The Environmental Protection Agency (“EPA”) has proposed
regulations of carbon emissions from new fossil fuel-fired
power plants under the authority of Section 111(b) of the Clean
Air Act (“CAA”). The agency proposes one set of standards
for gas-fired units and second pair of alternative standards
for coal-fired units. Most new combined cycle gas-fired units
already meet the proposed standard for gas-fired units. By
contrast, neither recently built nor recently proposed coal-fired
units can meet EPA’s proposed standard without using carbon
capture and sequestration (“CCS”), a technology that some
electric utilities are likely to assert has not yet been deployed
cost-effectively on a commercial basis. These new source performance
standards (“NSPS”) apply from the date of publication
of the proposal in the Federal Register, requiring proposed
coal plants that have not commenced construction as of publication
to meet the new performance standard.1
President Obama also has directed EPA to issue emissions
guidelines for existing sources under Section 111(d). EPA rarely
uses this authority, and there are significant legal obstacles to
the imposition of direct controls on existing sources. First, it is
not at all clear that EPA has any authority under Section 111(d)
to regulate electrical generating units (“EGUs”). Specifically,
conflicting statutory language in Section 111(d) disallows issuance
of standards for sources in categories with already existing
hazardous air pollutant standards, and electric generating
units are such a category. EPA takes the position that the specific
pollutant has to be regulated as part of the Section 112
category, which would allow simultaneous regulation of the
sources. However, it is not clear that EPA’s interpretation is
consistent with the statutory language.
Even if Section 111(d) is available to regulate greenhouse gases
from existing sources, the CAA leaves significant discretion to
states to implement the guidelines issued by EPA. Many states
already have programs in place to address greenhouse gas
emissions, and these states will champion flexibility to keep
their existing rules. Other states that do not currently have programs
may also want to take advantage of the inherent flexibility
in Section 111(d) to develop rules that best suit the state’s
particular circumstances. Together, the statutory language and
state flexibility indicate a lengthy process for comprehensive
regulation of greenhouse gases from existing sources.
This White Paper describes the operation of CAA Section 111
as a whole. Next, it explains the important aspects of two major
provisions, Section 111(b) and Section 111(d), by explaining EPA’s
authority and responsibilities under the relevant provisions and
related regulations. As this White Paper explains the statutory
and regulatory mechanisms of Section 111, it also highlights
portions of the regulatory process that are significant considering
the proposed rule for new sources and President
Obama’s direction to develop regulations for existing sources.
EPA published a new proposal differentiating the carbon emissions
standards for new coal-fired and new natural gas-fired
plants on January 8, 2014 after first informally introducing the
regulations in September 2013 (“2014 Proposed Rule”).2 While
existing technology should generally allow new natural gasfired
plants to meet the emissions standards relatively easily,
the stringent emissions levels in these new regulations may
make it extremely difficult to construct a new coal-fired plant
that does not include carbon capture technology. The new rule
will apply only to new fossil fuel-fired electric generating units.
It will not apply to existing units, units undergoing modification,
reconstructed units, or units that commenced construction
prior to publication of the new proposed rule.3
For natural gas-fired stationary combustion cycle (“NGCC”)
turbines larger than 850 mmBtu / hr, the proposed standard is
1,000 pounds of CO2 per megawatt-hour (“lb CO2 / MWh-gross”).
For units smaller than 850 mmBtu / hr, the proposed standard is
1,100 lb CO2 / MWh-gross. Depending on which standard best
suits the unit, the proposed limits for fossil fuel-fired utility boilers
and integrated gasification combined cycle (“IGCC”) are
1,100 lb CO2 / MWh-gross over a 12-month operating period, or
1,000–1,050 lb CO2 / MWh-gross over an 84-month (seven-year)
operating period.4 The aim of the longer compliance period
is to provide flexibility as CCS use is phased in for each unit.
The operator has the option to use some or all of the 84-month
operating period to optimize the system. EPA is specifically
seeking comments on what the standard should be within the
The potential regulations, first proposed in September 2013,
mark the Obama administration meeting its first self-imposed
deadline in its aggressive rulemaking agenda announced on
June 25, 2013 to address greenhouse gas emissions. President
Obama directed EPA to issue a new proposal for regulation of
greenhouse gases (“GHGs”) from new EGUs under the authority
of Section 111 the Clean Air Act (“CAA”) by September 20,
2013.5 Additionally, the President directed EPA “to issue standards,
regulations, or guidelines, as appropriate, that address
carbon pollution from modified, reconstructed and existing
power plants . . . ” under Sections 111(b) and (d) of the CAA.6
Previously, in 2012, EPA used its Section 111(b) authority to propose
a nationwide performance standard for CO2 emissions
from new fossil fuel-generating units (“2012 Proposed Rule”).7
In the 2012 Proposed Rule, EPA sought to combine electric
utility steam-generating units (boilers and IGCC units that are
currently in the Da category with combined cycle units (which
are currently in the KKKK category) into a new category of
sources (TTTT category) for purposes of GHG emissions. The
2012 Proposed Rule required that all new fossil fuel-fired EGUs
meet an electricity-output-based emissions rate of 1,000 lb
CO2 / MWh of electricity generated on a gross basis.8 As of
September 20, 2013, EPA withdrew the 2012 Proposed Rule.
