years. 

In determining whether to approve your 

request, we may consider the number of 

engines that have failed the emission 

tests. 

(f) We may ask you to make a 

reasonable number of production-line 

engines available for a reasonable time 

so we can test or inspect them for 

compliance with the requirements of 

this part. For Category 3 engines, you 

are not required to deliver engines to us, 

but we may inspect and test your 

engines at any facility at which they are 

assembled or installed in vessels. 

■ 173. A new § 1042.302 is added to 

subpart D to read as follows: 

§ 1042.302 Applicability of this subpart for 

Category 3 engines. 

If you produce Tier 3 or later Category 

3 engines that are certified under this 

part, you must test them as described in 

this subpart, except as specified in this 

section. 

(a) You must test each engine at the 

sea trial of the vessel in which it is 

installed or within the first 300 hours of 

operation, whichever occurs first. Since 

you must test each engine, the 

provisions of §§ 1042.310 and 

1042.315(b) do not apply for Category 3 

engines. If we determine that an engine 

failure under this subpart is caused by 

defective components or design 

deficiencies, we may revoke or suspend 

your certificate for the engine family as 

described in § 1042.340. If we determine 

that an engine failure under this subpart 

is caused only by incorrect assembly, 

we may suspend your certificate for the 

engine family as described in 

§ 1042.325. If the engine fails, you may 

continue operating only to complete the 

sea trial and return to port. It is a 

violation of 40 CFR 1068.101(b)(1) to 

operate the vessel further until you 

remedy the cause of failure. Each twohour period of such operation 

constitutes a separate offense. A 

violation lasting less than two hours 

constitutes a single offense. 

(b) You are only required to measure 

NOX emissions. You do not need to 

measure HC, CO or PM emissions under 

this subpart. 

(c) If you are unable to operate the 

engine at the test points for the specified 

duty cycle, you may approximate these 


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points consistent with the specifications 

of section 6 of Appendix 8 to the NOX

Technical Code (incorporated by 

reference in § 1042.910) and show 

compliance with the alternate installedengine standard of § 1042.104(g). You 

must obtain EPA approval of your test 

procedure prior to testing the engine. 

Include in your request a description of 

your basis for concluding that the 

engine cannot be tested at the actual test 

points of the specified duty cycle. 

(d) You may measure NOX emissions 

at additional test points for the purposes 

of the continuous NOX monitoring 

requirements of § 1042.110(d). If you do, 

you must report these values along with 

your other test results. Describe in your 

application for certification how you 

plan to use these values for continuous 

NOX monitoring. 

(e) You may ask to measure emissions 

according to the Direct Measurement 

and Monitoring method specified in 

section 6.4 of the NOX Technical Code 

(incorporated by reference in 

§ 1042.910). 

■ 174. Section 1042.305 is amended by 

revising paragraphs (a), (d) introductory 

text, (d)(2), (e)(2), and (g) to read as 

follows: 

§ 1042.305 Preparing and testing 

production-line engines. 

* * * * * 

(a) Test procedures. Test your 

production-line engines using the 

applicable testing procedures in subpart 

F of this part to show you meet the dutycycle emission standards in subpart B of 

this part. For Category 1 and Category 2 

engines, the not-to-exceed standards 

apply for this testing of Category 1 and 

Category 2 engines, but you need not do 

additional testing to show that 

production-line engines meet the not-toexceed standards. The mode cap 

standards apply for the testing of 

Category 3 engines. 

* * * * * 

(d) Setting adjustable parameters. 

Before any test, we may require you to 

adjust any adjustable parameter on a 

Category 1 engine to any setting within 

its physically adjustable range. We may 

adjust or require you to adjust any 

adjustable parameter on a Category 2 or 

Category 3 engine to any setting within 

its specified adjustable range. 

* * * * * 

(2) We may specify adjustments 

within the physically adjustable range 

or the specified adjustable range by 

considering their effect on emission 

levels. We may also consider how likely 

it is that someone will make such an 

adjustment with in-use engines. 

(e) * * * 

(2) For Category 2 or Category 3 

engines, you may ask us to approve a 

Green Engine Factor for each regulated 

pollutant for each engine family. Use 

the Green Engine Factor to adjust 

measured emission levels to establish a 

stabilized low-hour emission level. 

* * * * * 

(g) Retesting after invalid tests. You 

may retest an engine if you determine 

an emission test is invalid under 

subpart F of this part. Explain in your 

written report reasons for invalidating 

any test and the emission results from 

all tests. If we determine that you 

improperly invalidated a test, we may 

require you to ask for our approval for 

future testing before substituting results 

of the new tests for invalid ones. 

■ 175. Section 1042.310 is amended by 

revising the section heading to read as 

follows: 

§ 1042.310 Engine selection for Category 1 

and Category 2 engines. 

* * * * * 

■ 176. Section 1042.315 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 1042.315 Determining compliance. 

* * * * * 

(a) Calculate your test results as 

follows: 

(1) Initial and final test results. 

Calculate and round the test results for 

each engine. If you do several tests on 

an engine, calculate the initial results 

for each test, then add all the test results 

together and divide by the number of 

tests. Round this final calculated value 

for the final test results on that engine. 

Include the Green Engine Factor to 

determine low-hour emission results, if 

applicable. 

(2) Final deteriorated test results. 

Apply the deterioration factor for the 

engine family to the final test results 

(see § 1042.240(c)). 

(3) Round deteriorated test results. 

Round the results to the number of 

decimal places in the emission standard 

expressed to one more decimal place. 

(b) For Category 1 and Category 2 

engines, if a production-line engine fails 

to meet emission standards and you test 

two additional engines as described in 

§ 1042.310, calculate the average 

emission level for each pollutant for the 

three engines. If the calculated average 

emission level for any pollutant exceeds 

the applicable emission standard, the 

engine family fails the production-line 

testing requirements of this subpart. Tell 

us within ten working days if this 

happens. You may request to amend the 

application for certification to raise the 

FEL of the engine family as described in 

§ 1042.225(f). 

■ 177. Section 1042.320 is amended by 

revising paragraph (a)(2) to read as 

follows: 

§ 1042.320 What happens if one of my 

production-line engines fails to meet 

emission standards? 

(a) * * * 

(2) Include the test results and 

describe the remedy for each engine in 

the written report required under 

§ 1042.345. 

* * * * * 

■ 178. Section 1042.325 is amended by 

revising paragraph (e) to read as follows: 

§ 1042.325 What happens if an engine 

family fails the production-line testing 

requirements? 

* * * * * 

(e) You may request to amend the 

application for certification to raise the 

FEL of the entire engine family before or 

after we suspend your certificate as 

described in § 1042.225(f). We will 

approve your request if the failure is not 

caused by a defect and it is clear that 

you used good engineering judgment in 

establishing the original FEL. 

■ 179. Section 1042.345 is amended by 

revising paragraphs (a)(6) and (b) to read 

as follows: 

§ 1042.345 Reporting. 

(a) * * * 

(6) Provide the test number; the date, 

time and duration of testing; test 

procedure; all initial test results; final 

test results; and final deteriorated test 

results for all tests. Provide the emission 

results for all measured pollutants. 

Include information for both valid and 

invalid tests and the reason for any 

invalidation. 

* * * * * 

(b) We may ask you to add 

information to your written report so we 

can determine whether your new 

engines conform with the requirements 

of this subpart. We may also ask you to 

send less information. 

* * * * * 

■ 180. Section 1042.350 is amended by 

revising paragraphs (b), (e), and (f) to 

read as follows: 

§ 1042.350 Recordkeeping. 

* * * * * 

(b) Keep paper or electronic records of 

your production-line testing for eight 

years after you complete all the testing 

required for an engine family in a model 

year. 

* * * * * 

(e) If we ask, you must give us a more 

detailed description of projected or 

actual production figures for an engine 

family. We may ask you to divide your 


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production figures by maximum engine 

power, displacement, fuel type, or 

assembly plant (if you produce engines 

at more than one plant). 

(f) Keep records of the engine 

identification number for each engine 

you produce under each certificate of 

conformity. You may identify these 

numbers as a range. Give us these 

records within 30 days if we ask for 

them. 

* * * * * 

Subpart F—[Amended] 

■ 181. Section 1042.501 is amended by 

revising paragraphs (a) and (c) and 

adding paragraph (g) to read as follows: 

§ 1042.501 How do I run a valid emission 

test? 

(a) Use the equipment and procedures 

for compression-ignition engines in 40 

CFR part 1065 to determine whether 

engines meet the duty-cycle emission 

standards in §§ 1042.101 or 1042.104. 

Measure the emissions of all regulated 

pollutants as specified in 40 CFR part 

1065. Use the applicable duty cycles 

specified in § 1042.505. 

* * * * * 

(c) Use the fuels and lubricants 

specified in 40 CFR part 1065, subpart 

H, for all the testing we require in this 

part, except as specified in this section 

and § 1042.515. 

(1) For service accumulation, use the 

test fuel or any commercially available 

fuel that is representative of the fuel that 

in-use engines will use. 

(2) For diesel-fueled engines, use the 

appropriate diesel fuel specified in 40 

CFR part 1065, subpart H, for emission 

testing. Unless we specify otherwise, the 

appropriate diesel test fuel for Category 

1 and Category 2 engines is the ultra 

low-sulfur diesel fuel. If we allow you 

to use a test fuel with higher sulfur 

levels, identify the test fuel in your 

application for certification. Unless we 

specify otherwise, the appropriate diesel 

test fuel for Category 3 engines is the 

high-sulfur diesel fuel. For Category 2 

and Category 3 engines, you may ask to 

use commercially available diesel fuel 

similar but not necessarily identical to 

the applicable fuel specified in 40 CFR 

part 1065, subpart H; we will approve 

your request if you show us that it does 

not affect your ability to demonstrate 

compliance with the applicable 

emission standards. 

(3) For Category 1 and Category 2 

engines that are expected to use a type 

of fuel (or mixed fuel) other than diesel 

fuel (such as natural gas, methanol, or 

residual fuel), use a commercially 

available fuel of that type for emission 

testing. If a given engine is designed to 

operate on different fuels, we may (at 

our discretion) require testing on each 

fuel. Propose test fuel specifications that 

take into account the engine design and 

the properties of commercially available 

fuels. Describe these test fuel 

specifications in the application for 

certification. 

* * * * * 

(g) For Category 3 engines, instead of 

test data collected as specified in 40 

CFR part 1065, you may submit test data 

for NOX, HC, and CO emissions that 

were collected as specified in the NOX

Technical Code (incorporated by 

reference in § 1042.910). For example, 

this allowance includes the allowance 

to perform the testing using test fuels 

allowed under the NOX Technical Code 

that do not meet the sulfur 

specifications of this section. We may 

require you to include a brief 

engineering analysis showing how these 

data demonstrate that your engines 

would meet the applicable emission 

standards if you had used the test 

procedures specified in 40 CFR part 

1065. 

■ 182. Section 1042.505 is amended by 

revising paragraph (b) introductory text 

to read as follows: 

§ 1042.505 Testing engines using discretemode or ramped-modal duty cycles. 

* * * * * 

(b) Measure emissions by testing the 

engine on a dynamometer with one of 

the following duty cycles (as specified) 

to determine whether it meets the 

emission standards in §§ 1042.101 or 

1042.104: 

* * * * * 

■ 183. Section 1042.525 is amended by 

revising paragraph (b) and adding 

paragraph (g) to read as follows: 

§ 1042.525 How do I adjust emission levels 

to account for infrequently regenerating 

aftertreatment devices? 

* * * * * 

(b) Calculating average adjustment 

factors. Calculate the average 

adjustment factor (EFA) based on the 

following equation: 

EFA = (F)(EFH) + (1¥F)(EFL) 

Where: 

F = The frequency of the regeneration event 

during normal in-use operation, 

expressed in terms of the fraction of 

equivalent tests during which the 

regeneration occurs. You may determine 

F from in-use operating data or running 

replicate tests. For example, if you 

observe that the regeneration occurs 125 

times during 1,000 MW-hrs of operation, 

and your engine typically accumulates 1 

MW-hr per test, F would be (125) ÷ 

(1,000) ÷ (1) = 0.125. No further 

adjustments, including weighting factors, 

may be applied to F. 

EFH = Measured emissions from a test 

segment in which the regeneration 

occurs. 

EFL = Measured emissions from a test 

segment in which the regeneration does 

not occur. 

* * * * * 

(g) Category 3 engines. We may 

specify an alternate methodology to 

account for regeneration events from 

Category 3 engines. If we do not, the 

provisions of this section apply as 

specified. 

Subpart G—[Amended] 

■ 184. Section 1042.601 is amended by 

revising paragraph (b) and adding 

paragraphs (g), (h), and (i) to read as 

follows: 

§ 1042.601 General compliance provisions 

for marine engines and vessels. 

* * * * * 

(b) Subpart I of this part describes 

how the prohibitions of 40 CFR 

1068.101(a)(1) apply for certain 

remanufactured engines. The provisions 

of 40 CFR 1068.105 do not allow the 

installation of a new remanufactured 

engine in a vessel that is defined as a 

new vessel unless the remanufactured 

engine is subject to the same standards 

as the standards applicable to freshly 

manufactured engines of the required 

model year. 

* * * * * 

(g) The selective enforcement audit 

provisions of 40 CFR part 1068 do not 

apply for Category 3 engines. 

(h) The defect reporting requirements 

of 40 CFR 1068.501 apply for Category 

3 engines, except the threshold for filing 

a defect report is two engines. 

(i) You may not circumvent the 

requirements of this part or the Clean 

Air Act by manufacturing a vessel 

outside the United States or initially 

flagging a vessel in another country. The 

definition of ‘‘new marine engine’’ in 

§ 1042.901 includes provisions for U.S.- 

flagged vessels that are manufactured or 

reflagged outside of U.S. waters. These 

provisions have the effect of applying 

the prohibitions of 40 CFR 

1068.101(a)(1) to such vessels no later 

than when they first enter U.S. waters. 

The inclusion of these provisions does 

not affect requirements or prohibitions 

of the Clean Air Act or other statutes 

that may apply to the vessel before it 

first enters U.S. waters. 

■ 185. Section 1042.605 is amended by 

revising paragraph (a) to read as follows: 


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§ 1042.605 Dressing engines already 

certified to other standards for nonroad or 

heavy-duty highway engines for marine 

use. 

(a) General provisions. If you are an 

engine manufacturer (including 

someone who marinizes a land-based 

engine), this section allows you to 

introduce new marine engines into U.S. 

commerce if they are already certified to 

the requirements that apply to 

compression-ignition engines under 40 

CFR parts 85 and 86 or 40 CFR part 89, 

92, 1033, or 1039 for the appropriate 

model year. If you comply with all the 

provisions of this section, we consider 

the certificate issued under 40 CFR part 

86, 89, 92, 1033, or 1039 for each engine 

to also be a valid certificate of 

conformity under this part 1042 for its 

model year, without a separate 

application for certification under the 

requirements of this part 1042. This 

section does not apply for Category 3 

engines. 

* * * * * 

■ 186. Section 1042.610 is amended by 

revising the introductory text to read as 

follows: 

§ 1042.610 Certifying auxiliary marine 

engines to land-based standards. 

This section applies to auxiliary 

marine engines that are identical to 

certified land-based engines. See 

§ 1042.605 for provisions that apply to 

propulsion marine engines or auxiliary 

marine engines that are modified for 

marine applications. This section does 

not apply for Category 3 engines. 

* * * * * 

■ 187. Section 1042.615 is amended by 

revising the introductory text and 

paragraph (a)(4) and adding paragraph 

(d) to read as follows: 

§ 1042.615 Replacement engine 

exemption. 

For Category 1 and Category 2 

replacement engines, apply the 

provisions of 40 CFR 1068.240 as 

described in this section. In unusual 

circumstances, you may ask us to allow 

you to apply these provisions for a new 

Category 3 engine. 

(a) * * * 

(4) The replacement engine must 

conform to the applicable requirements 

of 40 CFR part 1043. Note that 40 CFR 

1043.10 specifies allowances for vessels 

that operate only domestically. 

* * * * * 

(d) We may reduce the reporting and 

recordkeeping requirements in this 

section. 

■ 188. Section 1042.620 is revised to 

read as follows: 

§ 1042.620 Engines used solely for 

competition. 

The provisions of this section apply 

for new Category 1 engines and vessels 

built on or after January 1, 2009. 

(a) We may grant you an exemption 

from the standards and requirements of 

this part for a new engine on the 

grounds that it is to be used solely for 

competition. The requirements of this 

part, other than those in this section, do 

not apply to engines that we exempt for 

use solely for competition. 

(b) We will exempt engines that we 

determine will be used solely for 

competition. The basis of our 

determination is described in 

paragraphs (c) and (d) of this section. 

Exemptions granted under this section 

are good for only one model year and 

you must request renewal for each 

subsequent model year. We will not 

approve your renewal request if we 

determine the engine will not be used 

solely for competition. 

(c) Engines meeting all the following 

criteria are considered to be used solely 

for competition: 

(1) Neither the engine nor any vessels 

containing the engine may be displayed 

for sale in any public dealership or 

otherwise offered for sale to the general 

public. Note that this does not preclude 

display of these engines as long as they 

are not available for sale to the general 

public. 

(2) Sale of the vessel in which the 

engine is installed must be limited to 

professional racing teams, professional 

racers, or other qualified racers. For 

replacement engines, the sale of the 

engine itself must be limited to 

professional racing teams, professional 

racers, other qualified racers, or to the 

original vessel manufacturer. 

(3) The engine and the vessel in 

which it is installed must have 

performance characteristics that are 

substantially superior to noncompetitive 

models. 

(4) The engines are intended for use 

only as specified in paragraph (e) of this 

section. 

(d) You may ask us to approve an 

exemption for engines not meeting the 

criteria listed in paragraph (c) of this 

section as long as you have clear and 

convincing evidence that the engines 

will be used solely for competition. 

(e) Engines are considered to be used 

solely for competition only if their use 

is limited to competition events 

sanctioned by the U.S. Coast Guard or 

another public organization with 

authorizing permits for participating 

competitors. Operation of such engines 

may include only racing events, trials to 

qualify for racing events, and practice 

associated with racing events. 

Authorized attempts to set speed 

records are also considered racing 

events. Engines will not be considered 

to be used solely for competition if they 

are ever used for any recreational or 

other noncompetitive purpose. Use of 

exempt engines in any recreational 

events, such as poker runs and 

lobsterboat races, is a violation of 40 

CFR 1068.101(b)(4). 

(f) You must permanently label 

engines exempted under this section to 

clearly indicate that they are to be used 

only for competition. Failure to properly 

label an engine will void the exemption 

for that engine. 

(g) If we request it, you must provide 

us any information we need to 

determine whether the engines are used 

solely for competition. This would 

include documentation regarding the 

number of engines and the ultimate 

purchaser of each engine as well as any 

documentation showing a vessel 

manufacturer’s request for an exempted 

engine. Keep these records for five 

years. 

■ 189. Section 1042.625 is amended by 

adding introductory text to read as 

follows: 

§ 1042.625 Special provisions for engines 

used in emergency applications. 

This section describes an exemption 

that is available for certain Category 1 

and Category 2 engines. This exemption 

is not available for Category 3 engines. 

* * * * * 

■ 190. Section 1042.630 is amended by 

revising the introductory text to read as 

follows: 

§ 1042.630 Personal-use exemption. 

This section applies to individuals 

who manufacture vessels for personal 

use with used Category 1 engines. If you 

and your vessel meet all the conditions 

of this section, the vessel and its engine 

are considered to be exempt from the 

standards and requirements of this part 

that apply to new engines and new 

vessels. The prohibitions in 

§ 1068.101(a)(1) do not apply to engines 

exempted under this section. For 

example, you may install an engine that 

was not certified as a marine engine. 

* * * * * 

■ 191. Section 1042.635 is amended by 

revising paragraph (a) to read as follows: 

§ 1042.635 National security exemption. 

* * * * * 

(a) An engine is exempt without a 

request if it will be used or owned by 

an agency of the Federal government 

responsible for national defense, where 

the vessel in which it is installed has 

armor, permanently attached weaponry, 


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specialized electronic warfare systems, 

unique stealth performance 

requirements, and/or unique combat 

maneuverability requirements. This 

applies to both remanufactured and 

freshly manufactured marine engines. 

Gas turbine engines are also exempt 

without a request if they will be owned 

by an agency of the Federal government 

responsible for national defense. 

* * * * * 

■ 192. Section 1042.650 is amended by 

revising the section heading and the 

introductory text and adding a new 

paragraph (d) to read as follows: 

§ 1042.650 Exemptions for migratory 

vessels and auxiliary engines on Category 

3 vessels. 

The provisions of this section apply 

for Category 1 and Category 2 engines, 

including auxiliary engines installed on 

vessels with Category 3 propulsion 

engines. These provisions do not apply 

for any Category 3 engines. All engines 

exempted under this section must 

comply with the applicable 

requirements of 40 CFR part 1043. 

* * * * * 

(d) Auxiliary engines on Category 3 

vessels. As specified in this paragraph 

(d), auxiliary engines on vessels with 

Category 3 propulsion engines are 

exempt from the standards of this part. 

(1) To be eligible for this exemption, 

the engine must meet all of the 

following criteria. 

(i) The engine must conform fully to 

the applicable NOX standards of Annex 

VI and meet all other applicable 

requirements of 40 CFR part 1043. 

Engines installed on vessels constructed 

on or after January 1, 2016 must 

conform fully to the Annex VI Tier III 

NOX standards under 40 CFR part 1043 

and meet all other applicable 

requirements in 40 CFR part 1043. 

Engines that would otherwise be subject 

to the Tier 4 standards of this part must 

also conform fully to the Annex VI Tier 

III NOX standards under 40 CFR part 

1043. 

(ii) The engine may not be used for 

propulsion (except for emergency 

engines). 

(iii) The engine may be equipped with 

on-off NOX controls, provided it 

conforms to the requirements of 

§ 1042.115(g). 

(2) You must notify the Designated 

Compliance Officer of your intent to use 

this exemption when applying for the 

EIAPP certificate for the engine under 

40 CFR part 1043. 

(3) The remanufactured engine 

requirements of subpart I of this part do 

not apply. 

(4) If you introduce an engine into 

U.S. commerce under this paragraph (d), 

you must meet the labeling 

requirements in § 1042.135, but add the 

following statement instead of the 

compliance statement in 

§ 1042.135(c)(10): 

THIS ENGINE DOES NOT COMPLY 

WITH CURRENT U.S. EPA EMISSION 

STANDARDS UNDER 40 CFR 1042.650 

AND IS FOR USE SOLELY IN VESSELS 

WITH CATEGORY 3 PROPULSION 

ENGINES. INSTALLATION OR USE OF 

THIS ENGINE IN ANY OTHER 

APPLICATION MAY BE A VIOLATION 

OF FEDERAL LAW SUBJECT TO CIVIL 

PENALTY. 

■ 193. A new § 1042.655 is added to 

subpart G to read as follows: 

§ 1042.655 Special certification provisions 

for—Category 3 engines with 

aftertreatment. 

This section describes an optional 

approach for demonstrating for 

certification that catalyst-equipped 

engines (or engines equipped with other 

aftertreatment devices) comply with 

applicable emission standards. You 

must use good engineering judgment for 

all aspects of this allowance. 

(a) Eligibility. You may use the 

provisions of this section without our 

prior approval to demonstrate that 

aftertreatment-equipped Category 3 

engines meet the Tier 3 standards. In 

unusual circumstances, we may also 

allow you to use this approach to 

demonstrate that aftertreatmentequipped Category 2 engines meet the 

Tier 4 standards. We will generally 

approve this for Category 2 engines only 

if the engines are too large to be 

practically tested in a laboratory with a 

fully assembled aftertreatment system. If 

we approve this approach for a Category 

2 engine, interpret references to Tier 3 

in this section to mean Tier 4, and 

interpret references to Tier 2 in this 

section to mean Tier 3. 

(b) Required testing. The emissiondata engine must be tested as specified 

in Subpart F to verify that the engineout emissions comply with the Tier 2 

standards. The catalyst material or other 

aftertreatment device must be tested 

under conditions that accurately 

represent actual engine conditions for 

the test points. This catalyst or 

aftertreatment testing may be performed 

on a benchscale. 

(c) Engineering analysis. Include with 

your application a detailed engineering 

analysis describing how the test data 

collected for the engine and 

aftertreatment demonstrate that all 

engines in the family will meet all 

applicable emission standards. We may 

require that you submit this analysis 

separately from your application, or that 

you obtain preliminary approval under 

§ 1042.210. 

(d) Verification. You must verify your 

design by testing a complete production 

engine with installed aftertreatment in 

the final assembled configuration. 

Unless we specify otherwise, do this by 

complying with production-line testing 

requirements of subpart D of this part. 

(e) Other requirements. All other 

requirements of this part, including the 

non-testing requirements for 

certification, apply for these engines. 

Nothing in this section affects 

requirements in other regulatory parts, 

such as Coast Guard safety 

requirements. 

■ 194. Section 1042.660 is revised to 

read as follows: 

§ 1042.660 Requirements for vessel 

manufacturers, owners, and operators. 

(a) For vessels equipped with 

emission controls requiring the use of 

specific fuels, lubricants, or other fluids, 

owners and operators must comply with 

the manufacturer/remanufacturer’s 

specifications for such fluids when 

operating the vessels. Failure to comply 

with the requirements of this paragraph 

is a violation of 40 CFR 1068.101(b)(1). 

For marine vessels that are excluded 

from the requirements of 40 CFR part 

1043 because they operate only 

domestically, it is also a violation of 40 

CFR 1068.101(b)(1) to operate the vessel 

using residual fuel on or after January 1, 

2015. Note that 40 CFR part 80 also 

includes provisions that restrict the use 

of certain fuels by certain marine 

engines. 

(b) For vessels equipped with SCR 

systems requiring the use of urea or 

other reductants, owners and operators 

must report to us within 30 days any 

operation of such vessels without the 

appropriate reductant. Failure to 

comply with the requirements of this 

paragraph is a violation of 40 CFR 

1068.101(a)(2). Note that such operation 

is a violation of 40 CFR 1068.101(b)(1). 

(c) The provisions of this paragraph 

(c) apply for marine vessels containing 

Category 3 engines. 

(1) The requirements of this paragraph 

(c)(1) apply only for Category 3 engines. 

All maintenance, repair, adjustment, 

and alteration of Category 3 engines 

subject to the provisions of this part 

performed by any owner, operator or 

other maintenance provider must be 

perform using good engineering 

judgment, in such a manner that the 

engine continues (after the maintenance, 

repair, adjustment or alteration) to meet 

the emission standards it was certified 

as meeting prior to the need for service. 

This includes but is not limited to 

complying with the maintenance 


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instructions described in § 1042.125. 

Adjustments are limited to the range 

specified by the engine manufacturer in 

the approved application for 

certification. Note that where a repair 

(or other maintenance) cannot be 

completed while at sea, it is not a 

violation to continue operating the 

engine to reach your destination. 

(2) It is a violation of 40 CFR 

1068.101(b)(1) to operate the vessel with 

the engine adjusted outside of the 

specified adjustable range. Each twohour period of such operation 

constitutes a separate offense. A 

violation lasting less than two hours 

constitutes a single offense. 

(3) The owner and operator of the 

engine must maintain on board the 

vessel records of all maintenance, 

repair, and adjustment that could 

reasonably affect the emission 

performance of any engine subject to the 

provision of this part. Owners and 

operators must also maintain, on board 

the vessel, records regarding 

certification, parameter adjustment, and 

fuels used. For engines that are 

automatically adjusted electronically, 

all adjustments must be logged 

automatically. Owners and operators 

must make these records available to 

EPA upon request. These records must 

include the following: 

(i) The Technical File, Record Book of 

Engine Parameters, and bunker delivery 

notes as specified in 40 CFR 1043.70. 

The Technical File must be transferred 

to subsequent purchasers in the event of 

a sale of the engine or vessel. (ii) 

Specific descriptions of engine 

maintenance, repair, adjustment, and 

alteration (including rebuilding). The 

descriptions must include at least the 

date, time, and nature of the 

maintenance, repair, adjustment, or 

alteration and the position of the vessel 

when the maintenance, repair, 

adjustment, or alteration was made. 

(iii) Emission-related maintenance 

instructions provided by the 

manufacturer. These instructions must 

be transferred to subsequent purchasers 

in the event of a sale of the engine or 

vessel. 

(4) Owners and operators of engines 

equipped with on-off emission controls 

must comply with the requirements of 

this paragraph (c)(4) whenever a 

malfunction of the emission controls is 

indicated as specified in § 1042.110(d). 

You must determine the cause of the 

malfunction and remedy it consistent 

with paragraph (c)(1) of this section. See 

paragraph (b) of this section if the 

malfunction is due to either a lack of 

reductant or inadequate reductant 

quality. If the malfunction occurs during 

the useful life, report the malfunction to 

the certificate holder for investigation 

and compliance with defect reporting 

requirements of 40 CFR 1068.501 

(unless the malfunction is due to 

operation without adequate urea or 

other malmaintenance). 

(d) For each marine vessel containing 

a Category 3 engine, the owner must 

annually review the vessel’s records and 

submit to EPA a signed statement 

certifying compliance during the 

preceding year with the requirements of 

this part that are applicable to owners 

and operators of such vessels. 

Alternately, if review of the vessel’s 

records indicates that there has been 

one or more violations of the 

requirements of this part, the owner 

must submit to EPA a signed statement 

specifying the noncompliance, 

including the nature of the 

noncompliance, the time of the 

noncompliance, and any efforts made to 

remedy the noncompliance. The 

statement of compliance (or 

noncompliance) required by this 

paragraph must be signed by the 

executive with responsibility for marine 

activities of the owner. If the vessel is 

operated by a different business entity 

than the vessel owner, the reporting 

requirements of this paragraph (e) apply 

to both the owner and the operator. 

Compliance with these review and 

certification requirements by either the 

vessel owner or the vessel operator with 

respect to a compliance statement will 

be considered compliance with these 

requirements by both of these parties for 

that compliance statement. The 

executive(s) may authorize a captain or 

other primary operator to conduct this 

review and submit the certification, 

provided that the certification statement 

is accompanied by written authorization 

for that individual to submit such 

statements. The Administrator may 

waive the requirements of this 

paragraph when equivalent assurance of 

compliance is otherwise available. 

(e) Manufacturers, owners and 

operators must allow emission tests and 

inspections required by this part to be 

conducted and must provide reasonable 

assistance to perform such tests or 

inspections. 

■ 195. A new § 1042.670 is added to 

subpart G to read as follows: 

§ 1042.670 Special provisions for gas 

turbine engines. 

The provisions of this section apply 

for gas turbine engines. 

(a) Implementation schedule. The 

requirements of this part do not apply 

for gas turbine engines below 600 kW 

before the 2014 model year. The 

requirements of this part do not apply 

for Tier 3 or earlier gas turbine engines 

at or above 600 kW. The provisions of 

40 CFR part 1068 also do not apply for 

gas turbine engines produced in these 

earlier model years. 

(b) Special test procedures. 

Manufacturers seeking certification of 

gas turbine engines must obtain 

preliminary approval of the test 

procedures to be used, consistent with 

§ 1042.210 and 40 CFR 1065.10. 

(c) Remanufacturing. The 

requirements of subpart I of this part do 

not apply for gas turbine engines. 

(d) Equivalent displacement. Apply 

displacement-based provisions of this 

part by calculating an equivalent 

displacement from the maximum engine 

power. The equivalent per-cylinder 

displacement (in liters) equals the 

maximum engine power in kW 

multiplied by 0.00311, except that all 

gas turbines with maximum engine 

power above 9,300 kW are considered to 

have an equivalent per-cylinder 

displacement of 29.0 liters. 

(e) Emission-related components. All 

components meeting the criteria of 40 

CFR 1068.501(a)(1) are considered to be 

emission-related components with 

respect to maintenance, warranty, and 

defect reporting for gas turbine engines. 

(f) Engines used for national defense. 

See § 1042.635 for provisions related to 

exempting gas turbine engines used for 

national defense. 

Subpart H—[Amended] 

■ 196. Section 1042.701 is amended by 

adding introductory text to read as 

follows: 

§ 1042.701 General provisions. 

This subpart describes how you may 

use emission credits to demonstrate that 

Category 1 and Category 2 engines 

comply with emission standards under 

this part. The provisions of this subpart 

do not apply for Category 3 engines. 

* * * * * 

■ 197. Section 1042.705 is amended by 

revising paragraph (a) introductory text, 

before the equation, to read as follows: 

§ 1042.705 Generating and calculating 

emission credits. 

* * * * * 

(a) For each participating family, 

calculate positive or negative emission 

credits relative to the otherwise 

applicable emission standard. Calculate 

positive emission credits for a family 

that has an FEL below the standard. 

Calculate negative emission credits for a 

family that has an FEL above the 

standard. Sum your positive and 

negative credits for the model year 

before rounding. Round the sum of 

emission credits to the nearest kilogram 


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(kg) using consistent units throughout 

the following equation: 

* * * * * 

■ 198. Section 1042.715 is revised to 

read as follows: 

§ 1042.715 Banking emission credits. 

(a) Banking is the retention of 

emission credits by the manufacturer 

generating the emission credits for use 

in future model years for averaging or 

trading. 

(b) You may designate any emission 

credits you plan to bank in the reports 

you submit under § 1042.730 as 

reserved credits. During the model year 

and before the due date for the final 

report, you may designate your reserved 

emission credits for averaging or 

trading. 

(c) Reserved credits become actual 

emission credits when you submit your 

final report. However, we may revoke 

these emission credits if we are unable 

to verify them after reviewing your 

reports or auditing your records. 

■ 199. Section 1042.720 is amended by 

revising paragraph (b) to read as follows: 

§ 1042.720 Trading emission credits. 

* * * * * 

(b) You may trade actual emission 

credits as described in this subpart. You 

may also trade reserved emission 

credits, but we may revoke these 

emission credits based on our review of 

your records or reports or those of the 

company with which you traded 

emission credits. You may trade banked 

credits within an averaging set to any 

certifying manufacturer. 

* * * * * 

■ 200. Section 1042.725 is amended by 

revising paragraph (b)(2) to read as 

follows: 

§ 1042.725 Information required for the 

application for certification. 

* * * * * 

(b) * * * 

(2) Detailed calculations of projected 

emission credits (positive or negative) 

based on projected production volumes. 

We may require you to include similar 

calculations from your other engine 

families to demonstrate that you will be 

able to avoid a negative credit balance 

for the model year. If you project 

negative emission credits for a family, 

state the source of positive emission 

credits you expect to use to offset the 

negative emission credits. 

■ 201. Section 1042.730 is amended by 

revising paragraphs (b)(3), (b)(4), and 

(b)(5) to read as follows: 

§ 1042.730 ABT reports. 

* * * * * 

(b) * * * 

(3) The FEL for each pollutant. If you 

change the FEL after the start of 

production, identify the date that you 

started using the new FEL and/or give 

the engine identification number for the 

first engine covered by the new FEL. In 

this case, identify each applicable FEL 

and calculate the positive or negative 

emission credits under each FEL. 

(4) The projected and actual U.S.- 

directed production volumes for the 

model year, as described in 

§ 1042.705(c). If you changed an FEL 

during the model year, identify the 

actual production volume associated 

with each FEL. 

(5) Maximum engine power for each 

engine configuration, and the average 

engine power weighted by U.S.-directed 

production volumes for the engine 

family. 

* * * * * 

■ 202. Section 1042.735 is amended by 

revising paragraphs (b), (d), and (e) to 

read as follows: 

§ 1042.735 Recordkeeping. 

* * * * * 

(b) Keep the records required by this 

section for at least eight years after the 

due date for the end-of-year report. You 

may not use emission credits for any 

engines if you do not keep all the 

records required under this section. You 

must therefore keep these records to 

continue to bank valid credits. Store 

these records in any format and on any 

media as long as you can promptly send 

us organized, written records in English 

if we ask for them. You must keep these 

records readily available. We may 

review them at any time. 

* * * * * 

(d) Keep records of the engine 

identification number for each engine 

you produce that generates or uses 

emission credits under the ABT 

program. You may identify these 

numbers as a range. If you change the 

FEL after the start of production, 

identify the date you started using each 

FEL and the range of engine 

identification numbers associated with 

each FEL. You must also identify the 

purchaser and destination for each 

engine you produce to the extent this 

information is available. 

(e) We may require you to keep 

additional records or to send us relevant 

information not required by this section 

in accordance with the Clean Air Act. 

Subpart I—[Amended] 

■ 203. Section 1042.801 is amended by 

revising the introductory text and 

paragraph (a) to read as follows: 

§ 1042.801 General provisions. 

This subpart describes how the 

provisions of this part 1042 apply for 

certain remanufactured marine engines. 

(a) The requirements of this subpart 

apply for remanufactured Tier 2 and 

earlier commercial Category 1 and 

Category 2 marine engines at or above 

600 kW, excluding those engines 

originally manufactured before 1973. 

Note that the requirements of this 

subpart do not apply for engines below 

600 kW, Category 3 engines, engines 

installed on recreational vessels, or Tier 

3 and later engines. 

* * * * * 

■ 204. Section 1042.836 is amended by 

revising the introductory text and 

paragraphs (a) introductory text and (c) 

to read as follows: 

§ 1042.836 Marine certification of 

locomotive remanufacturing systems. 

If you certify a Tier 0, Tier 1, or Tier 

2 remanufacturing system for 

locomotives under 40 CFR part 1033, 

you may also certify the system under 

this part 1042, according to the 

provisions of this section. Note that in 

certain cases before 2013, locomotives 

may be certified under 40 CFR part 1033 

to the standards of 40 CFR part 92. 

(a) Include the following with your 

application for certification under 40 

CFR part 1033 (or as an amendment to 

your application): 

* * * * * 

(c) Systems certified to the standards 

of 40 CFR part 92 are subject to the 

following restrictions: 

(1) Tier 0 locomotives systems may 

not be used for any Category 1 engines 

or Tier 1 or later Category 2 engines. 

(2) Where systems certified to the 

standards of 40 CFR part 1033 are also 

available for an engine, you may not use 

a system certified to the standards of 40 

CFR part 92. 

■ 205. Section 1042.850 is amended by 

revising paragraph (c) to read as follows: 

§ 1042.850 Exemptions and hardship 

relief. 

* * * * * 

(c) If you believe that a 

remanufacturing system that we 

identified as being available cannot be 

installed without significant 

modification of your vessel, you may 

ask us to determine that a 

remanufacturing system is not 

considered available for your vessel 

because the cost would exceed the total 

marginal cost threshold in 

§ 1042.815(a)(2). 

* * * * * 


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Subpart J—[Amended] 

■ 206. Section 1042.901 is amended as 

follows: 

■ a. By revising the definitions for 

‘‘Carryover’’, ‘‘Category 1’’, ‘‘Category 2’’, 

‘‘Category 3’’, ‘‘Compression-ignition’’, 

‘‘Deterioration factor’’, ‘‘Engine 

configuration’’, ‘‘Freshly manufactured 

marine engine’’, ‘‘Hydrocarbon (HC)’’, 

‘‘Manufacture’’, ‘‘Manufacturer’’, ‘‘Model 

year’’, ‘‘New marine engine’’, ‘‘Residual 

fuel’’, ‘‘Small-volume boat builder’’, 

‘‘Small-volume engine manufacturer’’, 

‘‘Tier 2’’, ‘‘Tier 3’’, ‘‘Total hydrocarbon 

equivalent’’, and ‘‘Useful life’’. 

■ b. Adding new definitions for ‘‘2008 

Annex VI’’, ‘‘Alcohol-fueled engine’’, 

‘‘Date of manufacture’’, ‘‘ECA associated 

area’’, ‘‘Emission control area (ECA)’’, 

‘‘Gas turbine engine’’, ‘‘Maximum in-use 

engine speed’’, ‘‘Reflag’’, ‘‘NOX Technical 

Code’’, and ‘‘U.S. waters’’ in 

alphanumeric order. 

■ c. By removing the definition for 

‘‘Annex VI Technical Code’’. 

§ 1042.901 Definitions. 

* * * * * 

2008 Annex VI means MARPOL 

Annex VI, which is an annex to the 

International Convention on the 

Prevention of Pollution from Ships, 

1973, as modified by the protocol of 

1978 relating thereto (incorporated by 

reference in § 1042.910). 

* * * * * 

Alcohol-fueled engine means an 

engine that is designed to run using an 

alcohol fuel. For purposes of this 

definition, alcohol fuels do not include 

fuels with a nominal alcohol content 

below 25 percent by volume. 

* * * * * 

Carryover means relating to 

certification based on emission data 

generated from an earlier model year as 

described in § 1042.235(d). 

Category 1 means relating to a marine 

engine with specific engine 

displacement below 7.0 liters per 

cylinder. See § 1042.670 to determine 

equivalent per-cylinder displacement 

for nonreciprocating marine engines 

(such as gas turbine engines). 

Category 2 means relating to a marine 

engine with a specific engine 

displacement at or above 7.0 liters per 

cylinder but less than 30.0 liters per 

cylinder. See § 1042.670 to determine 

equivalent per-cylinder displacement 

for nonreciprocating marine engines 

(such as gas turbine engines). 

Category 3 means relating to a 

reciprocating marine engine with a 

specific engine displacement at or above 

30.0 liters per cylinder. 

* * * * * 

Compression-ignition means relating 

to a type of reciprocating, internalcombustion engine that is not a sparkignition engine. Note that certain other 

marine engines (such as those powered 

by natural gas with maximum engine 

power at or above 250 kW) are deemed 

to be compression-ignition engines in 

§ 1042.1. 

* * * * * 

Date of manufacture has the meaning 

given in 40 CFR 1068.30. 

* * * * * 

Deterioration factor means the 

relationship between emissions at the 

end of useful life and emissions at the 

low-hour test point (see §§ 1042.240 and 

1042.245), expressed in one of the 

following ways: 

(1) For multiplicative deterioration 

factors, the ratio of emissions at the end 

of useful life to emissions at the lowhour test point. 

(2) For additive deterioration factors, 

the difference between emissions at the 

end of useful life and emissions at the 

low-hour test point. 

* * * * * 

ECA associated area has the meaning 

given in 40 CFR 1043.20. 

Emission control area (ECA) has the 

meaning given in 40 CFR 1043.20. 

* * * * * 

Engine configuration means a unique 

combination of engine hardware and 

calibration within an engine family. 

Engines within a single engine 

configuration differ only with respect to 

normal production variability or factors 

unrelated to emissions. 

* * * * * 

Freshly manufactured marine engine 

means a marine engine that has not been 

placed into service. An engine becomes 

freshly manufactured when it is 

originally manufactured. See the 

definition of ‘‘New marine engine’’ for 

provisions that specify that certain other 

types of new engines are treated as 

freshly manufactured engines. 

* * * * * 

Gas turbine engine has the meaning 

given in 40 CFR 1068.30. In general, this 

means anything commercially known as 

a gas turbine engine. It does not include 

external combustion steam engines. 