Although President Obama directed EPA to issue a new proposed
rule for new EGUs no later than September 20, 2013,
the President provided no deadline for the final rule for new
sources.9 For existing, reconstructed, or modified EGUs, the
president directed EPA to propose performance standards no
later than June 1, 2014 with a final version due no later than
June 1, 2015.10
After receiving more than 2.5 million comments, EPA significantly
revised the 2012 Proposed Rule. Specifically, EPA has
elected to use existing EGU categories, to propose separate
standards of performance based on distinct “best system of
emissions reduction” (“BSER”) for each subcategory, and to
clarify fee calculation for greenhouse gases in Title V permits.
Table of Acronyms
BSER Best System of Emissions Reduction
CAA Clean Air Act
CCS Carbon Capture and Storage (or
CO2 Carbon Dioxide
EGU Electric Generating Unit
EPA Environmental Protection Agency
GHG Greenhouse Gas
HAP Hazardous Air Pollutant
IGCC Integrated Gasification Combined Cycle
lb CO2 / MWh Pounds of CO2 per Megawatt-hour
MMBtu / hr Million British Thermal Units per Hour
NOX Nitrous Oxide
NAA QS National Ambient Air Quality Standards
NGCC Natural Gas Combined Cycle
NSPS New Source Performance Standards
PM Particulate Matter
RIA Regulatory Impact Analysis
SO2 Sulfur Dioxide
OVERVIEW OF STATUTORY AND REGULATORY
AUTHORITY TO REGULATE GHGs UNDER CAA
Section 111 enumerates two types of authority EPA may use
to regulate air pollutant emissions from stationary sources
like power plants. First, under Section 111(b), EPA may directly
set performance standards for new sources or existing
sources undergoing a major modification.11 Second, under
Section 111(d), EPA can require the states to set performance
standards for existing sources.12 In June 2011, the U.S. Supreme
Court held that the CAA preempted GHG pollution suits under
federal common law because the CAA, through provisions like
Section 111, “speaks directly” to the regulation of greenhouse
gas emissions from sources like power plants.13
n New Source Performance St andards (“NSPS”)
for Categories Designated Under CAA
Under CAA Section 111(b), EPA must list categories of stationary
sources that cause or contribute to air pollution that likely
endanger public health or welfare. Under Section 111(b), EPA
must then regulate emissions from new sources and some
modified sources within the defined source categories by
issuing a standard of performance for that source category.
Under Section 111(b), EPA has no authority to regulate existing
sources in the designated categories either directly or
Category Designation Under CAA Section 111(b)
CAA Section 111(b)(1)(A) requires EPA to list any category of stationary
sources that “causes, or contributes significantly to, air
pollution that may reasonably be anticipated to endanger public
health or welfare” on a periodic basis.14 This endangerment
finding is a “prerequisite for listing additional source categories
under Section 111(b), but is not required to regulate GHGs
from source categories that have already been listed [under
Section 111(b)], such as EGUs at power plants and refineries.” 15
Endangerment findings apply to a source category as whole.16
EPA’s authority to “distinguish among classes, types, and sizes
within categories of new sources” is quite broad.17 EPA can
exercise “considerable discretion” under its Section 111 authority.
18 Although Section 111 allows EPA to distinguish between
subcategories of sources, “EPA is not required by law to subcategorize
. . . .” 19 For example, EPA did not exceed its discretion
in establishing one uniform new source performance
Su mmary of Key Provisions of 2014 Proposed Ru le
Performance St andard Ex clusions Title V Operating Permit Fees
Subpart Da: Natural Gas-Fired
Combustion Turbines (BSER: Natural
Gas Combined Cycle)
• Large Turbines (heat input >
850 mmBtu / hr – 1,000 lb CO2 / MW-hr)
• Small Turbines (heat input <
850 mmBtu / hr – 1,000 lb CO2 / MW-hr)
Small Size Exemption — NSPS not applicable
to units of less than 219,000 MWh
Exemption of GHGs from the presumptive
minimum fee of ∼ $47 / ton via cost
adjustment that ensures sufficient
fee collection to cover program costs
while not collecting Title V permit fees
approaching $200,000 annually for
Potential Electric Output
Exemption — NSPS not applicable to
units selling less than one third of
output to the grid (replacing the Simple-
Cycle Combustion Turbine Exemption
of the 2012 Proposed Rule).