* * * * * 

Hydrocarbon (HC) means the 

hydrocarbon group on which the 

emission standards are based for each 

fuel type, as described in § 1042.101(d) 

and § 1042.104(a). 

* * * * * 

Manufacture means the physical and 

engineering process of designing, 

constructing, and assembling an engine 

or a vessel, or modifying or operating an 

engine or vessel in a way that makes it 

a new marine engine or new marine 

vessel. 

Manufacturer means any person who 

manufactures (see definition of 

‘‘manufacture’’ in this section) a new 

engine or vessel or imports such engines 

or vessels for resale. All manufacturing 

entities under the control of the same 

person are considered to be a single 

manufacturer. 

(1) This term includes, but is not 

limited to: 

(i) Any person who manufactures an 

engine or vessel for sale in the United 

States or otherwise introduces a new 

marine engine into U.S. commerce. 

(ii) Importers who import engines or 

vessels for resale. 

(iii) Post-manufacture marinizers. 

(iv) Vessel owners/operators that 

reflag a formerly foreign vessel as a U.S.- 

flagged vessel. 

(v) Any person who modifies or 

operates an engine or vessel in a way 

that makes it a new marine engine or 

new marine vessel. 

(2) Dealers that do not cause an 

engine or vessel to become new are not 

manufacturers. 

* * * * * 

Maximum in-use engine speed has the 

meaning given in § 1042.140. 

* * * * * 

Model year means any of the 

following: 

(1) For freshly manufactured marine 

engines (see definition of ‘‘new marine 

engine,’’ paragraph (1)), model year 

means one of the following: 

(i) Calendar year. 

(ii) Your annual new model 

production period if it is different than 

the calendar year. This must include 

January 1 of the calendar year for which 

the model year is named. It may not 

begin before January 2 of the previous 

calendar year and it must end by 

December 31 of the named calendar 

year. For seasonal production periods 

not including January 1, model year 

means the calendar year in which the 

production occurs, unless you choose to 

certify the applicable engine family with 

the following model year. For example, 

if your production period is June 1, 

2010 through November 30, 2010, your 

model year would be 2010 unless you 

choose to certify the engine family for 

model year 2011. 

(2) For an engine that is converted to 

a marine engine after being certified and 

placed into service as a motor vehicle 

engine, a nonroad engine that is not a 

marine engine, or a stationary engine, 

model year means the calendar year in 

which the engine was originally 

produced. For an engine that is 


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converted to a marine engine after being 

placed into service as a motor vehicle 

engine, a nonroad engine that is not a 

marine engine, or a stationary engine 

without having been certified, model 

year means the calendar year in which 

the engine becomes a new marine 

engine. (See definition of ‘‘new marine 

engine,’’ paragraph (2)). 

(3) For an uncertified marine engine 

excluded under § 1042.5 that is later 

subject to this part 1042 as a result of 

being installed in a different vessel, 

model year means the calendar year in 

which the engine was installed in the 

non-excluded vessel. For a marine 

engine excluded under § 1042.5 that is 

later subject to this part 1042 as a result 

of reflagging the vessel, model year 

means the calendar year in which the 

engine was originally manufactured. For 

a marine engine that become new under 

paragraph (7) of the definition of ‘‘new 

marine engine,’’ model year means the 

calendar year in which the engine was 

originally manufactured. (See definition 

of ‘‘new marine engine,’’ paragraphs (3) 

and (7)). 

(4) For engines that do not meet the 

definition of ‘‘freshly manufactured’’ but 

are installed in new vessels, model year 

means the calendar year in which the 

engine is installed in the new vessel. 

(See definition of ‘‘new marine engine,’’ 

paragraph (4)). 

(5) For remanufactured engines, 

model year means the calendar year in 

which the remanufacture takes place. 

(6) For imported engines: 

(i) For imported engines described in 

paragraph (5)(i) of the definition of ‘‘new 

marine engine,’’ model year has the 

meaning given in paragraphs (1) through 

(4) of this definition. 

(ii) For imported engines described in 

paragraph (5)(ii) of the definition of 

‘‘new marine engine,’’ model year means 

the calendar year in which the engine is 

remanufactured. 

(iii) For imported engines described 

in paragraph (5)(iii) of the definition of 

‘‘new marine engine,’’ model year means 

the calendar year in which the engine is 

first assembled in its imported 

configuration, unless specified 

otherwise in this part or in 40 CFR part 

1068. 

(iv) For imported engines described in 

paragraph (5)(iv) of the definition of 

‘‘new marine engine,’’ model year means 

the calendar year in which the engine is 

imported. 

(7) [Reserved]. 

(8) For freshly manufactured vessels, 

model year means the calendar year in 

which the keel is laid or the vessel is at 

a similar stage of construction. For 

vessels that become new under 

paragraph (2) of the definition of ‘‘new 

vessel’’ (as a result of modifications), 

model year means the calendar year in 

which the modifications physically 

begin. 

* * * * * 

New marine engine means any of the 

following: 

(1) A freshly manufactured marine 

engine for which the ultimate purchaser 

has never received the equitable or legal 

title. This kind of engine might 

commonly be thought of as ‘‘brand 

new.’’ In the case of this paragraph (1), 

the engine is new from the time it is 

produced until the ultimate purchaser 

receives the title or the product is 

placed into service, whichever comes 

first. 

(2) An engine originally manufactured 

as a motor vehicle engine, a nonroad 

engine that is not a marine engine, or a 

stationary engine that is later used or 

intended to be used as a marine engine. 

In this case, the engine is no longer a 

motor vehicle, nonmarine, or stationary 

engine and becomes a ‘‘new marine 

engine.’’ The engine is no longer new 

when it is placed into marine service as 

a marine engine. This paragraph (2) 

applies for engines we exclude under 

§ 1042.5, where that engine is later 

installed as a marine engine in a vessel 

that is covered by this part 1042. For 

example, this would apply to an engine 

that is no longer used in a foreign 

vessel. An engine converted to a marine 

engine without having been certified is 

treated as a freshly manufactured engine 

under this part 1042. 

(3) A marine engine that has been 

previously placed into service in an 

application we exclude under § 1042.5, 

where that engine is installed in a vessel 

that is covered by this part 1042. The 

engine is new when it first enters U.S. 

waters on a vessel covered by this part 

1042. For example, this would apply to 

an engine that is no longer used in a 

foreign vessel and for engines on a 

vessel that is reflagged as a U.S. vessel. 

Note paragraph (7) of this definition 

may also apply. 

(4) An engine not covered by 

paragraphs (1) through (3) of this 

definition that is intended to be 

installed in a new vessel. This generally 

includes installation of used engines in 

new vessels. The engine is no longer 

new when the ultimate purchaser 

receives a title for the vessel or it is 

placed into service, whichever comes 

first. Such an engine is treated as a 

freshly manufactured engine under this 

part 1042, whether or not it meets the 

definition of ‘‘freshly manufactured 

marine engine.’’ 

(5) A remanufactured marine engine. 

An engine becomes new when it is 

remanufactured (as defined in this 

section) and ceases to be new when 

placed back into service. 

(6) An imported marine engine, 

subject to the following provisions: 

(i) An imported marine engine 

covered by a certificate of conformity 

issued under this part that meets the 

criteria of one or more of paragraphs (1) 

through (4) of this definition, where the 

original engine manufacturer holds the 

certificate, is new as defined by those 

applicable paragraphs. 

(ii) An imported remanufactured 

engine that would have been required to 

be certified if it had been 

remanufactured in the United States. 

(iii) An imported engine that will be 

covered by a certificate of conformity 

issued under this part, where someone 

other than the original engine 

manufacturer holds the certificate (such 

as when the engine is modified after its 

initial assembly), is a new marine 

engine when it is imported. It is no 

longer new when the ultimate purchaser 

receives a title for the engine or it is 

placed into service, whichever comes 

first. 

(iv) An imported marine engine that 

is not covered by a certificate of 

conformity issued under this part at the 

time of importation is new, but only if 

it was produced on or after the dates 

shown in the following table. This 

addresses uncertified engines and 

vessels initially placed into service that 

someone seeks to import into the United 

States. Importation of this kind of 

engine (or vessel containing such an 

engine) is generally prohibited by 40 

CFR part 1068. 

APPLICABILITY OF EMISSION STANDARDS FOR COMPRESSION-IGNITION MARINE ENGINES

Engine category and type Power 

(kW) 

Per-cylinder displacement 

(L/cyl) 

Initial model 

year of 

emission 

standards 

Category 1 ................................................ P < 19 ....................................................... All .............................................................. 2000 


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APPLICABILITY OF EMISSION STANDARDS FOR COMPRESSION-IGNITION MARINE ENGINES—Continued 

Engine category and type Power 

(kW) 

Per-cylinder displacement 

(L/cyl) 

Initial model 

year of 

emission 

standards 

Category 1 ................................................ 19 ≤ P < 37 ............................................... All .............................................................. 1999 

Category 1, Recreational .......................... P ≥ 37 ....................................................... disp. < 0.9 ................................................. 2007 

Category 1, Recreational .......................... All .............................................................. 0.9 ≤ disp. < 2.5 ....................................... 2006 

Category 1, Recreational .......................... All .............................................................. disp. ≥ 2.5 ................................................. 2004 

Category 1, Commercial ........................... P ≥ 37 ....................................................... disp. < 0.9 ................................................. 2005 

Category 1, Commercial ........................... All .............................................................. disp. ≥ 0.9 ................................................. 2004 

Category 2 and Category 3 ...................... All .............................................................. disp. ≥ 5.0 ................................................. 2004 

(7) A marine engine that is not 

covered by a certificate of conformity 

issued under this part on a U.S.-flag 

vessel entering U.S. waters is new, but 

only if it was produced on or after the 

dates identified in paragraph (6)(iv) of 

this definition. Such entrance is deemed 

to be introduction into U.S. commerce. 

* * * * * 

NOX Technical Code means the 

‘‘Technical Code on Control of Emission 

of Nitrogen Oxides from Marine Diesel 

Engines’’ adopted by the International 

Maritime Organization (incorporated by 

reference in § 1042.910). The Technical 

Code is part of 2008 Annex VI. 

* * * * * 

Reflag means to register as a U.S. 

vessel any vessel that previously had a 

foreign registry or had been placed into 

service without registration. 

* * * * * 

Residual fuel means any fuel with a 

T90 greater than 700 °F as measured with 

the distillation test method specified in 

40 CFR 1065.1010. This generally 

includes all RM grades of marine fuel 

without regard to whether they are 

known commercially as residual fuel. 

For example, fuel marketed as 

intermediate fuel may be residual fuel. 

* * * * * 

Small-volume boat builder means a 

boat manufacturer with fewer than 500 

employees and with annual worldwide 

production of fewer than 100 boats. For 

manufacturers owned by a parent 

company, these limits apply to the 

combined production and number of 

employees of the parent company and 

all its subsidiaries. Manufacturers that 

produce vessels with Category 3 engines 

are not small-volume boat builders. 

Small-volume engine manufacturer 

means a manufacturer of Category 1 

and/or Category 2 engines with annual 

worldwide production of fewer than 

1,000 internal combustion engines 

(marine and nonmarine). For 

manufacturers owned by a parent 

company, the limit applies to the 

production of the parent company and 

all its subsidiaries. Manufacturers that 

certify or produce any Category 3 

engines are not small-volume engine 

manufacturers. 

* * * * * 

Tier 2 means relating to the Tier 2 

emission standards, as shown in 

§ 1042.104 and Appendix I. 

Tier 3 means relating to the Tier 3 

emission standards, as shown in 

§ 1042.101 and § 1042.104. 

* * * * * 

Total hydrocarbon equivalent has the 

meaning given in 40 CFR 1065.1001. 

This generally means the sum of the 

carbon mass contributions of nonoxygenated hydrocarbons, alcohols and 

aldehydes, or other organic compounds 

that are measured separately as 

contained in a gas sample, expressed as 

exhaust hydrocarbon from petroleumfueled engines. The atomic hydrogen-tocarbon ratio of the equivalent 

hydrocarbon is 1.85:1. 

* * * * * 

U.S. waters includes U.S. navigable 

waters and the U.S. EEZ. 

Useful life means the period during 

which the engine is designed to 

properly function in terms of reliability 

and fuel consumption, without being 

remanufactured, specified as a number 

of hours of operation or calendar years, 

whichever comes first. It is the period 

during which an engine is required to 

comply with all applicable emission 

standards. See §§ 1042.101(e) and 

1042.104(d). 

■ 207. Section 1042.905 is amended by 

adding the acronyms ‘‘ECA’’, ‘‘EEZ’’, and 

‘‘IMO’’ in alphabetical order to read as 

follows: 

§ 1042.905 Symbols, acronyms, and 

abbreviations. 

* * * * * 

ECA Emission Control Area. 

EEZ Exclusive Economic Zone. 

* * * * * 

IMO International Maritime 

Organization. 

* * * * * 

■ 208. Section 1042.910 is revised to 

read as follows: 

§ 1042.910 Reference materials. 

Documents listed in this section have 

been incorporated by reference into this 

part. The Director of the Federal 

Register approved the incorporation by 

reference as prescribed in 5 U.S.C. 

552(a) and 1 CFR part 51. Anyone may 

inspect copies at the U.S. EPA, Air and 

Radiation Docket and Information 

Center, 1301 Constitution Ave., NW., 

Room B102, EPA West Building, 

Washington, DC 20460, (202) 566–1744, 

or at the National Archives and Records 

Administration (NARA). For 

information on the availability of this 

material at NARA, call 202–741–6030, 

or go to: http://www.archives.gov/ 

federal_register/ 

code_of_federal_regulations/ 

ibr_locations.html. 

(a) IMO material. This paragraph (a) 

lists material from the International 

Maritime Organization that we have 

incorporated by reference. Anyone may 

purchase copies of these materials from 

the International Maritime Organization, 

4 Albert Embankment, London SE1 7SR, 

United Kingdom, or http:// 

www.imo.org, or 44–(0)20–7735–7611. 

(1) Revised MARPOL Annex VI, 

Regulations for the Prevention of Air 

Pollution from Ships, and NOX

Technical Code 2008, 2009 edition. 

(i) Revised MARPOL Annex VI, 

Regulations for the Prevention of 

Pollution from Ships (‘‘2008 Annex VI’’); 

IBR approved for § 1042.901. 

(ii) NOX Technical Code 2008 (‘‘NOX

Technical Code’’); IBR approved for 

§§ 1042.104(g), 1042.230(d), 1042.302(c) 

and (e), 1042.501(g), and 1042.901. 

(2) [Reserved] 

(b) [Reserved] 

■ 209. Appendix I to part 1042 is 

amended by revising paragraphs (b)(2) 

introductory text and (b)(3) to read as 

follows: 

Appendix I to Part 1042—Summary of 

Previous Emission Standards 

* * * * * 

(b) * * * 

(2) Tier 2 primary standards. Exhaust 

emissions from Category 1 engines at or 


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above 37 kW and all Category 2 engines may 

not exceed the values shown in the following 

table: 

* * * * * 

(3) Tier 2 supplemental standards. The 

not-to-exceed emission standards specified in 

40 CFR 94.8(e) apply for all engines subject 

to the Tier 2 standards described in 

paragraph (b)(2) of this appendix. 

■ 210. A new part 1043 is added to 

subchapter U to read as follows: 

PART 1043—CONTROL OF NOX, SOX, 

AND PM EMISSIONS FROM MARINE 

ENGINES AND VESSELS SUBJECT TO 

THE MARPOL PROTOCOL 

Sec. 

1043.1 Overview. 

1043.5 Effective dates. 

1043.10 Applicability. 

1043.20 Definitions. 

1043.30 General obligations. 

1043.40 EIAPP certificates. 

1043.41 EIAPP certification process. 

1043.50 Approval of methods to meet Tier 

1 retrofit NOX standards. 

1043.55 Applying equivalent controls 

instead of complying with fuel 

requirements. 

1043.60 Operating requirements for engines 

and vessels subject to this part. 

1043.70 General recordkeeping and 

reporting requirements. 

1043.80 Recordkeeping and reporting 

requirements for fuel suppliers. 

1043.90 [RESERVED] 

1043.95 Interim provisions. 

1043.100 Reference materials. 

Authority: 33 U.S.C. 1901–1915. 

§ 1043.1 Overview. 

The Act to Prevent Pollution from 

Ships (APPS) requires engine 

manufacturers, owners and operators of 

vessels, and other persons to comply 

with Annex VI of the MARPOL 

Protocol. This part implements portions 

of APPS as it relates to Regulations 13, 

14 and 18 of Annex VI. These 

regulations clarify the application of 

some Annex VI provisions; provide 

procedures and criteria for the issuance 

of EIAPP certificates; and specify 

requirements applicable to ships that 

are not registered by Parties to Annex 

VI. This part includes provisions to 

apply the equivalency provisions of 

Regulation 4 of Annex VI with respect 

to Regulations 14 and 18 of Annex VI. 

Additional regulations may also apply 

with respect to the Annex VI, such as 

those issued separately by the U.S. 

Coast Guard. Note that references in this 

part to a specific subsection of an Annex 

VI regulation (such as Regulation 13.5.1) 

reflect the regulation numbering of the 

2008 Annex VI (incorporated by 

reference in § 1043.100). 

(a) The general requirements for nonpublic U.S.-flagged and other Party 

vessels are specified in Annex VI, as 

implemented by 33 U.S.C. 1901–1915. 

These requirements apply to engine 

manufacturers, owners and operators of 

vessels, and other persons. 

(b) The provisions of this part specify 

how Regulations 13, 14 and 18 of Annex 

VI, as implemented by APPS, will be 

applied to U.S.-flagged vessels that 

operate only domestically. 

(c) This part implements section 33 

U.S.C. 1902(e) by specifying that nonpublic vessels flagged by a country that 

is not a party to Annex VI are subject 

to certain provisions under this part that 

are equivalent to the substantive 

requirements of Regulations 13, 14 and 

18 of Annex VI as implemented by 

APPS. 

(d) This part also describes where the 

requirements of Regulation 13.5.1 of 

Annex VI and Regulation 14.4 of Annex 

VI will apply. 

(e) This part 1043 does not limit the 

requirements specified in Annex VI, as 

implemented by APPS, except as 

specified in § 1043.10(a)(2) and (b)(3). 

(f) Nothing in this part limits the 

operating requirements and restrictions 

applicable for engines and vessels 

subject to 40 CFR part 1042 or the 

requirements and restrictions applicable 

for fuels subject to 40 CFR part 80. 

(g) The provisions of this part specify 

how to obtain EIAPP certificates and 

certificates for Approved Methods. 

§ 1043.5 Effective dates. 

(a) The requirement of APPS for 

marine vessels to comply with Annex VI 

of the MARPOL Protocol is in effect. 

(b) The amendments to Annex VI 

adopted on October 8, 2008 enter into 

force July 1, 2010. The requirement of 

APPS for marine vessels to comply with 

the amended Annex VI is effective July 

1, 2010, although some requirements do 

not become applicable until later dates. 

(c) Compliance with the applicable 

regulations of this part is required for all 

persons as of July 1, 2010. (Note that 

certain requirements begin later, as 

described in paragraph (d) of this 

section.) Note also that compliance with 

§§ 1043.40 and 1043.41 is required to 

obtain EIAPP certificates under this part 

whether the application is submitted 

before July 1, 2010 or later. 

(d) Compliance with the requirements 

related to ECAs are effective as follows: 

(1) Compliance with the ECA NOX

requirements (see § 1043.60(a)) is 

required beginning on the date on 

which the ECA enters into force for the 

United States under Annex VI. 

(2) Compliance with the fuel content 

requirements applicable within ECAs 

and ECA associated areas (see 

§ 1043.60(b)) is required beginning 12 

months after date on which the ECA 

enters into force for the United States 

under Annex VI. 

§ 1043.10 Applicability. 

(a) U.S.-flagged vessels. The 

provisions of this part apply for all U.S.- 

flagged vessels wherever they are 

located (including engines installed or 

intended to be installed on such 

vessels), except as specified in this 

paragraph (a) or in § 1043.95. 

(1) Public vessels are excluded from 

this part. 

(2) Vessels that operate only 

domestically and conform to the 

requirements of this paragraph (a)(2) are 

excluded from Regulation 13 of Annex 

VI (including the requirement to obtain 

an EIAPP certificate) and the NOXrelated requirements of this part. For the 

purpose of this exclusion, the phrase 

‘‘operate only domestically’’ means the 

vessels do not enter waters subject to 

the jurisdiction or control of any foreign 

country, except for Canadian portions of 

the Great Lakes. (See §§ 1043.60 and 

1043.70 for provisions related to fuel 

use by such vessels). To be excluded, 

the vessel must conform to each of the 

following provisions: 

(i) All compression-ignition engines 

on the vessel must conform fully to all 

applicable provisions of 40 CFR parts 94 

and 1042. 

(ii) The vessel may not contain any 

engines with a specific engine 

displacement at or above 30.0 liters per 

cylinder. 

(iii) Any engine installed in the vessel 

that is not covered by an EIAPP must be 

labeled as specified in 40 CFR 1042.135 

with respect to whether it meets the 

requirements of Regulation 13 of Annex 

VI. 

(b) Foreign-flagged vessels. The 

provisions of this part apply for all nonpublic foreign-flagged vessels (including 

engines installed on such vessels) as 

follows: 

(1) The requirements of this part 

apply for foreign-flagged vessels 

operating in U.S. navigable waters or the 

U.S. EEZ. 

(2) For non-public vessels flagged by 

a country that is not a party to Annex 

VI, the requirements of this part apply 

in the same manner as apply for Party 

vessels, except as otherwise provided in 

this part. For example, see 

§ 1043.30(b)(3) for provisions related to 

showing compliance with this 

requirement without an EIAPP 

certificate. See § 1043.60 for specific 

operating requirements. 

(3) Canadian vessels that operate only 

within the Great Lakes and are subject 

to an alternative NOX control measure 

established by the Canadian government 


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are excluded from the NOX-related 

requirements of this part. 

(c) Fuel suppliers. The provisions of 

§ 1043.80 apply for all persons 

supplying fuel to any vessel subject to 

this part. 

(d) Sea bed mineral exploration. This 

part does not apply to emissions 

directly arising from the exploration, 

exploitation, and associated offshore 

processing of sea-bed mineral resources. 

Note that other regulations apply with 

respect to these emissions in certain 

circumstances, and that engines that are 

not solely dedicated to such activities 

are otherwise subject to all requirements 

of this part. 

§ 1043.20 Definitions. 

The following definitions apply to 

this part: 

2008 Annex VI means Annex VI to the 

MARPOL Protocol, including 

amendments adopted in October 2008. 

The 2008 Annex VI is incorporated by 

reference in § 1043.100. Note that this 

version of Annex VI does not include 

any amendments that may be adopted in 

the future. This 2008 version applies for 

certain provisions of this part such as 

those applicable for internal waters and 

for non-Party vessels. 

Administrator means the 

Administrator of the Environmental 

Protection Agency. 

Annex VI means Annex VI of the 

MARPOL Protocol. 

APPS means the Act to Prevent 

Pollution from Ships (33 U.S.C. 1901– 

1915). 

Designated Certification Officer 

means the EPA official to whom the 

Administrator has delegated authority to 

issue EIAPP certificates. Note that the 

Designated Certification Officer is also 

delegated certain authorities under this 

part in addition to the authority to issue 

EIAPP certificates. 

ECA associated area means the U.S. 

internal waters that are navigable from 

the ECA. This term does not include 

internal waters that are shoreward of 

ocean waters that are not part of an 

emission control area. 

EIAPP certificate means a certificate 

issued to certify initial compliance with 

Regulation 13 of Annex VI. (Note that 

EIAPP stands for Engine International 

Air Pollution Prevention under Annex 

VI.) 

Emission control area (ECA) means an 

area designated pursuant to Annex VI as 

an Emission Control Area that: 

(1) Is in force; and 

(2) Includes waters of the U.S. 

territorial sea and/or EEZ. 

Engine has the meaning given in 40 

CFR 1068.30. 

EPA means the United States 

Environmental Protection Agency. 

Foreign-flagged vessel means a vessel 

of foreign registry or a vessel operated 

under the authority of a country other 

than the United States. 

Good engineering judgment has the 

meaning given in 40 CFR 1068.30. We 

will evaluate engineering judgments as 

described in 40 CFR 1068.5. 

Great Lakes means all the streams, 

rivers, lakes, and other bodies of water 

that are within the drainage basin of the 

St. Lawrence River, west of Anticosti 

Island. 

IMO means the International Maritime 

Organization. 

Major conversion has the meaning 

given in 2008 Annex VI (incorporated 

by reference in § 1043.100). 

MARPOL Protocol has the meaning 

given in 33 U.S.C. 1901. 

Navigable waters has the meaning 

given in 33 U.S.C. 1901. 

Non-Party vessel means a vessel 

flagged by a country that is not a party 

to Annex VI. 

NOX Technical Code means the 

‘‘Technical Code on Control of Emission 

of Nitrogen Oxides from Marine Diesel 

Engines’’ adopted by IMO (incorporated 

by reference in § 1043.100). The 

Technical Code is part of 2008 Annex 

VI. 

Operator has the meaning given in 33 

U.S.C. 1901. 

Owner has the meaning given in 33 

U.S.C. 1901. 

Party vessel means a vessel flying the 

flag of, registered in, or operating under 

the authority of a country that is a party 

to Annex VI. 

Person has the meaning given in 33 

U.S.C. 1901. 

Public vessels means warships, naval 

auxiliary vessels, and other vessels 

owned or operated by a sovereign 

country when engaged in 

noncommercial service. 

Secretary has the meaning given in 33 

U.S.C. 1901. 

U.S. EEZ means the Exclusive 

Economic Zone of the United States, as 

defined in Presidential Proclamation 

5030 of March 10, 1983. 

U.S.-flagged vessel means a vessel of 

U.S. registry or a vessel operated under 

the authority of the United States. 

Vessel has the meaning given to 

‘‘ship’’ in APPS. 

We means EPA. 

§ 1043.30 General obligations. 

(a) 33 U.S.C. 1907 prohibits any 

person from violating any provisions of 

the MARPOL Protocol, whether or not 

they are a manufacturer, owner or 

operator. For manufacturers, owners 

and operators of vessels subject to this 

part, it is the responsibility of such 

manufacturers, owners and operators to 

ensure that all employees and other 

agents operating on their behalf comply 

with these requirements. 

(b) Manufacturers of engines to be 

installed on U.S. vessels subject to this 

part must obtain an EIAPP certificate for 

an engine prior to it being installed in 

a vessel. 

(c) Engines with power output of 

more than 130 kW that are listed in this 

paragraph (c) must be covered by a valid 

EIAPP certificate, certifying the engine 

meets the applicable emission standards 

of Annex VI, unless the engine is 

excluded under § 1043.10 or paragraph 

(d) of this section. An EIAPP certificate 

is valid for a given engine only if it 

certifies compliance with the tier of 

standards applicable to that engine and 

the vessel into which it is being 

installed (or a later tier). Note that none 

of the requirements of this paragraph (c) 

are limited to new engines. 

(1) Engines meeting any of the 

following criteria must be covered by a 

valid EIAPP certificate: 

(i) Engines installed (or intended to be 

installed) on vessels that were 

constructed on or after January 1, 2000. 

This includes engines that met the 

definition of ‘‘new marine engine’’ in 40 

CFR 1042.901 at any time on or after 

January 1, 2000, unless such engines are 

installed on vessels that were 

constructed before January 1, 2000. 

(ii) Engines that undergo a major 

conversion on or after January 1, 2000, 

unless the engines have been exempt 

from this requirement under paragraph 

(e) of this section. 

(2) For such engines intended to be 

installed on U.S.-flagged vessels, the 

engine may not be introduced into U.S. 

commerce before it is covered by a valid 

EIAPP certificate, except as allowed by 

this paragraph (c)(2). 

(i) This paragraph (c)(2) does not 

apply for engines installed on vessels 

excluded under this part 1043. 

(ii) Engines without a valid EIAPP 

certificate (because they are intended for 

domestic use only) may be introduced 

into U.S. commerce, but may not be 

installed on vessels that do not meet the 

requirements of § 1043.10(a)(2). 

(iii) Engines that have been 

temporarily exempted by EPA under 40 

CFR part 1042 or part 1068 may be 

introduced into U.S. commerce without 

a valid EIAPP certificate to the same 

extent they are allowed to be introduced 

into U.S. commerce without a valid part 

1042 certificate of conformity, however, 

this allowance does not affect whether 

the engine must ultimately be covered 

by an EIAPP certificate. Unless 

otherwise excluded or exempted under 

this part 1043, the engine must be 

covered by an EIAPP certificate before 


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being placed into service. For example, 

engines allowed to be temporarily 

distributed in an uncertified 

configuration under 40 CFR 1068.260 

would not be required to be covered by 

an EIAPP certificate while it is covered 

by the temporary exemption under 40 

CFR 1068.260; however, it would be 

required to be covered by an EIAPP 

certificate before being placed into 

service. 

(iv) All uninstalled marine engines 

within the United States are presumed 

to be intended to be installed on a U.S.- 

flagged vessel, unless there is clear and 

convincing evidence to the contrary. 

(3) For engines installed on Party 

vessels, the engine may not operate in 

the U.S. navigable waters or the U.S. 

exclusive economic zone, or other areas 

designated under 33 U.S.C. 

1902(a)(5)(B)(iii), (C)(iii), or (D)(iv) 

unless it is covered by a valid EIAPP 

certificate. 

(4) Engines installed on non-Party 

vessels are not required to have EIAPP 

certificates, but the operator must have 

evidence of conformity with Regulation 

13 of Annex VI issued by either the 

government of a country that is party to 

Annex VI or a recognized classification 

society. For the purposes of this 

paragraph, ‘‘recognized classification 

society’’ means a classification society 

that is a participating member of the 

International Association of 

Classification Societies (IACS). 

(d) In addition to the engines 

excluded under § 1043.10, the following 

engines are excluded from the 

requirement to have an EIAPP certificate 

(or equivalent demonstration of 

compliance in the case of non-Party 

vessels) or otherwise meet the 

requirements of Regulation 13 of Annex 

VI. 

(1) Spark-ignition engines. 

(2) Non-reciprocating engines. 

(3) Engines that do not use liquid fuel. 

(4) Engines intended to be used solely 

for emergencies. This includes engines 

that power equipment such as pumps 

that are intended to be used solely for 

emergencies and engines installed in 

lifeboats intended to be used solely for 

emergencies. It does not include engines 

to be used for both emergency and nonemergency purposes. 

(e) The following requirements apply 

to Party vessels, including U.S.-flagged 

vessels: 

(1) The requirements specified in 

Annex VI apply for vessels subject to 

this part for operation in U.S. navigable 

waters or the U.S. EEZ. (See § 1043.60 

for a summary of the standards included 

in these requirements.) 

(2) Vessels operating in an ECA must 

also comply with the requirements of 

Annex VI applicable to operation in an 

ECA. 

(3) Vessels operating in waters of an 

ECA associated area must also comply 

with the requirements in § 1043.60. 

(f) The following requirements apply 

to non-Party vessels: 

(1) Non-Party vessels operating in 

U.S. navigable waters or the U.S. EEZ 

must comply with the operating and 

recordkeeping requirements of the 2008 

Annex VI (incorporated by reference in 

§ 1043.100) related to Regulations 13, 14 

and 18 of the 2008 Annex VI. This 

paragraph (f)(1) does not address 

requirements of other portions of Annex 

VI. 

(2) Non-Party vessels operating in an 

ECA or ECA associated area must also 

comply with the requirements in 

§ 1043.60. 

(g) A replacement engine may be 

exempted by EPA from Regulation 13 of 

Annex VI and the NOX-related 

requirements of this part if it is identical 

to the engine being replaced and the old 

engine was not subject to Regulation 13 

of Annex VI. Send requests for such 

exemptions to the Designated 

Certification Officer. 

(h) Compliance with the provisions of 

this part 1043 does not affect your 

responsibilities under 40 CFR part 1042 

for engines subject to that part 1042. 

§ 1043.40 EIAPP certificates. 

(a) Engine manufacturers seeking 

EIAPP certificates for new engines to be 

used in U.S.-flagged vessels must apply 

to EPA for an EIAPP certificate in 

compliance with the requirements of 

this section (which references 40 CFR 

part 1042). Note that under APPS engine 

manufacturers must comply with the 

applicable requirements of Regulation 

13 of Annex VI to obtain a certificate. 

Note also that only the Administrator or 

the EPA official designated by the 

Administrator may issue EIAPP 

certificates on behalf of the U.S. 

Government. 

(b) Persons other than engine 

manufacturers may apply for and obtain 

EIAPP certificates for new engines to be 

used in U.S.-flagged vessels by 

complying with the requirements of this 

section (which references 40 CFR part 

1042) and the applicable requirements 

of Regulation 13 of Annex VI. 

(c) In appropriate circumstances, EPA 

may issue an EIAPP certificate under 

this section for non-new engines or 

engines for vessels that will not initially 

be flagged in the U.S. 

(d) The process for obtaining an 

EIAPP certificate is described in 

§ 1043.41. That section references 

regulations in 40 CFR part 1042, which 

apply under the Clean Air Act. 

References in that part to certificates of 

conformity are deemed to mean EIAPP 

certificates. References in that part to 

the Clean Air Act as the applicable 

statute are deemed to mean 33 U.S.C. 

1901–1915. 

(e) For engines that undergo a major 

conversion or for engines installed on 

imported vessels that become subject to 

the requirements of this part, we may 

specify alternate certification provisions 

consistent with the intent of this part. 

(f) This paragraph (f) applies for 

engines that were originally excluded 

from this part because they were 

intended for domestic use and were 

introduced into U.S. commerce without 

an EIAPP certificate. Note that such 

engines must be labeled as specified 

under 40 CFR 1042.135 to indicate that 

they are intended for domestic use. 

Such engines may be installed on 

vessels not intended only for domestic 

operation provided the engine 

manufacturer, vessel manufacturer, or 

vessel owner obtains an EIAPP 

certificate. Similarly, vessels originally 

intended only for domestic operation 

may be used internationally provided 

the engine manufacturer, vessel 

manufacturer, or vessel owner obtains 

an EIAPP certificate. In either case, the 

Technical File must specify that the 

engine was originally certified for 

domestic use only, prior to being 

covered by an EIAPP certificate. Engine 

manufacturers may provide a 

supplemental label to clarify that the 

engine is no longer limited to domestic 

service. An engine manufacturer, vessel 

manufacturer, or vessel owner may also 

ask to apply the provisions of this 

paragraph to engines originally certified 

for public vessels. 

§ 1043.41 EIAPP certification process. 

This section describes the process for 

obtaining the EIAPP certificate required 

by § 1043.40. 

(a) You must send the Designated 

Certification Officer a separate 

application for an EIAPP certificate for 

each engine family. An EIAPP certificate 

is valid starting with the indicated 

effective date and is valid for any 

production until such time as the design 

of the engine family changes or more 

stringent emission standards become 

applicable, whichever comes first. You 

may obtain preliminary approval of 

portions of the application under 40 

CFR 1042.210. 

(b) The application must contain all 

the information required by this part. It 

must not include false or incomplete 

statements or information (see 40 CFR 

1042.255). Include the information 

specified in 40 CFR 1042.205 except as 

follows: 


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(1) You must include the dates on 

which the test engines were built and 

the locations where the test engines 

were built. 

(2) Include a copy of documentation 

required by this part related to 

maintenance and in-use compliance for 

operators, such as the Technical File 

and onboard NOX verification 

procedures as specified by the NOX

Technical Code (incorporated by 

reference in § 1043.100). 

(3) You are not required to provide 

information specified in 40 CFR 

1042.205 regarding useful life, emission 

labels, deterioration factors, PM 

emissions, or not-to-exceed standards. 

(4) You must include a copy of your 

warranty instructions, but are not 

required to describe how you will meet 

warranty obligations. 

(c) We may ask you to include less 

information than we specify in this 

section as long as you maintain all the 

information required by paragraph (b) of 

this section. 

(d) You must use good engineering 

judgment for all decisions related to 

your application (see 40 CFR 1068.5). 

(e) An authorized representative of 

your company must approve and sign 

the application. 

(f) See 40 CFR 1042.255 for provisions 

describing how we will process your 

application. 

(g) Your application, including the 

Technical File and onboard NOX

verification procedures, is subject to 

amendment as described in 40 CFR 

1042.225. 

(h) Perform emission tests as follows: 

(1) Select an emission-data engine 

from each engine family for testing. For 

engines at or above 560 kW, you may 

use a development engine that is 

equivalent in design to the engine being 

certified. For Category 3 engines, you 

may use a single-cylinder version of the 

engine. Using good engineering 

judgment, select the engine 

configuration most likely to exceed an 

applicable emission standard, 

considering all exhaust emission 

constituents and the range of 

installation options available to vessel 

manufacturers. 

(2) Test your emission-data engines 

using the procedures and equipment 

specified in 40 CFR part 1042, subpart 

F, or in the NOX Technical Code 

(incorporated by reference in 

§ 1043.100). We may require that your 

test be witnessed by an EPA official. 

(3) We may measure emissions from 

any of your test engines or other engines 

from the engine family, as follows: 

(i) We may decide to do the testing at 

your plant or any other facility. You 

must deliver the test engine to any test 

facility we designate. The test engine 

you provide must include appropriate 

manifolds, aftertreatment devices, 

electronic control units, and other 

emission-related components not 

normally attached directly to the engine 

block. If we do the testing at your plant, 

you must schedule it as soon as possible 

and make available the instruments, 

personnel, and equipment we need. 

(ii) If we measure emissions from one 

of your test engines, the results of that 

testing become the official emission 

results for the engine. Unless we later 

invalidate these data, we may decide 

not to consider your data in determining 

if your engine family meets applicable 

requirements. 

(iii) Before we test one of your 

engines, we may set its adjustable 

parameters to any point within the 

specified adjustable ranges (see 40 CFR 

1042.115(d)). 

(iv) Before we test one of your 

engines, we may calibrate it within 

normal production tolerances for 

anything we do not consider an 

adjustable parameter. 

(4) We may require you to test a 

second engine of the same or different 

configuration in addition to the engine 

tested under paragraph (b) of this 

section. 

(5) If you use an alternate test 

procedure under 40 CFR 1065.10 and 

later testing shows that such testing 

does not produce results that are 

equivalent to the procedures otherwise 

required by this part, we may reject data 

you generated using the alternate 

procedure. 

(i) Collect emission data using 

measurements to one more decimal 

place than the applicable standard, then 

round the value to the same number of 

decimal places as the emission 

standard. Compare the rounded 

emission levels to the emission standard 

for each emission-data engine. 

(j) Your engine family is considered in 

compliance with the emission standards 

in Regulation 13 of Annex VI if all 

emission-data engines representing that 

family have test results showing 

emission levels at or below these 

standards. Your engine family is 

deemed not to comply if any emissiondata engine representing that family has 

test results showing an emission level 

above an applicable emission standard 

for any pollutant. 

(k) If we determine your application 

is complete and shows that the engines 

meet all the requirements of this part, 

we will issue an EIAPP certificate for 

your engines. We may make the 

approval subject to additional 

conditions. 

§ 1043.50 Approval of methods to meet 

Tier 1 retrofit NOX standards. 

Regulation 13 of Annex VI provides 

for certification of Approved Methods, 

which are retrofit procedures that 

enable Pre-Tier 1 engines to meet the 

Tier 1 NOX standard of regulation 13 of 

Annex VI. Any person may request 

approval of such a method by 

submitting an application for 

certification of an Approve Method to 

the Designated Certification Officer. If 

we determine that your application 

conforms to the requirements of 

Regulation 13 of Annex VI, we will 

issue a certificate and notify IMO that 

your Approved Method has been 

certified. 

§ 1043.55 Applying equivalent controls 

instead of complying with fuel 

requirements. 

Regulation 4 of Annex VI allows 

Administrations to approve the use of 

fuels not meeting the requirements of 

Regulation 14 of the Annex, provided 

the vessel applies a method that results 

in equivalent emission reductions. This 

section describes provisions related to 

applying this allowance. 

(a) Any person may request approval 

of such equivalent methods for 

controlling emissions on U.S.-flagged 

vessels by submitting an application for 

certification of an equivalent control 

method to the Designated Certification 

Officer. If we determine that your 

control method achieves emission levels 

equivalent to those achieved by the use 

of fuels meeting the requirements of 

Regulation 14 of Annex VI, we will 

issue a certificate and notify IMO that 

your method has been certified. 

(b) The provisions of this paragraph 

(b) apply for vessels equipped with 

controls certified by the Administration 

of a foreign flag vessel to achieve 

emission levels equivalent to those 

achieved by the use of fuels meeting the 

applicable fuel sulfur limits of 

Regulation 14 of Annex VI. Fuels not 

meeting the applicable fuel sulfur limits 

of Regulation 14 of Annex VI may be 

used on such vessels consistent with the 

provisions of the IAPP certificate, APPS 

and Annex VI. 

(c) Compliance with the requirements 

of this section does not affect the 

applicability of requirements or 

prohibitions specified by other statutes 

or regulations with respect to water 

pollution. 

§ 1043.60 Operating requirements for 

engines and vessels subject to this part. 

This section specifies the operating 

requirements of this part. Note that it 

does not limit the operating 

requirements of APPS or Annex VI that 


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are applicable to U.S.-flagged vessels 

outside of U.S. domestic waters. 

(a) Except as specified otherwise in 

this part, NOX emission limits apply to 

all vessels subject to this part as 

specified in the following table: 

TABLE 1 TO § 1043.60 ANNEX VI NOX EMISSION STANDARDS (G/KW-HR) 

Tier Area of applicability Model year 

Maximum in-use engine speed 

Less than 

130 RPM 130–2000 RPMa Over 2000 

RPM 

Tier 1 .......... All U.S. navigable waters and EEZ ....................... 2004–2010 ......................... 17.0 45.0·n(¥0.20) 9.8 

Tier 2 .......... All U.S. navigable waters and EEZ ....................... 2011–2015 ......................... 14.4 44.0·n(¥0.23) 7.7 

Tier 2 .......... All U.S. navigable waters and EEZ, exluding ECA 

and ECA associated areas.

2016 and later .................... 14.4 44.0·n(¥0.23) 7.7 

Tier 3 .......... ECA and ECA associated areas ............................ 2016 and later .................... 3.4 9.0·n(¥0.20) 2.0 

aApplicable standards are calculated from n (maximum in-use engine speed, in RPM, as specified in § 1042.140). Round the standards to one 

decimal place. 

(b) Except as specified otherwise in 

this part, fuel sulfur limits apply to all 

vessels subject to this part as specified 

in the following table: 

TABLE 2 TO § 1043.60 ANNEX VI FUEL SULFUR LIMITS

[wt %] 

Calendar years 

Sulfur limit in all U.S. 

navigable waters and 

EEZ 

(percent) 

Sulfur limit in ECA and 

ECA associated areas 

(percent) 

2010–2011 ............................................................................................................................... 4.50 1.00 

2012–2015 ............................................................................................................................... 3.50 1.00 

2016–2019 ............................................................................................................................... 3.50 0.10 

2020 and later .......................................................................................................................... 0.50 0.10 

(c) Operators of non-Party vessels 

must comply with the requirements of 

paragraphs (a) and (b) of this section as 

well as other operating requirements 

and restrictions specified in 2008 Annex 

VI (incorporated by reference in 

§ 1043.100) related to Regulations 13, 

14, and 18. 

(d) This paragraph (d) applies for 

vessels that are excluded from 

Regulation 13 of Annex VI and the NOXrelated requirements of this part under 

§ 1043.10(a)(2) or (b)(3) because they 

operate only domestically. Where the 

vessels operate using only fuels meeting 

the specifications of 40 CFR part 80 for 

distillate fuel, they are deemed to be in 

full compliance with the fuel use 

requirements and prohibitions of this 

part and of Regulations 14 and 18 of 

Annex VI. 

(e) Except as noted in paragraph (d) of 

this section, nothing in this section 

limits the operating requirements and 

restrictions of Annex VI, as 

implemented by APPS, for Party vessels, 

including U.S.-flagged vessels. Note also 

that nothing in this part limits the 

operating requirements and restrictions 

applicable for engines and vessels 

subject to 40 CFR part 1042 or the 

requirements and restrictions applicable 

for fuels subject to 40 CFR part 80. 

(f) We may exempt historic 

steamships from the fuel requirements 

of this part for operation in U.S. internal 

waters. Send requests for exemptions to 

the Designated Certification Officer. 

§ 1043.70 General recordkeeping and 

reporting requirements. 

(a) Under APPS, owners and operators 

of Party vessels must keep records 

related to NOX standards and in-use fuel 

specifications such as the Technical 

File, the Engine Book of Record 

Parameters, and bunker delivery notes. 

Owners and operators of non-Party 

vessels must keep these records as 

specified in the NOX Technical Code 

and Regulations 13, 14, and 18 of Annex 

VI (incorporated by reference in 

§ 1043.100). We may inspect these 

records as allowed by APPS. As part of 

our inspection, we may require that the 

owner submit copies of these records to 

us. 

(b) Nothing in this part limits 

recordkeeping and reporting the 

Secretary may require, nor does it 

preclude the Secretary from providing 

copies of any records to EPA. 

(c) Nothing in this part limits the 

recordkeeping and reporting 

requirements applicable with respect to 

engines and vessels subject to 40 CFR 

part 1042 or with respect to fuels subject 

to 40 CFR part 80. 

(d) This paragraph (d) applies for 

vessels that are excluded from 

Regulation 13 of Annex VI and the NOXrelated requirements of this part under 

§ 1043.10(a)(2) or (b)(3) because they 

operate only domestically. Where the 

vessel operator has fuel receipts (or 

equivalent records) for the preceding 

three years showing it operated using 

only fuels meeting the specifications of 

40 CFR part 80 for distillate fuel, they 

are deemed to be in full compliance 

with the fuel recordkeeping 

requirements and prohibitions of this 

part and Annex VI. 

§ 1043.80 Recordkeeping and reporting 

requirements for fuel suppliers. 

Under APPS, fuel suppliers must 

provide bunker delivery notes to vessel 

operators for any fuel for an engine on 

any vessel identified in paragraph (a) of 

this section. Fuel suppliers must also 

keep copies of these records. 

(a) The requirements of this section 

apply for fuel delivered to any of the 

following vessels: 

(1) Vessels of 400 gross tonnage and 

above engaged in voyages to ports or 

offshore terminals under the jurisdiction 

of other Parties. 

(2) Platforms and drilling rigs engaged 

in voyages to waters under the 

sovereignty or jurisdiction of other 

Parties. 


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(b) Except as allowed by paragraph (c) 

of this section, the bunker delivery note 

must contain the following: 

(1) The name and IMO number of the 

receiving vessel. 

(2) Port (or other description of the 

location, if the delivery does not take 

place at a port). 

(3) Date the fuel is delivered to the 

vessel (or date on which the delivery 

begins where the delivery begins on one 

day and ends on a later day). 

(4) Name, address, and telephone 

number of fuel supplier. 

(5) Fuel type and designation under 

40 CFR part 80. 

(6) Quantity in metric tons. 

(7) Density at 15 °C, in kg/m3. 

(8) Sulfur content in weight percent. 

(9) A signed statement by an 

authorized representative of fuel 

supplier certifying that the fuel supplied 

conforms to Regulations 14 and 18 of 

Annex VI consistent with it designation, 

intended use, and the date on which it 

is to be used. For example, with respect 

to conformity to Regulation 14 of Annex 

VI, a fuel designated and intended for 

use in an ECA any time between July 1, 

2010 and January 1, 2015 may not have 

a sulfur content above 1.00 weight 

percent. This statement is not required 

where the vessel conforms to the 

requirements of § 1043.55. 

(c) You may measure density and 

sulfur content according to the 

specifications of Annex VI, or according 

to other equivalent methods that we 

approve. Where the density and/or 

sulfur content of the delivered fuel 

cannot be measured, we may allow the 

use of alternate methods to specify the 

density and/or sulfur content of the fuel. 

For example, where fuel is supplied 

from multiple tanks on a supply vessel, 

we may allow the density and sulfur 

content of the fuel to be calculated as a 

weighted average of the measured 

densities and sulfur contents of the fuel 

that is supplied from each tank. 

§ 1043.90 [Reserved] 

§ 1043.95 Interim provisions. 

The interim provisions of this section 

apply for vessels operating exclusively 

in the Great Lakes. 

(a) Notwithstanding other provisions 

of this part, the requirements of this part 

do not apply for vessels propelled by 

steam turbine engines or reciprocating 

steam engines (also known as 

steamships), provided they were 

propelled by steam engines and 

operated within the Great Lakes before 

October 30, 2009 and continue to 

operate exclusively within the Great 

Lakes. 

(b) In cases of serious economic 

hardship, we may exempt Great Lakes 

vessels from the otherwise applicable 

fuel use requirements under this part. 

(1) To be eligible, you must 

demonstrate that all of the following are 

true: 

(i) Unusual circumstances exist that 

impose serious economic hardship and 

significantly affect your ability to 

comply. 

(ii) You have taken all reasonable 

steps to minimize the extent of the 

nonconformity. 

(iii) No other allowances are available 

under the regulations in this chapter to 

avoid the impending violation. 

(2) Send the Designated Certification 

Officer a written request for an 

exemption no later than January 1, 2014. 

(3) Applicants must provide, at a 

minimum, the following information: 

(i) Detailed description of existing 

contract freight rates, the additional 

operating costs attributed to complying 

with the regulations, any loan covenants 

or other requirements regarding vessel 

financial instruments or agreements. 

(ii) Bond rating of entity that owns the 

vessels in question (in the case of joint 

ventures, include the bond rating of the 

joint venture entity and the bond ratings 

of all partners; in the case of 

corporations, include the bond ratings 

of any parent or subsidiary 

corporations). 

(iii) Estimated capital investment 

needed to comply with the requirements 

of this part by the applicable date. 

(4) In determining whether to grant 

the exemptions, we will consider all 

relevant factors, including the 

following: 

(i) The number of vessels to be 

exempted. 

(ii) The size of your company and 

your ability to endure the hardship. 

(iii) The length of time a vessel is 

expected to remain out of compliance 

with this part. 

(iv) The ability of an individual vessel 

to recover capital investments incurred 

to repower or otherwise modify a vessel 

to reduce air emissions. 

(5) In addition to the application 

requirements of paragraphs (b)(1) 

through (4) of this section, your 

application for temporary relief under 

this paragraph (b) must also include a 

compliance plan that shows the period 

over which the waiver is needed. 

(6) We may impose conditions on the 

waiver, including conditions to limit or 

recover any environmental loss. 

(c) Prior to January 1, 2015, it is not 

a violation of this part for vessels 

operating exclusively in the Great Lakes 

to use a residual fuel not meeting the 

sulfur limits of Regulation 14.4.2 of 

Annex VI, where the operator bunkers 

with the lowest sulfur marine residual 

fuel that was available within the port 

area where the vessel bunkered the fuel. 

For purposes of this paragraph (c), port 

area means the geographic limits of the 

port as specified by the Army Corps of 

Engineers. The reporting and 

recordkeeping requirements of this part 

continue to apply for such operation. In 

addition, if you operate using a residual 

fuel not meeting the sulfur limits of 

Regulation 14.4.2 under this paragraph 

(c), you must send a report to the 

Designated Certification Officer that 

identifies the fuel that was used and 

documents how you determined that no 

compliant fuel was available. You must 

send this report within three months 

after the fueling event. 

§ 1043.100 Reference materials. 

Documents listed in this section have 

been incorporated by reference into this 

part. The Director of the Federal 

Register approved the incorporation by 

reference as prescribed in 5 U.S.C. 

552(a) and 1 CFR part 51. Anyone may 

inspect copies at the U.S. EPA, Air and 

Radiation Docket and Information 

Center, 1301 Constitution Ave., NW., 

Room B102, EPA West Building, 

Washington, DC 20460, (202) 566–1744, 

or at the National Archives and Records 

Administration (NARA). For 

information on the availability of this 

material at NARA, call 202–741–6030, 

or go to: http://www.archives.gov/ 

federal_register/ 

code_of_federal_regulations/ 

ibr_locations.html. 

(a) IMO material. This paragraph (a) 

lists material from the International 

Maritime Organization that we have 

incorporated by reference. Anyone may 

purchase copies of these materials from 

the International Maritime Organization, 

4 Albert Embankment, London SE1 7SR, 

United Kingdom, or http:// 

www.imo.org, or 44–(0)20–7735–7611. 

(1) Revised MARPOL Annex VI, 

Regulations for the Prevention of Air 

Pollution from Ships, and NOX

Technical Code 2008, 2009 edition. 

(i) Revised MARPOL Annex VI, 

Regulations for the Prevention of 

Pollution from Ships (‘‘2008 Annex VI’’); 

IBR approved for § 1043.1, 1043.20, 

1043.30(f), and 1043.60(c), and 

1043.70(a). 

(ii) NOX Technical Code 2008 (‘‘NOX

Technical Code’’); IBR approved for 

§§ 1043.20, 1043.41(b) and (h), and 

1043.70(a). 

(2) [Reserved] 

(b) [Reserved] 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23019 

PART 1045—CONTROL OF EMISSIONS 

FROM SPARK-IGNITION PROPULSION 

MARINE ENGINES AND VESSELS 

■ 211. The authority citation for part 

1045 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart B—[Amended] 

■ 212. Section 1045.103 is amended by 

revising paragraph (b) introductory text 

to read as follows: 

§ 1045.103 What exhaust emission 

standards must my outboard and personal 

watercraft engines meet? 

* * * * * 

(b) Averaging, banking, and trading. 

You may generate or use emission 

credits under the averaging, banking, 

and trading (ABT) program described in 

subpart H of this part for demonstrating 

compliance with HC+NOX emission 

standards. For CO emissions, you may 

generate or use emission credits for 

averaging as described in subpart H of 

this part, but such credits may not be 

banked or traded. To generate or use 

emission credits, you must specify a 

family emission limit for each pollutant 

you include in the ABT program for 

each engine family. These family 

emission limits serve as the emission 

standards for the engine family with 

respect to all required testing instead of 

the standards specified in this section. 

An engine family meets emission 

standards even if its family emission 

limit is higher than the standard, as long 

as you show that the whole averaging 

set of applicable engine families meets 

the emission standards using emission 

credits and the engines within the 

family meet the family emission limit. 

The following FEL caps apply: 

* * * * * 

■ 213. Section 1045.125 is amended as 

follows: 

■ a. By revising paragraphs (a)(2). 

■ b. By adding paragraph (a)(3). 

■ c. By revising paragraph (c). 

§ 1045.125 What maintenance instructions 

must I give to buyers? 

* * * * * 

(a) * * * 

(2) You may not schedule critical 

emission-related maintenance within 

the useful life period for aftertreatment 

devices, pulse-air valves, fuel injectors, 

oxygen sensors, electronic control units, 

superchargers, or turbochargers, except 

as specified in paragraph (a)(3), (b), or 

(c) of this section. 

(3) You may ask us to approve a 

maintenance interval shorter than that 

specified in paragraph (a)(2) of this 

section. In your request you must 

describe the proposed maintenance 

step, recommend the maximum feasible 

interval for this maintenance, include 

your rationale with supporting evidence 

to support the need for the maintenance 

at the recommended interval, and 

demonstrate that the maintenance will 

be done at the recommended interval on 

in-use engines. In considering your 

request, we will evaluate the 

information you provide and any other 

available information to establish 

alternate specifications for maintenance 

intervals, if appropriate. 

* * * * * 

(c) Special maintenance. You may 

specify more frequent maintenance to 

address problems related to special 

situations, such as atypical engine 

operation. You must clearly state that 

this additional maintenance is 

associated with the special situation you 

are addressing. We may disapprove your 

maintenance instructions if we 

determine that you have specified 

special maintenance steps to address 

engine operation that is not atypical, or 

that the maintenance is unlikely to 

occur in use. If we determine that 

certain maintenance items do not 

qualify as special maintenance under 

this paragraph (c), you may identify this 

as recommended additional 

maintenance under paragraph (b) of this 

section. 

* * * * * 

■ 214. Section 1045.140 is amended by 

revising paragraph (a) to read as follows: 

§ 1045.140 What is my engine’s maximum 

engine power? 

(a) An engine configuration’s 

maximum engine power is the 

maximum brake power point on the 

nominal power curve for the engine 

configuration, as defined in this section. 

Round the power value to the nearest 

whole kilowatt for engines above 30 kW 

and to the nearest 0.1 kilowatt for 

engines at or below 30 kW. 

* * * * * 

■ 215. Section 1045.145 is amended by 

adding paragraph (o) to read as follows: 

§ 1045.145 Are there interim provisions 

that apply only for a limited time? 

* * * * * 

(o) Banking early credits for jet boat 

engines. Banked emission credits that 

were originally generated from outboard 

and personal watercraft engines under 

40 CFR part 91 may be used to certify 

jet boat engines under the provisions 

§ 1045.660. 

Subpart C—[Amended] 

■ 216. Section 1045.201 is amended by 

adding paragraph (h) to read as follows: 

§ 1045.201 What are the general 

requirements for obtaining a certificate of 

conformity? 

* * * * * 

(h) For engines that become new after 

being placed into service, such as 

engines installed on imported vessels or 

engines converted to run on a different 

fuel, we may specify alternate 

certification provisions consistent with 

the intent of this part. See § 1045.645 

and the definition of ‘‘new propulsion 

marine engine’’ in § 1045.801. 

■ 217. Section 1045.220 is amended by 

revising paragraph (a) to read as follows: 

§ 1045.220 How do I amend the 

maintenance instructions in my 

application? 

* * * * * 

(a) If you are decreasing or 

eliminating any specified maintenance, 

you may distribute the new 

maintenance instructions to your 

customers 30 days after we receive your 

request, unless we disapprove your 

request. This would generally include 

replacing one maintenance step with 

another. We may approve a shorter time 

or waive this requirement. 

* * * * * 

■ 218. Section 1045.230 is amended by 

revising paragraph (b)(4) to read as 

follows: 

§ 1045.230 How do I select engine 

families? 

* * * * * 

(b) * * * 

(4) The number, arrangement (such as 

in-line or vee configuration), and 

approximate bore diameter of cylinders. 

* * * * * 

■ 219. Section 1045.240 is amended by 

revising paragraphs (a) and (b) and 

adding paragraph (e) to read as follows: 

§ 1045.240 How do I demonstrate that my 

engine family complies with exhaust 

emission standards? 

(a) For purposes of certification, your 

engine family is considered in 

compliance with the duty-cycle 

emission standards in § 1045.103 or 

§ 1045.105 if all emission-data engines 

representing that family have test results 

showing official emission results and 

deteriorated emission levels at or below 

these standards. This also applies for all 

test points for emission-data engines 

within the family used to establish 

deterioration factors. Note that your 

FELs are considered to be the applicable 


wwoods2 on DSK1DXX6B1PROD with RULES_2
23020 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

emission standards with which you 

must comply if you participate in the 

ABT program in subpart H of this part. 

See paragraph (e) of this section for 

provisions related to demonstrating 

compliance with NTE standards. 

(b) Your engine family is deemed not 

to comply with the duty-cycle emission 

standards in § 1045.103 or § 1045.105 if 

any emission-data engine representing 

that family has test results showing an 

official emission result or a deteriorated 

emission level for any pollutant that is 

above an applicable emission standard. 

Similarly, your engine family is deemed 

not to comply if any emission-data 

engine representing that family has test 

results showing any emission level 

above the applicable not-to-exceed 

emission standard for any pollutant. 

This also applies for all test points for 

emission-data engines within the family 

used to establish deterioration factors. 

* * * * * 

(e) Use good engineering judgment to 

demonstrate compliance with NTE 

standards throughout the useful life. 

You may, but are not required to, apply 

the same deterioration factors used to 

show compliance with the applicable 

duty-cycle standards. 

Subpart E—[Amended] 

■ 220. Section 1045.405 is amended by 

revising paragraphs (c) and (e) to read as 

follows: 

§ 1045.405 How does this program work? 

* * * * * 

(c) Send us an in-use testing plan for 

engine families selected for testing as 

described in this paragraph (c). 

Complete the testing within 36 months 

after we direct you to test a particular 

engine family. Send us a complete inuse testing plan according to the 

following deadlines: 

(1) Within six months after we direct 

you to test a particular engine family. 

(2) By February 28 of the following 

year if you select engine families for 

testing under paragraph (b)(1) of this 

section. 

(3) Within six months after we 

approve certification for engine families 

subject to the requirements of paragraph 

(b)(2) of this section. 

(4) If we request additional 

information or require you to modify 

your plan to meet the requirements of 

this subpart, you must provide the 

information or the modified plan within 

30 days of our request. 

* * * * * 

(e) In appropriate extreme and 

unusual circumstances that are clearly 

outside your control and could not have 

been avoided by the exercise of 

prudence, diligence, and due care, we 

may allow more time to complete 

testing or we may waive the in-use 

testing requirement for an engine 

family. For example, if your test fleet is 

destroyed by severe weather during 

service accumulation and we agree that 

completion of testing is not possible, we 

would generally waive testing 

requirements for that engine family. 

Subpart F—[Amended] 

■ 221. Section 1045.515 is amended by 

revising paragraph (c)(5) introductory 

text to read as follows: 

§ 1045.515 What are the test procedures 

related to not-to-exceed standards? 

* * * * * 

(c) * * * 

(5) For two-stroke engines not 

equipped with a catalyst, the NTE zone 

described in paragraph (c)(3) of this 

section is divided into subzones for 

testing to determine compliance with 

the applicable NTE standards. Measure 

emissions to get an NTE result by 

collecting emissions at five points as 

described in this paragraph (c)(5). 

Calculate a weighted test result for these 

emission measurements using the 

weighting factors from Appendix II of 

this part for the corresponding modal 

result (similar to discrete-mode testing 

for certification). Test engines over the 

following modes corresponding to the 

certification duty cycle: 

* * * * * 

Subpart H—[Amended] 

■ 222. Section 1045.701 is amended by 

revising paragraphs (d), (g), (j)(4) and 

(j)(5) to read as follows: 

§ 1045.701 General provisions. 

* * * * * 

(d) Sterndrive/inboard engines 

certified under § 1045.660 for jet boats 

may use HC+NOx and CO exhaust 

credits generated from outboard and 

personal watercraft engines, as long as 

the credit-using engine is the same 

model as an engine model from an 

outboard or personal watercraft family. 

Such emission credits that you generate 

under this part 1045 may be used for 

averaging, but not for banking or 

trading. The FEL caps for such jet boat 

families are the HC+NOx and CO 

standard for outboard and personal 

watercraft engines. U.S.-directed sales 

from jet boat engines using the 

provisions of this paragraph (d) may not 

be greater than the U.S.-directed sales of 

the same engine model for outboard or 

personal watercraft engines. 

* * * * * 

(g) Emission credits may be used for 

averaging in the model year they are 

generated or banked for averaging in 

future model years, except that CO 

emission credits for outboard and 

personal watercraft engines may not be 

banked or traded. 

* * * * * 

(j) * * * 

(4) Engines or vessels not subject to 

the requirements of this part, such as 

those excluded under § 1045.5. 

(5) Any other engines or vessels 

where we indicate elsewhere in this part 

1045 that they are not to be included in 

the calculations of this subpart. 

■ 223. Section 1045.705 is amended by 

revising paragraph (a) to read as follows: 

§ 1045.705 How do I generate and 

calculate exhaust emission credits? 

* * * * * 

(a) For each participating family, 

calculate positive or negative emission 

credits relative to the otherwise 

applicable emission standard. Calculate 

positive emission credits for a family 

that has an FEL below the standard. 

Calculate negative emission credits for a 

family that has an FEL above the 

standard. Sum your positive and 

negative credits for the model year 

before rounding. Round the sum of 

emission credits to the nearest kilogram 

(kg) using consistent units throughout 

the following equation: 

Emission credits (kg) = (STD¥FEL) × 

(Volume) × (Power) × (UL) × (LF) × 

(10¥3) 

Where: 

STD = the emission standard, in g/kW-hr. 

FEL = the family emission limit for the 

family, in g/kW-hr. 

Volume = the number of engines eligible to 

participate in the averaging, banking, 

and trading program within the given 

family during the model year, as 

described in § 1045.701(j). 

Power = maximum engine power for the 

family, in kilowatts (see § 1045.140). 

UL = The useful life for the given family. 

LF = load factor. Use 0.207. We may specify 

a different load factor if we approve the 

use of special test procedures for an 

engine family under 40 CFR 

1065.10(c)(2), consistent with good 

engineering judgment. 

* * * * * 

Subpart I—[Amended] 

■ 224. Section 1045.801 is amended by 

revising the definition of ‘‘Fuel system’’ 

and paragraphs (2) and (5)(iii) of the 

definition of ‘‘Model year’’ to read as 

follows: 

§ 1045.801 What definitions apply to this 

part? 

* * * * * 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23021 

Fuel system means all components 

involved in transporting, metering, and 

mixing the fuel from the fuel tank to the 

combustion chamber(s), including the 

fuel tank, fuel tank cap, fuel pump, fuel 

filters, fuel lines, carburetor or fuelinjection components, and all fuelsystem vents. In the case where the fuel 

tank cap or other components 

(excluding fuel lines) are directly 

mounted on the fuel tank, they are 

considered to be a part of the fuel tank. 

* * * * * 

Model year * * * 

(2) For an engine that is converted to 

a propulsion marine engine after being 

certified and placed into service as a 

motor vehicle engine, a nonroad engine 

that is not a propulsion marine engine, 

or a stationary engine, model year 

means the calendar year in which the 

engine was originally produced. For an 

engine that is converted to a propulsion 

marine engine after being placed into 

service as a motor vehicle engine, a 

nonroad engine that is not a propulsion 

marine engine, or a stationary engine 

without having been certified, model 

year means the calendar year in which 

the engine becomes a new propulsion 

marine engine. (See definition of ‘‘new 

propulsion marine engine,’’ paragraph 

(2).) 

* * * * * 

(5) * * * 

(iii) For imported engines described 

in paragraph (5)(iii) of the definition of 

‘‘new propulsion marine nonroad 

engine,’’ model year means the calendar 

year in which the engine is first 

assembled in its imported configuration, 

unless specified otherwise in this part 

or in 40 CFR part 1068. 

* * * * * 

PART 1048—CONTROL OF EMISSIONS 

FROM NEW, LARGE NONROAD 

SPARK-IGNITION ENGINES 

■ 225. The authority citation for part 

1048 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 226. Section 1048.15 is amended by 

revising paragraph (b) to read as follows: 

§ 1048.15 Do any other regulation parts 

apply to me? 

* * * * * 

(b) Part 1065 of this chapter describes 

procedures and equipment 

specifications for testing engines to 

measure exhaust emissions. Subpart F 

of this part 1048 describes how to apply 

the provisions of part 1065 of this 

chapter to determine whether engines 

meet the exhaust emission standards in 

this part. 

* * * * * 

■ 227. A new § 1048.30 is added to 

subpart A to read as follows: 

§ 1048.30 Submission of information. 

(a) This part includes various 

requirements to record data or other 

information. Refer to § 1048.825 and 40 

CFR 1068.25 regarding recordkeeping 

requirements. Unless we specify 

otherwise, store these records in any 

format and on any media and keep them 

readily available for one year after you 

send an associated application for 

certification, or one year after you 

generate the data if they do not support 

an application for certification. You 

must promptly send us organized, 

written records in English if we ask for 

them. We may review them at any time. 

(b) The regulations in § 1048.255 and 

40 CFR 1068.101 describe your 

obligation to report truthful and 

complete information and the 

consequences of failing to meet this 

obligation. This includes information 

not related to certification. 

(c) Send all reports and requests for 

approval to the Designated Compliance 

Officer (see § 1048.801). 

(d) Any written information we 

require you to send to or receive from 

another company is deemed to be a 

required record under this section. Such 

records are also deemed to be 

submissions to EPA. We may require 

you to send us these records whether or 

not you are a certificate holder. 

Subpart B—[Amended] 

■ 228. Section 1048.120 is amended by 

revising paragraph (b) to read as follows: 

§ 1048.120 What emission-related warranty 

requirements apply to me? 

* * * * * 

(b) Warranty period. Your emissionrelated warranty for evaporative 

emission controls must be valid for at 

least two years. Your emission-related 

warranty for exhaust emission controls 

must be valid for at least 50 percent of 

the engine’s useful life in hours of 

operation or at least three years, 

whichever comes first. In the case of a 

high-cost warranted part, the warranty 

must be valid for at least 70 percent of 

the engine’s useful life in hours of 

operation or at least five years, 

whichever comes first. You may offer an 

emission-related warranty more 

generous than we require. The emissionrelated warranty for the engine may not 

be shorter than any published warranty 

you offer without charge for the engine. 

Similarly, the emission-related warranty 

for any component may not be shorter 

than any published warranty you offer 

without charge for that component. If an 

engine has no hour meter, we base the 

warranty periods in this paragraph (b) 

only on the engine’s age (in years). The 

warranty period begins when the engine 

is placed into service. 

* * * * * 

■ 229. Section 1048.125 is amended by 

adding paragraph (a)(4) and revising 

paragraph (c) to read as follows: 

§ 1048.125 What maintenance instructions 

must I give to buyers? 

* * * * * 

(a) * * * 

(4) You may ask us to approve a 

maintenance interval shorter than that 

specified in paragraphs (a)(2) of this 

section. In your request you must 

describe the proposed maintenance 

step, recommend the maximum feasible 

interval for this maintenance, include 

your rationale with supporting evidence 

to support the need for the maintenance 

at the recommended interval, and 

demonstrate that the maintenance will 

be done at the recommended interval on 

in-use engines. In considering your 

request, we will evaluate the 

information you provide and any other 

available information to establish 

alternate specifications for maintenance 

intervals, if appropriate. 

* * * * * 

(c) Special maintenance. You may 

specify more frequent maintenance to 

address problems related to special 

situations, such as substandard fuel or 

atypical engine operation. For example, 

you may specify more frequent cleaning 

of fuel system components for engines 

you have reason to believe will be using 

fuel that causes substantially more 

engine performance problems than 

commercial fuels of the same type that 

are generally available across the United 

States. You must clearly state that this 

additional maintenance is associated 

with the special situation you are 

addressing. We may disapprove your 

maintenance instructions if we 

determine that you have specified 

special maintenance steps to address 

engine operation that is not atypical, or 

that the maintenance is unlikely to 

occur in use. If we determine that 

certain maintenance items do not 

qualify as special maintenance under 

this paragraph (c), you may identify this 

as recommended additional 

maintenance under paragraph (b) of this 

section. 

* * * * * 


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23022 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

Subpart C—[Amended] 

■ 230. Section 1048.201 is amended by 

adding paragraph (h) to read as follows: 

§ 1048.201 What are the general 

requirements for obtaining a certificate of 

conformity? 

* * * * * 

(h) For engines that become new after 

being placed into service, such as 

engines converted to nonroad use after 

being used in motor vehicles, we may 

specify alternate certification provisions 

consistent with the intent of this part. 

See the definition of ‘‘new nonroad 

engine’’ in § 1048.801. 

■ 231. Section 1048.220 is amended by 

revising paragraphs (a) and (c) to read as 

follows: 

§ 1048.220 How do I amend the 

maintenance instructions in my 

application? 

* * * * * 

(a) If you are decreasing or 

eliminating any specified maintenance, 

you may distribute the new 

maintenance instructions to your 

customers 30 days after we receive your 

request, unless we disapprove your 

request. This would generally include 

replacing one maintenance step with 

another. We may approve a shorter time 

or waive this requirement. 

* * * * * 

(c) You need not request approval if 

you are making only minor corrections 

(such as correcting typographical 

mistakes), clarifying your maintenance 

instructions, or changing instructions 

for maintenance unrelated to emission 

control. We may ask you to send us 

copies of maintenance instructions 

revised under this paragraph (c). 

■ 232. Section 1048.230 is amended by 

revising paragraph (b)(6) to read as 

follows: 

§ 1048.230 How do I select engine 

families? 

* * * * * 

(b) * * * 

(6) The number, arrangement (such as 

in-line or vee configuration), and 

approximate bore diameter of cylinders. 

* * * * * 

■ 233. Section 1048.240 is amended by 

revising paragraphs (a) and (b) and 

adding paragraph (e) to read as follows: 

§ 1048.240 How do I demonstrate that my 

engine family complies with exhaust 

emission standards? 

(a) For purposes of certification, your 

engine family is considered in 

compliance with the applicable 

numerical emission standards in 

§ 1048.101(a) and (b) if all emission-data 

engines representing that family have 

test results showing official emission 

results and deteriorated emission levels 

at or below these standards. This 

includes all test points over the course 

of the durability demonstration. This 

also applies for all test points for 

emission-data engines within the family 

used to establish deterioration factors. 

See paragraph (e) of this section for 

provisions related to demonstrating 

compliance with field-testing standards. 

(b) Your engine family is deemed not 

to comply if any emission-data engine 

representing that family has test results 

showing an official emission result or a 

deteriorated emission level for any 

pollutant that is above an applicable 

emission standard from § 1048.101(a) 

and (b). Similarly, your engine family is 

deemed not to comply if any emissiondata engine representing that family has 

test results showing any emission level 

above the applicable field-testing 

standard for any pollutant. This also 

applies for all test points for emissiondata engines within the family used to 

establish deterioration factors. 

* * * * * 

(e) Use good engineering judgment to 

demonstrate compliance with fieldtesting standards throughout the useful 

life. You may, but are not required to, 

apply the same deterioration factors 

used to show compliance with the 

applicable duty-cycle standards. 

■ 234. Section 1048.245 is amended by 

revising paragraph (e) to read as follows: 

§ 1048.245 How do I demonstrate that my 

engine family complies with evaporative 

emission standards? 

* * * * * 

(e) You may demonstrate that your 

engine family complies with the 

evaporative emission standards by 

demonstrating that you use the 

following control technologies: 

(1) For certification to the standards 

specified in § 1048.105(c), with the 

following technologies: 

(i) Use a tethered or self-closing gas 

cap on a fuel tank that stays sealed up 

to a positive pressure of 24.5 kPa (3.5 

psig); however, they may contain air 

inlets that open when there is a vacuum 

pressure inside the tank. Nonmetal fuel 

tanks must also use one of the 

qualifying designs for controlling 

permeation emissions specified in 40 

CFR 1060.240. 

(ii) [Reserved] 

(2) For certification to the standards 

specified in § 1048.105(d), 

demonstrating that you use design 

features to prevent fuel boiling under all 

normal operation. If you install engines 

in equipment, you may do this using 

fuel temperature data measured during 

normal operation. Otherwise, you may 

do this by including appropriate 

information in your emission-related 

installation instructions. 

(3) We may establish additional 

options for design-based certification 

where we find that new test data 

demonstrate that a technology will 

ensure compliance with the emission 

standards in this section. 

■ 235. Section 1048.255 is amended by 

revising paragraph (b) to read as follows: 

§ 1048.255 What decisions may EPA make 

regarding my certificate of conformity? 

* * * * * 

(b) We may deny your application for 

certification if we determine that your 

engine family fails to comply with 

emission standards or other 

requirements of this part or the Clean 

Air Act. We will base our decision on 

all available information. If we deny 

your application, we will explain why 

in writing. 

* * * * * 

Subpart E—[Amended] 

■ 236. Section 1048.405 is amended by 

revising paragraphs (b) and (d) to read 

as follows: 

§ 1048.405 How does this program work? 

* * * * * 

(b) Send us an in-use testing plan 

within six months after we direct you to 

test a particular engine family. If we 

request additional information or 

require you to modify your plan to meet 

the requirements of this subpart, you 

must provide the information or the 

modified plan within 30 days of our 

request. Complete the testing within 36 

months after we direct you to test a 

particular engine family. 

* * * * * 

(d) In appropriate extreme and 

unusual circumstances that are clearly 

outside your control and could not have 

been avoided by the exercise of 

prudence, diligence, and due care, we 

may allow more time to complete 

testing or we may waive the in-use 

testing requirement for an engine 

family. For example, if your test fleet is 

destroyed by severe weather during 

service accumulation and we agree that 

completion of testing is not possible, we 

would generally waive testing 

requirements for that engine family. 

Subpart F—[Amended] 

■ 237. Section 1048.505 is amended by 

revising the section heading and 

paragraph (b)(5)(i) and Table 3 to read 

as follows: 


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§ 1048.505 How do I test engines using 

steady-state duty cycles, including rampedmodal testing? 

* * * * * 

(b) * * * 

(5) * * * 

(i) The following duty cycle applies 

for discrete-mode testing: 

TABLE 3 OF § 1048.505 

Mode No. Engine 

speed 

Torque 

(percent) 1

Minimum time in 

mode (minutes) Weighting factors 

1 .................. Maximum test speed .............................................................................. 100 3.0 0.50

2 .................. Maximum test speed .............................................................................. 75 3.0 0.50 

1The percent torque is relative to the maximum torque at maximum test speed. 

* * * * * 

■ 238. Section 1048.510 is amended by 

adding paragraph (b) to read as follows: 

§ 1048.510 What transient duty cycles 

apply for laboratory testing? 

* * * * * 

(b) Calculate cycle statistics and 

compare with the established criteria as 

specified in 40 CFR 1065.514 to confirm 

that the test is valid. 

* * * * * 

Subpart I—[Amended] 

■ 239. Section 1048.801 is amended by 

adding definitions for ‘‘Carryover’’ and 

‘‘Date of manufacture’’ in alphabetical 

order to read as follows: 

§ 1048.801 What definitions apply to this 

part? 

* * * * * 

Carryover means relating to 

certification based on emission data 

generated from an earlier model year as 

described in § 1048.235(d). 

* * * * * 

Date of manufacture has the meaning 

given in 40 CFR 1068.30. 

* * * * * 

PART 1051—CONTROL OF EMISSIONS 

FROM RECREATIONAL ENGINES AND 

VEHICLES 

■ 240. The authority citation for part 

1051 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 241. Section 1051.15 is amended by 

revising paragraph (a) to read as follows: 

§ 1051.15 Do any other regulation parts 

apply to me? 

(a) Parts 86 and 1065 of this chapter 

describe procedures and equipment 

specifications for testing vehicles and 

engines to measure exhaust emissions. 

Subpart F of this part 1051 describes 

how to apply the provisions of parts 86 

and 1065 of this chapter to determine 

whether vehicles meet the exhaust 

emission standards in this part. 

* * * * * 

■ 242. Section 1051.20 is amended by 

adding paragraph (g) to read as follows: 

§ 1051.20 May I certify a recreational 

engine instead of the vehicle? 

* * * * * 

(g) Apply the provisions of 40 CFR 

part 1068 for engines certified under 

this section as if they were subject to 

engine-based standards. For example, 

you may rely on the provisions of 40 

CFR 1068.261 to have vehicle 

manufacturers install catalysts that you 

describe in your application for 

certification. 

■ 243. A new § 1051.30 is added to 

subpart A to read as follows: 

§ 1051.30 Submission of information. 

(a) This part includes various 

requirements to record data or other 

information. Refer to § 1051.825 and 40 

CFR 1068.25 regarding recordkeeping 

requirements. Unless we specify 

otherwise, store these records in any 

format and on any media and keep them 

readily available for one year after you 

send an associated application for 

certification, or one year after you 

generate the data if they do not support 

an application for certification. You 

must promptly send us organized, 

written records in English if we ask for 

them. We may review them at any time. 

(b) The regulations in § 1051.255 and 

40 CFR 1068.101 describe your 

obligation to report truthful and 

complete information and the 

consequences of failing to meet this 

obligation. This includes information 

not related to certification. 

(c) Send all reports and requests for 

approval to the Designated Compliance 

Officer (see § 1051.801). 

(d) Any written information we 

require you to send to or receive from 

another company is deemed to be a 

required record under this section. Such 

records are also deemed to be 

submissions to EPA. We may require 

you to send us these records whether or 

not you are a certificate holder. 

Subpart B—[Amended] 

■ 244. Section 1051.125 is amended by 

adding paragraph (a)(3) and revising 

paragraph (c) to read as follows: 

§ 1051.125 What maintenance instructions 

must I give to buyers? 

* * * * * 

(a) * * * 

(3) You may ask us to approve a 

maintenance interval shorter than that 

specified in paragraph (a)(2) of this 

section. In your request you must 

describe the proposed maintenance 

step, recommend the maximum feasible 

interval for this maintenance, include 

your rationale with supporting evidence 

to support the need for the maintenance 

at the recommended interval, and 

demonstrate that the maintenance will 

be done at the recommended interval on 

in-use engines. In considering your 

request, we will evaluate the 

information you provide and any other 

available information to establish 

alternate specifications for maintenance 

intervals, if appropriate. 

* * * * * 

(c) Special maintenance. You may 

specify more frequent maintenance to 

address problems related to special 

situations, such as atypical engine 

operation. You must clearly state that 

this additional maintenance is 

associated with the special situation you 

are addressing. We may disapprove your 

maintenance instructions if we 

determine that you have specified 

special maintenance steps to address 

engine operation that is not atypical, or 

that the maintenance is unlikely to 

occur in use. If we determine that 

certain maintenance items do not 

qualify as special maintenance under 

this paragraph (c), you may identify this 

as recommended additional 

maintenance under paragraph (b) of this 

section. 

* * * * * 


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■ 245. Section 1051.135 is amended by 

revising paragraph (c)(12) to read as 

follows: 

§ 1051.135 How must I label and identify 

the vehicles I produce? 

* * * * * 

(c) * * * 

(12) State: ‘‘THIS VEHICLE MEETS 

U.S. EPA REGULATIONS FOR [MODEL 

YEAR] [SNOWMOBILES or OFF–ROAD 

MOTORCYCLES or ATVs or OFFROAD 

UTILITY VEHICLES].’’ 

* * * * * 

Subpart C—[Amended] 

■ 246. Section 1051.201 is amended by 

adding paragraph (h) to read as follows: 

§ 1051.201 What are the general 

requirements for obtaining a certificate of 

conformity? 

* * * * * 

(h) For vehicles that become new after 

being placed into service, such as 

vehicles converted to run on a different 

fuel, we may specify alternate 

certification provisions consistent with 

the intent of this part. See § 1051.650 

and the definition of ‘‘new’’ in 

§ 1051.801. 

■ 247. Section 1051.220 is amended by 

revising paragraphs (a) and (c) to read as 

follows: 

§ 1051.220 How do I amend the 

maintenance instructions in my 

application? 

* * * * * 

(a) If you are decreasing or 

eliminating any specified maintenance, 

you may distribute the new 

maintenance instructions to your 

customers 30 days after we receive your 

request, unless we disapprove your 

request. This would generally include 

replacing one maintenance step with 

another. We may approve a shorter time 

or waive this requirement. 

* * * * * 

(c) You need not request approval if 

you are making only minor corrections 

(such as correcting typographical 

mistakes), clarifying your maintenance 

instructions, or changing instructions 

for maintenance unrelated to emission 

control. We may ask you to send us 

copies of maintenance instructions 

revised under this paragraph (c). 

■ 248. Section 1051.230 is amended by 

revising paragraph (b)(7) to read as 

follows: 

§ 1051.230 How do I select engine 

families? 

* * * * * 

(b) * * * 

(7) The number, arrangement (such as 

in-line or vee configuration), and 

approximate bore diameter of cylinders. 

* * * * * 

■ 249. Section 1051.255 is amended by 

revising paragraph (b) to read as follows: 

§ 1051.255 What decisions may EPA make 

regarding my certificate of conformity? 

* * * * * 

(b) We may deny your application for 

certification if we determine that your 

engine family fails to comply with 

emission standards or other 

requirements of this part or the Clean 

Air Act. We will base our decision on 

all available information. If we deny 

your application, we will explain why 

in writing. 

* * * * * 

Subpart I—[Amended] 

■ 250. Section 1051.801 is amended by 

revising paragraph (2) of the definition 

for ‘‘All-terrain vehicle’’ and the 

definition for ‘‘Offroad utility vehicle’’ to 

read as follows: 

§ 1051.801 What definitions apply to this 

part? 

* * * * * 

All-terrain vehicle means * * * 

(2) Other all-terrain vehicles have 

three or more wheels and one or more 

seats, are designed for operation over 

rough terrain, are intended primarily for 

transportation, and have a maximum 

vehicle speed higher than 25 miles per 

hour. Golf carts generally do not meet 

these criteria since they are generally 

not designed for operation over rough 

terrain. 

* * * * * 

Offroad utility vehicle means a 

nonroad vehicle that has four or more 

wheels, seating for two or more persons, 

is designed for operation over rough 

terrain, and has either a rear payload 

capacity of 350 pounds or more or 

seating for six or more passengers. 

Vehicles intended primarily for 

recreational purposes that are not 

capable of transporting six passengers 

(such as dune buggies) are not offroad 

utility vehicles. (Note: § 1051.1(a) 

specifies that some offroad utility 

vehicles are required to meet the 

requirements that apply for all-terrain 

vehicles.) Unless there is significant 

information to the contrary, we consider 

vehicles to be intended primarily for 

recreational purposes if they are 

marketed for recreational use, have a 

rear payload capacity no greater than 

1,000 pounds, and meet at least five of 

the following criteria: 

(1) Front and rear suspension travel is 

greater than 18 cm. 

(2) The vehicle has no tilt bed. 

(3) The vehicle has no mechanical 

power take-off (PTO) and no 

permanently installed hydraulic system 

for operating utility-oriented accessory 

devices. 

(4) The engine has in-use operating 

speeds at or above 4,000 rpm. 

(5) Maximum vehicle speed is greater 

than 35 miles per hour. 