Subpart KKKK: Fossil Fuel-Fired Boilers
and IGCC Units
(BSER: Partial Carbon Capture and
• 1,100 lb CO2 / MW-hr 12-operating-month
• 1,000–1,050 lb CO2 / MW-hr 84-month
Non-Fossil Fuel Exemption — Unit generates
90% or more of electricity with
standards for nitrogen oxide (“NOx”) emissions from utility and
industrial boilers under Section 111 of CAA even though EPA
had previously set a range of standards based on boiler and
fuel type.20 This precedent indicates that if EPA provides sufficient
justification for doing so, EPA could potentially combine
multiple source categories that have previously been identified
as endangering public health or welfare though emission
of a pollutant to create a single, designated source category.
EGUs are sources under CAA Section 111. EPA has included
EGUs on the Section 111(b) list of stationary sources since 1979,
and has issued final standards of performance for new utility
units for pollutants, such as NOX, particulate matter (“PM”), and
sulfur dioxide (“SO2”).21 In April 2007 in Massachusetts v. EPA,22
the U.S. Supreme Court held that GHGs meet the definition
of “air pollutant” under the CAA. In 2009, EPA issued a finding
that GHG air emissions may reasonably be anticipated
to endanger Americans’ public health and welfare (“2009
The 2012 Proposed Rule for new sources of carbon dioxide
adopted a “one category approach” in which EPA did not distinguish
between categories and subcategories it has previously
recognized under Section 111(b); it proposed that all
EGUs falling within the category meet the same emissions limit
regardless of fuel type.24
In contrast, the 2014 Proposed Rule uses existing source categories
under current 40 CFR part 60 subpart Da for fossil
fuel-fired utility boilers and IGCC and current subpart KKKK
for simple and combined cycle natural gas-fired stationary
combustion turbines under two co-proposals.25 First, EPA
proposes redefining “EGU” under the subparts solely for the
2014 Proposed Rule by incorporating three additional criteria:
(1) the unit actually supplies more than one third of its
potential electric output to the grid using a three year rolling
average methodology; (2) the unit supplies more than
219,000 MWh, not the current 25 MW, of net electrical output
to the grid (similar to the EPA Acid Rain Program definition)
and (3) any EGU which derives 10% or less of its heat input
over a three year period from fossil fuel is not subject to the
proposed carbon standards.26
As an alternative to modifying existing subparts for carbon
standards, EPA co-proposes combining Da and KKKK for
purposes of regulating CO2 emissions only, not emissions of
other conventional pollutants, in a new subpart: TTTT.27 By
combining existing categories, EPA states that it is not creating
a new source category.28 EPA seeks input on whether
combining categories under new subpart TTTT will offer additional
flexibility in emissions guidelines for existing sources.
For example, EPA posits that the TTTT subcategory may be
eligible for a system-wide approach, such as emissions rate
averaging, that covers fossil-fuel fired steam generating units
and combustion turbines.29
Interaction between the 2009 Endangerment Finding and
Category Designation for EGUs. According to EPA, “Clean Air
Act Section 111 does not require the EPA, as a prerequisite to
regulating any particular air pollutant, to issue an endangerment
finding or a cause-or-contribute significantly finding for
that air pollutant from that source category.” 30 However, CAA
Section 111 may be alternatively interpreted to require that EPA
base its regulations of the GHG CO2 from EGUs on finding
both that (1) CO2 air pollution may reasonably be anticipated to
endanger public health or welfare and (2) that CO2 emissions
from EGUs cause or contribute significantly to air pollution.31
Under this interpretation, the 2009 Endangerment Finding
would likely suffice for the first prerequisite for all categories
of EGUs, but the fulfillment of the second prerequisite may be
category dependent with larger EGUs more easily identified as
causing or significantly contributing to air pollution.32
A third interpretation takes a mixed approach of the first two.
This interpretation of Section 111 may require that EPA base
its regulation of CO2 emissions from electric generating units
on a rational basis for protection of the public health or welfare.
Under this interpretation, the 2009 Endangerment Finding
combined with the fact that EGUs are the largest stationary
source emitters of CO2 could provide a strong justification for
regulation of electric generating units.33
In American Electric Power Co. v. Connecticut, the Court
explained that under the mechanics of the Section 111(b)(1)(B),
EPA “must establish standards of performance for emission of
pollutants” for new or modified sources within each designated
category EPA has listed under Section 111(b).34 The language
of Section 111 defines a standard of performance as “a standard
for emissions of air pollutants which reflects the degree
of emission limitation achievable through the application of the
best system of emission reduction which (taking into account
the cost of achieving such reduction and any non-air quality
health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated.”