(6) The speed at which the engine 

produces peak power is above 4,500 

rpm and the engine is equivalent to 

engines in ATVs certified by the same 

manufacturer. For the purpose of this 

paragraph (6), the engine is considered 

equivalent if it could be included in the 

same emission family based on the 

characteristics specified in 

§ 1051.230(b). 

(7) Gross Vehicle Weight Rating is no 

greater than 3,750 pounds. This is the 

maximum design loaded weight of the 

vehicle as defined in 40 CFR 86.1803– 

01, including passengers and cargo. 

* * * * * 

PART 1054—CONTROL OF EMISSIONS 

FROM NEW, SMALL NONROAD 

SPARK-IGNITION ENGINES AND 

EQUIPMENT 

■ 251. The authority citation for part 

1054 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 252. Section 1054.1 is amended by 

revising paragraph (a)(4) to read as 

follows: 

§ 1054.1 Does this part apply for my 

engines and equipment? 

(a) * * * 

(4) This part 1054 applies for other 

spark-ignition engines as follows: 

(i) The provisions of §§ 1054.620 and 

1054.801 apply for new engines used 

solely for competition beginning 

January 1, 2010. 

(ii) The provisions of §§ 1054.660 and 

1054.801 apply for new engines used in 

emergency rescue equipment beginning 

January 1, 2010. 

* * * * * 

Subpart B—[Amended] 

■ 253. Section 1054.125 is amended by 

adding paragraph (a)(4) and revising 

paragraph (c) to read as follows: 

§ 1054.125 What maintenance instructions 

must I give to buyers? 

* * * * * 

(a) * * * 

(4) You may ask us to approve a 

maintenance interval shorter than that 

specified in paragraph (a)(3) of this 


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section. In your request you must 

describe the proposed maintenance 

step, recommend the maximum feasible 

interval for this maintenance, include 

your rationale with supporting evidence 

to support the need for the maintenance 

at the recommended interval, and 

demonstrate that the maintenance will 

be done at the recommended interval on 

in-use engines. In considering your 

request, we will evaluate the 

information you provide and any other 

available information to establish 

alternate specifications for maintenance 

intervals, if appropriate. 

* * * * * 

(c) Special maintenance. You may 

specify more frequent maintenance to 

address problems related to special 

situations, such as atypical engine 

operation. You must clearly state that 

this additional maintenance is 

associated with the special situation you 

are addressing. We may disapprove your 

maintenance instructions if we 

determine that you have specified 

special maintenance steps to address 

engine operation that is not atypical, or 

that the maintenance is unlikely to 

occur in use. If we determine that 

certain maintenance items do not 

qualify as special maintenance under 

this paragraph (c), you may identify this 

as recommended additional 

maintenance under paragraph (b) of this 

section. 

* * * * * 

■ 254. Section 1054.145 is amended by 

adding paragraph (o) to read as follows: 

§ 1054.145 Are there interim provisions 

that apply only for a limited time? 

* * * * * 

(o) Interim bonding provisions. 

Through 2012, the maximum value of 

the bond under § 1054.690 is $10 

million. This maximum value applies 

without adjustment for inflation. 

Subpart C—[Amended] 

■ 255. Section 1054.201 is amended by 

adding paragraph (h) to read as follows: 

§ 1054.201 What are the general 

requirements for obtaining a certificate of 

conformity? 

* * * * * 

(h) For engines that become new after 

being placed into service, such as 

engines converted to run on a different 

fuel, we may specify alternate 

certification provisions consistent with 

the intent of this part. See § 1054.645 

and the definition of ‘‘new nonroad 

engine’’ in § 1054.801. 

■ 256. Section 1054.205 is amended by 

revising paragraph (b) to read as follows: 

§ 1054.205 What must I include in my 

application? 

* * * * * 

(b) Explain how the emission control 

systems operate. Describe the 

evaporative emission controls and show 

how your design will prevent running 

loss emissions, if applicable. Also 

describe in detail all system 

components for controlling exhaust 

emissions, including all auxiliary 

emission control devices (AECDs) and 

all fuel-system components you will 

install on any production or test engine. 

Identify the part number of each 

component you describe. For this 

paragraph (b), treat as separate AECDs 

any devices that modulate or activate 

differently from each other. Include 

sufficient detail to allow us to evaluate 

whether the AECDs are consistent with 

the defeat device prohibition of 

§ 1054.115. For example, if your engines 

will routinely experience in-use 

operation that differs from the specified 

duty cycle for certification, describe 

how the fuel-metering system responds 

to varying speeds and loads not 

represented by the duty cycle. If you test 

an emission-data engine by disabling 

the governor for full-load operation such 

that the engine operates at an air-fuel 

ratio significantly different than under 

full-load operation with an installed 

governor, explain why these differences 

are necessary or appropriate. For 

conventional carbureted engines 

without electronic fuel controls, it is 

sufficient to state that there is no 

significant difference in air-fuel ratios. 

* * * * * 

■ 257. Section 1054.220 is amended by 

revising paragraph (a) to read as follows: 

§ 1054.220 How do I amend the 

maintenance instructions in my 

application? 

* * * * * 

(a) If you are decreasing or 

eliminating any specified maintenance, 

you may distribute the new 

maintenance instructions to your 

customers 30 days after we receive your 

request, unless we disapprove your 

request. This would generally include 

replacing one maintenance step with 

another. We may approve a shorter time 

or waive this requirement. 

* * * * * 

■ 258. Section 1054.230 is amended by 

revising paragraph (b)(6) to read as 

follows: 

§ 1054.230 How do I select emission 

families? 

* * * * * 

(b) * * * 

(6) The number and arrangement of 

cylinders (such as in-line or vee 

configuration) and approximate total 

displacement. 

* * * * * 

Subpart G—[Amended] 

■ 259. Section 1054.601 is amended by 

revising the section heading and adding 

paragraph (c) to read as follows: 

§ 1054.601 What compliance provisions 

apply? 

* * * * * 

(c) The provisions of 40 CFR 1068.215 

apply for cases in which the 

manufacturer takes possession of 

engines for purposes of recovering 

components as described in this 

paragraph (c). Note that this paragraph 

(c) does not apply for certified engines 

that still have the emission control 

information label since such engines do 

not need an exemption. 

(1) You must label the engine as 

specified in 40 CFR 1068.215(c)(3), 

except that the label may be removable 

as specified in 40 CFR 1068.45(b). 

(2) You may not resell the engine. For 

components other than the engine 

block, you may generate revenue from 

the sale of the components that you 

recover, or from the sale of new engines 

containing these components. You may 

also use components other than the 

engine block for engine rebuilds as 

otherwise allowed under the 

regulations. You may use the engine 

block from an engine that is exempted 

under this paragraph (c) only to make a 

new engine, and then only where such 

an engine has a separate identity from 

the original engine. 

(3) Once the engine has reached its 

final destination, you may stop 

collecting records describing the 

engine’s final disposition and how you 

use the engine. This does not affect the 

requirement to maintain the records you 

have already collected under 40 CFR 

1068.215. This also does not affect the 

requirement to maintain records for new 

engines. 

■ 260. Section 1054.690 is amended by 

revising paragraphs (d), (f), and (j) to 

read as follows: 

§ 1054.690 What bond requirements apply 

for certified engines? 

* * * * * 

(d) The minimum value of the bond 

is $500,000. A higher bond value may 

apply based on the per-engine bond 

values shown in Table 1 to this section 

and on the U.S.-directed production 

volume from each displacement 

grouping for the calendar model year. 

For example, if you have projected U.S.- 

directed production volumes of 10,000 

engines with 180 cc displacement and 


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23026 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

10,000 engines with 400 cc 

displacement in 2013, the appropriate 

bond amount is $750,000. Adjust the 

value of the bond as follows: 

(1) If your estimated or actual U.S.- 

directed production volume in any later 

year increases beyond the level 

appropriate for your current bond 

payment, you must post additional bond 

to reflect the increased volume within 

90 days after you change your estimate 

or determine the actual production 

volume. You may not decrease your 

bond. 

(2) If you sell engines without 

aftertreatment components under the 

provisions of § 1054.610, you must 

increase the per-engine bond values for 

the current year by 20 percent. 

TABLE 1 TO § 1054.690—PER-ENGINE

BOND VALUES

For engines with displacement falling in the following 

ranges . . . 

The per-engine 

bond value 

is . . . 

Disp. < 225 cc .................... $25 

225 ≤ Disp. < 740 cc .......... 50 

740 ≤ Disp. ≤ 1,000 cc ....... 100 

Disp. > 1,000 cc ................. 200 

* * * * * 

(f) You may meet the bond 

requirements of this section by 

obtaining a bond from a third-party 

surety that is cited in the U.S. 

Department of Treasury Circular 570, 

‘‘Companies Holding Certificates of 

Authority as Acceptable Sureties on 

Federal Bonds and as Acceptable 

Reinsuring Companies’’ (http:// 

www.fms.treas.gov/c570/ 

c570.html#certified). You must maintain 

this bond for every year in which you 

sell certified engines. The surety agent 

remains responsible for obligations 

under the bond for two years after the 

bond is cancelled or expires without 

being replaced. 

* * * * * 

(j) The following provisions apply if 

you import engines for resale when 

those engines have been certified by 

someone else (or equipment containing 

such engines): 

(1) You and the certificate holder are 

each responsible for compliance with 

the requirements of this part and the 

Clean Air Act. For example, we may 

require you to comply with the warranty 

requirements in § 1054.120. 

(2) You do not need to post bond if 

you or the certificate holder complies 

with the bond requirements of this 

section. You also do not need to post 

bond if the certificate holder complies 

with the asset requirements of this 

section and the repair-network 

provisions of § 1054.120(f)(4). 

Subpart H—[Amended] 

■ 261. Section 1054.730 is amended by 

revising paragraph (b)(4) to read as 

follows: 

§ 1054.730 What ABT reports must I send 

to EPA? 

* * * * * 

(b) * * * 

(4) The projected and actual U.S.- 

directed production volumes for the 

model year, as described in 

§ 1054.701(i). For fuel tanks, state the 

production volume in terms of surface 

area and production volume for each 

fuel tank configuration and state the 

total surface area for the emission 

family. If you changed an FEL during 

the model year, identify the actual 

production volume associated with each 

FEL. 

* * * * * 

Subpart I—[Amended] 

■ 262. Section 1054.801 is amended by 

revising the definitions for ‘‘Oxides of 

nitrogen’’, ‘‘Total hydrocarbon’’, and 

‘‘Total hydrocarbon equivalent’’ to read 

as follows: 

§ 1054.801 What definitions apply to this 

part? 

* * * * * 

Oxides of nitrogen has the meaning 

given in 40 CFR 1065.1001. 

* * * * * 

* * * * * 

Total hydrocarbon has the meaning 

given in 40 CFR 1065.1001. This 

generally means the combined mass of 

organic compounds measured by the 

specified procedure for measuring total 

hydrocarbon, expressed as an atomic 

hydrocarbon with a hydrogen-to-carbon 

ratio of 1.85:1. 

Total hydrocarbon equivalent has the 

meaning given in 40 CFR 1065.1001. 

This generally means the sum of the 

carbon mass contributions of nonoxygenated hydrocarbons, alcohols and 

aldehydes, or other organic compounds 

that are measured separately as 

contained in a gas sample, expressed as 

exhaust hydrocarbon from petroleumfueled engines. The atomic hydrogen-tocarbon ratio of the equivalent 

hydrocarbon is 1.85:1. 

* * * * * 

PART 1060—CONTROL OF 

EVAPORATIVE EMISSIONS FROM 

NEW AND IN-USE NONROAD AND 

STATIONARY EQUIPMENT 

■ 263. The authority citation for part 

1060 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart B—[Amended] 

■ 264. Section 1060.103 is amended by 

revising paragraph (e) to read as follows: 

§ 1060.103 What permeation emission 

control requirements apply for fuel tanks? 

* * * * * 

(e) Fuel caps may be certified 

separately relative to the permeation 

emission standard in paragraph (b) of 

this section using the test procedures 

specified in § 1060.521. Fuel caps 

certified alone do not need to meet the 

emission standard. Rather, fuel caps 

would be certified with a Family 

Emission Limit, which is used for 

demonstrating that fuel tanks meet the 

emission standard as described in 

§ 1060.520(b)(5). For the purposes of 

this paragraph (e), gaskets or O-rings 

that are produced as part of an assembly 

with the fuel cap are considered part of 

the fuel cap. 

* * * * * 

■ 265. Section 1060.135 is amended by 

revising paragraph (a)(5) to read as 

follows: 

§ 1060.135 How must I label and identify 

the engines and equipment I produce? 

* * * * * 

(a) * * * 

(5) Readily visible in the final 

installation. It may be under a hinged 

door or other readily opened cover. It 

may not be hidden by any cover 

attached with screws or any similar 

designs. Labels on marine vessels 

(except personal watercraft) must be 

visible from the helm. 

* * * * * 

■ 266. Section 1060.137 is amended by 

revising paragraphs (a) introductory text 

and (a)(4) to read as follows: 

§ 1060.137 How must I label and identify 

the fuel-system components I produce? 

* * * * * 

(a) Label the components identified in 

this paragraph (a), unless the 

components are too small to be properly 

labeled. Unless we approve otherwise, 

we consider parts large enough to be 

properly labeled if they have space for 

12 characters in six-point font 

(approximately 2 mm × 12 mm). For 

these small parts, you may omit the 

label as long as you identify those part 

numbers in your maintenance and 

installation instructions. 

* * * * * 

(4) Fuel caps, as described in this 

paragraph (a)(4). Fuel caps must be 

labeled if they are separately certified 

under § 1060.103 or if the diurnal 

control system requires that the fuel 

tank hold pressure. Fuel caps must also 

be labeled if they are mounted directly 


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on the fuel tank, unless the fuel tank is 

certified based on a worst-case fuel cap. 

* * * * * 

Subpart F—[Amended] 

■ 267. Section 1060.515 is amended by 

revising paragraph (c) to read as follows: 

§ 1060.515 How do I test EPA Nonroad 

Fuel Lines and EPA Cold-Weather Fuel 

Lines for permeation emissions? 

* * * * * 

(c) Measure fuel line permeation 

emissions using the equipment and 

procedures for weight-loss testing 

specified in SAE J30 or SAE J1527 

(incorporated by reference in 

§ 1060.810). Start the measurement 

procedure within 8 hours after draining 

and refilling the fuel line. Perform the 

emission test over a sampling period of 

14 days. Determine your final emission 

result based on the highest measured 

valued over the 14-day period. 

* * * * * 

■ 268. Section 1060.520 is amended as 

follows: 

■ a. By adding paragraph (a)(4). 

■ b. By removing and reserving 

paragraph (b)(3). 

■ c. By revising paragraphs (b)(5)(ii)(B), 

(d)(8), (d)(9), and (d)(10). 

§ 1060.520 How do I test fuel tanks for 

permeation emissions? 

* * * * * 

(a) * * * 

(4) Cap testing. Perform durability 

cycles on fuel caps intended for use 

with handheld equipment by putting 

the fuel cap on and taking it off 300 

times. Tighten the fuel cap each time in 

a way that represents the typical in-use 

experience. 

(b) * * * 

(5) * * * 

(ii) * * * 

(B) You may seal the fuel inlet with 

a nonpermeable covering if you 

separately account for permeation 

emissions from the fuel cap. This may 

involve a separate measurement of 

permeation emissions from a worst-case 

fuel cap as described in § 1060.521. This 

may also involve specifying a worst-case 

Family Emission Limit based on 

separately certified fuel caps as 

described in § 1060.103(e). 

* * * * * 

(d) * * * 

(8) Measure weight loss daily by 

retaring the balance using the reference 

tank and weighing the sealed test tank. 

Calculate the cumulative weight loss in 

grams for each measurement. Calculate 

the coefficient of determination, r2, 

based on a linear plot of cumulative 

weight loss vs. test days. Use the 

equation in 40 CFR 1065.602(k), with 

cumulative weight loss represented by 

yi and cumulative time represented by 

yref. The daily measurements must be at 

approximately the same time each day. 

You may omit up to two daily 

measurements in any seven-day period. 

Test for ten full days, then determine 

when to stop testing as follows: 

(i) You may stop testing after the 

measurement on the tenth day if r2 is at 

or above 0.95 or if the measured value 

is less than 50 percent of the applicable 

standard. (Note that if a Family 

Emission Limit applies for the family, it 

is considered to be the applicable 

standard for that family.) This means 

that if you stop testing with an r2 below 

0.95, you may not use the data to show 

compliance with a Family Emission 

Limit less than twice the measured 

value. 

(ii) If after ten days of testing your r2

value is below 0.95 and your measured 

value is more than 50 percent of the 

applicable standard, continue testing for 

a total of 20 days or until r2 is at or 

above 0.95. If r2 is not at or above 0.95 

within 20 days of testing, discontinue 

the test and precondition the fuel tank 

further until it has stabilized emission 

levels, then repeat the testing. 

(9) Record the difference in mass 

between the reference tank and the test 

tank for each measurement. This value 

is Mi, where i is a counter representing 

the number of days elapsed. Subtract Mi

from Mo and divide the difference by 

the internal surface area of the fuel tank. 

Divide this g/m2 value by the number of 

test days (using at least two decimal 

places) to calculate the emission rate in 

g/m2/day. Example: If a tank with an 

internal surface area of 0.720 m2

weighed 1.31 grams less than the 

reference tank at the beginning of the 

test and weighed 9.86 grams less than 

the reference tank after soaking for 10.03 

days, the emission rate would be— 

((¥1.31 g) ¥ (¥9.82 g))/0.720 m2/10.03 

days = 1.1784 g/m2/day 

(10) Determine your final emission 

result based on the cumulative weight 

loss measured on the final day of 

testing. Round this result to the same 

number of decimal places as the 

emission standard. 

* * * * * 

Subpart G—[Amended] 

■ 269. Section 1060.601 is amended by 

adding paragraph (h) to read as follows: 

§ 1060.601 How do the prohibitions of 40 

CFR 1068.101 apply with respect to the 

requirements of this part? 

* * * * * 

(h) If equipment manufacturers hold 

certificates of conformity for their 

equipment but they use only fuelsystem components that have been 

certified by other companies, they may 

satisfy their defect-reporting obligations 

by tracking the information described in 

40 CFR 1068.501(b)(1) related to 

possible defects, reporting this 

information to the appropriate 

component manufacturers, and keeping 

these records for eight years. Such 

equipment manufacturers will not be 

considered in violation of 40 CFR 

1068.101(b)(6) for failing to perform 

investigations, make calculations, or 

submit reports to EPA as specified in 40 

CFR 1068.501. See § 1060.5(a). 

Subpart I—[Amended] 

■ 270. Section 1060.801 is amended by 

revising the definitions for ‘‘Detachable 

fuel line’’, ‘‘Installed marine fuel tank’’, 

and ‘‘Sealed’’ and adding definitions for 

‘‘Installed marine fuel line’’ and 

‘‘Portable marine fuel line’’ to read as 

follows: 

§ 1060.801 What definitions apply to this 

part? 

* * * * * 

Detachable fuel line means a fuel line 

or fuel line assembly intended to be 

used with a portable nonroad fuel tank 

and which is connected by special 

fittings to the fuel tank and/or engine for 

easy disassembly. Fuel lines that require 

a wrench or other tools to disconnect 

are not considered detachable fuel lines. 

Fuel lines that are labeled or marketed 

as USCG Type B1 fuel line as specified 

in 33 CFR 183.540 are not considered 

detachable fuel lines if they are sold to 

the ultimate purchaser without quickconnect fittings or similar hardware. 

* * * * * 

Installed marine fuel line means a fuel 

line designed for delivering fuel to a 

Marine SI engine that does not meet the 

definition of portable marine fuel line. 

Installed marine fuel tank means a 

fuel tank designed for delivering fuel to 

a Marine SI engine that does not meet 

the definition of portable marine fuel 

tanks. 

* * * * * 

Portable marine fuel line means a 

detachable fuel line that is used or 

intended to be used to supply fuel to a 

marine engine during operation. This 

also includes any fuel line labeled or 

marketed at USCG Type B1 fuel line as 

specified in 33 CFR 183.540, whether or 

not it includes detachable connecting 

hardware; this is often called universal 

fuel line. 

* * * * * 


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Sealed means lacking openings to the 

atmosphere that would allow a 

measurable amount of liquid or vapor to 

leak out under normal operating 

pressures or other pressures specified in 

this part. For example, you may 

generally establish a maximum value for 

operating pressures based on the highest 

pressure you would observe from an 

installed fuel tank during continuous 

equipment operation on a sunny day 

with ambient temperatures of 35 °C. A 

fuel system may be considered to have 

no measurable leak if it does not release 

bubbles when held underwater at the 

identified tank pressure for 60 seconds. 

This determination presumes the use of 

good engineering judgment; for 

example, it would not be appropriate to 

test the fuel tank such that small leaks 

would avoid detection by collecting in 

a cavity created by holding the tank 

with a certain orientation. Sealed fuel 

systems may have openings for emission 

controls or for fuel lines needed to route 

fuel to the engine. 

* * * * * 

PART 1065—ENGINE-TESTING 

PROCEDURES 

■ 271. The authority citation for part 

1065 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 272. Section 1065.1 is amended by 

revising paragraphs (d) and (g) to read 

as follows: 

§ 1065.1 Applicability. 

* * * * * 

(d) Paragraph (a) of this section 

identifies the parts of the CFR that 

define emission standards and other 

requirements for particular types of 

engines. In this part, we refer to each of 

these other parts generically as the 

’’standard-setting part.’’ For example, 40 

CFR part 1051 is always the standardsetting part for snowmobiles. Note that 

while 40 CFR part 86 is the standardsetting part for heavy-duty highway 

engines, this refers specifically to 40 

CFR part 86, subpart A, and to certain 

portions of 40 CFR part 86, subpart N, 

as described in 40 CFR 86.1301. 

* * * * * 

(g) For additional information 

regarding these test procedures, visit our 

Web site at http://www.epa.gov, and in 

particular http://www.epa.gov/nvfel/ 

testing/regulations.htm. 

■ 273. Section 1065.2 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 1065.2 Submitting information to EPA 

under this part. 

(a) You are responsible for statements 

and information in your applications for 

certification, requests for approved 

procedures, selective enforcement 

audits, laboratory audits, productionline test reports, field test reports, or any 

other statements you make to us related 

to this part 1065. If you provide 

statements or information to someone 

for submission to EPA, you are 

responsible for these statements and 

information as if you had submitted 

them to EPA yourself. 

(b) In the standard-setting part and in 

40 CFR 1068.101, we describe your 

obligation to report truthful and 

complete information and the 

consequences of failing to meet this 

obligation. See also 18 U.S.C. 1001 and 

42 U.S.C. 7413(c)(2). This obligation 

applies whether you submit this 

information directly to EPA or through 

someone else. 

* * * * * 

■ 274. Section 1065.10 is amended by 

revising paragraphs (c)(2) and (c)(7) 

introductory text to read as follows: 

§ 1065.10 Other procedures. 

* * * * * 

(c) * * * 

(2) You may request to use special 

procedures if your engine cannot be 

tested using the specified procedures. 

For example, this may apply if your 

engine cannot operate on the specified 

duty cycle. In this case, tell us in 

writing why you cannot satisfactorily 

test your engine using this part’s 

procedures and ask to use a different 

approach. We will approve your request 

if we determine that it would produce 

emission measurements that represent 

in-use operation and we determine that 

it can be used to show compliance with 

the requirements of the standard-setting 

part. Where we approve special 

procedures that differ substantially from 

the specified procedures, we may 

preclude you from participating in 

averaging, banking, and trading with the 

affected engine families. 

* * * * * 

(7) You may request to use alternate 

procedures that are equivalent to the 

allowed procedures, or procedures that 

are more accurate or more precise than 

the allowed procedures. The following 

provisions apply to requests for 

alternate procedures: 

* * * * * 

■ 275. Section 1065.15 is amended by 

revising paragraph (c) to read as follows: 

§ 1065.15 Overview of procedures for 

laboratory and field testing. 

* * * * * 

(c) We generally set brake-specific 

emission standards over test intervals 

and/or duty cycles, as follows: 

(1) Engine operation. Testing may 

involve measuring emissions and work 

in a laboratory-type environment or in 

the field, as described in paragraph (f) 

of this section. For most laboratory 

testing, the engine is operated over one 

or more duty cycles specified in the 

standard-setting part. However, 

laboratory testing may also include nonduty cycle testing (such as simulation of 

field testing in a laboratory). For field 

testing, the engine is operated under 

normal in-use operation. The standardsetting part specifies how test intervals 

are defined for field testing. Refer to the 

definitions of ‘‘duty cycle’’ and ‘‘test 

interval’’ in § 1065.1001. Note that a 

single duty cycle may have multiple test 

intervals and require weighting of 

results from multiple test intervals to 

calculate a composite brake-specific 

emissions value to compare to the 

standard. 

(2) Constituent determination. 

Determine the total mass of each 

constituent over a test interval by 

selecting from the following methods: 

(i) Continuous sampling. In 

continuous sampling, measure the 

constituent’s concentration 

continuously from raw or dilute 

exhaust. Multiply this concentration by 

the continuous (raw or dilute) flow rate 

at the emission sampling location to 

determine the constituent’s flow rate. 

Sum the constituent’s flow rate 

continuously over the test interval. This 

sum is the total mass of the emitted 

constituent. 

(ii) Batch sampling. In batch 

sampling, continuously extract and 

store a sample of raw or dilute exhaust 

for later measurement. Extract a sample 

proportional to the raw or dilute 

exhaust flow rate. You may extract and 

store a proportional sample of exhaust 

in an appropriate container, such as a 

bag, and then measure HC, CO, and NOX

concentrations in the container after the 

test interval. You may deposit PM from 

proportionally extracted exhaust onto 

an appropriate substrate, such as a filter. 

In this case, divide the PM by the 

amount of filtered exhaust to calculate 

the PM concentration. Multiply batch 

sampled concentrations by the total 

(raw or dilute) flow from which it was 

extracted during the test interval. This 

product is the total mass of the emitted 

constituent. 

(iii) Combined sampling. You may use 

continuous and batch sampling 


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simultaneously during a test interval, as 

follows: 

(A) You may use continuous sampling 

for some constituents and batch 

sampling for others. 

(B) You may use continuous and 

batch sampling for a single constituent, 

with one being a redundant 

measurement. See § 1065.201 for more 

information on redundant 

measurements. 

(3) Work determination. Determine 

work over a test interval by one of the 

following methods: 

(i) Speed and torque. Synchronously 

multiply speed and brake torque to 

calculate instantaneous values for 

engine brake power. Sum engine brake 

power over a test interval to determine 

total work. 

(ii) Fuel consumed and brake-specific 

fuel consumption. Directly measure fuel 

consumed or calculate it with chemical 

balances of the fuel, intake air, and 

exhaust. To calculate fuel consumed by 

a chemical balance, you must also 

measure either intake-air flow rate or 

exhaust flow rate. Divide the fuel 

consumed during a test interval by the 

brake-specific fuel consumption to 

determine work over the test interval. 

For laboratory testing, calculate the 

brake-specific fuel consumption using 

fuel consumed and speed and torque 

over a test interval. For field testing, 

refer to the standard-setting part and 

§ 1065.915 for selecting an appropriate 

value for brake-specific fuel 

consumption. 

* * * * * 

Subpart B—[Amended] 

■ 276. Section 1065.125 is amended by 

revising paragraphs (c) and (e) to read as 

follows: 

§ 1065.125 Engine intake air. 

* * * * * 

(c) Maintain the temperature of intake 

air to (25 ± 5) °C, except as follows: 

(1) Follow the standard-setting part if 

it specifies different temperatures. 

(2) For engines above 560 kW, you 

may use 35 °C as the upper bound of the 

tolerance. However, your system must 

be capable of controlling the 

temperature to the 25 °C setpoint for any 

steady-state operation at > 30% of 

maximum engine power. 

(3) You may ask us to allow you to 

apply a different setpoint for intake air 

temperature if it is necessary to remain 

consistent with the provisions of 

§ 1065.10(c)(1) for testing during which 

ambient temperature will be outside this 

range. 

* * * * * 

(e) This paragraph (e) includes 

provisions for simulating charge-air 

cooling in the laboratory. This approach 

is described in paragraph (e)(1) of this 

section. Limits on using this approach 

are described in paragraphs (e)(2) and 

(3) of this section. 

(1) Use a charge-air cooling system 

with a total intake-air capacity that 

represents production engines’ in-use 

installation. Design any laboratory 

charge-air cooling system to minimize 

accumulation of condensate. Drain any 

accumulated condensate and 

completely close all drains before 

starting a duty cycle. Keep the drains 

closed during the emission test. 

Maintain coolant conditions as follows: 

(i) Maintain a coolant temperature of 

at least 20 °C at the inlet to the chargeair cooler throughout testing. We 

recommend maintaining a coolant 

temperature of 25 ±5 °C at the inlet of 

the charge-air cooler. 

(ii) At the engine conditions specified 

by the manufacturer, set the coolant 

flow rate to achieve an air temperature 

within ±5 °C of the value specified by 

the manufacturer after the charge-air 

cooler’s outlet. Measure the air-outlet 

temperature at the location specified by 

the manufacturer. Use this coolant flow 

rate set point throughout testing. If the 

engine manufacturer does not specify 

engine conditions or the corresponding 

charge-air cooler air outlet temperature, 

set the coolant flow rate at maximum 

engine power to achieve a charge-air 

cooler air outlet temperature that 

represents in-use operation. 

(iii) If the engine manufacturer 

specifies pressure-drop limits across the 

charge-air cooling system, ensure that 

the pressure drop across the charge-air 

cooling system at engine conditions 

specified by the manufacturer is within 

the manufacturer’s specified limit(s). 

Measure the pressure drop at the 

manufacturer’s specified locations. 

(2) Using a constant flow rate as 

described in paragraph (e)(1) of this 

section may result in unrepresentative 

overcooling of the intake air. The 

provisions of this paragraph (e)(2) apply 

instead of the provisions of 

§ 1065.10(c)(1) for this simulation. Our 

allowance to cool intake air as specified 

in this paragraph (e) does not affect your 

liability for field testing or for laboratory 

testing that is done in a way that better 

represents in-use operation. Where we 

determine that this allowance adversely 

affects your ability to demonstrate that 

your engines would comply with 

emission standards under in-use 

conditions, we may require you to use 

more sophisticated setpoints and 

controls of charge-air pressure drop, 

coolant temperature, and flow rate to 

achieve more representative results. 

(3) This approach does not apply for 

field testing. You may not correct 

measured emission levels from field 

testing to account for any differences 

caused by the simulated cooling in the 

laboratory. 

■ 277. Section 1065.140 is revised 

amended by revising paragraphs (c)(6), 

(e) introductory text, and (e)(4) to read 

as follows: 

§ 1065.140 Dilution for gaseous and PM 

constituents. 

* * * * * 

(c) * * * 

(6) Aqueous condensation. This 

paragraph (c)(6) describes how you must 

address aqueous condensation in the 

CVS. As described below, you may meet 

these requirements by preventing or 

limiting aqueous condensation in the 

CVS from the exhaust inlet to the last 

emission sample probe. See that 

paragraph for provisions related to the 

CVS between the last emission sample 

probe and the CVS flow meter. You may 

heat and/or insulate the dilution tunnel 

walls, as well as the bulk stream tubing 

downstream of the tunnel to prevent or 

limit aqueous condensation. Where we 

allow aqueous condensation to occur, 

use good engineering judgment to 

ensure that the condensation does not 

affect your ability to demonstrate that 

your engines comply with the 

applicable standards (see § 1065.10(a)). 

(i) Preventing aqueous condensation. 

To prevent condensation, you must 

keep the temperature of internal 

surfaces, excluding any sample probes, 

above the dew point of the dilute 

exhaust passing through the CVS 

tunnel. Use good engineering judgment 

to monitor temperatures in the CVS. For 

the purposes of this paragraph (c)(6), 

assume that aqueous condensation is 

pure water condensate only, even 

though the definition of ‘‘aqueous 

condensation’’ in § 1065.1001 includes 

condensation of any constituents that 

contain water. No specific verification 

check is required under this paragraph 

(c)(6)(i), but we may ask you to show 

how you comply with this requirement. 

You may use engineering analysis, CVS 

tunnel design, alarm systems, 

measurements of wall temperatures, and 

calculation of water dew point to 

demonstrate compliance with this 

requirement. For optional CVS heat 

exchangers, you may use the lowest 

water temperature at the inlet(s) and 

outlet(s) to determine the minimum 

internal surface temperature. 

(ii) Limiting aqueous condensation. 

This paragraph (c)(6)(ii) specifies limits 

of allowable condensation and requires 


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you to verify that the amount of 

condensation that occurs during each 

test interval does not exceed the 

specified limits. 

(A) Use chemical balance equations in 

§ 1065.655 to calculate the mole fraction 

of water in the dilute exhaust 

continuously during testing. 

Alternatively, you may continuously 

measure the mole fraction of water in 

the dilute exhaust prior to any 

condensation during testing. Use good 

engineering judgment to select, calibrate 

and verify water analyzers/detectors. 

The linearity verification requirements 

of § 1065.307 do not apply to water 

analyzers/detectors used to correct for 

the water content in exhaust samples. 

(B) Use good engineering judgment to 

select and monitor locations on the CVS 

tunnel walls prior to the last emission 

sample probe. If you are also verifying 

limited condensation from the last 

emission sample probe to the CVS flow 

meter, use good engineering judgment to 

select and monitor locations on the CVS 

tunnel walls, optional CVS heat 

exchanger, and CVS flow meter. For 

optional CVS heat exchangers, you may 

use the lowest water temperature at the 

inlet(s) and outlet(s) to determine the 

minimum internal surface temperature. 

Identify the minimum surface 

temperature on a continuous basis. 

(C) Identify the maximum potential 

mole fraction of dilute exhaust lost on 

a continuous basis during the entire test 

interval. This value must be less than or 

equal to 0.02 (i.e. 2%). Calculate on a 

continuous basis the mole fraction of 

water that would be in equilibrium with 

liquid water at the measured minimum 

surface temperature. Subtract this mole 

fraction from the mole fraction of water 

that would be in the exhaust without 

condensation (either measured or from 

the chemical balance), and set any 

negative values to zero. This difference 

is the potential mole fraction of the 

dilute exhaust that would be lost due to 

water condensation on a continuous 

basis. 

(D) Integrate the product of the molar 

flow rate of the dilute exhaust and the 

potential mole fraction of dilute exhaust 

lost, and divide by the totalized dilute 

exhaust molar flow over the test 

interval. This is the potential mole 

fraction of the dilute exhaust that would 

be lost due to water condensation over 

the entire test interval. Note that this 

assumes no re-evaporation. This value 

must be less than or equal to 0.005 (i.e. 

0.5%). 

* * * * * 

(e) Dilution air temperature, dilution 

ratio, residence time, and temperature 

control of PM samples. Dilute PM 

samples at least once upstream of 

transfer lines. You may dilute PM 

samples upstream of a transfer line 

using full-flow dilution, or partial-flow 

dilution immediately downstream of a 

PM probe. In the case of partial-flow 

dilution, you may have up to 26 cm of 

insulated length between the end of the 

probe and the dilution stage, but we 

recommend that the length be as short 

as practical. The intent of these 

specifications is to minimize heat 

transfer to or from the emission sample 

before the final stage of dilution, other 

than the heat you may need to add to 

prevent aqueous condensation. This is 

accomplished by initially cooling the 

sample through dilution. Configure 

dilution systems as follows: 

* * * * * 

(4) Control sample temperature to a 

(47 ±5) °C tolerance, as measured 

anywhere within 20 cm upstream or 

downstream of the PM storage media 

(such as a filter). Measure this 

temperature with a bare-wire junction 

thermocouple with wires that are (0.500 

±0.025) mm diameter, or with another 

suitable instrument that has equivalent 

performance. 

■ 278. Section 1065.145 is revised to 

read as follows: 

§ 1065.145 Gaseous and PM probes, 

transfer lines, and sampling system 

components. 

(a) Continuous and batch sampling. 

Determine the total mass of each 

constituent with continuous or batch 

sampling, as described in 

§ 1065.15(c)(2). Both types of sampling 

systems have probes, transfer lines, and 

other sampling system components that 

are described in this section. 

(b) Options for engines with multiple 

exhaust stacks. Measure emissions from 

a test engine as described in this 

paragraph (b) if it has multiple exhaust 

stacks. You may choose to use different 

measurement procedures for different 

pollutants under this paragraph (b) for 

a given test. For purposes of this part 

1065, the test engine includes all the 

devices related to converting the 

chemical energy in the fuel to the 

engine’s mechanical output energy. This 

may or may not involve vehicle- or 

equipment-based devices. For example, 

all of an engine’s cylinders are 

considered to be part of the test engine 

even if the exhaust is divided into 

separate exhaust stacks. As another 

example, all the cylinders of a dieselelectric locomotive are considered to be 

part of the test engine even if they 

transmit power through separate output 

shafts, such as might occur with 

multiple engine-generator sets working 

in tandem. Use one of the following 

procedures to measure emissions with 

multiple exhaust stacks: 

(1) Route the exhaust flow from the 

multiple stacks into a single flow as 

described in § 1065.130(c)(6). Sample 

and measure emissions after the exhaust 

streams are mixed. Calculate the 

emissions as a single sample from the 

entire engine. We recommend this as 

the preferred option, since it requires 

only a single measurement and 

calculation of the exhaust molar flow for 

the entire engine. 

(2) Sample and measure emissions 

from each stack and calculate emissions 

separately for each stack. Add the mass 

(or mass rate) emissions from each stack 

to calculate the emissions from the 

entire engine. Testing under this 

paragraph (b)(2) requires measuring or 

calculating the exhaust molar flow for 

each stack separately. If the exhaust 

molar flow in each stack cannot be 

calculated from combustion air flow(s), 

fuel flow(s), and measured gaseous 

emissions, and it is impractical to 

measure the exhaust molar flows 

directly, you may alternatively 

proportion the engine’s calculated total 

exhaust molar flow rate (where the flow 

is calculated using combustion air mass 

flow(s), fuel mass flow(s), and emissions 

concentrations) based on exhaust molar 

flow measurements in each stack using 

a less accurate, non-traceable method. 

For example, you may use a total 

pressure probe and static pressure 

measurement in each stack. 

(3) Sample and measure emissions 

from one stack and repeat the duty cycle 

as needed to collect emissions from 

each stack separately. Calculate the 

emissions from each stack and add the 

separate measurements to calculate the 

mass (or mass rate) emissions from the 

entire engine. Testing under this 

paragraph (b)(3) requires measuring or 

calculating the exhaust molar flow for 

each stack separately. You may 

alternatively proportion the engine’s 

calculated total exhaust molar flow rate 

based on calculation and measurement 

limitations as described in paragraph 

(b)(2) of this section. Use the average of 

the engine’s total power or work values 

from the multiple test runs to calculate 

brake-specific emissions. Divide the 

total mass (or mass rate) of each 

emission by the average power (or 

work). You may alternatively use the 

engine power or work associated with 

the corresponding stack during each test 

run if these values can be determined 

for each stack separately. 

(4) Sample and measure emissions 

from each stack separately and calculate 

emissions for the entire engine based on 

the stack with the highest concentration. 

Testing under this paragraph (b)(4) 


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requires only a single exhaust flow 

measurement or calculation for the 

entire engine. You may determine 

which stack has the highest 

concentration by performing multiple 

test runs, reviewing the results of earlier 

tests, or using good engineering 

judgment. Note that the highest 

concentration of different pollutants 

may occur in different stacks. Note also 

that the stack with the highest 

concentration of a pollutant during a 

test interval for field testing may be a 

different stack than the one you 

identified based on average 

concentrations over a duty cycle. 

(5) Sample emissions from each stack 

separately and combine the wet sample 

streams from each stack proportionally 

to the exhaust molar flows in each stack. 

Measure the emission concentrations 

and calculate the emissions for the 

entire engine based on these weighted 

concentrations. Testing under this 

paragraph (b)(5) requires measuring or 

calculating the exhaust molar flow for 

each stack separately during the test run 

to proportion the sample streams from 

each stack. If it is impractical to 

measure the exhaust molar flows 

directly, you may alternatively 

proportion the wet sample streams 

based on less accurate, non-traceable 

flow methods. For example, you may 

use a total pressure probe and static 

pressure measurement in each stack. 

The following restrictions apply for 

testing under this paragraph (b)(5): 

(i) You must use an accurate, 

traceable measurement or calculation of 

the engine’s total exhaust molar flow 

rate for calculating the mass of 

emissions from the entire engine. 

(ii) You may dry the single, combined, 

proportional sample stream; you may 

not dry the sample streams from each 

stack separately. 

(iii) You must measure and 

proportion the sample flows from each 

stack with active flow controls. For PM 

sampling, you must measure and 

proportion the diluted sample flows 

from each stack with active flow 

controls that use only smooth walls 

with no sudden change in crosssectional area. For example, you may 

control the dilute exhaust PM sample 

flows using electrically conductive 

vinyl tubing and a control device that 

pinches the tube over a long enough 

transition length so no flow separation 

occurs. 

(iv) For PM sampling, the transfer 

lines from each stack must be joined so 

the angle of the joining flows is 12.5° or 

less. Note that the exhaust manifold 

must meet the same specifications as the 

transfer line according to paragraph (d) 

of this section. 

(6) Sample emissions from each stack 

separately and combine the wet sample 

streams from each stack equally. 

Measure the emission concentrations 

and calculate the emissions for the 

entire engine based on these measured 

concentrations. Testing under this 

paragraph (b)(6) assumes that the rawexhaust and sample flows are the same 

for each stack. The following 

restrictions apply for testing under this 

paragraph (b)(6): 

(i) You must measure and 

demonstrate that the sample flow from 

each stack is within 5% of the value 

from the stack with the highest sample 

flow. You may alternatively ensure that 

the stacks have equal flow rates without 

measuring sample flows by designing a 

passive sampling system that meets the 

following requirements: 

(A) The probes and transfer line 

branches must be symmetrical, have 

equal lengths and diameters, have the 

same number of bends, and have no 

filters. 

(B) If probes are designed such that 

they are sensitive to stack velocity, the 

stack velocity must be similar at each 

probe. For example, a static pressure 

probe used for gaseous sampling is not 

sensitive to stack velocity. 

(C) The stack static pressure must be 

the same at each probe. You can meet 

this requirement by placing probes at 

the end of stacks that are vented to 

atmosphere. 

(D) For PM sampling, the transfer 

lines from each stack must be joined so 

the angle of the joining flows is 12.5° or 

less. Note that the exhaust manifold 

must meet the same specifications as the 

transfer line according to paragraph (d) 

of this section. 

(ii) You may use the procedure in this 

paragraph (b)(6) only if you perform an 

analysis showing that the resulting error 

due to imbalanced stack flows and 

concentrations is either at or below 2%. 

You may alternatively show that the 

resulting error does not impact your 

ability to demonstrate compliance with 

applicable standards. For example, you 

may use less accurate, non-traceable 

measurements of emission 

concentrations and molar flow in each 

stack and demonstrate that the 

imbalances in flows and concentrations 

cause 2% or less error. 

(iii) For a two-stack engine, you may 

use the procedure in this paragraph 

(b)(6) only if you can show that the 

stack with the higher flow has the lower 

average concentration for each pollutant 

over the duty cycle. 

(iv) You must use an accurate, 

traceable measurement or calculation of 

the engine’s total exhaust molar flow 

rate for calculating the mass of 

emissions from the entire engine. 

(v) You may dry the single, equally 

combined, sample stream; you may not 

dry the sample streams from each stack 

separately. 

(vi) You may determine your exhaust 

flow rates with a chemical balance of 

exhaust gas concentrations and either 

intake air flow or fuel flow. 

(c) Gaseous and PM sample probes. A 

probe is the first fitting in a sampling 

system. It protrudes into a raw or 

diluted exhaust stream to extract a 

sample, such that its inside and outside 

surfaces are in contact with the exhaust. 

A sample is transported out of a probe 

into a transfer line, as described in 

paragraph (d) of this section. The 

following provisions apply to sample 

probes: 

(1) Probe design and construction. 

Use sample probes with inside surfaces 

of 300 series stainless steel or, for raw 

exhaust sampling, use any nonreactive 

material capable of withstanding raw 

exhaust temperatures. Locate sample 

probes where constituents are mixed to 

their mean sample concentration. Take 

into account the mixing of any 

crankcase emissions that may be routed 

into the raw exhaust. Locate each probe 

to minimize interference with the flow 

to other probes. We recommend that all 

probes remain free from influences of 

boundary layers, wakes, and eddies— 

especially near the outlet of a rawexhaust tailpipe where unintended 

dilution might occur. Make sure that 

purging or back-flushing of a probe does 

not influence another probe during 

testing. You may use a single probe to 

extract a sample of more than one 

constituent as long as the probe meets 

all the specifications for each 

constituent. 

(2) Gaseous sample probes. Use either 

single-port or multi-port probes for 

sampling gaseous emissions. You may 

orient these probes in any direction 

relative to the raw or diluted exhaust 

flow. For some probes, you must control 

sample temperatures, as follows: 

(i) For probes that extract NOX from 

diluted exhaust, control the probe’s wall 

temperature to prevent aqueous 

condensation. 

(ii) For probes that extract 

hydrocarbons for THC or NMHC 

analysis from the diluted exhaust of 

compression-ignition engines, 2-stroke 

spark-ignition engines, or 4-stroke 

spark-ignition engines below 19 kW, we 

recommend heating the probe to 

minimize hydrocarbon contamination 

consistent with good engineering 

judgment. If you routinely fail the 

contamination check in the 1065.520 

pretest check, we recommend heating 


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the probe section to approximately 

190 °C to minimize contamination. 

(3) PM sample probes. Use PM probes 

with a single opening at the end. Orient 

PM probes to face directly upstream. If 

you shield a PM probe’s opening with 

a PM pre-classifier such as a hat, you 

may not use the preclassifier we specify 

in paragraph (f)(1) of this section. We 

recommend sizing the inside diameter 

of PM probes to approximate isokinetic 

sampling at the expected mean flow 

rate. 

(d) Transfer lines. You may use 

transfer lines to transport an extracted 

sample from a probe to an analyzer, 

storage medium, or dilution system, 

noting certain restrictions for PM 

sampling in § 1065.140(e). Minimize the 

length of all transfer lines by locating 

analyzers, storage media, and dilution 

systems as close to probes as practical. 

We recommend that you minimize the 

number of bends in transfer lines and 

that you maximize the radius of any 

unavoidable bend. Avoid using 90° 

elbows, tees, and cross-fittings in 

transfer lines. Where such connections 

and fittings are necessary, take steps, 

using good engineering judgment, to 

ensure that you meet the temperature 

tolerances in this paragraph (d). This 

may involve measuring temperature at 

various locations within transfer lines 

and fittings. You may use a single 

transfer line to transport a sample of 

more than one constituent, as long as 

the transfer line meets all the 

specifications for each constituent. The 

following construction and temperature 

tolerances apply to transfer lines: 

(1) Gaseous samples. Use transfer 

lines with inside surfaces of 300 series 

stainless steel, PTFE, VitonTM, or any 

other material that you demonstrate has 

better properties for emission sampling. 

For raw exhaust sampling, use a nonreactive material capable of 

withstanding raw exhaust temperatures. 

You may use in-line filters if they do not 

react with exhaust constituents and if 

the filter and its housing meet the same 

temperature requirements as the transfer 

lines, as follows: 

(i) For NOX transfer lines upstream of 

either an NO2-to-NO converter that 

meets the specifications of § 1065.378 or 

a chiller that meets the specifications of 

§ 1065.376, maintain a sample 

temperature that prevents aqueous 

condensation. 

(ii) For THC transfer lines for testing 

compression-ignition engines, 2-stroke 

spark-ignition engines, or 4-stroke 

spark-ignition engines below 19 kW, 

maintain a wall temperature tolerance 

throughout the entire line of (191 ±11) 

°C. If you sample from raw exhaust, you 

may connect an unheated, insulated 

transfer line directly to a probe. Design 

the length and insulation of the transfer 

line to cool the highest expected raw 

exhaust temperature to no lower than 

191 °C, as measured at the transfer line’s 

outlet. For dilute sampling, you may use 

a transition zone between the probe and 

transfer line of up to 92 cm to allow 

your wall temperature to transition to 

(191 ±11) °C. 

(2) PM samples. We recommend 

heated transfer lines or a heated 

enclosure to minimize temperature 

differences between transfer lines and 

exhaust constituents. Use transfer lines 

that are inert with respect to PM and are 

electrically conductive on the inside 

surfaces. We recommend using PM 

transfer lines made of 300 series 

stainless steel. Electrically ground the 

inside surface of PM transfer lines. 

(e) Optional sample-conditioning 

components for gaseous sampling. You 

may use the following sampleconditioning components to prepare 

gaseous samples for analysis, as long as 

you do not install or use them in a way 

that adversely affects your ability to 

show that your engines comply with all 

applicable gaseous emission standards. 

(1) NO2-to-NO converter. You may use 

an NO2-to-NO converter that meets the 

converter conversion verification 

specified in § 1065.378 at any point 

upstream of a NOX analyzer, sample 

bag, or other storage medium. 

(2) Sample dryer. You may use either 

type of sample dryer described in this 

paragraph (e)(2) to decrease the effects 

of water on gaseous emission 

measurements. You may not use a 

chemical dryer, or use dryers upstream 

of PM sample filters. 

(i) Osmotic-membrane. You may use 

an osmotic-membrane dryer upstream of 

any gaseous analyzer or storage 

medium, as long as it meets the 

temperature specifications in paragraph 

(d)(1) of this section. Because osmoticmembrane dryers may deteriorate after 

prolonged exposure to certain exhaust 

constituents, consult with the 

membrane manufacturer regarding your 

application before incorporating an 

osmotic-membrane dryer. Monitor the 

dewpoint, Tdew, and absolute pressure, 

ptotal, downstream of an osmoticmembrane dryer. You may use 

continuously recorded values of Tdew

and ptotal in the amount of water 

calculations specified in § 1065.645. For 

our testing we may use average 

temperature and pressure values over 

the test interval or a nominal pressure 

value that we estimate as the dryer’s 

average pressure expected during testing 

as constant values in the amount of 

water calculations specified in 

§ 1065.645. For your testing, you may 

use the maximum temperature or 

minimum pressure values observed 

during a test interval or duty cycle or 

the high alarm temperature setpoint or 

low alarm pressure setpoint as constant 

values in the calculations specified in 

§ 1065.645. For your testing, you may 

also use a nominal ptotal, which you may 

estimate as the dryer’s lowest absolute 

pressure expected during testing. 

(ii) Thermal chiller. You may use a 

thermal chiller upstream of some gas 

analyzers and storage media. You may 

not use a thermal chiller upstream of a 

THC measurement system for 

compression-ignition engines, 2-stroke 

spark-ignition engines, or 4-stroke 

spark-ignition engines below 19 kW. If 

you use a thermal chiller upstream of an 

NO2-to-NO converter or in a sampling 

system without an NO2-to-NO converter, 

the chiller must meet the NO2 lossperformance check specified in 

§ 1065.376. Monitor the dewpoint, Tdew, 

and absolute pressure, ptotal, 

downstream of a thermal chiller. You 

may use continuously recorded values 

of Tdew and ptotal in the amount of water 

calculations specified in § 1065.645. If it 

is valid to assume the degree of 

saturation in the thermal chiller, you 

may calculate Tdew based on the known 

chiller performance and continuous 

monitoring of chiller temperature, 

Tchiller. If it is valid to assume a constant 

temperature offset between Tchiller and 

Tdew, due to a known and fixed amount 

of sample reheat between the chiller 

outlet and the temperature measurement 

location, you may factor in this assumed 

temperature offset value into emission 

calculations. If we ask for it, you must 

show by engineering analysis or by data 

the validity of any assumptions allowed 

by this paragraph (e)(2)(ii). For our 

testing we may use average temperature 

and pressure values over the test 

interval or a nominal pressure value that 

we estimate as the dryer’s average 

pressure expected during testing as 

constant values in the calculations 

specified in § 1065.645. For your testing 

you may use the maximum temperature 

and minimum pressure values observed 

during a test interval or duty cycle or 

the high alarm temperature setpoint and 

the low alarm pressure setpoint as 

constant values in the amount of water 

calculations specified in § 1065.645. For 

your testing you may also use a nominal 

ptotal, which you may estimate as the 

dryer’s lowest absolute pressure 

expected during testing. 

(3) Sample pumps. You may use 

sample pumps upstream of an analyzer 

or storage medium for any gas. Use 

sample pumps with inside surfaces of 

300 series stainless steel, PTFE, or any 

other material that you demonstrate has 


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better properties for emission sampling. 

For some sample pumps, you must 

control temperatures, as follows: 

(i) If you use a NOX sample pump 

upstream of either an NO2-to-NO 

converter that meets § 1065.378 or a 

chiller that meets § 1065.376, it must be 

heated to prevent aqueous 

condensation. 

(ii) For testing compression-ignition 

engines, 2-stroke spark-ignition engines, 

or 4-stroke spark-ignition engines below 

19 kW, if you use a THC sample pump 

upstream of a THC analyzer or storage 

medium, its inner surfaces must be 

heated to a tolerance of (191 ±11) °C. 

(4) Ammonia Scrubber. You may use 

ammonia scrubbers for any or all 

gaseous sampling systems to prevent 

interference with NH3, poisoning of the 

NO2-to-NO converter, and deposits in 

the sampling system or analyzers. 

Follow the ammonia scrubber 

manufacturer’s recommendations or use 

good engineering judgment in applying 

ammonia scrubbers. 

(f) Optional sample-conditioning 

components for PM sampling. You may 

use the following sample-conditioning 

components to prepare PM samples for 

analysis, as long as you do not install or 

use them in a way that adversely affects 

your ability to show that your engines 

comply with the applicable PM 

emission standards. You may condition 

PM samples to minimize positive and 

negative biases to PM results, as follows: 

(1) PM preclassifier. You may use a 

PM preclassifier to remove largediameter particles. The PM preclassifier 

may be either an inertial impactor or a 

cyclonic separator. It must be 

constructed of 300 series stainless steel. 

The preclassifier must be rated to 

remove at least 50% of PM at an 

aerodynamic diameter of 10 μm and no 

more than 1% of PM at an aerodynamic 

diameter of 1 μm over the range of flow 

rates for which you use it. Follow the 

preclassifier manufacturer’s instructions 

for any periodic servicing that may be 

necessary to prevent a buildup of PM. 

Install the preclassifier in the dilution 

system downstream of the last dilution 

stage. Configure the preclassifier outlet 

with a means of bypassing any PM 

sample media so the preclassifier flow 

may be stabilized before starting a test. 

Locate PM sample media within 75 cm 

downstream of the preclassifier’s exit. 

You may not use this preclassifier if you 

use a PM probe that already has a 

preclassifier. For example, if you use a 

hat-shaped preclassifier that is located 

immediately upstream of the probe in 

such a way that it forces the sample 

flow to change direction before entering 

the probe, you may not use any other 

preclassifier in your PM sampling 

system. 

(2) Other components. You may 

request to use other PM conditioning 

components upstream of a PM 

preclassifier, such as components that 

condition humidity or remove gaseousphase hydrocarbons from the diluted 

exhaust stream. You may use such 

components only if we approve them 

under § 1065.10. 

Subpart C—[Amended] 

■ 279. Section 1065.201 is amended by 

revising paragraph (h) to read as 

follows: 

§ 1065.201 Overview and general 

provisions. 

* * * * * 

(h) Recommended practices. This 

subpart identifies a variety of 

recommended but not required practices 

for proper measurements. We believe in 

most cases it is necessary to follow these 

recommended practices for accurate and 

repeatable measurements. However, we 

do not specifically require you to follow 

these recommended practices to 

perform a valid test, as long as you meet 

the required calibrations and 

verifications of measurement systems 

specified in subpart D of this part. 

Similarly, we are not required to follow 

all recommended practices, as long as 

we meet the required calibrations and 

verifications. Our decision to follow or 

not follow a given recommendation 

when testing your engine is not 

dependent on whether or not you 

followed it during your testing. 

■ 280. Section 1065.205 is revised to 

read as follows: 

§ 1065.205 Performance specifications for 

measurement instruments. 

Your test system as a whole must 

meet all the applicable calibrations, 

verifications, and test-validation criteria 

specified in subparts D and F of this 

part or subpart J of this part for using 

PEMS and for performing field testing. 

We recommend that your instruments 

meet the specifications in Table 1 of this 

section for all ranges you use for testing. 

We also recommend that you keep any 

documentation you receive from 

instrument manufacturers showing that 

your instruments meet the 

specifications in Table 1 of this section. 

BILLING CODE 6560–50–P 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23035 

BILLING CODE 6560–50–C 

■ 281. Section 1065.240 is amended by 

revising paragraph (d) introductory text 

to read as follows: 

§ 1065.240 Dilution air and diluted exhaust 

flow meters. 

* * * * * 

(d) Exhaust cooling. You may cool 

diluted exhaust upstream of a diluteexhaust flow meter, as long as you 

observe all the following provisions: 

* * * * * 

■ 282. Section 1065.260 is amended by 

revising paragraph (c) to read as follows: 

§ 1065.260 Flame-ionization detector. 

* * * * * 

(c) Heated FID analyzers. For 

compression-ignition engines, twostroke spark-ignition engines, and fourstroke spark-ignition engines below 19 

kW, you must use heated FID analyzers 

that maintain all surfaces that are 

exposed to emissions at a temperature of 

(191 ± 11) °C. 

* * * * * 

Subpart D—[Amended] 

■ 283. Section 1065.303 is revised to 

read as follows: 

§ 1065.303 Summary of required 

calibration and verifications 

The following table summarizes the 

required and recommended calibrations 

and verifications described in this 

subpart and indicates when these have 

to be performed: 

TABLE 1 OF § 1065.303—SUMMARY OF REQUIRED CALIBRATION AND VERIFICATIONS

Type of calibration or verification Minimum frequency a

§ 1065.305: Accuracy, repeatability and noise ......................................... Accuracy: Not required, but recommended for initial installation. 

Repeatability: Not required, but recommended for initial installation. 

Noise: Not required, but recommended for initial installation. 

§ 1065.307: Linearity verification .............................................................. Speed: Upon initial installation, within 370 days before testing and after 

major maintenance. 

Torque: Upon initial installation, within 370 days before testing and 

after major maintenance. 

Electrical power: Upon initial installation, within 370 days before testing 

and after major maintenance. 

Fuel flow: Upon initial installation, within 370 days before testing, and 

after major maintenance. 

Clean gas and diluted exhaust flows: Upon initial installation, within 

370 days before testing and after major maintenance, unless flow is 

verified by propane check or by carbon or oxygen balance. 

Raw exhaust flow: Upon initial installation, within 185 days before testing and after major maintenance, unless flow is verified by propane 

check or by carbon or oxygen balance. 


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TABLE 1 OF § 1065.303—SUMMARY OF REQUIRED CALIBRATION AND VERIFICATIONS—Continued 

Type of calibration or verification Minimum frequency a

Gas dividers: Upon initial installation, within 370 days before testing, 

and after major maintenance. 

Gas analyzers: Upon initial installation, within 35 days before testing 

and after major maintenance. 

FTIR and photoacoustic analyzers: Upon initial installation, within 370 

days before testing and after major maintenance. 

GC–ECD: Upon initial installation and after major maintenance. 

PM balance: Upon initial installation, within 370 days before testing and 

after major maintenance. 

Pressure, temperature, and dewpoint: Upon initial installation, within 

370 days before testing and after major maintenance. 

§ 1065.308: Continuous gas analyzer system response and updatingrecording verification—for gas analyzers not continuously compensated for other gas species.Upon initial installation or after system modification that would affect response. 

§ 1065.309: Continuous gas analyzer system-response and updatingrecording verification—for gas analyzers continuously compensated 

for other gas species.

Upon initial installation or after system modification that would affect response. 

§ 1065.310: Torque ................................................................................... Upon initial installation and after major maintenance. 

§ 1065.315: Pressure, temperature, dewpoint ......................................... Upon initial installation and after major maintenance. 

§ 1065.320: Fuel flow ............................................................................... Upon initial installation and after major maintenance. 

§ 1065.325: Intake flow ............................................................................. Upon initial installation and after major maintenance. 

§ 1065.330: Exhaust flow ......................................................................... Upon initial installation and after major maintenance. 

§ 1065.340: Diluted exhaust flow (CVS) .................................................. Upon initial installation and after major maintenance. 

§ 1065.341: CVS and batch sampler verification b ................................... Upon initial installation, within 35 days before testing, and after major 

maintenance. 

§ 1065.342 Sample dryer verification ....................................................... For thermal chillers: Upon installation and after major maintenance. 

For osmotic membranes; upon installation, within 35 days of testing, 

and after major maintenance. 

§ 1065.345: Vacuum leak ......................................................................... For laboratory testing: Upon initial installation of the sampling system, 

within 8 hours before the start of the first test interval of each dutycycle sequence, and after maintenance such as pre-filter changes. 

For field testing: After each installation of the sampling system on the 

vehicle, prior to the start of the field test, and after maintenance such 

as pre-filter changes. 

§ 1065.350: CO2 NDIR H2O interference ................................................. Upon initial installation and after major maintenance. 

§ 1065.355: CO NDIR CO2 and H2O interference ................................... Upon initial installation and after major maintenance. 

§ 1065.360: FID calibration ....................................................................... Calibrate all FID analyzers: Upon initial installation and after major 

maintenance. 

THC FID optimization, and THC FID verification ..................................... Optimize and determine CH4 response for THC FID analyzers: Upon 

initial installation and after major maintenance. 

Verify CH4 response for THC FID analyzers: Upon initial installation, 

within 185 days before testing, and after major maintenance. 

§ 1065.362: Raw exhaust FID O2 interference ........................................ For all FID analyzers: Upon initial installation, and after major maintenance. 

For THC FID analyzers: Upon initial installation, after major maintenance, and after FID optimization according to § 1065.360. 

§ 1065.365: Nonmethane cutter penetration ............................................ Upon initial installation, within 185 days before testing, and after major 

maintenance. 

§ 1065.370: CLD CO2 and H2O quench .................................................. Upon initial installation and after major maintenance. 

§ 1065.372: NDUV HC and H2O interference .......................................... Upon initial installation and after major maintenance. 

§ 1065.375: N2O analyzer interference .................................................... Upon initial installation and after major maintenance. 

§ 1065.376: Chiller NO2 penetration ........................................................ Upon initial installation and after major maintenance. 

§ 1065.378: NO2-to-NO converter conversion ......................................... Upon initial installation, within 35 days before testing, and after major 

maintenance. 

§ 1065.390: PM balance and weighing .................................................... Independent verification: Upon initial installation, within 370 days before testing, and after major maintenance. 

Zero, span, and reference sample verifications: Within 12 hours of 

weighing, and after major maintenance. 

§ 1065.395: Inertial PM balance and weighing ........................................ Independent verification: Upon initial installation, within 370 days before testing, and after major maintenance. 

Other verifications: Upon initial installation and after major maintenance. 

aPerform calibrations and verifications more frequently, according to measurement system manufacturer instructions and good engineering 

judgment. bThe CVS verification described in § 1065.341 is not required for systems that agree within ± 2% based on a chemical balance of carbon or 

oxygen of the intake air, fuel, and diluted exhaust. 


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■ 284. Section 1065.305 is amended by 

revising paragraphs (d)(4), (d)(5), and 

(d)(7) to read as follows: 

§ 1065.305 Verifications for accuracy, 

repeatability, and noise. 

* * * * * 

(d) * * * 

(4) Use the instrument to quantify a 

NIST-traceable reference quantity, yref.

For gas analyzers the reference gas must 

meet the specifications of § 1065.750. 

Select a reference quantity near the 

mean value expected during testing. For 

all gas analyzers, use a quantity near the 

flow-weighted mean concentration 

expected at the standard or expected 

during testing, whichever is greater. For 

noise verification, use the same zero gas 

from paragraph (d)(2) of this section as 

the reference quantity. In all cases, 

allow time for the instrument to 

stabilize while it measures the reference 

quantity. Stabilization time may include 

time to purge an instrument and time to 

account for its response. 

(5) Sample and record values for 30 

seconds (you may select a longer 

sampling period if the recording update 

frequency is less than 0.5 Hz), record 

the arithmetic mean, y ̄i and record the 

standard deviation, si of the recorded 

values. Refer to § 1065.602 for an 

example of calculating arithmetic mean 

and standard deviation. 

* * * * * 

(7) Subtract the reference value, yref

(or y ̄ refi), from the arithmetic mean, y ̄i. 

Record this value as the error, ei.

* * * * * 

■ 285. Section 1065.307 is amended by 

revising paragraphs (c)(6), (c)(11), (d), 

(e), and Table 1 of § 1065.307 to read as 

follows: 

§ 1065.307 Linearity verification. 

* * * * * 

(c) * * * 

(6) For all measured quantities, use 

instrument manufacturer 

recommendations and good engineering 

judgment to select reference values, yrefi,

that cover a range of values that you 

expect would prevent extrapolation 

beyond these values during emission 

testing. We recommend selecting a zero 

reference signal as one of the reference 

values of the linearity verification. For 

pressure, temperature, dewpoint, and 

GC–ECD linearity verifications, we 

recommend at least three reference 

values. For all other linearity 

verifications select at least ten reference 

values. 

* * * * * 

(11) At a recording frequency of at 

least f Hz, specified in Table 1 of 

§ 1065.205, measure the reference value 

for 30 seconds (you may select a longer 

sampling period if the recording update 

frequency is less than 0.5 Hz) and 

record the arithmetic mean of the 

recorded values, y ̄i. Refer to § 1065.602 

for an example of calculating an 

arithmetic mean. 

* * * * * 

(d) Reference signals. This paragraph 

(d) describes recommended methods for 

generating reference values for the 

linearity-verification protocol in 

paragraph (c) of this section. Use 

reference values that simulate actual 

values, or introduce an actual value and 

measure it with a referencemeasurement system. In the latter case, 

the reference value is the value reported 

by the reference-measurement system. 

Reference values and referencemeasurement systems must be NISTtraceable. We recommend using 

calibration reference quantities that are 

NIST-traceable within 0.5% uncertainty, 

if not specified otherwise in other 

sections of this part 1065. Use the 

following recommended methods to 

generate reference values or use good 

engineering judgment to select a 

different reference: 

(1) Speed. Run the engine or 

dynamometer at a series of steady-state 

speeds and use a strobe, a photo 

tachometer, or a laser tachometer to 

record reference speeds. 

(2) Torque. Use a series of calibration 

weights and a calibration lever arm to 

simulate engine torque. You may 

instead use the engine or dynamometer 

itself to generate a nominal torque that 

is measured by a reference load cell or 

proving ring in series with the torquemeasurement system. In this case use 

the reference load cell measurement as 

the reference value. Refer to § 1065.310 

for a torque-calibration procedure 

similar to the linearity verification in 

this section. 

(3) Electrical power. Use a controlled 

source of current and a watt-hour 

standard reference meter. Complete 

calibration systems that contain a 

current source and a reference watt-hour 

meter are commonly used in the 

electrical power distribution industry 

and are therefore commercially 

available. 

(4) Fuel rate. Operate the engine at a 

series of constant fuel-flow rates or recirculate fuel back to a tank through the 

fuel flow meter at different flow rates. 

Use a gravimetric reference 

measurement (such as a scale, balance, 

or mass comparator) at the inlet to the 

fuel-measurement system. Use a 

stopwatch or timer to measure the time 

intervals over which reference masses of 

fuel are introduced to the fuel 

measurement system. The reference fuel 

mass divided by the time interval is the 

reference fuel flow rate. 

(5) Flow rates—inlet air, dilution air, 

diluted exhaust, raw exhaust, or sample 

flow. Use a reference flow meter with a 

blower or pump to simulate flow rates. 

Use a restrictor, diverter valve, a 

variable-speed blower or a variablespeed pump to control the range of flow 

rates. Use the reference meter’s response 

as the reference values. 

(i) Reference flow meters. Because the 

flow range requirements for these 

various flows are large, we allow a 

variety of reference meters. For 

example, for diluted exhaust flow for a 

full-flow dilution system, we 

recommend a reference subsonic venturi 

flow meter with a restrictor valve and a 

blower to simulate flow rates. For inlet 

air, dilution air, diluted exhaust for 

partial-flow dilution, raw exhaust, or 

sample flow, we allow reference meters 

such as critical flow orifices, critical 

flow venturis, laminar flow elements, 

master mass flow standards, or Roots 

meters. Make sure the reference meter is 

calibrated by the flow-meter 

manufacturer and its calibration is 

NIST-traceable. If you use the difference 

of two flow measurements to determine 

a net flow rate, you may use one of the 

measurements as a reference for the 

other. 

(ii) Reference flow values. Because the 

reference flow is not absolutely 

constant, sample and record values of 

n ̇ refi for 30 seconds and use the 

arithmetic mean of the values, n

Ôref, as 

the reference value. Refer to § 1065.602 

for an example of calculating arithmetic 

mean. 

(6) Gas division. Use one of the two 

reference signals: 

(i) At the outlet of the gas-division 

system, connect a gas analyzer that 

meets the linearity verification 

described in this section and has not 

been linearized with the gas divider 

being verified. For example, verify the 

linearity of an analyzer using a series of 

reference analytical gases directly from 

compressed gas cylinders that meet the 

specifications of § 1065.750. We 

recommend using a FID analyzer or a 

PMD or MPD O2 analyzer because of 

their inherent linearity. Operate this 

analyzer consistent with how you 

would operate it during an emission 

test. Connect a span gas to the gasdivider inlet. Use the gas-division 

system to divide the span gas with 

purified air or nitrogen. Select gas 

divisions that you typically use. Use a 

selected gas division as the measured 

value. Use the analyzer response 

divided by the span gas concentration as 

the reference gas-division value. 


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Because the instrument response is not 

absolutely constant, sample and record 

values of xrefi for 30 seconds and use the 

arithmetic mean of the values, x ̄ ref, as 

the reference value. Refer to § 1065.602 

for an example of calculating arithmetic 

mean. 

(ii) Using good engineering judgment 

and gas divider manufacturer 

recommendations, use one or more 

reference flow meters to measure the 

flow rates of the gas divider and verify 

the gas-division value. 

(7) Continuous constituent 

concentration. For reference values, use 

a series of gas cylinders of known gas 

concentration or use a gas-division 

system that is known to be linear with 

a span gas. Gas cylinders, gas-division 

systems, and span gases that you use for 

reference values must meet the 

specifications of § 1065.750. 

(8) Temperature. You may perform 

the linearity verification for temperature 

measurement systems with 

thermocouples, RTDs, and thermistors 

by removing the sensor from the system 

and using a simulator in its place. Use 

a NIST-traceable simulator that is 

independently calibrated and, as 

appropriate, cold-junction compensated. 

The simulator uncertainty scaled to 

temperature must be less than 0.5% of 

Tmax. If you use this option, you must 

use sensors that the supplier states are 

accurate to better than 0.5% of Tmax

compared with their standard 

calibration curve. 

(e) Measurement systems that require 

linearity verification. Table 1 of this 

section indicates measurement systems 

that require linearity verifications, 

subject to the following provisions: 

(1) Perform a linearity verification 

more frequently based on the 

instrument manufacturer’s 

recommendation or good engineering 

judgment. 

(2) The expression ‘‘xmin’’ refers to the 

reference value used during the linearity 

verification that is closest to zero. This 

is the value used to calculate the first 

tolerance in Table 1 of this section using 

the intercept, a0. Note that this value 

may be zero, positive, or negative 

depending on the reference values. For 

example, if the reference values chosen 

to validate a pressure transducer vary 

from ¥10 to ¥1 kPa, xmin is ¥1 kPa. If 

the reference values used to validate a 

temperature device vary from 290 to 390 

K, xmin is 290 K. 

(3) The expression ‘‘max’’ generally 

refers to the absolute value of the 

reference value used during the linearity 

verification that is furthest from zero. 

This is the value used to scale the first 

and third tolerances in Table 1 of this 

section using a0 and SEE. For example, 

if the reference values chosen to 

validate a pressure transducer vary from 

¥10 to ¥1 kPa, then pmax is +10 kPa. 

If the reference values used to validate 

a temperature device vary from 290 to 

390 K, then Tmax is 390 K. For gas 

dividers where ‘‘max’’ is expressed as, 

xmax/xspan; xmax is the maximum gas 

concentration used during the 

verification, xspan is the undivided, 

undiluted, span gas concentration, and 

the resulting ratio is the maximum 

divider point reference value used 

during the verification (typically 1). The 

following are special cases where ‘‘max’’ 

refers to a different value: 

(i) For linearity verification with a PM 

balance, mmax refers to the typical mass 

of a PM filter. 

(ii) For linearity verification of torque 

on the engine’s primary output shaft, 

Tmax refers to the manufacturer’s 

specified engine torque peak value of 

the lowest torque engine to be tested. 

(4) The specified ranges are inclusive. 

For example, a specified range of 0.98– 

1.02 for a1 means 0.98≤a1≤1.02. 

(5) These linearity verifications are 

optional for systems that pass the flowrate verification for diluted exhaust as 

described in § 1065.341 (the propane 

check) or for systems that agree within 

±2% based on a chemical balance of 

carbon or oxygen of the intake air, fuel, 

and exhaust. 

(6) You must meet the a1 criteria for 

these quantities only if the absolute 

value of the quantity is required, as 

opposed to a signal that is only linearly 

proportional to the actual value. 

(7) Linearity checks are required for 

the following temperature 

measurements: 

(i) The following temperature 

measurements always require linearity 

checks: 

(A) Air intake. 

(B) Aftertreatment bed(s), for engines 

tested with aftertreatment devices 

subject to cold-start testing. 

(C) Dilution air for PM sampling, 

including CVS, double-dilution, and 

partial-flow systems. 

(D) PM sample, if applicable. 

(E) Chiller sample, for gaseous 

sampling systems that use thermal 

chillers to dry samples and use chiller 

temperature to calculate the dewpoint at 

the outlet of the chiller. For your testing, 

if you choose to use a high alarm 

temperature setpoint for the chiller 

temperature as a constant value in the 

amount of water calculations in 

§ 1065.645, you may use good 

engineering judgment to verify the 

accuracy of the high alarm temperature 

setpoint in lieu of the linearity 

verification on the chiller temperature. 

We recommend that you input a 

reference simulated temperature signal 

below the alarm trip point, increase this 

signal until the high alarm trips, and 

verify that the alarm trip point value is 

no less than 2.0 °C below the reference 

value at the trip point. 

(ii) Linearity checks are required for 

the following temperature 

measurements if these temperature 

measurements are specified by the 

engine manufacturer: 

(A) Fuel inlet. 

(B) Air outlet to the test cell’s charge 

air cooler air outlet, for engines tested 

with a laboratory heat exchanger that 

simulates an installed charge air cooler. 

(C) Coolant inlet to the test cell’s 

charge air cooler, for engines tested with 

a laboratory heat exchanger that 

simulates an installed charge air cooler. 

(D) Oil in the sump/pan. 

(E) Coolant before the thermostat, for 

liquid-cooled engines. 

(8) Linearity checks are required for 

the following pressure measurements: 

(i) The following pressure 

measurements always require linearity 

checks: 

(A) Air intake restriction. 

(B) Exhaust back pressure. 

(C) Barometer. 

(D) CVS inlet gage pressure. 

(E) Sample dryer, for gaseous 

sampling systems that use either 

osmotic-membrane or thermal chillers 

to dry samples. For your testing, if you 

choose to use a low alarm pressure 

setpoint for the sample dryer pressure as 

a constant value in the amount of water 

calculations in § 1065.645, you may use 

good engineering judgment to verify the 

accuracy of the low alarm pressure 

setpoint in lieu of the linearity 

verification on the sample dryer 

pressure. We recommend that you input 

a reference pressure signal above the 

alarm trip point, decrease this signal 

until the low alarm trips, and verify that 

the trip point value is no more than 4.0 

kPa above the reference value at the trip 

point. 

(ii) Linearity checks are required for 

the following pressure measurements if 

these pressure measurements are 

specified by the engine manufacturer: 

(A) The test cell’s charge air cooler 

and interconnecting pipe pressure drop, 

for turbo-charged engines tested with a 

laboratory heat exchanger that simulates 

an installed charge air cooler. 

(B) Fuel outlet. 


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TABLE 1 OF § 1065.307—MEASUREMENT SYSTEMS THAT REQUIRE LINEARITY VERIFICATIONS—CONTINUED

Measurement 

system Quantity Minimum verification frequency 

Linearity criteria 

⎢xmin(a1¥1) + a0 ⎢ a1 SEE r 2

Speed ...................... fn .............. Within 370 days before 

testing.

≤0.05% · fnmax ............ 0.98–1.02 ≤2% · fnmax ................ ≥0.990 

Torque ..................... T .............. Within 370 days before 

testing.

≤1% · Tmax ................ 0.98–1.02 ≤2% · Tmax ................ ≥0.990 

Electrical power ...... P .............. Within 370 days before 

testing.

≤1% · Pmax ................ 0.98–1.02 ≤2% · Pmax ................ ≥0.990 

Fuel flow rate .......... m ̇ ............. Within 370 days before 

testing.

≤1% · m ̇ max ............... 0.98–1.02 ≤2% · m ̇ max ............... >0.990 

Intake-air flow rate .. n ̇ ............... Within 370 days before 

testing.

≤1% · n ̇ max ................ 0.98–1.02 ≤2% · n ̇ max ................ ≥0.990 

Dilution air flow rate n ̇ ............... Within 370 days before 

testing.

≤1% · n ̇ max ................ 0.98–1.02 ≤2% · n ̇ max ................ ≥0.990 

Diluted exhaust .......

flow rate. 

n ̇ .............. Within 370 days before 

testing.

≤1% · n ̇ max ................ 0.98–1.02 ≤2% · n ̇ max ................ ≥0.990 

Raw exhaust flow 

rate.

n ̇ .............. Within 185 days before 

testing.

≤1% · n ̇ max ................ 0.98–1.02 ≤2% · n ̇ max ................ ≥0.990 

Batch sampler flow 

rates.

n ̇ ............... Within 370 days before 

testing.

≤1% · n ̇ max ................ 0.98–1.02 ≤2% · n ̇ max ................ ≥0.990 

Gas dividers ............ x/xspan ....... Within 370 days before 

testing.

≤0.5% · xmax/xspan ...... 0.98–1.02 ≤2% · xmax/xspan ......... >0.990 

Gas analyzers for 

laboratory testing.

x ............... Within 35 days before 

testing.

≤0.5% · xmax ............. 0.99–1.01 ≤1% · xmax ................ ≥0.998 

Gas analyzers for 

field testing.

x ............... Within 35 days before 

testing.

≤1% · xmax ................ 0.99–1.01 ≤1% · xmax ................ ≥0.998 

PM balance ............. m .............. Within 370 days before 

testing.

≤1% · mmax ............... 0.99–1.01 ≤1% · mmax ............... ≥0.998 

Pressures ................ p ............... Within 370 days before 

testing.

≤1% · pmax ................ 0.99–1.01 ≤1% · pmax ................ ≥0.998 

Dewpoint for intake 

air, PM-stabilization and balance 

environments.

Tdew .......... Within 370 days before 

testing.

≤0.5% · Tdewmax ........ 0.99–1.01 ≤0.5% · Tdewmax ........ ≥0.998 

Other dewpoint 

measurements.

Tdew .......... Within 370 days before 

testing.

≤1% · Tdewmax ........... 0.99–1.01 ≤1% · Tdewmax ........... ≥0.998 

Analog-to-digital 

conversion of temperature signals.

T .............. Within 370 days before 

testing.

≤1% · Tmax ................ 0.99–1.01 ≤1% · Tmax ................ ≥0.998 

■ 286. Section 1065.309 is amended by 

revising paragraph (d)(2) to read as 

follows: 

§ 1065.309 Continuous gas analyzer 

system-response and updating-recording 

verification—for gas analyzers continuously 

compensated for other gas species. 

* * * * * 

(d) * * * 

(2) Equipment setup. We recommend 

using minimal lengths of gas transfer 

lines between all connections and fastacting three-way valves (2 inlets, 1 

outlet) to control the flow of zero and 

blended span gases to the sample 

system’s probe inlet or a tee near the 

outlet of the probe. Normally the gas 

flow rate is higher than the probe 

sample flow rate and the excess is 

overflowed out the inlet of the probe. If 

the gas flow rate is lower than the probe 

flow rate, the gas concentrations must 

be adjusted to account for the dilution 

from ambient air drawn into the probe. 

Select span gases for the species being 

continuously combined, other than H2O. 

Select concentrations of compensating 

species that will yield concentrations of 

these species at the analyzer inlet that 

covers the range of concentrations 

expected during testing. You may use 

binary or multi-gas span gases. You may 

use a gas blending or mixing device to 

blend span gases. A gas blending or 

mixing device is recommended when 

blending span gases diluted in N2 with 

span gases diluted in air. You may use 

a multi-gas span gas, such as NO-COCO2-C3H8-CH4, to verify multiple 

analyzers at the same time. In designing 

your experimental setup, avoid pressure 

pulsations due to stopping the flow 

through the gas blending device. If H2O 

correction is applicable, then span gases 

must be humidified before entering the 

analyzer; however, you may not 

humidify NO2 span gas by passing it 

through a sealed humidification vessel 

that contains water. You must humidify 

NO2 span gas with another moist gas 

stream. We recommend humidifying 

your NO-CO-CO2-C3H8-CH4, balance N2

blended gas by flowing the gas mixture 

through a sealed vessel that humidifies 

the gas by bubbling it through distilled 

water and then mixing the gas with dry 

NO2 gas, balance purified synthetic air. 

If your system does not use a sample 

dryer to remove water from the sample 

gas, you must humidify your span gas 

to the highest sample H2O content that 

you estimate during emission sampling. 

If your system uses a sample dryer 

during testing, it must pass the sample 

dryer verification check in § 1065.342, 

and you must humidify your span gas 

to an H2O content greater than or equal 

to the level determined in 

§ 1065.145(e)(2). If you are humidifying 

span gases without NO2, use good 

engineering judgment to ensure that the 

wall temperatures in the transfer lines, 

fittings, and valves from the 

humidifying system to the probe are 

above the dewpoint required for the 

target H2O content. If you are 

humidifying span gases with NO2, use 

good engineering judgment to ensure 

that there is no condensation in the 

transfer lines, fittings, or valves from the 

point where humidified gas is mixed 


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with NO2 span gas to the probe. We 

recommend that you design your setup 

so that the wall temperatures in the 

transfer lines, fittings, and valves from 

the humidifying system to the probe are 

at least 5 °C above the local sample gas 

dewpoint. Operate the measurement 

and sample handling system as you do 

for emission testing. Make no 

modifications to the sample handling 

system to reduce the risk of 

condensation. Flow humidified gas 

through the sampling system before this 

check to allow stabilization of the 

measurement system’s sampling 

handling system to occur, as it would 

for an emission test. 

* * * * * 

■ 287. Section 1065.315 is amended by 

revising paragraph (a)(2) to read as 

follows: 

§ 1065.315 Pressure, temperature, and 

dewpoint calibration. 

(a) * * * 

(2) Temperature. We recommend 

digital dry-block or stirred-liquid 

temperature calibrators, with data 

logging capabilities to minimize 

transcription errors. We recommend 

using calibration reference quantities 

that are NIST-traceable within 0.5% 

uncertainty. You may perform the 

linearity verification for temperature 

measurement systems with 

thermocouples, RTDs, and thermistors 

by removing the sensor from the system 

and using a simulator in its place. Use 

a NIST-traceable simulator that is 

independently calibrated and, as 

appropriate, cold-junction compensated. 

The simulator uncertainty scaled to 

temperature must be less than 0.5% of 

Tmax. If you use this option, you must 

use sensors that the supplier states are 

accurate to better than 0.5% of Tmax

compared with their standard 

calibration curve. 

* * * * * 

■ 288. Section 1065.342 is amended by 

revising paragraphs (a), (c), (d)(4), and 

(d)(7) to read as follows: 

§ 1065.342 Sample dryer verification. 

(a) Scope and frequency. If you use a 

sample dryer as allowed in 

§ 1065.145(e)(2) to remove water from 

the sample gas, verify the performance 

upon installation, after major 

maintenance, for thermal chiller. For 

osmotic membrane dryers, verify the 

performance upon installation, after 

major maintenance, and within 35 days 

of testing. 

* * * * * 

(c) System requirements. The sample 

dryer must meet the specifications as 

determined in § 1065.145(e)(2) for 

dewpoint, Tdew, and absolute pressure, 

ptotal, downstream of the osmoticmembrane dryer or thermal chiller. 

(d) * * * 

(4) Maintain the sample lines, fittings, 

and valves from the location where the 

humidified gas water content is 

measured to the inlet of the sampling 

system at a temperature at least 5 °C 

above the local humidified gas 

dewpoint. For dryers used in NOX

sample systems, verify the sample 

system components used in this 

verification prevent aqueous 

condensation as required in 

§ 1065.145(d)(1)(i). We recommend that 

the sample system components be 

maintained at least 5 °C above the local 

humidified gas dewpoint to prevent 

aqueous condensation. 

* * * * * 

(7) The sample dryer meets the 

verification if the dewpoint at the 

sample dryer pressure as measured in 

paragraph (d)(6) of this section is less 

than the dewpoint corresponding to the 

sample dryer specifications as 

determined in § 1065.145(e)(2) plus 2 °C 

or if the mole fraction of water as 

measured in (d)(6) is less than the 

corresponding sample dryer 

specifications plus 0.002 mol/mol. 