Performance standards for new sources apply nationally
and are effective upon promulgation.35
Emissions Limitation or Emissions Standard. An emissions
limitation or an emissions standard under the CAA is “a requirement
established by the State or the Administrator which limits
the quantity, rate or concentration of emissions of air pollutants
on a continuous basis.” 36 As with designation of categories,
EPA has significant discretion to determine the appropriate
level for the standards. Nonetheless, the CAA requires EPA to
set a standard of performance reflecting “the best system of
emission reduction . . . adequately demonstrated.” 37 To determine
the best technological system of emission reduction,
EPA reviews technologies to determine the types of emissions
reduction systems that exist and their effectiveness in reducing
the target air pollutant.38 Included in the technology review
is an analysis of the benefits and disbenefits of the systems
in terms of cost, air quality impacts, non-air quality impacts
and energy efficiency.39 The final result is often a rate-based
standard determined by the emissions reductions achievable
by the effectiveness of one or more systems, but not a requirement
that a specific technology be implemented to meet the
new source performance standard (“NSPS”).40
BSER and Defining “Adequately Demonstrated” Under CAA
Section 111. EPA identifies four factors for determining the
“best system of emission reductions . . . adequately demonstrated
(“BSER”)”: (i) technical feasibility,41 (ii) technology
(innovation),42 (iii) costs of the system,43 and (iv) degree of
In the 2014 Proposed Rule, EPA briefly addresses its proposed
emissions standards for natural gas-fired stationary combustion
turbines base on NGCC as a BSER, stating that “virtually
all new sources in this category are using NGCC technology.”
45 The Proposed Rule does not thoroughly analyze NGCC
as a BSER in terms of its technological innovations or costs.
In contrast, EPA’s lengthier analysis of the proposed BSER for
fossil fuel-fired and IGCC EGUs signals EPA’s concern that carbon
capture and sequestration is less obviously “adequately
Technically Feasible: EPA Considers a Technology to be
“Adequately Demonstrated” if the Technology is Reasonably
Projected to Exist in the Near Future. EPA may be able to
“adequately demonstrate[ ]” a performance standard is
“achievable,” or “technically feasible,” even in the absence of
specific data, if EPA has reasonably extrapolated from existing
data. “[S]ection 111 ‘looks toward what may fairly be projected
for the regulated future, rather than the state of the art
at present.’” 46 To do so, EPA “may make a projection based on
existing technology, though that projection is subject to the
restraints of reasonableness.” 47 Furthermore, “EPA may compensate
for a shortage of data through the use of other qualitative
methods, including the reasonable extrapolation of a
technology’s performance in other industries.” 48 Yet, “EPA may
not base its determination that a technology is adequately
demonstrated or that a standard is achievable on mere speculation
or conjecture.” 49
As a result of the holdings in Portland Cement and Lignite
Energy Council v. EPA, EPA may determine that an emissions
control technology will be adequately demonstrated in a specific
number of years, and may set a current standard for that
future time that will reflect the projected emissions reductions.
EPA also has the authority to revise performance standards
and determine that a technology that EPA had previously
reasoned would be adequately demonstrated is in fact not
adequately demonstrated. EPA can then delay or revise the
performance standard to correct the misjudgment.
EPA argues it is not required to demonstrate at the plant level
that its selected technology is feasible, because it is charged
with creating national, uniform standards.50 Court decisions
under other provisions of the CAA have reinforced EPA’s contention
that standards need not be feasible for every potential
actor affected by the standard in order to be deemed “adequately
In a 1976 rulemaking under CAA Section 111 concerning copper
smelting furnaces, EPA promulgated standards that were
achievable for most but not all types of existing furnaces.52
EPA asserted that it was authorized to set only one standard
for the different sources “in order that the standard may reflect
the maximum feasible control for that class.” 53 EPA explained
that where the application of the standard would effectively
ban a process, there must be an alternative process that is
“functionally interchangeable” and the economic impact of
the single standard must be reasonable.54 EPA was satisfied
that both requirements were met for new sources, but finding
the economic impact for converting existing reverberatory
furnaces unreasonable, it exempted them from the standard.
Thus, where EPA is setting standards for new plants, the technology
need not be possible in all types of plants currently
In defending the 2014 Proposed Rule, EPA asserts that “each
step in the [CCS] process has been determined to be feasible”
through (i) an extensive literature record;55 (ii) data from fossil
fuel-fired industrial plants currently in commercial operation
and pilot-scale fossil-fuel-fired EGUs currently in operation;
and (iii) progress toward completion of construction of fossil
fuel-fired EGUs implementing CCS at commercial scale.56
From these data points, EPA asserts that “there are no insurmountable
technological, legal, institutional, regulatory or
other barriers that prevent CCS from playing a role in reducing
GHG emissions.” 57
Technology Innovation: EPA’s Aim of Promoting Emerging
Technology and Innovation Can Be at Odds with the Analysis
of Whether a BSER is Adequately Demonstrated. The D.C.