* * * * * 

■ 289. Section 1065.345 is amended by 

revising paragraphs (a) and (e)(1)(iii) to 

read as follows: 

§ 1065.345 Vacuum-side leak verification. 

(a) Scope and frequency. Verify that 

there are no significant vacuum-side 

leaks using one of the leak tests 

described in this section. For laboratory 

testing, perform the vacuum-side leak 

verification upon initial sampling 

system installation, within 8 hours 

before the start of the first test interval 

of each duty-cycle sequence, and after 

maintenance such as pre-filter changes. 

For field testing, perform the vacuumside leak verification after each 

installation of the sampling system on 

the vehicle, prior to the start of the field 

test, and after maintenance such as prefilter changes. This verification does not 

apply to any full-flow portion of a CVS 

dilution system. 

* * * * * 

(e) * * * 

(1) * * * 

(iii) Close a leak-tight valve located in 

the sample transfer line within 92 cm of 

the probe. 

* * * * * 

■ 290. Section 1065.350 is amended by 

revising paragraph (d) to read as 

follows: 

§ 1065.350 H2O interference verification 

for CO2 NDIR analyzers. 

* * * * * 

(d) Procedure. Perform the 

interference verification as follows: 

(1) Start, operate, zero, and span the 

CO2 NDIR analyzer as you would before 

an emission test. If the sample is passed 

through a dryer during emission testing, 

you may run this verification test with 

the dryer if it meets the requirements of 

§ 1065.342. Operate the dryer at the 

same conditions as you will for an 

emission test. You may also run this 

verification test without the sample 

dryer. 

(2) Create a humidified test gas by 

bubbling zero gas that meets the 

specifications in § 1065.750 through 

distilled water in a sealed vessel. If the 

sample is not passed through a dryer 

during emission testing, control the 

vessel temperature to generate an H2O 

level at least as high as the maximum 

expected during emission testing. If the 

sample is passed through a dryer during 

emission testing, control the vessel 

temperature to generate an H2O level at 

least as high as the level determined in 

§ 1065.145(e)(2) for that dryer. 

(3) Introduce the humidified test gas 

into the sample system. You may 

introduce it downstream of any sample 

dryer, if one is used during testing. 

(4) If the sample is not passed through 

a dryer during this verification test, 

measure the water mole fraction, xH2O,

of the humidified test gas, as close as 

possible to the inlet of the analyzer. For 

example, measure dewpoint, Tdew, and 

absolute pressure, ptotal, to calculate 

xH2O. Verify that the water content meets 

the requirement in paragraph (d)(2) of 

this section. If the sample is passed 

through a dryer during this verification 

test, you must verify that the water 

content of the humidified test gas 

downstream of the vessel meets the 

requirement in paragraph (d)(2) of this 

section based on either direct 

measurement of the water content (e.g., 

dewpoint and pressure) or an estimate 

based on the vessel pressure and 

temperature. Use good engineering 

judgment to estimate the water content. 

For example, you may use previous 

direct measurements of water content to 

verify the vessel’s level of saturation. 

(5) If a sample dryer is not used in this 

verification test, use good engineering 

judgment to prevent condensation in the 

transfer lines, fittings, or valves from the 

point where xH2O is measured to the 

analyzer. We recommend that you 

design your system so the wall 

temperatures in the transfer lines, 

fittings, and valves from the point where 

xH2O is measured to the analyzer are at 


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least 5 °C above the local sample gas 

dewpoint. 

(6) Allow time for the analyzer 

response to stabilize. Stabilization time 

may include time to purge the transfer 

line and to account for analyzer 

response. 

(7) While the analyzer measures the 

sample’s concentration, record 30 

seconds of sampled data. Calculate the 

arithmetic mean of this data. The 

analyzer meets the interference 

verification if this value is within (0 

±0.4) mmol/mol. 

■ 291. Section 1065.355 is amended by 

revising paragraphs (d) and (e)(1) to read 

as follows: 

§ 1065.355 H2O and CO2 interference 

verification for CO NDIR analyzers. 

* * * * * 

(d) Procedure. Perform the 

interference verification as follows: 

(1) Start, operate, zero, and span the 

CO NDIR analyzer as you would before 

an emission test. If the sample is passed 

through a dryer during emission testing, 

you may run this verification test with 

the dryer if it meets the requirements of 

§ 1065.342. Operate the dryer at the 

same conditions as you will for an 

emission test. You may also run this 

verification test without the sample 

dryer. 

(2) Create a humidified CO2 test gas 

by bubbling a CO2 span gas that meets 

the specifications in § 1065.750 through 

distilled water in a sealed vessel. If the 

sample is not passed through a dryer 

during emission testing, control the 

vessel temperature to generate an H2O 

level at least as high as the maximum 

expected during emission testing. If the 

sample is passed through a dryer during 

emission testing, control the vessel 

temperature to generate an H2O level at 

least as high as the level determined in 

§ 1065.145(e)(2) for that dryer. Use a 

CO2 span gas concentration at least as 

high as the maximum expected during 

testing. 

(3) Introduce the humidified CO2 test 

gas into the sample system. You may 

introduce it downstream of any sample 

dryer, if one is used during testing. 

(4) If the sample is not passed through 

a dryer during this verification test, 

measure the water mole fraction, xH2O,

of the humidified CO2 test gas as close 

as possible to the inlet of the analyzer. 

For example, measure dewpoint, Tdew,

and absolute pressure, ptotal, to calculate 

xH2O. Verify that the water content meets 

the requirement in paragraph (d)(2) of 

this section. If the sample is passed 

through a dryer during this verification 

test, you must verify that the water 

content of the humidified test gas 

downstream of the vessel meets the 

requirement in paragraph (d)(2) of this 

section based on either direct 

measurement of the water content (e.g., 

dewpoint and pressure) or an estimate 

based on the vessel pressure and 

temperature. Use good engineering 

judgment to estimate the water content. 

For example, you may use previous 

direct measurements of water content to 

verify the vessel’s level of saturation. 

(5) If a sample dryer is not used in this 

verification test, use good engineering 

judgment to prevent condensation in the 

transfer lines, fittings, or valves from the 

point where xH2O is measured to the 

analyzer. We recommend that you 

design your system so that the wall 

temperatures in the transfer lines, 

fittings, and valves from the point where 

xH2O is measured to the analyzer are at 

least 5 °C above the local sample gas 

dewpoint. 

(6) Allow time for the analyzer 

response to stabilize. Stabilization time 

may include time to purge the transfer 

line and to account for analyzer 

response. 

(7) While the analyzer measures the 

sample’s concentration, record its 

output for 30 seconds. Calculate the 

arithmetic mean of this data. 

(8) The analyzer meets the 

interference verification if the result of 

paragraph (d)(7) of this section meets 

the tolerance in paragraph (c) of this 

section. 

(9) You may also run interference 

procedures for CO2 and H2O separately. 

If the CO2 and H2O levels used are 

higher than the maximum levels 

expected during testing, you may scale 

down each observed interference value 

by multiplying the observed 

interference by the ratio of the 

maximum expected concentration value 

to the actual value used during this 

procedure. You may run separate 

interference concentrations of H2O 

(down to 0.025 mol/mol H2O content) 

that are lower than the maximum levels 

expected during testing, but you must 

scale up the observed H2O interference 

by multiplying the observed 

interference by the ratio of the 

maximum expected H2O concentration 

value to the actual value used during 

this procedure. The sum of the two 

scaled interference values must meet the 

tolerance in paragraph (c) of this 

section. 

(e) * * * 

(1) You may omit this verification if 

you can show by engineering analysis 

that for your CO sampling system and 

your emission-calculation procedures, 

the combined CO2 and H2O interference 

for your CO NDIR analyzer always 

affects your brake-specific CO emission 

results within ±0.5% of the applicable 

CO standard. 

* * * * * 

■ 292. Section 1065.360 is amended by 

revising paragraph (e)(2) to read as 

follows: 

§ 1065.360 FID optimization and 

verification. 

* * * * * 

(e) * * * 

(2) If RFCH4[THC-FID] is not within the 

tolerance specified in this paragraph (e), 

re-optimize the FID response as 

described in paragraph (c) of this 

section. 

* * * * * 

■ 293. Section 1065.370 is amended by 

revising paragraphs (e)(5) and (g)(1) to 

read as follows: 

§ 1065.370 CLD CO2 and H2O quench 

verification. 

* * * * * 

(e) * * * 

(5) Humidify the NO span gas by 

bubbling it through distilled water in a 

sealed vessel. If the humidified NO span 

gas sample does not pass through a 

sample dryer for this verification test, 

control the vessel temperature to 

generate an H2O level approximately 

equal to the maximum mole fraction of 

H2O expected during emission testing. If 

the humidified NO span gas sample 

does not pass through a sample dryer, 

the quench verification calculations in 

§ 1065.675 scale the measured H2O 

quench to the highest mole fraction of 

H2O expected during emission testing. If 

the humidified NO span gas sample 

passes through a dryer for this 

verification test, control the vessel 

temperature to generate an H2O level at 

least as high as the level determined in 

§ 1065.145(e)(2). For this case, the 

quench verification calculations in 

§ 1065.675 do not scale the measured 

H2O quench. 

* * * * * 

(g) * * * 

(1) You may omit this verification if 

you can show by engineering analysis 

that for your NOX sampling system and 

your emission calculation procedures, 

the combined CO2 and H2O interference 

for your NOX CLD analyzer always 

affects your brake-specific NOX

emission results within no more than 

±1.0% of the applicable NOX standard. 

If you certify to a combined emission 

standard (such as a NOX + NMHC 

standard), scale your NOX results to the 

combined standard based on the 

measured results (after incorporating 

deterioration factors, if applicable). For 

example, if your final NOX + NMHC 

value is half of the emission standard, 


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23042 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

double the NOX result to estimate the 

level of NOX emissions corresponding to 

the applicable standard. 

* * * * * 

■ 294. Section 1065.390 is amended by 

revising paragraph (d)(9) to read as 

follows: 

§ 1065.390 PM balance verifications and 

weighing process verification. 

* * * * * 

(d) * * * 

(9) If any of the reference filters’ 

observed mass changes by more than 

that allowed under this paragraph, you 

must invalidate all PM mass 

determinations made since the last 

successful reference media (e.g. filter) 

mass validation. You may discard 

reference PM media (e.g. filters) if only 

one of the filter’s mass changes by more 

than the allowable amount and you can 

positively identify a special cause for 

that filter’s mass change that would not 

have affected other in-process filters. 

Thus, the validation can be considered 

a success. In this case, you do not have 

to include the contaminated reference 

media when determining compliance 

with paragraph (d)(10) of this section, 

but the affected reference filter must be 

immediately discarded and replaced 

prior to the next weighing session. 

* * * * * 

Subpart F—[Amended] 

■ 295. Section 1065.501 is amended by 

revising paragraph (b)(2) to read as 

follows: 

§ 1065.501 Overview. 

* * * * * 

(b) * * * 

(2) Steady-state cycles. Steady-state 

duty cycles are typically specified in the 

standard-setting part as a list of discrete 

operating points (modes or notches), 

where each operating point has one 

value of a normalized speed command 

and one value of a normalized torque (or 

power) command. Ramped-modal 

cycles for steady-state testing also list 

test times for each mode and transition 

times between modes where speed and 

torque are linearly ramped between 

modes, even for cycles with % power. 

Start a steady-state cycle as a hot 

running test, where you start to measure 

emissions after an engine is started, 

warmed up and running. You may run 

a steady-state duty cycle as a discretemode cycle or a ramped-modal cycle, as 

follows: 

(i) Discrete-mode cycles. Before 

emission sampling, stabilize an engine 

at the first discrete mode. Sample 

emissions and other parameters for that 

mode in the same manner as a transient 

cycle, with the exception that reference 

speed and torque values are constant. 

Record mean values for that mode, and 

then stabilize the engine at the next 

mode. Continue to sample each mode 

discretely as separate test intervals and 

calculate weighted emission results 

according to the standard-setting part. 

(ii) Ramped-modal cycles. Perform 

ramped-modal cycles similar to the way 

you would perform transient cycles, 

except that ramped-modal cycles 

involve mostly steady-state engine 

operation. Generate a ramped-modal 

duty cycle as a sequence of second-bysecond (1 Hz) reference speed and 

torque points. Run the ramped-modal 

duty cycle in the same manner as a 

transient cycle and use the 1 Hz 

reference speed and torque values to 

validate the cycle, even for cycles with 

% power. Proportionally sample 

emissions and other parameters during 

the cycle and use the calculations in 

subpart G of this part to calculate 

emissions. 

* * * * * 

■ 296. Section 1065.510 is amended by 

revising paragraphs (b)(5) and (d)(5) to 

read as follows: 

§ 1065.510 Engine mapping. 

* * * * * 

(b) * * * 

(5) Perform one of the following: 

(i) For any engine subject only to 

steady-state duty cycles (i.e., discretemode or ramped-modal), you may 

perform an engine map by using 

discrete speeds. Select at least 20 evenly 

spaced setpoints from 95% of warm idle 

speed to the highest speed above 

maximum power at which 50% of 

maximum power occurs. We refer to 

this 50% speed as the check point speed 

as described in paragraph (b)(5)(iii) of 

this section. At each setpoint, stabilize 

speed and allow torque to stabilize. 

Record the mean speed and torque at 

each setpoint. We recommend that you 

stabilize an engine for at least 15 

seconds at each setpoint and record the 

mean feedback speed and torque of the 

last (4 to 6) seconds. Use linear 

interpolation to determine intermediate 

speeds and torques. Use this series of 

speeds and torques to generate the 

power map as described in paragraph (e) 

of this section. 

(ii) For any variable-speed engine, you 

may perform an engine map by using a 

continuous sweep of speed by 

continuing to record the mean feedback 

speed and torque at 1 Hz or more 

frequently and increasing speed at a 

constant rate such that it takes (4 to 6) 

min to sweep from 95% of warm idle 

speed to the check point speed as 

described in paragraph (b)(5)(iii) of this 

section. Use good engineering judgment 

to determine when to stop recording 

data to ensure that the sweep is 

complete. In most cases, this means that 

you can stop the sweep at any point 

after the power falls to 50% of the 

maximum value. From the series of 

mean speed and maximum torque 

values, use linear interpolation to 

determine intermediate values. Use this 

series of speeds and torques to generate 

the power map as described in 

paragraph (e) of this section. 

(iii) The check point speed of the map 

is the highest speed above maximum 

power at which 50% of maximum 

power occurs. If this speed is unsafe or 

unachievable (e.g., for ungoverned 

engines or engines that do not operate 

at that point), use good engineering 

judgment to map up to the maximum 

safe speed or maximum achievable 

speed. For discrete mapping, if the 

engine cannot be mapped to the check 

point speed, make sure the map 

includes at least 20 points from 95% of 

warm idle to the maximum mapped 

speed. For continuous mapping, if the 

engine cannot be mapped to the check 

point speed, verify that the sweep time 

from 95% of warm idle to the maximum 

mapped speed is (4 to 6) min. 

(iv) Note that under § 1065.10(c)(1) we 

may allow you to disregard portions of 

the map when selecting maximum test 

speed if the specified procedure would 

result in a duty cycle that does not 

represent in-use operation. 

* * * * * 

(d) * * * 

(5) Record at 1 Hz the mean of 

feedback speed and torque. Use the 

dynamometer to increase torque at a 

constant rate. Unless the standardsetting part specifies otherwise, 

complete the map such that it takes (2 

to 4) min to sweep from no-load 

governed speed to the speed below 

maximum mapped power at which the 

engine develops 90% of maximum 

mapped power. You may map your 

engine to lower speeds. Stop recording 

after you complete the sweep. Use this 

series of speeds and torques to generate 

the power map as described in 

paragraph (e) of this section. 

* * * * * 

■ 297. Section 1065.514 is amended by 

revising paragraph (d) and Table 1 of 

§ 1065.514 to read as follows: 

§ 1065.514 Cycle-validation criteria for 

operation over specified duty cycles. 

* * * * * 

(d) Omitting additional points. 

Besides engine cranking, you may omit 

additional points from cycle-validation 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23043 

statistics as described in the following 

table: 

TABLE 1 OF § 1065.514—PERMISSIBLE CRITERIA FOR OMITTING POINTS FROM DUTY-CYCLE REGRESSION STATISTICS

When operator demand is at 

its . . . you may omit . . . if . . . 

For reference duty cycles that are specified in terms of speed and torque (fnref, Tref) 

minimum ............................... power and torque ............... Tref < 0% (motoring). 

minimum ............................... power and speed ............... fnref = 0% (idle speed) and Tref = 0% (idle torque) and Tref ¥ (2% · Tmax mapped) < 

T < Tref + (2% · Tmax mapped). 

minimum ............................... power and either torque or 

speed.

fn >fnref or T > Tref but not if fn > (fnref · 102%) and T >Tref ± (2% · Tmax mapped). 

maximum .............................. power and either torque or 

speed.

fn < fnref or T < Tref but not if fn < (fnref · 98%) and T < Tref ¥ (2% · Tmax mapped). 

For reference duty cycles that are specified in terms of speed and power (fnref, Pref) 

minimum ............................... power and torque ............... Pref < 0% (motoring). 

minimum ............................... power and speed ............... fnref = 0% (idle speed) and Pref = 0% (idle power) and Pref ¥ (2% · Pmax mapped) < 

P < Pref + (2% · Pmax mapped). 

minimum ............................... power and either torque or 

speed.

fn >fnref or P > Pref but not if fn > (fnref · 102%) and P >Pref + (2% · Pmax mapped). 

maximum .............................. power and either torque or 

speed.

fn < fnref or P < Pref but not if fn < (fnref · 98%) and P < Pref ¥ (2% · Pmax mapped). 

* * * * * 

■ 298. Section 1065.520 is amended by 

revising paragraphs (b) and (g) 

introductory text to read as follows: 

§ 1065.520 Pre-test verification procedures 

and pre-test data collection. 

* * * * * 

(b) Unless the standard-setting part 

specifies different tolerances, verify at 

some point before the test that ambient 

conditions are within the tolerances 

specified in this paragraph (b). For 

purposes of this paragraph (b), ‘‘before 

the test’’ means any time from a point 

just prior to engine starting (excluding 

engine restarts) to the point at which 

emission sampling begins. 

(1) Ambient temperature of (20 to 30) 

°C. See § 1065.530(j) for circumstances 

under which ambient temperatures 

must remain within this range during 

the test. 

(2) Atmospheric pressure of (80.000 to 

103.325) kPa and within ±5 kPa of the 

value recorded at the time of the last 

engine map. You are not required to 

verify atmospheric pressure prior to a 

hot start test interval for testing that also 

includes a cold start. 

(3) Dilution air conditions as specified 

in § 1065.140, except in cases where you 

preheat your CVS before a cold start 

test. We recommend verifying dilution 

air conditions just prior to the start of 

each test interval. 

* * * * * 

(g) Verify the amount of nonmethane 

contamination in the exhaust and 

background HC sampling systems 

within 8 hours before the start of the 

first test interval of each duty-cycle 

sequence for laboratory tests. You may 

verify the contamination of a 

background HC sampling system by 

reading the last bag fill and purge using 

zero gas. For any NMHC measurement 

system that involves separately 

measuring methane and subtracting it 

from a THC measurement, verify the 

amount of THC contamination using 

only the THC analyzer response. There 

is no need to operate any separate 

methane analyzer for this verification, 

however you may measure and correct 

for THC contamination in the CH4

sample train for the cases where NMHC 

is determined by subtracting CH4 from 

THC, using an NMC as configured in 

§ 1065.365(d), (e), and (f); and the 

calculations in § 1065.660(b)(2). Perform 

this verification as follows: 

* * * * * 

■ 299. Section 1065.530 is amended by 

revising paragraphs (g)(3)(iv), (g)(4)(i), 

and (j) to read as follows: 

§ 1065.530 Emission test sequence. 

* * * * * 

(g) * * * 

(3) * * * 

(iv) Analyze non-conventional 

gaseous batch samples, such as ethanol 

(NMHCE) as soon as practical using 

good engineering judgment. 

(4) * * * 

(i) For batch and continuous gas 

analyzers, record the mean analyzer 

value after stabilizing a zero gas to the 

analyzer. Stabilization may include time 

to purge the analyzer of any sample gas, 

plus any additional time to account for 

analyzer response. 

* * * * * 

(j) Measure and record ambient 

temperature, pressure, and humidity, as 

appropriate. For testing the following 

engines, you must record ambient 

temperature continuously to verify that 

it remains within the pre-test 

temperature range as specified in 

§ 1065.520(b): 

(1) Air-cooled engines. 

(2) Engines equipped with auxiliary 

emission control devices that sense and 

respond to ambient temperature. 

(3) Any other engine for which good 

engineering judgment indicates this is 

necessary to remain consistent with 

§ 1065.10(c)(1). 

■ 300. Section 1065.545 is amended by 

revising the section heading and 

removing paragraph (d) to read as 

follows: 

§ 1065.545 Validation of proportional flow 

control for batch sampling. 

* * * * * 

■ 301. A new § 1065.546 is added to 

subpart F to read as follows: 

§ 1065.546 Validation of minimum dilution 

ratio for PM batch sampling. 

Use continuous flows and/or tracer 

gas concentrations for transient and 

ramped modal cycles to validate the 

minimum dilution ratios for PM batch 

sampling as specified in § 1065.140(e)(2) 

over the test interval. You may use 

mode-average values instead of 

continuous measurements for discrete 

mode steady-state duty cycles. 

Determine the minimum primary and 

minimum overall dilution ratios using 

one of the following methods (you may 


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23044 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

use a different method for each stage of 

dilution): 

(a) Determine minimum dilution ratio 

based on molar flow data. This involves 

determination of at least two of the 

following three quantities: Raw exhaust 

flow (or previously diluted flow), 

dilution air flow, and dilute exhaust 

flow. You may determine the raw 

exhaust flow rate based on the measured 

intake air molar flow rate and the 

chemical balance terms in § 1065.655. 

You may alternatively estimate the 

molar raw exhaust flow rate based on 

intake air, fuel rate measurements, and 

fuel properties, consistent with good 

engineering judgment. 

(b) Determine minimum dilution ratio 

based on tracer gas (e.g., CO2) 

concentrations in the raw (or previously 

diluted) and dilute exhaust corrected for 

any removed water. 

(c) Use good engineering judgment to 

develop your own method of 

determining dilution ratios. 

■ 302. Section 1065.550 is amended by 

revising paragraph (b)(2) and adding 

paragraph (b)(3) to read as follows: 

§ 1065.550 Gas analyzer range validation, 

drift validation, and drift correction. 

* * * * * 

(b) * * * 

(2) For standards consisting of 

multiple emission mass measurements 

(such as NMHC + NOX or separate NO 

and NO2 measurements to comply with 

a NOX standard), the duty cycle shall be 

validated for drift if you satisfy one of 

the following: 

(i) For each test interval of the duty 

cycle and for each individual mass, the 

difference between the uncorrected and 

the corrected brake-specific emission 

values over the test interval is within 

±4% of the uncorrected value; or 

(ii) For the entire duty cycle the 

difference between the combined (e.g. 

NMHC + NOX) uncorrected and 

combined (e.g. NMHC + NOX) corrected 

composite brake-specific emissions 

values over the entire duty cycle is 

within ±4% of the uncorrected value or 

the applicable emissions standard, 

whichever is greater. 

(3) If the test is not validated for drift, 

you may consider the test results for the 

duty cycle to be valid only if, using 

good engineering judgment, the 

observed drift does not affect your 

ability to demonstrate compliance with 

the applicable emission standards. For 

example, if the drift-corrected value is 

less than the standard by at least two 

times the absolute difference between 

the uncorrected and corrected values, 

you may consider the data to be valid 

for demonstrating compliance with the 

applicable standard. 

* * * * * 

Subpart G—[Amended] 

■ 303. Section 1065.601 is amended by 

revising paragraph (b) to read as follows: 

§ 1065.601 Overview. 

* * * * * 

(b) You may use data from multiple 

systems to calculate test results for a 

single emission test, consistent with 

good engineering judgment. You may 

also make multiple measurements from 

a single batch sample, such as multiple 

weighings of a PM filter or multiple 

readings from a bag sample. You may 

not use test results from multiple 

emission tests to report emissions. We 

allow weighted means where 

appropriate. You may discard statistical 

outliers, but you must report all results. 

* * * * * 

■ 304. Section 1065.602 is amended by 

revising paragraphs (b), (e), and (l)(1)(iii) 

to read as follows: 

§ 1065.602 Statistics. 

* * * * * 

(b) Arithmetic mean. Calculate an 

arithmetic mean, y ̄, as follows: 

y =

y

N

N

i

i=1

∑

Eq. 1065.602-1

Example: 

N = 3 

y1 = 10.60 

y2 = 11.91 

yN = y3 = 11.09 

y =

10.60 + 11.91 + 11.09

3

y ̄ = 11.20 

* * * * * 

(e) Accuracy. Determine accuracy as 

described in this paragraph (e). Make 

multiple measurements of a standard 

quantity to create a set of observed 

values, yi, and compare each observed 

value to the known value of the 

standard quantity. The standard 

quantity may have a single known 

value, such as a gas standard, or a set 

of known values of negligible range, 

such as a known applied pressure 

produced by a calibration device during 

repeated applications. The known value 

of the standard quantity is represented 

by yrefi . If you use a standard quantity 

with a single value, yrefi would be 

constant. Calculate an accuracy value as 

follows: 

accuracy = N y y

N 1

i ref

i=1 i ∑( ) − Eq. 1065.602-4

Example: 

yref = 1800.0 

N = 3 

y1 = 1806.4 

y2 = 1803.1 

y3 = 1798.9 

accuracy = −+−+−

1

3

(( . . ) ( . . ) ( . . 1806 4 1800 0 1803 1 1800 0 1798 9 1800 0))

accuracy = + +−

1

3

(( . ) ( . ) ( . )) 64 31 11

accuracy = 2.8 

* * * * * 

(l) * * * 

(1) * * * 

(iii) Use your estimated values as 

described in the following example 

calculation: 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23045 

x

e W

Mn t

P PP

P

exp

ref

exhmax duty cycle

ref frict max

m

= ⋅

⋅⋅ ⋅ + ⋅ ( )

std

Δ

ax

⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟

Eq. 1065.602-13

n

pV f N

R T exhmax

disp nmax

stroke

V

max

=

⋅⋅ ⋅ ⋅

⋅

max

2

η

Eq. 1065.602-14

Example: 

eNOx = 2.5 g/(kW·hr) 

Wref = 11.883 kW·hr 

MNOx = 46.0055 g/mol = 46.0055·10¥6 g/μmol 

Dtdutycycle = 20 min = 1200 s 

P ̄ ref = 35.65 kW 

P ̄ frict = 15% 

Pmax = 125 kW 

pmax = 300 kPa = 300000 Pa 

Vdisp = 3.0 l = 0.0030 m3

fnmax = 2800 rev/min = 46.67 rev/s 

Nstroke = 4 1/rev 

hV = 0.9 

R = 8.314472 J/(mol·K) 

Tmax = 348.15 K 

nexhmax =

⋅ ⋅ ⋅⋅

⋅

300000 0 0030 46 67 2

4

0 9

8 314472 348 15

. ..

. .

n ̇ exhmax = 6.53 mol/s 

x = exp

2.5 ⋅

⋅⋅⋅ ⋅ − ⎛ + ⋅

11 883

46 0055 10 6 53 1200 35 65 0 15 125

125

6

.

. . . (. )

⎝

⎜ ⎞

⎠

⎟

x ̄ exp = 189.4 μmol/mol 

* * * * * 

■ 305. Section 1065.610 is amended by 

revising paragraph (c)(3) introductory 

text to read as follows: 

§ 1065.610 Duty cycle generation. 

* * * * * 

(c) * * * 

(3) Intermediate speed. If your 

normalized duty cycle specifies a speed 

as ‘‘intermediate speed,’’ use your 

torque-versus-speed curve to determine 

the speed at which maximum torque 

occurs. This is peak torque speed. If 

maximum torque occurs in a flat region 

of the torque-versus-speed curve, your 

peak torque speed is the midpoint 

between the lowest and highest speeds 

at which the trace reaches the flat 

region. For purposes of this paragraph 

(c)(3), a flat region is one in which 

measured torque values are within 2.0% 

of the maximum recorded value. 

Identify your reference intermediate 

speed as one of the following values: 

* * * * * 

■ 306. Section 1065.640 is amended as 

follows: 

■ a. By revising paragraphs (b)(1), (b)(5), 

and Table 1 of § 1065.640. 

■ b. By revising paragraphs (c)(3), (c)(4) 

introductory text, and (c)(4)(i). 

■ c. By revising paragraph (c)(5), (d)(1) 

(including Table 4 of § 1065.640), and 

(e)(3). 

§ 1065.640 Flow meter calibration 

calculations. 

* * * * * 

(b) * * * 

(1) PDP volume pumped per 

revolution, Vrev (m3/rev): 

V

n RT

P f rev

in nPDP

= ⋅ ⋅

⋅

ref in Eq. 1065.640-2

Example: 

n

Ôref = 25.096 mol/s 

R = 8.314472 J/(mol·K) 

T ̄ in = 299.5 K 

P ̄ in = 98290 Pa 

f

 ̄

nPDP = 1205.1 rev/min = 20.085 rev/s 

Vrev = ⋅ ⋅

⋅

25 096 8 314472 299 5

98290 20 085

.. .

.

Vrev = 0.03166 m3/rev 

* * * * * 

(5) The following example illustrates 

these calculations: 

TABLE 1 OF § 1065.640—EXAMPLE OF

PDP CALIBRATION DATA

f

 ̄

nPDP

(rev/min) 

a1

(m3/min) 

a0

(m3/rev) 

755.0 ................. 50.43 0.056 

987.6 ................. 49.86 ¥0.013 

1254.5 ............... 48.54 0.028 

1401.3 ............... 47.30 ¥0.061 

* * * * * 

(c) * * * 

(3) Calculate r as follows: 

(i) For SSV systems only, calculate 

rSSV using the following equation: 

r p

p SSV

SSV

in

= −1

Δ

Eq. 1065.640-7

Where: 

DpSSV = Differential static pressure; venturi 

inlet minus venturi throat. 

(ii) For CFV systems only, calculate 

rCFV iteratively using the following 

equation: 

r r CFV

4

CFV

1 2

1

2

1

2

−

+ ⎛ −

⎝

⎜ ⎞

⎠

⎟ ⋅⋅ = +

γ

γ γ γ γ β Eq. 1065.640-8

(4) You may make any of the 

following simplifying assumptions of 

the governing equations, or you may use 

good engineering judgment to develop 

more appropriate values for your 

testing: 

(i) For emission testing over the full 

ranges of raw exhaust, diluted exhaust 

and dilution air, you may assume that 


ER30AP10.008</MATH> ER30AP10.009</MATH> ER30AP10.010</MATH> ER30AP10.011</MATH> ER30AP10.012</MATH> ER30AP10.013</MATH> ER30AP10.014</MATH> ER30AP10.015</MATH>wwoods2 on DSK1DXX6B1PROD with RULES_2
23046 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

the gas mixture behaves as an ideal gas: 

Z = 1. 

* * * * * 

(5) The following example illustrates 

the use of the governing equations to 

calculate the discharge coefficient, Cd of 

an SSV flow meter at one reference flow 

meter value. Note that calculating Cd for 

a CFV flow meter would be similar, 

except that Cf would be determined 

from Table 2 of this section or 

calculated iteratively using values of β 

and γ as described in paragraph (c)(2) of 

this section. 

Example: 

n

Ôref= 57.625 mol/s 

Z = 1 

Mmix = 28.7805 g/mol = 0.0287805 kg/mol 

R = 8.314472 J/(mol·K) 

Tin = 298.15 K 

At = 0.01824 m2

pin = 99132.0 Pa 

γ = 1.399 

β = 0.8 

Dp = 2.312 kPa 

rSSV =− = 1 2 312

99 132

0 977 .

. .

Cf =

⋅⋅ −

⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟

−⋅ −

−

2 1 399 0 977 1

1 399 1 0 8 0 977

1 399 1

1 399

4

. .

(. ) . .

.

.

− ⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟

⎡

⎣

⎢

⎢

⎢

⎢

⎢

⎢

⎤

⎦

⎥

⎥

⎥

⎥

⎥

⎥

2

1 399

1

2

.

Cf = 0.274 

Cd = ⋅ ⋅ ⋅⋅

⋅ ⋅ 57 625

1 0 0287805 8 314472 298 15

0 274 0 01824 99132 0 . .. ... .

Cd = 0.981 

(d) * * * 

(1) Calculate the Reynolds number, 

Re#, for each reference molar flow rate, 

using the throat diameter of the venturi, 

dt. Because the dynamic viscosity, μ, is 

needed to compute Re#, you may use 

your own fluid viscosity model to 

determine μ for your calibration gas 

(usually air), using good engineering 

judgment. Alternatively, you may use 

the Sutherland three-coefficient 

viscosity model to approximate μ, as 

shown in the following sample 

calculation for Re#: 

Re

M n

d

# = ⋅ ⋅

⋅ ⋅

4 mix ref

t



π μ

Eq. 1065.640-10

Where, using the Sutherland threecoefficient viscosity model: 

μ μ = ⋅⎛

⎝

⎜ ⎞

⎠

⎟ ⋅ +

+

⎛

⎝

⎜ ⎞

⎠ 0 ⎟

3

T 2

T

T S

T S

in

0

0

in

Eq. 1065.640-11

Where: 

μ = Dynamic viscosity of calibration gas. 

μ0 = Sutherland reference viscosity. 

T0 = Sutherland reference temperature. 

S = Sutherland constant. 

TABLE 4 OF § 1065.640—SUTHERLAND THREE-COEFFICIENT VISCOSITY MODEL PARAMETERS

Gas a

μ0 T0 S Temp range 

within ± 2% 

error 

Pressure 

limit 

kg/(m·s) K K 

K kPa 

Air ..................................................................................................... 1.716·10¥5 273 111 170 to 1,900 ≤ 1,800 

CO2 .................................................................................................. 1.370·10¥5 273 222 190 to 1,700 ≤ 3,600 

H2O .................................................................................................. 1.12·10¥5 350 1,064 360 to 1,500 ≤ 10,000 

O2 ..................................................................................................... 1.919·10¥5 273 139 190 to 2,000 ≤ 2,500 

N2 ..................................................................................................... 1.663·10¥5 273 107 100 to 1,500 ≤ 1,600 

a Use tabulated parameters only for the pure gases, as listed. Do not combine parameters in calculations to calculate viscosities of gas 

mixtures. 

Example: 

μ0 = 1.716 · 10¥5 kg/(m·s) 

T0 = 273.11 K 

S = 110.56 K 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23047 

μ =1 716 10 298 15

273 11

273 11 110 56

298 15 110

5

3

2

. .

.

. .

. . ⋅ ⋅⎛

⎝

⎜ ⎞

⎠

⎟ ⋅ +

+

−

56

⎛

⎝

⎜ ⎞

⎠

⎟

μ = 1.837·10¥5 kg/(m·s) 

Mmix = 28.7805 g/mol 

n ̇ ref = 57.625 mol/s 

dt = 152.4 mm 

Tin = 298.15 K 

Re# . .

. .. = ⋅ ⋅⋅⋅⋅ −

4 28 7805 57 625

3 14159 152 4 1 837 10 5

Re# = 7.541·105

* * * * * 

(e) * * * 

(3) If the standard deviation of all the 

Cd values is less than or equal to 0.3% 

of the mean Cd, use the mean Cd in Eq 

1065.642–6, and use the CFV only down 

to the lowest r measured during 

calibration using the following equation: 

r p

p = −1

Δ CFV

in

Eq. 1065.640-13

Where: 

DpCFV = Differential static pressure; venturi 

inlet minus venturi outlet. 

* * * * * 

■ 307. Section 1065.642 is revised to 

read as follows: 

§ 1065.642 SSV, CFV, and PDP molar flow 

rate calculations. 

This section describes the equations 

for calculating molar flow rates from 

various flow meters. After you calibrate 

a flow meter according to § 1065.640, 

use the calculations described in this 

section to calculate flow during an 

emission test. 

(a) PDP molar flow rate. Based upon 

the speed at which you operate the PDP 

for a test interval, select the 

corresponding slope, a1, and intercept, 

a0, as calculated in § 1065.640, to 

calculate molar flow rate, n ̇ as follows: 

n= f p V

R T nPDP ⋅ ⋅

⋅

in rev

in

Eq. 1065.642-1

Where: 

V

a

f

p p

p

a rev

nPDP

out in

out

= ⋅ − + 1

0 Eq. 1065.642-2

Example: 

a1 = 50.43 (m3/min) = 0.8405 (m3/s) 

f

 ̄

nPDP = 755.0 rev/min = 12.58 rev/s 

pout = 99950 Pa 

pin = 98575 Pa 

a0 = 0.056 (m3/rev) 

R = 8.314472 J/(mol·K) 

Tin = 323.5 K 

Cp = 1000 (J/m3)/kPa 

Ct = 60 s/min 

Vrev = ⋅ − +

0 8405

12 58

99950 98575

99950

0 056 .

. .

Vrev = 0.06383 m3/rev 

n= ⋅ ⋅

⋅ 12 58 98575 0 063838 314472 323 5 . .. .

n ̇ = 29.428 mol/s 

(b) SSV molar flow rate. Based on the 

Cd versus Re# equation you determined 

according to § 1065.640, calculate SSV 

molar flow rate, n ̇ during an emission 

test as follows: 

nCC A p

Z M RT =⋅⋅ ⋅⋅ ⋅⋅ d f

in

t in

mix

Eq. 1065.642-3

Example: 

At = 0.01824 m2

pin = 99132 Pa 

Z = 1 

Mmix = 28.7805 g/mol = 0.0287805 kg/mol 

R = 8.314472 J/(mol.K) 

Tin = 298.15 K 

Re# = 7.232.

105

γ = 1.399 

β = 0.8 

Dp = 2.312 kPa 

Using Eq. 1065.640–7, 

rssv = 0.997 

Using Eq. 1065.640–6, 

Cf = 0.274 

Using Eq. 1065.640–5, 

Cd = 0.990 

n=⋅⋅ ⋅

⋅ ⋅⋅ 0 990 0 274 0 01824 991321 0 0287805 8 314472 298 15 . . ... .

n ̇ = 58.173 mol/s 

(c) CFV molar flow rate. Some CFV 

flow meters consist of a single venturi 

and some consist of multiple venturis, 

where different combinations of 

venturis are used to meter different flow 

rates. If you use multiple venturis and 

you calibrated each venturi 

independently to determine a separate 

discharge coefficient, Cd, for each 

venturi, calculate the individual molar 

flow rates through each venturi and sum 

all their flow rates to determine n ̇ . If you 

use multiple venturis and you calibrated 

each combination of venturis, calculate 

n ̇ using the sum of the active venturi 

throat areas as At, the sum of the active 

venturi throat diameters as dt, and the 

ratio of venturi throat to inlet diameters 

as the ratio of the sum of the active 

venturi throat diameters to the diameter 

of the common entrance to all of the 

venturis. To calculate the molar flow 

rate through one venturi or one 

combination of venturis, use its 

respective mean Cd and other constants 

you determined according to § 1065.640 

and calculate its molar flow rate n ̇

during an emission test, as follows: 


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23048 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

nCC A p

Z M RT =⋅⋅ ⋅⋅ ⋅⋅ d f

in

t in

mix

Eq. 1065.642-4

Example: 

Cd = 0.985 

Cf = 0.7219 

At = 0.00456 m2

pin = 98836 Pa 

Z = 1 

Mmix = 28.7805 g/mol = 0.0287805 kg/mol 

R = 8.314472 J/(mol.

K) 

Tin = 378.15 K 

n=⋅ ⋅ ⋅

⋅ ⋅⋅ 0 985 0 7219 0 00456 988361 0 0287805 8 314472 378 15 . . ... .

n ̇ = 33.690 mol/s 

■ 308. Section 1065.645 is amended by 

revising paragraphs (a)(2), (b), and (c) to 

read as follows: 

§ 1065.645 Amount of water in an ideal 

gas. 

* * * * * 

(a) * * * 

(2) For humidity measurements over 

ice at ambient temperatures from (¥100 

to 0) °C, use the following equation: 

log . . . log 10 10 9 096853 273 16 1 3 566506 273p T sat

sat

( ) =− ⋅ − ⎛

⎝

⎜ ⎞

⎠

⎟ − ⋅ . . . . 16 0 876812 1

273 16

0 2138602

T

T

sat

sat ⎛

⎝

⎜ ⎞

⎠

⎟ + ⋅− ⎛

⎝

⎜ ⎞

⎠

⎟ − Eq. 1065.645-2

Example: 

Tice = ¥15.4 °C 

Tice = ¥15.4 + 273.15 = 257.75 K 

log . .

. . log 10 10 9 096853 273 16257 75

1 3 566506 2p( ) sat =− ⋅ − ⎛

⎝

⎜ ⎞

⎠

⎟ − ⋅ 73 16

257 75

0 876812 1 257 75

273 16

0 2138602 .

. . .. . ⎛

⎝

⎜ ⎞

⎠

⎟ + ⋅− ⎛

⎝

⎜ ⎞

⎠

⎟ −

log10(pH20) = ¥0.798207 

pH20 = 10 0.79821 = 0.159145 kPa 

(b) Dewpoint. If you measure 

humidity as a dewpoint, determine the 

amount of water in an ideal gas, xH20, as 

follows: 

x

p

p H2O

H2O

abs

= Eq. 1065.645-3

Where: 

xH20 = amount of water in an ideal gas. 

pH20 = water vapor pressure at the measured 

dewpoint, Tsat = Tdew. 

pabs = wet static absolute pressure at the 

location of your dewpoint measurement. 

Example:: 

pabs = 99.980 kPa 

Tsat = Tdew = 9.5 °C 

Using Eq. 1065.645–1, 

pH20 = 1.186581 kPa 

xH2O = 1.186581/99.980 

xH2O = 0.011868 mol/mol 

(c) Relative humidity. If you measure 

humidity as a relative humidity, RH%, 

determine the amount of water in an 

ideal gas, xH2O, as follows: 

x

RH p

p H2O

H2O

abs

= % ⋅ Eq. 1065.645-4

Where: 

xH20 = amount of water in an ideal gas. 

RH% = relative humidity. 

pH20 = water vapor pressure at 100% relative 

humidity at the location of your relative 

humidity measurement, Tsat = Tamb. 

pabs = wet static absolute pressure at the 

location of your relative humidity 

measurement. 

Example: 

RH% = 50.77% 

pabs = 99.980 kPa 

Tsat = Tamb = 20 °C 

Using Eq. 1065.645–1, 

pH20 = 2.3371 kPa 

xH2O = (50.77% · 2.3371)/99.980 

xH2O = 0.011868 mol/mol 

■ 309. Section 1065.650 is amended by 

revising paragraphs (a), (b), (c) 

introductory text, (d) introductory text, 

(d)(7), (e)(2), (f)(4), (g), and (h) to read 

as follows: 

§ 1065.650 Emission calculations. 

(a) General. Calculate brake-specific 

emissions over each applicable duty 

cycle or test interval. For test intervals 

with zero work (or power), calculate the 

emission mass (or mass rate), but do not 

calculate brake-specific emissions. For 

duty cycles with multiple test intervals, 

refer to the standard-setting part for 

calculations you need to determine a 

composite result, such as a calculation 

that weights and sums the results of 

individual test intervals in a duty cycle. 

If the standard-setting part does not 

include those calculations, use the 

equations in paragraph (g) of this 

section. This section is written based on 

rectangular integration, where each 

indexed value (i.e., ‘‘i’’) represents (or 

approximates) the mean value of the 

parameter for its respective time 

interval, delta-t. You may also integrate 

continuous signals using trapezoidal 

integration consistent with good 

engineering judgment. 

(b) Brake-specific emissions over a 

test interval. We specify three 

alternative ways to calculate brakespecific emissions over a test interval, as 

follows: 

(1) For any testing, you may calculate 

the total mass of emissions, as described 

in paragraph (c) of this section, and 

divide it by the total work generated 

over the test interval, as described in 

paragraph (d) of this section, using the 

following equation: 

e m

W

= Eq. 1065.650-1

Example: 

mNOx = 64.975 g 

W = 25.783 kW·hr 

eNOx = 64.975/25.783 

eNOx = 2.520 g/(kW·hr) 

(2) For discrete-mode steady-state 

testing, you may calculate the brakespecific emissions over a test interval 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23049 

using the ratio of emission mass rate to 

power, as described in paragraph (e) of 

this section, using the following 

equation: 

e m

P = Eq. 1065.650-2

(3) For field testing, you may calculate 

the ratio of total mass to total work, 

where these individual values are 

determined as described in paragraph (f) 

of this section. You may also use this 

approach for laboratory testing, 

consistent with good engineering 

judgment. Good engineering judgment 

dictates that this method not be used if 

there are any work flow paths described 

in § 1065.210 that cross the system 

boundary, other than the primary output 

shaft (crankshaft). This is a special case 

in which you use a signal linearly 

proportional to raw exhaust molar flow 

rate to determine a value proportional to 

total emissions. You then use the same 

linearly proportional signal to 

determine total work using a chemical 

balance of fuel, intake air, and exhaust 

as described in § 1065.655, plus 

information about your engine’s brakespecific fuel consumption. Under this 

method, flow meters need not meet 

accuracy specifications, but they must 

meet the applicable linearity and 

repeatability specifications in subpart D 

or subpart J of this part. The result is a 

brake-specific emission value calculated 

as follows: 

e = m

W



 Eq. 1065.650-3

Example: 

m ̃ = 805.5 g 

W ̃ = 52.102 kW·hr 

eCO = 805.5/52.102 

eCO = 2.520 g/(kW·hr) 

(c) Total mass of emissions over a test 

interval. To calculate the total mass of 

an emission, multiply a concentration 

by its respective flow. For all systems, 

make preliminary calculations as 

described in paragraph (c)(1) of this 

section, then use the method in 

paragraphs (c)(2) through (4) of this 

section that is appropriate for your 

system. Calculate the total mass of 

emissions as follows: 

* * * * * 

(d) Total work over a test interval. To 

calculate the total work from the engine 

over a test interval, add the total work 

from all the work paths described in 

§ 1065.210 that cross the system 

boundary including electrical energy/ 

work, mechanical shaft work, and fluid 

pumping work. For all work paths, 

except the engine’s primary output shaft 

(crankshaft), the total work for the path 

over the test interval is the integration 

of the net work flow rate (power) out of 

the system boundary. When energy/ 

work flows into the system boundary, 

this work flow rate signal becomes 

negative; in this case, include these 

negative work rate values in the 

integration to calculate total work from 

that work path. Some work paths may 

result in a negative total work. Include 

negative total work values from any 

work path in the calculated total work 

from the engine rather than setting the 

values to zero. The rest of this paragraph 

(d) describes how to calculate total work 

from the engine’s primary output shaft 

over a test interval. Before integrating 

power on the engine’s primary output 

shaft, adjust the speed and torque data 

for the time alignment used in 

§ 1065.514(c). Any advance or delay 

used on the feedback signals for cycle 

validation must also be used for 

calculating work. Account for work of 

accessories according to § 1065.110. 

Exclude any work during cranking and 

starting. Exclude work during actual 

motoring operation (negative feedback 

torques), unless the engine was 

connected to one or more energy storage 

devices. Examples of such energy 

storage devices include hybrid 

powertrain batteries and hydraulic 

accumulators, like the ones illustrated 

in Figure 1 of § 1065.210. Exclude any 

work during reference zero-load idle 

periods (0% speed or idle speed with 0 

N·m reference torque). Note, that there 

must be two consecutive reference zero 

load idle points to establish a period 

where this applies. Include work during 

idle points with simulated minimum 

torque such as Curb Idle Transmissions 

Torque (CITT) for automatic 

transmissions in ‘‘drive’’. The work 

calculation method described in 

paragraphs (b)(1) through (7) of this 

section meets these requirements using 

rectangular integration. You may use 

other logic that gives equivalent results. 

For example, you may use a trapezoidal 

integration method as described in 

paragraph (b)(8) of this section. 

* * * * * 

(7) Integrate the resulting values for 

power over the test interval. Calculate 

total work as follows: 

W t

N

= ⋅ =

∑Pi

i

Δ Eq. 1065.650-10 1

Where: 

W = total work from the primary output shaft 

Pi = instantaneous power from the primary 

output shaft over an interval i. 

PfT i ni i = ⋅ Eq. 1065.650-11

Example: 

N = 9000 

fn1 = 1800.2 rev/min 

fn2 = 1805.8 rev/min 

T1 = 177.23 N.m 

T2 = 175.00 N.m 

Crev = 2·π rad/rev 

Ct1 = 60 s/min 

Cp = 1000 (N·m·rad/s)/kW 

frecord = 5 Hz 

Ct2 = 3600 s/hr 

P1 = ⋅ ⋅⋅

⋅

1800 2 177 23 2 3 14159

60 1000

.. .

P1 = 33.41 kW 

P2 = 33.09 kW 

Using Eq. 1065.650–5, 

Dt = 1⁄5 = 0.2 s 

W

P = ( ) 33 41 33 09 0 2 + ++ ⋅

3600

. . ... . 9000

W = 16.875 kW·hr 

* * * * * 

(e) * * * 

(2) To calculate an engine’s mean 

steady-state total power, P ̄ , add the 

mean steady-state power from all the 

work paths described in § 1065.210 that 

cross the system boundary including 

electrical power, mechanical shaft 

power, and fluid pumping power. For 

all work paths, except the engine’s 

primary output shaft (crankshaft), the 

mean steady-state power over the test 

interval is the integration of the net 

work flow rate (power) out of the system 

boundary divided by the period of the 

test interval. When power flows into the 

system boundary, the power/work flow 

rate signal becomes negative; in this 

case, include these negative power/work 

rate values in the integration to 

calculate the mean power from that 

work path. Some work paths may result 

in a negative mean power. Include 

negative mean power values from any 

work path in the mean total power from 

the engine rather than setting these 

values to zero. The rest of this paragraph 

(e)(2) describes how to calculate the 

mean power from the engine’s primary 

output shaft. Calculate P ̄ using Equation 

1065.650–13, noting that P ̄ , f

 ̄

n ̄ and T ̄

refer to mean power, mean rotational 

shaft frequency, and mean torque from 

the primary output shaft. Account for 

the power of simulated accessories 

according to § 1065.110 (reducing the 

mean primary output shaft power or 

torque by the accessory power or 

torque). Set the power to zero during 

actual motoring operation (negative 

feedback torques), unless the engine was 

connected to one or more energy storage 

devices. Examples of such energy 


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23050 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

storage devices include hybrid 

powertrain batteries and hydraulic 

accumulators, like the ones illustrated 

in Figure 1 of § 1065.210. Set the power 

to zero for modes with a zero reference 

load (0 N·m reference torque or 0 kW 

reference power). Include power during 

idle modes with simulated minimum 

torque or power. 

P fT = ⋅ n Eq. 1065.650-13

* * * * * 

(f) * * * 

(4) Example. The following example shows 

how to calculate mass of emissions using 

proportional values: 

N= 3000 

frecord = 5 Hz 

efuel = 285 g/(kW·hr) 

wfuel = 0.869 g/g 

Mc = 12.0107 g/mol 

n ̇ 1= 3.922 ∼mol/s = 14119.2 mol/hr 

xCcombdry1 = 91.634 mmol/mol = 0.091634 

mol/mol 

xH2Oexh1 = 27.21 mmol/mol = 0.02721 mol/ 

mol 

Using Eq. 1065.650–5, 

Dt = 0.2 s 







W

n x

x =

⋅

+

+ ⋅ 12 0107 3 922 0 091634

1 0 02721 . . ..

2 Ccombdry2

H2Oexh 1+ 2

3000 Ccombdry3000

H2Oexh3000 1+

+ +

⎡ ⋅

⎣

⎢

⎢

⎤

⎦

⎥

⎥

⋅

⋅

... . 



n x

x

0 2

285 0.869

W= 5.09 (kW·hr) 

(g) Brake-specific emissions over a 

duty cycle with multiple test intervals. 

The standard-setting part may specify a 

duty cycle with multiple test intervals, 

such as with discrete-mode steady-state 

testing. Unless we specify otherwise, 

calculate composite brake-specific 

emissions over the duty cycle as 

described in this paragraph (g). If a 

measured mass (or mass rate) is 

negative, set it to zero for calculating 

composite brake-specific emissions, but 

leave it unchanged for drift validation. 

In the case of calculating composite 

brake-specific emissions relative to a 

combined emission standard (such as a 

NOX + NMHC standard), change any 

negative mass (or mass rate) values to 

zero for a particular pollutant before 

combining the values for the different 

pollutants. 

(1) Use the following equation to 

calculate composite brake-specific 

emissions for duty cycles with multiple 

test intervals all with prescribed 

durations, such as cold-start and hotstart transient cycles: 

e

WF m

WF W

i i

i

N

i i

i

composite N

=1

=1

=

⋅

⋅

∑

∑

Eq. 1065.650-17

Where: 

i = test interval number. 

N = number of test intervals. 

WF = weighting factor for the test interval as 

defined in the standard-setting part. 

m = mass of emissions over the test interval 

as determined in paragraph (c) of this 

section. 

W = total work from the engine over the test 

interval as determined in paragraph (d) 

of this section. 

Example: 

N = 2 

WF1 = 0.1428 

WF2 = 0.8572 

m1 = 70.125 g 

m2 = 64.975 g 

W1 = 25.783 kW·hr 

W2 = 25.783 kW·hr 

eNO composite x = ⋅+⋅

⋅

(. . ) (. . )

(. .

0 1428 70 125 0 8572 64 975

0 1428 25 783 0 8572 25 783 ) (. . ) + ⋅

eNOxcomposite = 2.548 g/kW·hr 

(2) Calculate composite brake-specific 

emissions for duty cycles with multiple 

test intervals that allow use of varying 

duration, such as discrete-mode steadystate duty cycles, as follows: 

(i) Use the following equation if you 

calculate brake-specific emissions over 

test intervals based on total mass and 

total work as described in paragraph 

(b)(1) of this section: 

e

WF m

t

WF W

t

i

i

i i

N

i

i

i i

composite N

=1

=1

=

⋅

⋅

∑

∑

Eq. 1065.650-18

Where: 

i = test interval number. 

N = number of test intervals. 

WF = weighting factor for the test interval as 

defined in the standard-setting part. 

m = mass of emissions over the test interval 

as determined in paragraph (c) of this 

section. 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23051 

W = total work from the engine over the test 

interval as determined in paragraph (d) 

of this section. 

t = duration of the test interval. 

Example: 

N = 2 

WF1 = 0.85 

WF2 = 0.15 

m1 = 1.3753 g 

m2 = 0.4135 g 

t1 = 120 s 

t2 = 200 s 

W1 = 2.8375 kW·hr 

W2 = 0.0 kW·hr 

eNO composite x =

⋅ ⎛

⎝

⎜ ⎞

⎠

⎟ + ⋅ ⎛

⎝

⎜ ⎞

⎠

⎟ 0 85 1 3753

120

0 15 0 4135

200

0 8

. . . .

. 5 2 8375

120

0 15 0 0

200 ⋅ ⎛

⎝

⎜ ⎞

⎠

⎟ + ⋅ ⎛

⎝

⎜ ⎞

⎠

⎟ . . .

eNOxcomposite = 0.5001 g/kW·hr (ii) Use the following equation if you 

calculate brake-specific emissions over 

test intervals based on the ratio of mass 

rate to power as described in paragraph 

(b)(2) of this section: 

e

WF m

WF P

i i

i

N

i i

i

composite N

=1

=1

=

⋅

⋅

∑

∑



Eq. 1065.650-19

Where: 

i = test interval number. 

N = number of test intervals. 

WF = weighting factor for the test interval as 

defined in the standard-setting part. 

m

Ô= mean steady-state mass rate of emissions 

over the test interval as determined in 

paragraph (e) of this section. 

P ̄ is the mean steady-state power over the test 

interval as described in paragraph (e) of 

this section. 

Example: 

N = 2 

WF1 = 0.85 

WF2 = 0.15 

m

Ô1 = 2.25842 g/hr 

m

Ô2 = 0.063443 g/hr 

P ̄ 1= 4.5383 kW 

P ̄ 2= 0.0 kW 

eNO composite x = ⋅ +⋅

⋅ +

(. . ) (. . )

(. . )

0 85 2 25842 0 15 0 063443

0 85 4 5383 (. .) 0 15 0 0 ⋅

eNOxcomposite = 0.5001 g/kW·hr 

(h) Rounding. Round the final brakespecific emission values to be compared 

to the applicable standard only after all 

calculations are complete (including 

any drift correction, applicable 

deterioration factors, adjustment factors, 

and allowances) and the result is in 

g/(kW·hr) or units equivalent to the 

units of the standard, such as g/(hp·hr). 

See the definition of ‘‘Round’’ in 

§ 1065.1001. 

■ 310. Section 1065.655 is amended by 

revising paragraphs (c), (d), Table 1 of 

§ 1065.655, and paragraph (e)(3) to read 

as follows: 

§ 1065.655 Chemical balances of fuel, 

intake air, and exhaust. 

* * * * * 

(c) Chemical balance procedure. The 

calculations for a chemical balance 

involve a system of equations that 

require iteration. We recommend using 

a computer to solve this system of 

equations. You must guess the initial 

values of up to three quantities: The 

amount of water in the measured flow, 

xH2Oexh, fraction of dilution air in 

diluted exhaust, xdil/exh, and the amount 

of products on a C1 basis per dry mole 

of dry measured flow, xCcombdry. You 

may use time-weighted mean values of 

combustion air humidity and dilution 

air humidity in the chemical balance; as 

long as your combustion air and 

dilution air humidities remain within 

tolerances of ±0.0025 mol/mol of their 

respective mean values over the test 

interval. For each emission 

concentration, x, and amount of water, 

xH2Oexh, you must determine their 

completely dry concentrations, xdry and 

xH2Oexhdry. You must also use your fuel’s 

atomic hydrogen-to-carbon ratio, α, 

oxygen-to-carbon ratio, β, sulfur-tocarbon ratio, γ, and nitrogen-to-carbon 

ratio, δ. You may measure α, β, γ, and 

δ or you may use default values for a 

given fuel as described in § 1065.655(d). 

Use the following steps to complete a 

chemical balance: 

(1) Convert your measured 

concentrations such as, xCO2meas, xNOmeas, 

and xH2Oint, to dry concentrations by 

dividing them by one minus the amount 

of water present during their respective 

measurements; for example: 

xH2OxCO2meas x, H2OxNOmeas, and xH2Oint. If 

the amount of water present during a 

‘‘wet’’ measurement is the same as the 

unknown amount of water in the 

exhaust flow, xH2Oexh, iteratively solve 

for that value in the system of equations. 

If you measure only total NOX and not 

NO and NO2 separately, use good 

engineering judgment to estimate a split 

in your total NOX concentration 

between NO and NO2 for the chemical 

balances. For example, if you measure 

emissions from a stoichiometric sparkignition engine, you may assume all 

NOX is NO. For a compression-ignition 

engine, you may assume that your molar 

concentration of NOX, xNOx, is 75% NO 

and 25% NO2. For NO2 storage 

aftertreatment systems, you may assume 

xNOx is 25% NO and 75% NO2. Note 

that for calculating the mass of NOX

emissions, you must use the molar mass 

of NO2 for the effective molar mass of 

all NOX species, regardless of the actual 

NO2 fraction of NOX. 

(2) Enter the equations in paragraph 

(c)(4) of this section into a computer 

program to iteratively solve for xH2Oexh, 


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23052 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

xCcombdry, and xdil/exh. Use good 

engineering judgment to guess initial 

values for xH2Oexh, xCcombdry, and xdil/exh. 

We recommend guessing an initial 

amount of water that is about twice the 

amount of water in your intake or 

dilution air. We recommend guessing an 

initial value of xCcombdry as the sum of 

your measured CO2, CO, and THC 

values. We also recommend guessing an 

initial xdil/exh between 0.75 and 0.95, 

such as 0.8. Iterate values in the system 

of equations until the most recently 

updated guesses are all within ± 1% of 

their respective most recently calculated 

values. 

(3) Use the following symbols and 

subscripts in the equations for this 

paragraph (c): 

xdil/exh = amount of dilution gas or 

excess air per mole of exhaust. 

xH2Oexh = amount of water in exhaust per 

mole of exhaust. 

xCcombdry = amount of carbon from fuel 

in the exhaust per mole of dry 

exhaust. 

xH2dry = amount of H2 in exhaust per 

amount of dry exhaust. 

KH2Ogas = water-gas reaction equilibrium 

coefficient. You may use 3.5 or 

calculate your own value using 

good engineering judgment. 

xH2Oexhdry = amount of water in exhaust 

per dry mole of dry exhaust. 

xprod/intdry = amount of dry stoichiometric 

products per dry mole of intake air. 

xdil/exhdry = amount of dilution gas and/ 

or excess air per mole of dry 

exhaust. 

xint/exhdry = amount of intake air required 

to produce actual combustion 

products per mole of dry (raw or 

diluted) exhaust. 

xraw/exhdry = amount of undiluted 

exhaust, without excess air, per 

mole of dry (raw or diluted) 

exhaust. 

xO2int = amount of intake air O2 per mole 

of intake air. 

xCO2intdry = amount of intake air CO2 per 

mole of dry intake air. You may use 

xCO2intdry = 375 μmol/mol, but we 

recommend measuring the actual 

concentration in the intake air. 

xH2Ointdry = amount of intake air H2O per 

mole of dry intake air. 

xCO2int = amount of intake air CO2 per 

mole of intake air. 

xCO2dil = amount of dilution gas CO2 per 

mole of dilution gas. 

xCO2dildry = amount of dilution gas CO2

per mole of dry dilution gas. If you 

use air as diluent, you may use 

xCO2dildry = 375 μmol/mol, but we 

recommend measuring the actual 

concentration in the intake air. 

xH2Odildry = amount of dilution gas H2O 

per mole of dry dilution gas. 

xH2Odil = amount of dilution gas H2O per 

mole of dilution gas. 

x[emission]meas = amount of measured 

emission in the sample at the 

respective gas analyzer. 

x[emission]dry = amount of emission per 

dry mole of dry sample. 

xH2O[emission]meas = amount of water in 

sample at emission-detection 

location. Measure or estimate these 

values according to 

§ 1065.145(e)(2). 

xH2Oint = amount of water in the intake 

air, based on a humidity 

measurement of intake air.nb 

α = atomic hydrogen-to-carbon ratio of 

the mixture of fuel(s) being 

combusted, weighted by molar 

consumption. 

β = atomic oxygen-to-carbon ratio of the 

mixture of fuel(s) being combusted, 

weighted by molar consumption. 

γ = atomic sulfur-to-carbon ratio of the 

mixture of fuel(s) being combusted, 

weighted by molar consumption. 

δ = atomic nitrogen-to-carbon ratio of 

the mixture of fuel(s) being 

combusted, weighted by molar 

consumption. 

(4) Use the following equations to 

iteratively solve for xdil/exh, xH2Oexh, and 

xCcombdry: 

x

x

x dil exh / = −1 raw/exhdry

H2Oexhdry 1+ Eq. 1065.655-1

x

x

x H Oexh

H Oexhdry

H Oexhdry

Eq 2

2

2 1

= +. 1065.655-2

x x x x xx x Ccombdry CO dry COdry THCdry CO dil dil exhdry CO = ++ − ⋅ − 2 22 / int int/ ⋅ x exhdry Eq. 1065.655-3

x

x x xx

K x H2dry

COdry H2Oexhdry H2Odil dil/exhdry

H2O CO

= ⋅ −⋅ ( )

⋅ -gas ( ) 2dry CO2dil dil/exhdry − ⋅ x x

Eq. 1065.655-4

x x x xx x H Oexhdry Ccombdry THCdry H Odil dil exhdry H O 2 22 2 = − ( ) +⋅ +

α / int int/ ⋅ − x x exhdry H2dry Eq. 1065.655-5

x

x

x dil exhdry

dil exh

H Oexh

/

/ =

1− 2

Eq. 1065.655-6

x

x

xx x int/

int

exhdry

O

= Ccombdry THCdry C ⋅ − ++ ⎛

⎝

⎜ ⎞

⎠

⎟( ) − − 1

2 2

2 2

2

α β γ ( ) Odry NOdry NO dry −− + ⎛

⎝

⎜ ⎞

⎠

⎟ x xx 2 2 H2dry Eq. 1065.655-7

x x x xx raw exhdry Ccombdry THCdry THCdry CO / = ++ ⎛

⎝

⎜ ⎞

⎠

⎟( ) − + +

1

2 2

2 α β δ ( ) dry NO dry exhdry − + ⎛

⎝

⎜ ⎞

⎠

xx x 2 H2dry int/ ⎟ + Eq. 1065.655-8


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23053 

x

x

x O

CO

H O

2

2

2

0 209820

1 int

. = −

+

intdry

intdry

Eq. 1065.655-9

x

x

x CO

CO

H O

2

2

2 1 int = +

intdry

intdry

Eq. 1065.655-10

x

x

x H O

H O

H O

2

2

2 1 intdry = Eq. 1065.655-11 −

int

int

x x

x CO dil

CO

H O

2

2

2 1 = +

dildry

dildry

Eq. 1065.655-12

x

x

x H Odildry

H Odil

H Odil

2

2

2 1 = − Eq. 1065.655-13

x

x

x COdry

COmeas

H OCOmeas

= 1− 2Eq. 1065.655-14

x

x

x CO dry

CO meas

H OCO meas

2

2

2 2 1 = − Eq. 1065.655-15

x

x

x NOdry

NOmeas

H ONOmeas

= 1− 2Eq. 1065.655-16

x

x

x NO dry

NO meas

H ONO meas

2

2

2 2 1 = − Eq. 1065.655-17

x

x

x THCdry

THCmeas

H OTHCmeas

= 1− 2Eq. 1065.655-18

(5) The following example is a 

solution for xdil/exh, xH2Oexh, and xCcombdry

using the equations in paragraph (c)(4) 

of this section: 

x mol/mol dil/exh = −

+

1 = 0 184

1 35 38

1000

0 822 .

. . x mmol/mol H Oexh 2

35 38

1 35 38

1000

= 34 18

+

= .

. .

xCcombdry =+ + − ⋅− 0 025 29 3

1000000

47 6

1000000

0 371

1000

0 851 0 . . .. . .369

1000 ⋅ = 0 172 0 0249 . . mol/mol

xH2dry = ⋅ −⋅ ( )

⋅ −⋅

29 3 0 034 0 012 0 851

3 5 25 2

1000

0 371

1000

0 85

.. . .

. . . . 1

8 5 ⎛

⎝

⎜ ⎞

⎠

⎟

= . μmol/mol


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23054 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

xH O2

1 8

2

0 0249 47 6

1000000

0 018 0 851 0 017 exhdry = − ⎛

⎝

⎜ ⎞

⎠

⎟ + ⋅+⋅ . . . .. . 0 172 8 5

1000000 . 0 0353 . − = . mol/mol

x mol/mol dil/exhdry = − = 0 822

1 0 034

0 851 .

. .

xint/exhdry = ⋅

− ++⋅ ⎛

⎝

⎜ ⎞

⎠

⎟ − 1

2 0 206

1 8

2

0 050 2 2 0 0003 0 0249 47 6

.

. . .. .

1000000

29 3

1000000

50 4

1000000

2 12 1

1000000

8 5

10

⎛

⎝

⎜ ⎞

⎠

⎟ −

− −⋅ + . . ..

00000

0 172 ⎛

⎝

⎜ ⎞

⎠

⎟

⎛

⎝

⎜

⎜

⎜

⎜

⎞

⎠

⎟

⎟

⎟

⎟

= . mol/mol

xraw/exhdry =

+ + ⎛

⎝

⎜ ⎞

⎠

⎟ − ⎛

⎝

⎜ 1

2

1 8

2

0 050 0 0001 0 0249 47 6

1000000

. .. . . ⎞

⎠

⎟ +

⋅+ −+ ⎛

⎝

⎜ ⎞

⎠ 2 47 6

1000000

29 3

1000000

12 1

1000000

8 5

1000000

. . .. ⎟

⎛

⎝

⎜

⎜

⎜

⎜

⎞

⎠

⎟

⎟

⎟

⎟

+ = 0 172 0 184 . . mol/mol

x mol/mol O2

0 209820 0 000375

1 17 22

1000

0 206 int

. .

. = . −

+

=

x mmol/mol CO2

0 000375 1000

1 17 22

1000

0 369 int

.

. = . ⋅

+

=

x mmol/mol H O2

16 93

1 16 93

1000

17 22 intdry =

−

= .

. .

x mmol/mol CO dil 2

0 375

1 12 01

1000

= 0 371

+

= .

. .

x mmol/mol H O2

11 87

1 11 87

1000

12 01 dildry =

−

= .

. .

x mmol/mol COdry =

−

= 29 0

1 8 601

1000

29 3 .

. .

x mmol/mol CO dry 2

24 98

1 8 601

1000

= 25 2

−

= .

. .

x mmol/mol NOdry =

−

= 50 0

1 8 601

1000

50 4 .

. .

x mmol/mol NO dry 2

12 0

1 8 601

1000

= 12 1

−

= .

. .

x mmol/mol THCdry =

−

= 46

1 34 18

1000

47 6 . .

α = 1.8 

β = 0.05 

γ = 0.0003 

δ = 0.0001 

(d) Carbon mass fraction. Determine 

carbon mass fraction of fuel, wc, using 

one of the following methods: 

(1) You may calculate wc as described 

in this paragraph (d)(1) based on 

measured fuel properties. To do so, you 

must determine values for α and β in all 

cases, but you may set g and d to zero 

if the default value listed in Table 1 of 

this section is zero. Calculate wc using 

the following equation: 

w

M

M M C

C

C H 1

= ⋅

⋅ + ⋅ + ⋅ +⋅ + ⋅

1

α γ βΜ δ Ο M M S N

Eq. 1065.655-19


ER30AP10.073</MATH> ER30AP10.074</MATH> ER30AP10.075</MATH> ER30AP10.076</MATH> ER30AP10.077</MATH> ER30AP10.078</MATH> ER30AP10.079</MATH> ER30AP10.080</MATH> ER30AP10.081</MATH> ER30AP10.082</MATH> ER30AP10.083</MATH> ER30AP10.084</MATH> ER30AP10.085</MATH> ER30AP10.086</MATH> ER30AP10.087</MATH>wwoods2 on DSK1DXX6B1PROD with RULES_2
Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23055 

Where: 

wC, = carbon mass fraction of fuel. 

MC = molar mass of carbon. 

α = atomic hydrogen-to-carbon ratio of the 

mixture of fuel(s) being combusted, 

weighted by molar consumption. 

MH = molar mass of hydrogen. 

β = atomic oxygen-to-carbon ratio of the 

mixture of fuel(s) being combusted, 

weighted by molar consumption. 

MO = molar mass of oxygen. 

γ = atomic sulfur-to-carbon ratio of the 

mixture of fuel(s) being combusted, 

weighted by molar consumption. 

MS = molar mass of sulfur. 

δ = atomic nitrogen-to-carbon ratio of the 

mixture of fuel(s) being combusted, 

weighted by molar consumption. 

MN = molar mass of nitrogen. 

Example: 

α = 1.8 

β = 0.05 

γ = 0.0003 

δ = 0.0001 

MC = 12.0107 

MH = 1.01 

MO = 15.9994 

MS = 32.065 

MN = 14.0067 

wC = ⋅

⋅ +⋅ + ⋅ + ⋅ +

1 12 0107

1 12 0107 1 8 1 01 0 05 15 9994 0 0003 32 065

.

. .. . . . . 0 0001 14 0067 . . ⋅

wC, = 0.8205 (2) You may use the default values in 

the following table to determine wc for 

a given fuel: 

TABLE 1 OF § 1065.655—DEFAULT VALUES OF α, β, γ, δ, AND wc, FOR VARIOUS FUELS

Fuel Atomic hydrogen, oxygen, sulfur, and 

nitrogen-to-carbon ratios 

CHaObSgNd 

Carbon mass 

fraction, wc

g/g. 

Gasoline ................................................................................................. CH1.85O0S0N0 ................................................................. 0.866 

#2 Diesel ................................................................................................ CH1.80O0S0N0 ................................................................. 0.869 

#1 Diesel ................................................................................................ CH1.93O0S0N0 ................................................................. 0.861 

Liquefied Petroleum Gas ....................................................................... CH2.64O0S0N0 ................................................................. 0.819 

Natural gas ............................................................................................ CH3.78O0.016S0N0 ............................................................ 0.747 

Ethanol ................................................................................................... CH3O0.5S0N0 ................................................................... 0.521 

Methanol ................................................................................................ CH4O1S0N0 ..................................................................... 0.375 

Residual fuel blends .............................................................................. Must be determined by measured fuel properties as described in paragraph (d)(1) of this section. 

(e) * * * (3) Fuel mass flow rate calculation. 

Based on m ̇ fuel, calculate n ̇ exh as follows: 

n mw x

M x exh

fuel c H Oexhdry

c Ccombdry

= ⋅ ⋅+ ( )

⋅

1 2

Eq. 1065.655-21

Where: 

n ̇ exh = raw exhaust molar flow rate from 

which you measured emissions. 

m ̇ fuel = fuel flow rate including humidity in 

intake air. 

Example: 

m ̇ fuel = 7.559 g/s 

wC = 0.869 g/g 

MC = 12.0107 g/mol 

xCcombdry = 99.87 mmol/mol = 0.09987 mol/ 

mol 

xH20exhdry = 107.64 mmol/mol = 0.10764 mol/ 

mol 

nexh = ⋅ ⋅+

⋅

7 559 0 869 1 0 10764

12 0107 0 09987

. . (. )

. .

n ̇ exh= 6.066 mol/s 

■ 311. Section 1065.667 is amended by 

revising paragraphs (d) and (e) to read 

as follows: 

§ 1065.667 Dilution air background 

emission correction. 

* * * * * 

(d) The following is an example of 

using the flow-weighted mean fraction 

of dilution air in diluted exhaust, x ̄ dil/exh, 

and the total mass of background 

emissions calculated using the total 

flow of diluted exhaust, ndexh, as 

described in § 1065.650(c): 

m xm bkgnd dil/exh bkgnddexh = ⋅ Eq. 1065.667-1

m =M x n bkgnddexh bkgnd dexh ⋅ ⋅ Eq. 1065.667-2

Example: 

MNOx = 46.0055 g/mol 

x ̄ bkgnd = 0.05 μmol/mol = 0.05·10¥6 mol/mol 

ndexh = 23280.5 mol 

x ̄ dil/exh = 0.843 mol/mol 

mbkgndNOxdexh = 46.0055·0.05·10¥6·23280.5 

mbkgndNOxdexh = 0.0536 g 

mbkgndNOx = 0.843 · 0.0536 

mbkgndNOx = 0.0452 g 

(e) The following is an example of 

using the fraction of dilution air in 


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23056 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

diluted exhaust, xdil/exh, and the mass 

rate of background emissions calculated 

using the flow rate of diluted exhaust, 

n ̇ dexh, as described in § 1065.650(c): 

m xm bkgnd dil/exh bkgnddexh = ⋅ Eq. 1065.667-3

m =M x n bkgnddexh bkgnd dexh ⋅ ⋅ Eq. 1065.667-4

Example: 

MNOx = 46.0055 g/mol 

xbkgnd = 0.05 μmol/mol = 0.05·10¥6 mol/mol 

n ̇ dexh = 23280.5 mol/s 

xdil/exh = 0.843 mol/mol 

m ̇ bkgndNOxdexh = 36.0055·0.05·10¥6 · 23280.5 

m ̇ bkgndNOXdexh = 0.0536 g/hr 

m ̇ bkgndNOx = 0.843 · 0.0536 

m ̇ bkgndNOx = 0.0452 g/hr 

■ 312. Section 1065.670 is revised to 

read as follows: 

§ 1065.670 NOX intake-air humidity and 

temperature corrections. 

See the standard-setting part to 

determine if you may correct NOX

emissions for the effects of intake-air 

humidity or temperature. Use the NOX

intake-air humidity and temperature 

corrections specified in the standardsetting part instead of the NOX intakeair humidity correction specified in this 

part 1065. If the standard-setting part 

does not prohibit correcting NOX

emissions for intake-air humidity 

according to this part 1065, first apply 

any NOX corrections for background 

emissions and water removal from the 

exhaust sample, then correct NOX

concentrations for intake-air humidity. 

You may use a time-weighted mean 

combustion air humidity to calculate 

this correction if your combustion air 

humidity remains within a tolerance of 

±0.0025 mol/mol of the mean value over 

the test interval. For intake-air humidity 

correction, use one of the following 

approaches: 

(a) For compression-ignition engines, 

correct for intake-air humidity using the 

following equation: 

xx x NOxcor NOxuncor H20 = ⋅ ⋅+ ( ) 9 953 0 832 . . Eq. 1065.670-1

Example: 

xNOxuncor = 700.5 μmol/mol 

xH2O = 0.022 mol/mol 

xNOxcor = 700.5 · (9.953 · 0.022 + 0.832) 

xNOxcor = 736.2 μmol/mol 

(b) For spark-ignition engines, correct 

for intake-air humidity using the 

following equation: 

xx x NOxcor NOxuncor H20 = ⋅ ⋅+ ( ) 18 840 0 68094 . . Eq. 1065.670-2

Example: 

xNOxuncor = 154.7 μmol/mol 

xH2O = 0.022 mol/mol 

xNOxcor = 154.7 · (18.840 · 0.022 + 0.68094) 

xNOxcor = 169.5 μmol/mol 

(c) Develop your own correction, 

based on good engineering judgment. 

■ 313. Section 1065.672 is amended by 

revising paragraph (d)(7) to read as 

follows: 

§ 1065.672 Drift correction. 

* * * * * 

(d) * * * 

(7) Usually the reference 

concentration of the zero gas, xrefzero, is 

zero: xrefzero = 0 μmol/mol. However, in 

some cases you might know that xrefzero

has a non-zero concentration. For 

example, if you zero a CO2 analyzer 

using ambient air, you may use the 

default ambient air concentration of 

CO2, which is 375 μmol/mol. In this 

case, xrefzero = 375 μmol/mol. Note that 

when you zero an analyzer using a nonzero xrefzero, you must set the analyzer to 

output the actual xrefzero concentration. 

For example, if xrefzero = 375 μmol/mol, 

set the analyzer to output a value of 375 

μmol/mol when the zero gas is flowing 

to the analyzer. 

■ 314. Section 1065.690 is amended by 

revising paragraphs (c) and (e) to read as 

follows: 

§ 1065.690 Buoyancy correction for PM 

sample media. 

* * * * * 

(c) Air density. Because a PM balance 

environment must be tightly controlled 

to an ambient temperature of (22 ±1) °C 

and humidity has an insignificant effect 

on buoyancy correction, air density is 

primarily a function of atmospheric 

pressure. Therefore you may use 

nominal constant values for temperature 

and humidity in the buoyancy 

correction equation in Eq. 1065.690–2. 

* * * * * 

(e) Correction calculation. Correct the 

PM sample media for buoyancy using 

the following equations: 

m m cor uncor

air

weight

air

media

= ⋅

−

−

⎡

⎣

⎢

⎢

⎢

⎢

⎤

⎦

⎥

⎥

⎥

⎥

1

1

ρ

ρ

ρ

ρ

Eq. 1065.690-1

Where: mcor = PM mass corrected for buoyancy. 

muncor = PM mass uncorrected for buoyancy. 

rair = density of air in balance environment. 


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Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23057 

rweight = density of calibration weight used to 

span balance. 

rmedia = density of PM sample media, such as 

a filter. 

ρair

abs mix

amb

= ⋅

⋅

p M

R T Eq.1065.690-2

Where: 

pabs = absolute pressure in balance 

environment. 

Mmix = molar mass of air in balance 

environment. 

R = molar gas constant. 

Tamb = absolute ambient temperature of 

balance environment. 

Example: 

pabs = 99.980 kPa 

Tsat = Tdew = 9.5 °C 

Using Eq. 1065.645–1, 

pH20 = 1.1866 kPa 

Using Eq. 1065.645–3, 

xH2O = 0.011868 mol/mol 

Using Eq. 1065.640–9, 

Mmix = 28.83563 g/mol 

R = 8.314472 J/(mol.K) 

Tamb = 20 °C 

ρair = ⋅

⋅

99 980 28 83563

8 314472 293 15

. .

. .

rair = 1.18282 kg/m3

muncorr = 100.0000 mg 

rweight = 8000 kg/m3

rmedia = 920 kg/m3

mcor = ⋅

−

−

⎡

⎣

⎢

⎢

⎢

⎤

⎦

⎥

⎥

⎥

100 0000

1 1 18282

8000

1 1 18282

920

.

.

.

mcor = 100.1139 mg 

Subpart H— [Amended] 

■ 315. Section 1065.701 is amended by 

revising paragraph (f) and Table 1 of 

§ 1065.701 to read as follows: 

§ 1065.701 General requirements for test 

fuels. 

* * * * * 

(f) Service accumulation and field 

testing fuels. If we do not specify a 

service-accumulation or field-testing 

fuel in the standard-setting part, use an 

appropriate commercially available fuel 

such as those meeting minimum 

specifications from the following table: 

TABLE 1 OF § 1065.701—EXAMPLES OF SERVICE-ACCUMULATION AND FIELD-TESTING FUELS

Fuel category Subcategory Reference procedure 1

Light distillate and light blends with residual ... ASTM D975–07b. 

Diesel .................................................................. Middle distillate ................................................ ASTM D6985–04a. 

Biodiesel (B100) ............................................... ASTM D6751–07b. 

Intermediate and residual fuel ............................ All ..................................................................... See § 1065.705. 

Gasoline ............................................................. Motor vehicle gasoline ..................................... ASTM D4814–07a. 

Minor oxygenated gasoline blends .................. ASTM D4814–07a. 

Alcohol ................................................................ Ethanol (Ed75–85) ........................................... ASTM D5798–07. 

Methanol (M70–M85) ....................................... ASTM D5797–07. 

Aviation fuel ........................................................ Aviation gasoline .............................................. ASTM D910–07. 

Gas turbine ...................................................... ASTM D1655–07e01. 

Jet B wide cut .................................................. ASTM D6615–06. 

Gas turbine fuel .................................................. General ............................................................ ASTM D2880–03l. 

1ASTM specifications are incorporated by reference in § 1065.1010. 

■ 316. Section 1065.703 is amended by 

revising Table 1 of § 1065.703 to read as 

follows: 

§ 1065.703 Distillate diesel fuel. 

* * * * * 

TABLE 1 OF § 1065.703—TEST FUEL SPECIFICATIONS FOR DISTILLATE DIESEL FUEL

Item Units Ultra low 

sulfur Low sulfur High sulfur Reference procedure 1

Cetane Number .......................................... ................. 40–50 40–50 40–50 ASTM D613–05. 

Distillation range: 

Initial boiling point ....................................... °C ............ 171–204 171–204 171–204 ASTM D86–07a. 

10 pct. point ................................................ ............ 204–238 204–238 204–238 

50 pct. point ................................................ ............ 243–282 243–282 243–282 

90 pct. point ................................................ ............ 293–332 293–332 293–332 

Endpoint ..................................................... ............ 321–366 321–366 321–366 

Gravity ........................................................ °API ........ 32–37 32–37 32–37 ASTM D4052–96e01. 

Total sulfur, ultra low sulfur ........................ mg/kg ...... 7–15 See 40 CFR 80.580. 

Total sulfur, low and high sulfur ................. mg/kg ...... 300–500 800–2500 ASTM D2622–07 or alternates as allowed 

under 40 CFR 80.580. 

Aromatics, min. (Remainder shall be 

paraffins, naphthalenes, and olefins) 

g/kg ......... 100 100 100 ASTM D5186–03. 

Flashpoint, min ........................................... °C ............ 54 54 54 ASTM D93–07. 


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TABLE 1 OF § 1065.703—TEST FUEL SPECIFICATIONS FOR DISTILLATE DIESEL FUEL—Continued 

Item Units Ultra low 

sulfur Low sulfur High sulfur Reference procedure 1

Kinematic Viscosity .................................... cSt .......... 2.0–3.2 2.0–3.2 2.0–3.2 ASTM D445–06. 

1ASTM procedures are incorporated by reference in § 1065.1010. See § 1065.701(d) for other allowed procedures. 

Subpart I—[Amended] 

■ 317. Section 1065.845 is amended by 

revising paragraph (b) to read as follows: 

§ 1065.845 Response factor determination. 

* * * * * 

(b) Alcohol/carbonyl calibration gases 

must remain within ±2% of the labeled 

concentration. You must demonstrate 

the stability based on a quarterly 

measurement procedure with a 

precision of ±2% percent or another 

method that we approve. Your 

measurement procedure may 

incorporate multiple measurements. If 

the true concentration of the gas 

changes deviates by more than ±2%, but 

less than ±10%, the gas may be 

relabeled with the new concentration. 

Subpart J— [Amended] 

■ 318. Section 1065.910 is amended by 

revising paragraphs (a)(3) and (c) to read 

as follows: 

§ 1065.910 PEMS auxiliary equipment for 

field testing. 

* * * * * 

(a) * * * 

(3) Flow restriction. Use flow meters, 

connectors, and tubing that do not 

increase flow restriction so much that it 

exceeds the manufacturer’s maximum 

specified value. You may verify this at 

the maximum exhaust flow rate by 

measuring pressure at the manufacturerspecified location with your system 

connected. You may also perform an 

engineering analysis to verify an 

acceptable configuration, taking into 

account the maximum exhaust flow rate 

expected, the field test system’s flexible 

connectors, and the tubing’s 

characteristics for pressure drops versus 

flow. 