Circuit has noted that “[a]lthough it is conceivable that a particular
control technique could be considered both an emerging
technology and an adequately demonstrated technology,
there is inherent tension between the two concepts.” 58
In justifying partial CCS in the 2014 Proposed Rule, EPA
discusses the potential for continued technological innovation.
59 In the preamble to the Proposed Rule, EPA summarizes
examples of EGUs implementing or proposing to
implement CCS on some scale. In particular, EPA mentions
five EGUs that are incorporating CCS on a commercial scale:
Southern Company’s Kemper County (Mississippi) Energy
Facility; SaskPower’s Boundary Dam CCS Project (Estevan,
Saskatchewan, Canada); Summit Power’s Texas Clean Energy
Project (near Odessa, Texas); the Hydrogen Energy California
Project (Kern County, California); and NRG Energy’s post-combustion
carbon capture project at the company’s W.A. Parish
generating station (southwest of Houston, Texas).60
Despite these examples, EPA has also noted that the example
projects have required significant tax dollars and none applies
CCS to coal-fired EGUs. As a result, it is arguable that EPA has
selected an emerging technology that is not adequately demonstrated
and lacks sufficient research success to consider
it technically feasible for purposes of generation planning for
the foreseeable future.
Costs: Courts Defer to EPA’s Analysis of Costs in the BSER
Analysis Unless the Costs are Unreasonable. Historically,
courts have been deferential to EPA on the agency’s analysis
of costs of the BSER, requiring no specific calculation methodology
of subfactors, only that the costs not be “exorbitant” 61 or
“excessive.” 62 Courts have relied on EPA’s own determination
that costs were not unreasonable, stating “[t]his is a judgment
call with which we are not inclined to quarrel,” even when characterizing
the cost of controls as “substantial.” 63
Arguably, EPA’s proposal reaches the threshold for “exorbitant”
costs as EPA itself has stated that using currently available
CCS technologies “would add around 80 percent to the cost
of electricity for a new pulverized coal (PC) plant, and around
35 percent” for a new IGCC plant.64 These increased costs
result from the parasitic energy load associated with CCS. As
much as 30 percent of the electricity that a plant produces
could be used for CCS.65
In the Regulatory Impact Analysis, EPA discounts the costs
of CCS by explaining that it does not expect that the 2014
Proposed Rule will have any impacts on the price of electricity,
employment or labor markets, or the U.S. economy because
EPA anticipates no new coal-fired units.66 EPA explains that the
large supply of natural gas is likely to ensure that all new fossil-
fuel-fired units are likely to be fueled by methane, not coal.
EPA analysis of costs associated with a control process often
accounts for any revenue generated by the sale of by-products
of the control process. For example, in a regional haze
program, EPA took into account the revenue from fly ash that
was generated during the control process.67 Under other sections
of the CAA, EPA has even considered savings to the end
consumer.68 While EPA considers cost savings to the customer
in its analysis, EPA often willingly ignores costs that are passed
along to the consumer.69
Although EPA minimizes consumer cost impacts, EPA does
acknowledge construction costs as a large barrier in CO2
capture and sequestration.70 EPA argues that many of these
costs can be offset by selling CO2 for enhanced oil recovery
(“EOR”).71 EPA has projected that installing carbon capture
would not unreasonably increase costs and, in some instances,
could decrease costs.72
EPA’s projections are based on a series of assumptions, which
may not reflect reality.73 For example, the Kemper site, which
has been touted as evidence that partial CSS can be commercialized,
has had ballooning construction costs (from
$2.4 billion to $4.7 billion) and has already resulted in significant
rate hikes for consumers.74 Most recently, Mississippi
Power Co. CEO Ed Holland, the owner of the Kemper facility,
sought approval for a 22 percent rate hike for the EGU.75
Degree of Emissions Reduction: EPA Balances Degree of
Emissions Reduction Against Factors Like Cost. Citing Sierra
Club v. Costle76 and Essex Chemical Corp. v. Ruckelhaus,77
EPA explains that a BSER analysis must weigh the degree
of reductions achievable by each system.78 Neither of these
cases states that emissions reductions be given more weight
than costs or other factors. Sierra Club v. Costle suggests that
no one factor is less important than others and that no one
factor is more important than others. The court highlighted the
difference in focusing on emissions reduction rates under the
BSER analysis as opposed to the “lowest achievable emission
rate” analysis used to prescribe standards for nonattainment
areas. It noted that costs and other factors are to have much
more of a role in the BSER analysis than in the “lowest achievable
emission rate” analysis.
In the 2014 Proposed Rule, EPA focuses heavily on the relative
amount of emissions reductions that could be achieved by
different technologies potentially applicable to coal-fired facilities.
For example, when making the BSER determination, EPA
discounted highly efficient generation options like subcritical
pulverized coal and circulating fluidized bed combustion.79
EPA stated that both lacked sufficient CO2 reductions because
even though the units are more efficient than existing technology,
they would emit between 1,450 to 1,800 lb CO2 / MWh.80
Performance Standard Options. Under the CAA, EPA has the
authority to issue traditional rate-based performance standards.
81 EPA may also set emissions limits either for equipment
within a facility or for an entire facility. Whether EPA has
authority under Section 111(b) to implement performance standards
based on market mechanisms is less clear. While EPA
attempted to create a national trading program for new and
existing sources under the Clean Air Mercury Rule (“CAMR”),82
the design of CAMR subjected new and modified sources
under Section 111(b) to traditional rate-based standards as well
as a trading program.
EPA has characterized its past rules for EGUs as “fuel- and
technology-neutral,” setting one standard for all included
sources.83 In EPA rules for PM, SO2, and NOx, EPA set the standard
by examining emissions rates of coal-fired units.84 EPA’s
rationale for focusing on coal was that coal has higher sulfur,
nitrogen, and ash contents compared to oil or gas, and as
a result selecting the BSER for coal was more “complex.” 85
For that BSER determination, EPA looked first at the source
technology that would have the greatest challenge reducing
emissions, and then used that to set the standard.
In contrast, in the current proposal, EPA is setting the standard
based on the best performer. In the 2012 Proposed Rule, EPA
recommended NGCC technology as the only BSER for both
coal and natural gas. By the agency’s own admission, doing
so represented “a departure from prior agency practice.” 86 In
the new Proposed Rule, EPA identifies partial CCS as the BSER
for coal-fired EGUs, yet EPA does not substantially change the
emissions standard (from 1,000 CO2 / MWh to 1,100 CO2 / MWh
for new fossil-fuel-fired boilers and IGCC units).87
EPA appears to be attempting to indirectly regulate fuel use
through the proposed emissions standard even though courts
have recognized that under the CAA, EPA cannot require use
of a certain fuel type.88 Although EPA has asserted that it can
prefer some technological processes at the expense of others,
in all similar examples, it was only the technology, and not the
fuel, that was being banned.89
Similarly, it appears that by setting the standard at 1,000 lb
CO2 / MWh, EPA is effectively requiring that all new coal plants
adopt CCS technology. Under Section 111(b)(5), EPA may not
prescribe a “particular technological system” unless EPA first
determines that it is not feasible to set or enforce a standard
of performance for a source category. Arguably, CCS is a
“particular technological system” and cannot be forced upon
EGUs without a determination by EPA. However, the possibility
that an EGU could switch fuel from coal to gas may undercut
the argument of EGUs that the 2014 Proposed Rule effectively
mandates a “particular technological system” because the
fuel switching is an alternative to installing and operating
Regulation of Modified and Reconstructed Sources
An existing source may be directly regulated by EPA under
Section 111(b) only if the particular facility undertakes a major
construction project that increases emissions, changes production
methods, or replaces a significant portion of components
after the date on which EPA has proposed to issue
emissions standards that would affect NSPS for a designated
EPA has specifically stated that the 2014 Proposed Rule
does not apply to modification or reconstruction of existing
sources.92 Thus, a modification or reconstruction of an existing
EGU at a site will not be subject to the emissions standard, but
new construction at a site with existing EGUs will be subject
to the 2014 Proposed Rule.93 Under Section 111(d) of the CAA,
EPA must create regulations for existing sources in a category
if it promulgates standards for new sources.
n St andards of Performance for Exi sting
Sources Under Section 111(d)
The 1979 version of the CAA grants EPA authority under 111(d)
to set standards for certain existing stationary sources not
already covered by Section 110 or Section 112 of the Act. In
the 1990 Clean Air Act Amendments, the referenced portion
of Section 112 was deleted and Section 111(d) was amended to
account for this change. However, the Senate and House versions
of the bill amended 111(d) in different ways. In the House
version, it was amended through Section 108(g): “REGULATION
OF EXISTING SOURCES. — Section 111(d)(1)(A)(i) of the Clean
Air Act . . . is amended by striking ‘or 112(b)(1)(A)’ and inserting
‘or emitted from a source category which is regulated under
section 112.’” 94 In the Senate version, Section 111 was amended
through Section 302(a): “Section 111(d)(1) of the Clean Air Act is
amended by striking ‘112(b)(1)(A)’ and inserting in lieu thereof
‘112(b).’” 95 Through a drafting error, both amendments are
included in the final version of the statute.