* * * * * 

(c) Use mounting hardware as 

required for securing flexible 

connectors, ambient sensors, and other 

equipment. Use structurally sound 

mounting points such as vehicle frames, 

trailer hitch receivers, walk spaces, and 

payload tie-down fittings. We 

recommend mounting hardware such as 

clamps, suction cups, and magnets that 

are specifically designed for your 

application. We also recommend 

considering mounting hardware such as 

commercially available bicycle racks, 

trailer hitches, and luggage racks where 

applicable. 

* * * * * 

Subpart K—[Amended] 

■ 319. Section 1065.1001 is amended by 

revising the definitions for ‘‘Duty cycle’’ 

and ‘‘Percent’’ to read as follows: 

§ 1065.1001 Definitions. 

* * * * * 

Duty cycle means one of the 

following: 

(1) A series of speed and torque 

values (or power values) that an engine 

must follow during a laboratory test. 

Duty cycles are specified in the 

standard-setting part. A single duty 

cycle may consist of one or more test 

intervals. A series of speed and torque 

values meeting the definition of this 

paragraph (1) may also be considered a 

test cycle. For example, a duty cycle 

may be a ramped-modal cycle, which 

has one test interval; a cold-start plus 

hot-start transient cycle, which has two 

test intervals; or a discrete-mode cycle, 

which has one test interval for each 

mode. 

(2) A set of weighting factors and the 

corresponding speed and torque values, 

where the weighting factors are used to 

combine the results of multiple test 

intervals into a composite result. 

* * * * * 

Percent (%) means a representation of 

exactly 0.01 (with infinite precision). 

Significant digits for the product of % 

and another value, or the expression of 

any other value as a percentage, are 

defined as follows: 

(1) Where we specify some percentage 

of a total value, the calculated value has 

the same number of significant digits as 

the total value. The specified percentage 

by which the total value is multiplied 

has infinite precision. Note that not all 

displayed or recorded digits are 

significant. For example, 2% of a span 

value where the span value is 101.3302 

is 2.026604. However, where the span 

value has limited precision such that 

only one digit to the right of the decimal 

is significant (i.e., the actual value is 

101.3), 2% of the span value is 2.026. 

(2) In other cases, determine the 

number of significant digits using the 

same method as you would use for 

determining the number of significant 

digits of any calculated value. For 

example, a calculated value of 0.321, 

where all three digits are significant, is 

equivalent to 32.1%. 

* * * * * 

PART 1068—GENERAL COMPLIANCE 

PROVISIONS FOR ENGINE 

PROGRAMS 

■ 320. The authority citation for part 

1068 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

■ 321. The heading for part 1068 is 

revised as set forth above. 

Subpart A—[Amended] 

■ 322. Section 1068.1 is amended by 

revising paragraphs (a)(4), (b)(4), (b)(8), 

and (d)(1) to read as follows: 

§ 1068.1 Does this part apply to me?

(a) * * * 

(4) Marine compression-ignition 

engines we regulate under 40 CFR part 

1042. 

* * * * * 

(b) * * * 

(4) Land-based nonroad compressionignition engines we regulate under 40 

CFR part 89. 

* * * * * 

(8) Marine compression-ignition 

engines we regulate under 40 CFR parts 

89 or 94. 

* * * * * 

(d) * * * 

(1) The provisions of §§ 1068.30 and 

1068.310 apply for stationary sparkignition engines built on or after January 

1, 2004, and for stationary compressionignition engines built on or after January 

1, 2006. 

* * * * * 

■ 323. Section 1068.25 is amended by 

adding paragraph (c) to read as follows: 

§ 1068.25 What information must I give to 

EPA? 

* * * * * 

(c) You are responsible for statements 

and information in your applications for 

certification or any other requests or 

reports. If you provide statements or 

information to someone for submission 

to EPA, you are responsible for these 

statements and information as if you 

had submitted them to EPA yourself. 

For example, knowingly submitting 


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false information to someone else for 

inclusion in an application for 

certification would be deemed to be a 

submission of false information to the 

U.S. government in violation of 18 

U.S.C. 1001. 

■ 324. Section 1068.30 is amended as 

follows: 

■ a. By revising the introductory text of 

the definition for ‘‘Engine’’. 

■ b. By adding a definition for ‘‘Engine 

configuration’’ in alphabetical order. 

■ c. By adding a definition for ‘‘Gas 

turbine engine’’ in alphabetical order. 

■ d. By revising the definition for 

‘‘Ultimate purchaser’’. 

§ 1068.30 What definitions apply to this 

part? 

* * * * * 

Engine means an engine block with an 

installed crankshaft, or a gas turbine 

engine. The term engine does not 

include engine blocks without an 

installed crankshaft, nor does it include 

any assembly of reciprocating engine 

components that does not include the 

engine block. (Note: For purposes of this 

definition, any component that is the 

primary means of converting an engine’s 

energy into usable work is considered a 

crankshaft, whether or not it is known 

commercially as a crankshaft.) This 

includes complete and partially 

complete engines as follows: 

* * * * * 

Engine configuration means a unique 

combination of engine hardware and 

calibration within an engine family. 

Engines within a single engine 

configuration differ only with respect to 

normal production variability or factors 

unrelated to emissions. 

* * * * * 

Gas turbine engine means anything 

commercially known as a gas turbine 

engine or any collection of assembled 

engine components that is substantially 

similar to engines commercially known 

as gas turbine engines. For example, a 

jet engine is a gas turbine engine. Gas 

turbine engines may be complete or 

partially complete. Turbines that rely on 

external combustion such as steam 

engines are not gas turbine engines. 

* * * * * 

Ultimate purchaser means the first 

person who in good faith purchases a 

new engine or new piece of equipment 

for purposes other than resale. 

* * * * * 

■ 325. Section 1068.31 is amended by 

revising paragraph (d) to read as 

follows: 

§ 1068.31 What provisions apply to 

nonroad or stationary engines that change 

their status? 

* * * * * 

(d) Changing the status of a nonroad 

engine to be a new stationary engine as 

described in paragraph (e) of this 

section is a violation of § 1068.101(a)(1) 

unless the engine complies with all the 

requirements of this chapter for new 

stationary engines of the same type (for 

example, a compression-ignition engine 

rated at 40 kW) and model year. For a 

new stationary engine that is required to 

be certified under 40 CFR part 60, the 

engine must have been certified to be 

compliant with all the requirements that 

apply to new stationary engines of the 

same type and model year, and must be 

in its certified configuration. Note that 

the definitions of ‘‘model year’’ in the 

standard-setting parts generally identify 

the engine’s original date of 

manufacture as the basis for 

determining which standards apply if it 

becomes a stationary engine after it is no 

longer new. For example, see 40 CFR 

60.4219 and 60.4248. 

* * * * * 

■ 326. Section 1068.40 is revised to read 

as follows: 

§ 1068.40 What special provisions apply 

for implementing changes in the 

regulations? 

(a) During the 12 months following 

the effective date of any change in the 

provisions of this part, you may ask to 

apply the previously applicable 

provisions. We will generally approve 

your request if you can demonstrate that 

it would be impractical to comply with 

the new requirements. We may consider 

the potential for adverse environmental 

impacts in our decision. Similarly, in 

unusual circumstances, you may ask for 

relief under this paragraph (a) from new 

requirements that apply under the 

standard-setting part. 

(b) During the 60 days following the 

effective date of any change in the 

provisions of this part, you may use the 

previously applicable provisions 

without request if they meet either of 

the following criteria: 

(1) The new provisions require you to 

redesign your engines/equipment, 

modify your engine/equipment labels, 

or change your production procedures. 

(2) The new provisions change what 

you must include in an application for 

certification that you submit before the 

end of this 60-day period. You are not 

required to amend such applications to 

comply with the new provisions for that 

model year; however, this allowance 

does not apply for later model years, 

even if you certify an engine family 

using carryover emission data. This 

allowance does not affect your 

obligation to provide information that 

we request separate from an application 

for certification. 

(c) Prior to the dates listed you may 

comply with earlier versions of 

applicable regulations as follows: 

(1) Prior to June 1, 2010, you may 

comply with the provisions of 

§ 1068.240 that were in effect on April 

30, 2010. 

(2) [Reserved] 

■ 327. Section 1068.45 is amended by 

revising paragraph (c) introductory text 

to read as follows: 

§ 1068.45 General labeling provisions. 

* * * * * 

(c) Labels on packaging. Unless we 

specify otherwise, where we require 

engine/equipment labels that may be 

removable, you may instead label the 

packaging if the engines/equipment are 

packaged together as described in this 

paragraph (c). For example, this may 

involve packaging engines together by 

attaching them to a rack, binding them 

together on a pallet, or enclosing them 

in a box. The provisions of this 

paragraph (c) also apply for engines/ 

equipment boxed individually where 

you do not apply labels directly to the 

engines/equipment. The following 

provisions apply if you label the 

packaging instead of labeling engines/ 

equipment individually: 

* * * * * 

■ 328. Section 1068.101 is revised to 

read as follows: 

§ 1068.101 What general actions does this 

regulation prohibit? 

This section specifies actions that are 

prohibited and the maximum civil 

penalties that we can assess for each 

violation in accordance with 42 U.S.C. 

7522 and 7524. The maximum penalty 

values listed in paragraphs (a) and (b) of 

this section apply as of January 12, 

2009. As described in paragraph (h) of 

this section, these maximum penalty 

limits are different for earlier violations 

and they may be adjusted as set forth in 

40 CFR part 19. 

(a) The following prohibitions and 

requirements apply to manufacturers of 

new engines, manufacturers of 

equipment containing these engines, 

and manufacturers of new equipment, 

except as described in subparts C and D 

of this part: 

(1) Introduction into commerce. You 

may not sell, offer for sale, or introduce 

or deliver into commerce in the United 

States or import into the United States 

any new engine/equipment after 

emission standards take effect for the 

engine/equipment, unless it is covered 

by a valid certificate of conformity for 

its model year and has the required 

label or tag. You also may not take any 

of the actions listed in the previous 

sentence with respect to any equipment 


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containing an engine subject to this 

part’s provisions unless the engine is 

covered by a valid certificate of 

conformity for its model year and has 

the required engine label or tag. We may 

assess a civil penalty up to $37,500 for 

each engine or piece of equipment in 

violation. 

(i) For purposes of this paragraph 

(a)(1), a valid certificate of conformity is 

one that applies for the same model year 

as the model year of the equipment 

(except as allowed by § 1068.105(a)), 

covers the appropriate category of 

engines/equipment (such as locomotive 

or Marine SI), and conforms to all 

requirements specified for equipment in 

the standard-setting part. Engines/ 

equipment are considered not covered 

by a certificate unless they are in a 

configuration described in the 

application for certification. 

(ii) The requirements of this 

paragraph (a)(1) also cover new engines 

you produce to replace an older engine 

in a piece of equipment, unless the 

engine qualifies for the replacementengine exemption in § 1068.240. 

(iii) For engines used in equipment 

subject to equipment-based standards, 

you may not sell, offer for sale, or 

introduce or deliver into commerce in 

the United States or import into the 

United States any new engine unless it 

is covered by a valid certificate of 

conformity for its model year and has 

the required label or tag. See the 

standard-setting part for more 

information about how this prohibition 

applies. 

(2) Reporting and recordkeeping. This 

chapter requires you to record certain 

types of information to show that you 

meet our standards. You must comply 

with these requirements to make and 

maintain required records (including 

those described in § 1068.501). You may 

not deny us access to your records or 

the ability to copy your records if we 

have the authority to see or copy them. 

Also, you must give us complete and 

accurate reports and information 

without delay as required under this 

chapter. Failure to comply with the 

requirements of this paragraph is 

prohibited. We may assess a civil 

penalty up to $37,500 for each day you 

are in violation. In addition, knowingly 

submitting false information is a 

violation of 18 U.S.C. 1001, which may 

involve criminal penalties and up to 

five years imprisonment. 

(3) Testing and access to facilities. 

You may not keep us from entering your 

facility to test engines/equipment or 

inspect if we are authorized to do so. 

Also, you must perform the tests we 

require (or have the tests done for you). 

Failure to perform this testing is 

prohibited. We may assess a civil 

penalty up to $37,500 for each day you 

are in violation. 

(b) The following prohibitions apply 

to everyone with respect to the engines 

and equipment to which this part 

applies: 

(1) Tampering. You may not remove 

or render inoperative any device or 

element of design installed on or in 

engines/equipment in compliance with 

the regulations prior to its sale and 

delivery to the ultimate purchaser. You 

also may not knowingly remove or 

render inoperative any such device or 

element of design after such sale and 

delivery to the ultimate purchaser. This 

includes, for example, operating an 

engine without a supply of appropriate 

quality urea if the emissions control 

system relies on urea to reduce NOx 

emissions or the use of incorrect fuel or 

engine oil that renders the emissions 

control system inoperative. Section 

1068.120 describes how this applies to 

rebuilding engines. See the standardsetting part, which may include 

additional provisions regarding actions 

prohibited by this requirement. For a 

manufacturer or dealer, we may assess 

a civil penalty up to $37,500 for each 

engine or piece of equipment in 

violation. For anyone else, we may 

assess a civil penalty up to $3,750 for 

each day an engine or piece of 

equipment is operated in violation. This 

prohibition does not apply in any of the 

following situations: 

(i) You need to repair the engine/ 

equipment and you restore it to proper 

functioning when the repair is 

complete. 

(ii) You need to modify the engine/ 

equipment to respond to a temporary 

emergency and you restore it to proper 

functioning as soon as possible. 

(iii) You modify new engines/ 

equipment that another manufacturer 

has already certified to meet emission 

standards and recertify them under your 

own family. In this case you must tell 

the original manufacturer not to include 

the modified engines/equipment in the 

original family. 

(2) Defeat devices. You may not 

knowingly manufacture, sell, offer to 

sell, or install, any part that bypasses, 

impairs, defeats, or disables the control 

of emissions of any regulated pollutant, 

except as explicitly allowed by the 

standard-setting part. We may assess a 

civil penalty up to $3,750 for each part 

in violation. 

(3) Stationary engines. For an engine 

that is excluded from any requirements 

of this chapter because it is a stationary 

engine, you may not move it or install 

it in any mobile equipment except as 

allowed by the provisions of this 

chapter. You may not circumvent or 

attempt to circumvent the residencetime requirements of paragraph (2)(iii) 

of the nonroad engine definition in 

§ 1068.30. Anyone violating this 

paragraph (b)(3) is deemed to be a 

manufacturer in violation of paragraph 

(a)(1) of this section. We may assess a 

civil penalty up to $37,500 for each 

engine or piece of equipment in 

violation. 

(4) Competition engines/equipment. 

For uncertified engines/equipment that 

are excluded or exempted from any 

requirements of this chapter because 

they are to be used solely for 

competition, you may not use any of 

them in a manner that is inconsistent 

with use solely for competition. Anyone 

violating this paragraph (b)(4) is deemed 

to be a manufacturer in violation of 

paragraph (a)(1) of this section. We may 

assess a civil penalty up to $37,500 for 

each engine or piece of equipment in 

violation. 

(5) Importation. You may not import 

an uncertified engine or piece of 

equipment if it is defined to be new in 

the standard-setting part with a model 

year for which emission standards 

applied. Anyone violating this 

paragraph (b)(5) is deemed to be a 

manufacturer in violation of paragraph 

(a)(1) of this section. We may assess a 

civil penalty up to $37,500 for each 

engine or piece of equipment in 

violation. Note the following: 

(i) The definition of new is broad for 

imported engines/equipment; 

uncertified engines and equipment 

(including used engines and equipment) 

are generally considered to be new 

when imported. 

(ii) Used engines/equipment that were 

originally manufactured before 

applicable EPA standards were in effect 

are generally not subject to emission 

standards. 

(6) Warranty, recall, and maintenance 

instructions. You must meet your 

obligation to honor your emissionrelated warranty under § 1068.115, 

including any commitments you 

identify in your application for 

certification. You must also fulfill all 

applicable requirements under subpart 

F of this part related to emission-related 

defects and recalls. You must also 

provide emission-related installation 

and maintenance instructions as 

described in the standard-setting part. 

Failure to meet these obligations is 

prohibited. Also, except as specifically 

provided by regulation, you are 

prohibited from directly or indirectly 

communicating to the ultimate 

purchaser or a later purchaser that the 

emission-related warranty is valid only 

if the owner has service performed at 


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authorized facilities or only if the owner 

uses authorized parts, components, or 

systems. We may assess a civil penalty 

up to $37,500 for each engine or piece 

of equipment in violation. 

(7) Labeling. (i) You may not remove 

or alter an emission control information 

label or other required permanent label 

except as specified in this paragraph 

(b)(7) or otherwise allowed by this 

chapter. Removing or altering an 

emission control information label is a 

violation of paragraph (b)(1) of this 

section. However, it is not a violation to 

remove a label in the following 

circumstances: 

(A) The engine is destroyed, is 

permanently disassembled, or otherwise 

loses its identity such that the original 

title to the engine is no longer valid. 

(B) The regulations specifically direct 

you to remove the label. For example, 

see § 1068.235. 

(C) The part on which the label is 

mounted needs to be replaced. In this 

case, you must have a replacement part 

with a duplicate of the original label 

installed by the certifying manufacturer 

or an authorized agent, except that the 

replacement label may omit the date of 

manufacture if applicable. We generally 

require labels to be permanently 

attached to parts that will not normally 

be replaced, but this provision allows 

for replacements in unusual 

circumstances, such as damage in a 

collision or other accident. 

(D) The original label is incorrect, 

provided that it is replaced with the 

correct label from the certifying 

manufacturer or an authorized agent. 

This allowance to replace incorrect 

labels does not affect whether the 

application of an incorrect original label 

is a violation. 

(ii) Removing or altering a temporary 

or removable label contrary to the 

provisions of this paragraph (b)(7)(ii) is 

a violation of paragraph (b)(1) of this 

section. 

(A) For labels identifying temporary 

exemptions, you may not remove or 

alter the label while the engine/ 

equipment is in an exempt status. The 

exemption is automatically revoked for 

each engine/equipment for which the 

label has been removed. 

(B) For temporary or removable 

consumer information labels, only the 

ultimate purchaser may remove the 

label. 

(iii) You may not apply a false 

emission control information label. You 

also may not manufacture, sell, or offer 

to sell false labels. The application, 

manufacture, sale, or offer for sale of 

false labels is a violation of this section 

(such as paragraph (a)(1) or (b)(2) of this 

section). Note that applying an 

otherwise valid emission control 

information label to the wrong engine is 

considered to be applying a false label. 

(c) If you cause someone to commit a 

prohibited act in paragraph (a) or (b) of 

this section, you are in violation of that 

prohibition. 

(d) Exemptions from these 

prohibitions are described in subparts C 

and D of this part and in the standardsetting part. 

(e) The standard-setting parts describe 

more requirements and prohibitions that 

apply to manufacturers (including 

importers) and others under this 

chapter. 

(f) The specification of prohibitions 

and penalties in this part does not limit 

the prohibitions and penalties described 

in the Clean Air Act. Additionally, a 

single act may trigger multiple 

violations under this section and the 

Act. We may pursue all available 

administrative, civil, or criminal 

remedies for those violations even if the 

regulation references only a single 

prohibited act in this section. 

(g) [Reserved] 

(h) The maximum penalty values 

listed in paragraphs (a) and (b) of this 

section apply as of January 12, 2009. 

Maximum penalty values for earlier 

violations are published in 40 CFR part 

19. Maximum penalty limits may be 

adjusted after January 12, 2009 based on 

the Consumer Price Index. The specific 

regulatory provisions for changing the 

maximum penalties, published in 40 

CFR part 19, reference the applicable 

U.S. Code citation on which the 

prohibited action is based. The 

following table is shown here for 

informational purposes: 

TABLE 1 OF § 1068.101—LEGAL CITATION FOR SPECIFIC PROHIBITIONS FOR DETERMINING MAXIMUM PENALTY AMOUNTS

Part 1068 regulatory citation 

of prohibited action General description of prohibition U.S. Code citation for Clean Air Act authority 

§ 1068.101(a)(1) ................... Introduction into U.S. commerce of an uncertified 

source.

42 U.S.C. 7522(a)(1) and (a)(4). 

§ 1068.101(a)(2) ................... Failure to provide information ......................................... 42 U.S.C. 7522(a)(2). 

§ 1068.101(a)(3) ................... Denying access to facilities ............................................. 42 U.S.C. 7522(a)(2). 

§ 1068.101(b)(1) ................... Tampering with emission controls by a manufacturer or 

dealer.

42 U.S.C. 7522(a)(3). 

Tampering with emission controls by someone other 

than a manufacturer or dealer.

§ 1068.101(b)(2) ................... Sale or use of a defeat device ........................................ 42 U.S.C. 7522(a)(3). 

§ 1068.101(b)(3) ................... Mobile use of a stationary engine ................................... 42 U.S.C. 7522(a)(1) and (a)(4). 

§ 1068.101(b)(4) ................... Noncompetitive use of uncertified engines/equipment 

that is exempted for competition.

42 U.S.C. 7522(a)(1) and (a)(4). 

§ 1068.101(b)(5) ................... Importation of an uncertified source ............................... 42 U.S.C. 7522(a)(1) and (a)(4). 

§ 1068.101(b)(6) ................... Recall and warranty ........................................................ 42 U.S.C. 7522(a)(4). 

§ 1068.101(b)(7) ................... Removing labels .............................................................. 42 U.S.C. 7522(a)(3). 

■ 329. Section 1068.103 is amended by 

revising paragraph (a) to read as follows: 

§ 1068.103 What are the provisions related 

to the duration and applicability of 

certificates of conformity? 

(a) Engines/equipment covered by a 

certificate of conformity are limited to 

those that are produced during the 

period specified in the certificate and 

conform to the specifications described 

in the certificate and the associated 

application for certification. For the 

purposes of this paragraph (a), 

‘‘specifications’’ includes any conditions 

or limitations identified by the 

manufacturer or EPA. For example, if 

the application for certification specifies 

certain engine configurations, the 

certificate does not cover any 

configurations that are not specified. We 

may ignore any information provided in 

the application that we determine is not 

relevant to a demonstration of 

compliance with applicable regulations, 


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such as your projected production 

volumes in many cases. 

* * * * * 

■ 330. Section 1068.105 is amended by 

revising paragraph (a) to read as follows: 

§ 1068.105 What other provisions apply to 

me specifically if I manufacture equipment 

needing certified engines? 

* * * * * 

(a) Transitioning to new engine-based 

standards. If new engine-based emission 

standards apply in a given model year, 

your equipment in that calendar year 

must have engines that are certified to 

the new standards, except that you may 

continue to use up normal inventories 

of earlier engines that were built before 

the date of the new or changed 

standards. For purposes of this 

paragraph (a), normal inventory applies 

for engines you possess and engines 

from your engine supplier’s inventory. 

(Note: this paragraph (a) does not apply 

in the case of new remanufacturing 

standards.) For example, if your normal 

inventory practice is to keep on hand a 

one-month supply of engines based on 

your upcoming production schedules, 

and a new tier of standards starts to 

apply for the 2015 model year, you may 

order engines consistent with your 

normal inventory requirements late in 

the engine manufacturer’s 2014 model 

year and install those engines in your 

equipment, regardless of the date of 

installation. Also, if your model year 

starts before the end of the calendar year 

preceding new standards, you may use 

engines from the previous model year 

for those units you produce before 

January 1 of the year that new standards 

apply. If emission standards for the 

engine do not change in a given model 

year, you may continue to install 

engines from the previous model year 

without restriction (or any earlier model 

year for which the same standards 

apply). You may not circumvent the 

provisions of § 1068.101(a)(1) by 

stockpiling engines that were built 

before new or changed standards take 

effect. Similarly, you may not 

circumvent the provisions of 

§ 1068.101(a)(1) by knowingly installing 

engines that were stockpiled by engine 

suppliers in violation of § 1068.103(f). 

Note that this allowance does not apply 

for equipment subject to equipmentbased standards. See 40 CFR 1060.601 

for similar provisions that apply for 

equipment subject to evaporative 

emission standards. 

* * * * * 

■ 331. Section 1068.120 is amended by 

revising paragraph (e) to read as follows: 

§ 1068.120 What requirements must I 

follow to rebuild engines? 

* * * * * 

(e) If the rebuilt engine remains 

installed or is reinstalled in the same 

piece of equipment, you must rebuild it 

to the original configuration, except as 

allowed by this paragraph (e). You may 

rebuild it to a different certified 

configuration of the same or later model 

year. You may also rebuild it to a 

certified configuration from an earlier 

model year as long as the earlier 

configuration is as clean or cleaner than 

the original configuration. For purposes 

of this paragraph (e), ‘‘as clean or 

cleaner’’ means one of the following: 

(1) For engines not certified with a 

Family Emission Limit for calculating 

credits for a particular pollutant, this 

means that the same emission standard 

applied for both model years. This 

includes supplemental standards such 

as Not-to-Exceed standards. 

(2) For engines certified with a Family 

Emission Limit for a particular 

pollutant, this means that the 

configuration to which the engine is 

being rebuilt has a Family Emission 

Limit for that pollutant that is at or 

below the standard that applied to the 

engine originally, and is at or below the 

original Family Emission Limit. 

* * * * * 

■ 332. Section 1068.125 is amended by 

revising paragraph (b) introductory text 

to read as follows: 

§ 1068.125 What happens if I violate the 

regulations? 

* * * * * 

(b) Administrative penalties. Instead 

of bringing a civil action, we may assess 

administrative penalties if the total is 

less than $295,000 against you 

individually. This maximum penalty 

may be greater if the Administrator and 

the Attorney General jointly determine 

that a greater administrative penalty 

assessment is appropriate, or if the limit 

is adjusted under 40 CFR part 19. No 

court may review this determination. 

Before we assess an administrative 

penalty, you may ask for a hearing 

(subject to 40 CFR part 22). The 

Administrator may compromise or 

remit, with or without conditions, any 

administrative penalty that may be 

imposed under this section. 

* * * * * 

Subpart C—[Amended] 

■ 333. Section 1068.215 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 1068.215 What are the provisions for 

exempting manufacturer-owned engines/ 

equipment? 

(a) You are eligible for the exemption 

for manufacturer-owned engines/ 

equipment only if you are a certificate 

holder. Any engine for which you meet 

all applicable requirements under this 

section is exempt without request. 

(b) Engines/equipment may be exempt 

without a request if they are 

nonconforming engines/equipment 

under your ownership, possession, and 

control and you do not operate them for 

purposes other than to develop 

products, assess production methods, or 

promote your engines/equipment in the 

marketplace, or other purposes we 

approve. You may not loan, lease, sell, 

or use the engine/equipment to generate 

revenue, either by itself or for an engine 

installed in a piece of equipment, except 

as allowed by § 1068.201(i). Note that 

this paragraph (b) does not prevent the 

sale or shipment of a partially complete 

engine to a secondary engine 

manufacturer that will meet the 

requirements of this paragraph (b). See 

§ 1068.262 for provisions related to 

shipping partially complete engines to 

secondary engine manufacturers. 

* * * * * 

■ 334. Section 1068.225 is amended by 

revising paragraph (b) to read as follows: 

§ 1068.225 What are the provisions for 

exempting engines/equipment for national 

security? 

* * * * * 

(b) Manufacturers may request a 

national security exemption for engines/ 

equipment not meeting the conditions 

of paragraph (a) of this section as long 

as the request is endorsed by an agency 

of the Federal government responsible 

for national defense. In your request, 

explain why you need the exemption. 

* * * * * 

■ 335. Section 1068.240 is amended as 

follows: 

■ a. By revising paragraphs (a) and 

(b)(6). 

■ b. By adding paragraph (b)(7). 

■ c. By revising paragraphs (c) 

introductory text, (c)(2)(ii), and (c)(4). 

■ d. By revising paragraphs (d), (e), and 

(g)(2). 

§ 1068.240 What are the provisions for 

exempting new replacement engines? 

* * * * * 

(a) General provisions. You are 

eligible for the exemption for new 

replacement engines only if you are a 

certificate holder. Note that this 

exemption does not apply for 

locomotives (40 CFR 1033.601) and that 

unique provisions apply to marine 

compression-ignition engines (40 CFR 


wwoods2 on DSK1DXX6B1PROD with RULES_2
Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23063 

1042.615). Paragraphs (b), (c), and (d) of 

this section describe different 

approaches for exempting new 

replacement engines where the engines 

are specially built to correspond to an 

earlier model year that was subject to 

less stringent standards than those that 

apply for current production (or is no 

longer covered by a certificate of 

conformity). Paragraph (e) of this 

section describes a simpler approach for 

exempting partially complete new 

replacement engines that are built under 

a certificate of conformity that is valid 

for producing engines for the current 

model year. 

(b) * * * 

(6) You add a permanent label, 

consistent with § 1068.45, with your 

corporate name and trademark and the 

following additional information: 

(i) Add the following statement if the 

engine being replaced was not subject to 

any emission standards under this 

chapter: 

THIS ENGINE DOES NOT COMPLY 

WITH U.S. EPA EMISSION 

REQUIREMENTS. SELLING OR 

INSTALLING THIS ENGINE FOR ANY 

PURPOSE OTHER THAN TO REPLACE 

AN ENGINE BUILT BEFORE JANUARY 

1, [Insert appropriate year reflecting 

when the earliest tier of standards began 

to apply to engines of that size and type] 

MAY BE A VIOLATION OF FEDERAL 

LAW SUBJECT TO CIVIL PENALTY. 

(ii) Add the following statement if the 

engine being replaced was subject to 

emission standards: 

THIS ENGINE COMPLIES WITH U.S. 

EPA EMISSION REQUIREMENTS FOR 

[Identify the appropriate emission 

standards (by model year, tier, or 

emission levels) for the replaced engine] 

ENGINES UNDER 40 CFR 1068.240. 

SELLING OR INSTALLING THIS 

ENGINE FOR ANY PURPOSE OTHER 

THAN TO REPLACE A [Identify the 

appropriate emission standards for the 

replaced engine, by model year(s), 

tier(s), or emission levels)] ENGINE 

MAY BE A VIOLATION OF FEDERAL 

LAW SUBJECT TO CIVIL PENALTY. 

(7) Engines exempt under this 

paragraph (b) may not be introduced 

into commerce before you make the 

determination under paragraph (b)(3), 

except as specified in this paragraph 

(b)(7). We may waive this restriction for 

engines excluded under paragraph (c)(5) 

of this section that you ship to a 

distributor. Where we waive this 

restriction, you must take steps to 

ensure that the engine is installed 

consistent with the requirements of this 

paragraph (b). For example, at a 

minimum you must report to us 

annually whether engines we allowed 

you to ship to a distributor under this 

paragraph (b)(7) have been placed into 

service or remain in inventory. After an 

engine is placed into service, your 

report must describe how the engine 

was installed consistent with the 

requirements of this paragraph (b). Send 

these reports to the Designated 

Compliance Officer by the deadlines we 

specify. 

(c) Previous-tier replacement engines 

without tracking. You may produce a 

limited number of new replacement 

engines that are not from a currently 

certified engine family under the 

provisions of this paragraph (c). If you 

produce new engines under this 

paragraph (c) to replace engines subject 

to emission standards, the new 

replacement engine must be in a 

configuration identical in all material 

respects to the old engine and meet the 

requirements of § 1068.265. This would 

apply, for example, for engine 

configurations that were certified in an 

earlier model year but are no longer 

covered by a certificate of conformity. 

You must comply with the requirements 

of paragraph (b) of this section for any 

number of replacement engines you 

produce in excess of what we allow 

under this paragraph (c). Engines 

produced under this paragraph (c) may 

be redesignated as engines subject to 

paragraph (b) of this section, as long as 

you meet all the requirements and 

conditions of paragraph (b) of this 

section before the end of the calendar 

year in which the engine was produced. 

The following provisions apply to 

engines exempted under this paragraph 

(c): 

(2) * * * 

(ii) Partially complete engines 

exempted under paragraph (e) of this 

section. 

* * * * * 

(4) Add a permanent label as specified 

in paragraph (b)(6) of this section. For 

partially complete engines, you may 

alternatively add a permanent or 

removable label as specified in 

paragraph (d) of this section. 

* * * * * 

(d) Partially complete engines. The 

following requirements apply if you 

ship a partially complete replacement 

engine under paragraph (b) or (c) of this 

section: 

(1) Provide instructions specifying 

how to complete the engine assembly 

such that the resulting engine conforms 

to the applicable certificate of 

conformity or the specifications of 

§ 1068.265. Where a partially complete 

engine can be built into multiple 

different configurations, you must be 

able to identify all the engine models 

and model years for which the partially 

complete engine may properly be used 

for replacement purposes. Your 

instructions must make clear how the 

final assembler can determine which 

configurations are appropriate for the 

engine they receive. 

(2) You must label the engine as 

follows: 

(i) If you have a reasonable basis to 

believe that the fully assembled engine 

will include the original emission 

control information label, you may add 

a removable label to the engine with 

your corporate name and trademark and 

the statement: ‘‘This replacement engine 

is exempt under 40 CFR 1068.240.’’ This 

would generally apply if all the engine 

models that are compatible with the 

replacement engine were covered by a 

certificate of conformity and they were 

labeled in a position on the engine or 

equipment that is not included as part 

of the partially complete engine being 

shipped for replacement purposes. 

Removable labels must meet the 

requirements specified in § 1068.45. 

(ii) If you do not qualify for using a 

removable label in paragraph (d)(1) of 

this section, you must add a permanent 

label in a readily visible location, 

though it may be obscured after 

installation in a piece of equipment. 

Include on the permanent label your 

corporate name and trademark, the 

engine’s part number (or other 

identifying information), and the 

statement: ‘‘This replacement engine is 

exempt under 40 CFR 1068.240.’’ If there 

is not enough space for this statement, 

you may alternatively add: 

‘‘REPLACEMENT’’ or ‘‘SERVICE 

ENGINE’’. For purposes of this 

paragraph (d)(2), engine part numbers 

permanently stamped or engraved on 

the engine are considered to be included 

on the label. 

(e) Partially complete current-tier 

replacement engines. The provisions of 

paragraph (d) of this section apply for 

partially complete engines you produce 

from a current line of certified engines 

or vehicles. This applies for enginebased and equipment-based standards 

as follows: 

(1) Where engine-based standards 

apply, you may introduce into U.S. 

commerce short blocks or other partially 

complete engines from a currently 

certified engine family as replacement 

components for in-use equipment 

powered by engines you originally 

produced. You must be able to identify 

all the engine models and model years 

for which the partially complete engine 

may properly be used for replacement 

purposes. 


wwoods2 on DSK1DXX6B1PROD with RULES_2
23064 Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 

(2) Where equipment-based standards 

apply, you may introduce into U.S. 

commerce engines that are identical to 

engines covered by a current certificate 

of conformity by demonstrating 

compliance with currently applicable 

standards where the engines will be 

installed as replacement engines. These 

engines might be fully assembled, but 

we would consider them to be partially 

complete engines because they are not 

yet installed in the equipment. 

* * * * * 

(g)* * * 

(2) Anyone installing or completing 

assembly of an exempted new 

replacement engine is deemed to be a 

manufacturer of a new engine with 

respect to the prohibitions of 

§ 1068.101(a)(1). This applies to all 

engines exempted under this section. 

* * * * * 

■ 336. Section 1068.260 is amended by 

revising paragraphs (a), (b), (c), and (e) 

to read as follows: 

§ 1068.260 What general provisions apply 

for selling or shipping engines that are not 

yet in their certified configuration? 

* * * * * 

(a) The provisions of this paragraph 

(a) apply for emission-related 

components that cannot practically be 

assembled before shipment because they 

depend on equipment design 

parameters. 

(1) You do not need an exemption to 

ship an engine that does not include 

installation or assembly of certain 

emission-related components, if those 

components are shipped along with the 

engine. For example, you may generally 

ship aftertreatment devices along with 

engines rather than installing them on 

the engine before shipment. We may 

require you to describe how you plan to 

use this provision. 

(2) You may ask us at the time of 

certification for an exemption to allow 

you to ship your engines without 

emission-related components. If we 

allow this, we may specify conditions 

that we determine are needed to ensure 

that shipping the engine without such 

components will not result in the engine 

being operated outside of its certified 

configuration. See paragraph (d) of this 

section for additional provisions that 

apply in certain circumstances. 

(b) You do not need an exemption to 

ship engines without specific 

components if they are not emissionrelated components identified in 

Appendix I of this part. For example, 

you may generally ship engines without 

radiators needed to cool the engine. 

(c) If you are a certificate holder, 

partially complete engines shipped 

between two of your facilities are 

exempt, subject to the provisions of this 

paragraph (c), as long as you maintain 

ownership and control of the engines 

until they reach their destination. We 

may also allow this where you do not 

maintain actual ownership and control 

of the engines (such as hiring a shipping 

company to transport the engines) but 

only if you demonstrate that the engines 

will be transported only according to 

your specifications. See § 1068.261(b) 

for the provisions that apply instead of 

this paragraph (c) for the special case of 

integrated manufacturers using the 

delegated-assembly exemption. Notify 

us of your intent to use this exemption 

in your application for certification, if 

applicable. Your exemption is effective 

when we grant your certificate. You may 

alternatively request an exemption in a 

separate submission; for example, this 

would be necessary if you will not be 

the certificate holder for the engines in 

question. We may require you to take 

specific steps to ensure that such 

engines are in a certified configuration 

before reaching the ultimate purchaser. 

Note that since this is a temporary 

exemption, it does not allow you to sell 

or otherwise distribute to ultimate 

purchasers an engine in an uncertified 

configuration. Note also that the 

exempted engine remains new and 

subject to emission standards (see 

definition of ‘‘exempted’’ in § 1068.30) 

until its title is transferred to the 

ultimate purchaser or it otherwise 

ceases to be new. 

* * * * * 

(e) Engines used in hobby vehicles are 

not presumed to be engines subject to 

the prohibitions of § 1068.101. Hobby 

vehicles are reduced-scale models of 

vehicles that are not capable of 

transporting a person. Some gas turbine 

engines are subject to the prohibitions of 

§ 1068.101, but we do not presume that 

all gas turbine engines are subject to 

these prohibitions. Other engines that 

do not have a valid certificate of 

conformity or exemption when 

introduced into U.S. commerce are 

presumed to be engines subject to the 

prohibitions of § 1068.101 unless we 

determine that such engines are 

excluded from the prohibitions of 

§ 1068.101. 

* * * * * 

§ 1068.261 [Amended] 

■ 337. Section 1068.261 is amended by 

removing and reserving paragraph (c)(5). 

Subpart D—[Amended] 

■ 338. Section 1068.325 is amended by 

revising paragraph (g) to read as follows: 

§ 1068.325 What are the temporary 

exemptions for imported engines/ 

equipment? 

* * * * * 

(g) Exemption for partially complete 

engines. You may import an engine if 

another company already has a 

certificate of conformity and will be 

modifying the engine to be in its final 

certified configuration or a final exempt 

configuration under the provisions of 

§ 1068.262. You may also import a 

partially complete engine by shipping it 

from one of your facilities to another 

under the provisions of § 1068.260(c). If 

you are importing a used engine that 

becomes new as a result of importation, 

you must meet all the requirements that 

apply to original engine manufacturers 

under § 1068.262. 

* * * * * 

Subpart E—[Amended] 

§ 1068.410 [Amended] 

■ 339. Section 1068.410 is amended by 

removing and reserving paragraph (e)(1). 

■ 340. Section 1068.440 is amended by 

revising paragraph (b) to read as follows: 

§ 1068.440 How do I ask EPA to reinstate 

my suspended certificate? 

* * * * * 

(b) Give us test data from production 

engines/equipment showing that 

engines/equipment in the remedied 

family comply with all the emission 

standards that apply. 

Subpart F—[Amended] 

■ 341. Section 1068.501 is amended by 

revising paragraphs (a)(5), (e), and (f) to 

read as follows: 

§ 1068.501 How do I report emissionrelated defects? 

* * * * * 

(a)* * * 

(5) You must track the information 

specified in paragraph (b)(1) of this 

section. You must assess this data at 

least every three months to evaluate 

whether you exceed the thresholds 

specified in paragraphs (e) and (f) of this 

section. Where thresholds are based on 

a percentage of engines/equipment in 

the family, use actual U.S.-directed 

production volumes for the whole 

model year when they become available. 

Use projected production figures until 

the actual production figures become 

available. You are not required to collect 

additional information other than that 

specified in paragraph (b)(1) of this 

section before reaching a threshold for 

an investigation specified in paragraph 

(e) of this section. 

* * * * * 


wwoods2 on DSK1DXX6B1PROD with RULES_2
Federal Register / Vol. 75, No. 83 / Friday, April 30, 2010 / Rules and Regulations 23065 

(e) Thresholds for conducting a defect 

investigation. You must begin a defect 

investigation based on the following 

number of engines/equipment that may 

have the defect: 

(1) For engines/equipment with 

maximum engine power at or below 560 

kW: 

(i) For families with annual 

production below 500 units: 50 or more 

engines/equipment. 

(ii) For families with annual 

production from 500 to 50,000 units: 

more than 10.0 percent of the total 

number of engines/equipment in the 

family. 

(iii) For families with annual 

production from 50,000 to 550,000 

units: more than the total number of 

engines/equipment represented by the 

following equation: 

Investigation threshold = 5,000 + 

(Production units—50,000) × 0.04 

(iv) For families with annual 

production above 550,000 units: 25,000 

or more engines/equipment. 

(2) For engines/equipment with 

maximum engine power greater than 

560 kW: 

(i) For families with annual 

production below 250 units: 25 or more 

engines/equipment. 

(ii) For families with annual 

production at or above 250 units: more 

than 10.0 percent of the total number of 

engines/equipment in the family. 

(f) Thresholds for filing a defect 

report. You must send a defect report 

based on the following number of 

engines/equipment that have the defect: 

(1) For engines/equipment with 

maximum engine power at or below 560 

kW: 

(i) For families with annual 

production below 1,000 units: 20 or 

more engines/equipment. 

(ii) For families with annual 

production from 1,000 to 50,000 units: 

more than 2.0 percent of the total 

number of engines/equipment in the 

family. 

(iii) For families with annual 

production from 50,000 to 550,000 

units: more than the total number of 

engines/equipment represented by the 

following equation: 

Reporting threshold = 1,000 + 

(Production units—50,000) × 0.01 

(iv) For families with annual 

production above 550,000 units: 6,000 

or more engines/equipment. 

(2) For engines/equipment with 

maximum engine power greater than 

560 kW: 

(i) For families with annual 

production below 150 units: 10 or more 

engines/equipment. 

(ii) For families with annual 

production from 150 to 750 units: 15 or 

more engines/equipment. 

(iii) For families with annual 

production above 750 units: more than 

2.0 percent of the total number of 

engines/equipment in the family. 

* * * * * 

[FR Doc. 2010–2534 Filed 4–29–10; 8:45 am] 

BILLING CODE 6560–50–P 


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