Under the House version, EPA is prohibited from regulating
a category of facilities that EPA already is regulating under
Section 112 of the statute, which addresses emissions of hazardous
air pollutants (“HAPs”). As EPA has issued a final rule
regulating HAP emissions from power plants (the Mercury and
Air Toxic Standards Rule), a literal interpretation of the language
disallows Section 111(d) regulation of GHGs from power
plants. EPA has elected to interpret the disparate language in
House and Senate Amendments to Section 111(d) to allow EPA
to regulate GHGs from existing power plants and other existing
stationary sources despite regulation of these categories
under Section 112.
EPA’s interpretation of Section 111(d) of the CAA allows for regulation
of pollutants from existing sources if two conditions
are met: (i) the target pollutant is not otherwise regulated by
the CAA as either a criteria pollutant under the national ambient
air quality standards or as a hazardous air pollutant, and
(ii) the category of sources is determined to require a NSPS
for the target pollutant.96 It is reasonable to expect that the
D.C. Circuit Court of Appeals will be called upon to decide this
important threshold issue. The outcome could turn on whether
the court decides that the statutory language is clear in denying
EPA authority to use Section 111(d) in these circumstances
or whether it decides that the statutory language is ambiguous
and defers to EPA’s reasonable interpretation.
If EPA has authority to proceed to regulate existing sources
under Section 111(d), it will encounter a different landscape
than the familiar command and control of new and modified
sources provided by Section 111(b) because Section 111(d)
uses a combined federal / state process to impose emissions
limits. Before EPA can indirectly regulate GHG emissions for
a category of existing sources, EPA must first propose regulations
for new sources in the same source category under
Section 111(b). EPA did so for new EGUs on January 8, 2014
with the 2014 Proposed Rule. After proposing NSPS, EPA may
establish an emissions guideline document for emissions at
existing sources. States subsequently use the guideline document
in drafting state plans that establish “standards of performance”
for existing sources within the source categories
EPA has established under Section 111(b).97 EPA then approves
each state plan in a manner similar to the National Ambient
Air Quality Standards program in CAA Section 110.98 In this
process, the EPA emissions guideline functions as a floor for
the state standard setting.99
EPA May Not Directly Prescribe Performance Standards for
CAA Section 111(d) does not give EPA direct authority to
develop nationally applicable standards of performance
for existing sources except in limited circumstances. CAA
Section 111(d) states that only “where a State fails to submit
a satisfactory plan,” EPA “shall have the same authority
. . . to prescribe a plan for [such] State . . . as [EPA] would
have under [CAA Section 110(c)] . . . in the case of failure [by a
state] to submit an implementation plan . . . .” 100 Under its more
restricted authority under Section 111(d), EPA has promulgated
regulations for itself and states to follow in developing and
submitting state plans under Section 111(d).101 The regulations
set forth the requirements EPA must meet to develop a guideline
document,102 actions EPA must undertake if a state plan
is unsatisfactory,103 and the substantive elements a state must
include for its plan to be approved by EPA.104
EPA’s Guideline Document. To aid states in complying with
Section 111(d), EPA drafts a guideline document “containing
information pertinent to control of the designated pollutant”
from the focused-upon source category.105 EPA has interpreted
CAA Section 111(d) to require a three-step process for
drafting an emissions guideline.106 First, EPA identifies potential
emissions limits achievable from existing “emissions reductions
systems” for a category of existing sources. Second, EPA
evaluates each emissions limit through a cost benefit analysis
so as to develop an emissions guideline on the “best system.”
Third, the agency publishes the emissions guideline.
Despite substantive requirements on EPA for establishing
emissions guidelines, EPA retains discretion to determine the
degree of specificity to include in the guideline.107 Additionally,
EPA may or may not elect to issue model standards for
existing sources that could then be adopted by states.108
Furthermore, the regulations do not specify the amount of
consideration that states or EPA are to give to the remaining
lives of existing sources.
Because Section 111(d) has been used relatively rarely compared
to other sections of the CAA, there are limited precedents
for how EPA will or should implement future performance
standards under Section 111(d). There have been no lawsuits
challenging the sufficiency of guidelines under Section 111(d);
instead, litigation touching upon Section 111(d) has avoided
substantive issues. For example, in New Jersey v. EPA, the performance
standards for existing sources established by the
Clean Air Mercury Rule were vacated because EPA failed to
properly delist coal- and oil-fired EGUs under CAA Section 112
prior to initiating rulemaking under Section 111.109 When setting
emissions guidelines in the past, EPA has mostly focused
the emissions guidelines on the implementation of emissions
control systems at the facility level. EPA has not significantly
ventured into “beyond-the-fence” measures that consider
emissions reduction systems that can be implemented across
a market sector or source category. The 2014 Proposed Rule’s
discussion of creating the new TTTT category indicates that
EPA is considering beyond-the-fence regulations for existing
EGUs. EPA stated:
We solicit comment on the relative merits of each
approach. In particular we seek comment on whether
the co-proposal to combine the categories and codify
the GHG standards for all new affected sources
in subpart TTTT will offer any additional flexibility for
any future emission guidelines for existing sources, for
example, by facilitating a system-wide approach, such
as emission rate averaging, that covers fossil-fuel fired
steam generating units and combustion turbines.110
Much of the deference granted EPA on Section 111 regulation
is rooted in the fact that under Section 111(b), EPA is in the role
of predicting the future of emissions reduction technology for
new sources.111 Under Section 111(d), EPA may not have the
same degree of discretion because EPA’s own regulation says
that EPA “will specify different emission guidelines” when relevant
subfactors “make subcategorization appropriate.” 112 Even
if EPA uses similar logic in setting the state guidance as it did
in selecting CCS as BSER for new sources, that analysis may
not be sufficient to justify nearly as stringent a standard for
existing sources. Nevertheless, even less stringent standards
could have a significant impact given the volume of carbon
emitted by existing EGUs.
The Congressional Research Service states that EPA has indicated
that the preferred approach for reducing GHGs from
existing units is increasing efficiency,113 but there is no formal
announcement of EPA’s plans.
Procedural Requirements for EPA’s Guideline Documents for
the States. The regulations in 40 C.F.R. Section 60.22 require
EPA to first issue emissions guidelines in a draft form that is
open to public review and comment. The regulations do not
state specific time periods for public review and comment.
After the comment period, EPA considers the received comments
and issues final guidelines.114 Additionally, EPA may
issue the draft guidelines at the same time as or following
proposal of a performance standard under Section 111(b), but
While the procedural requirements under Section 111(d) are
sparse, there is precedent for the process for establishing
guidelines in EPA’s previous issuance of guidelines under
Section 111(d) for municipal waste combustors, municipal solid
waste landfills, sulfuric acid production facilities, kraft pulp
mills, primary aluminum reduction plants, phosphate fertilizer
plants, and hospital / medical / infectious waste incinerators.116
State Plan Requirements
The CAA states that EPA’s “[r]egulations . . . under [Section 111(d)]
shall permit the State in applying a standard of performance
to any particular source under a plan submitted under
[Section 111(d)] to take into consideration, among other factors,
the full remaining useful life of the existing source to which the
standard applies.” States have great flexibility in developing
the plans as they can consider factors like the remaining useful
life of the existing source,117 and they can employ regulatory
mechanisms other than traditional emissions rate limitations.118
Under current regulations, states are required to submit plans
for the performance standards within nine months of the
publication of final emissions guidelines unless an exception
applies.119 If a state does not have any existing sources that
would be covered by the regulations, then that state instead
submits a certification letter by the nine-month state plan
deadline, and is thereafter exempt from the 111(d) guideline
Substantive Requirements. The state implementation plans
must include an emissions inventory as well as emissions limitations
and compliance times that meet the minimum requirements
set out in EPA’s emissions guidelines.121 Before adopting
the plan, the state must, in most circumstances, “conduct
one or more public hearings within the State on such plan or
plan revision.” 122 If the state’s compliance schedule exceeds
12 months from the date of the submittal of the plan, then the
plan must include legally enforceable increments of progress
to achieve compliance.123
Exceptions to EPA’s Minimum Requirements and Challenges
to EPA Decisions. A state may apply for an exception to the
minimum requirements of EPA’s emissions guidelines, either
as to the application of less stringent standards or as to longer
compliance schedules for existing sources than those in
the emissions guidelines. The state must demonstrate that
the cost of pollution controls is unreasonable for the affected
facilities due to (i) facility age, location, or design; (ii) physical
impossibility of installing controls; or (iii) other factors that
make a less demanding standard or final compliance time
significantly more reasonable.124 This petition is only “on a
case-by-case basis for particular designated facilities or
classes of facilities.” 125
In addition to states’ ability to petition on the basis that compliance
would be unreasonable for various factors, governors
may petition EPA to increase the rigor of CAA Section 111
regulations.126 Section 111 allows governors to compel EPA to
act by petitioning EPA to (i) list a category that it is required
to regulate, (ii) regulate pollutants from a listed category, or
(iii) increase the stringency of standards on the basis of a new,
innovative, or improved technology or process that achieves
greater continuous emissions reductions and that has been
State Options for Regulating Existing Sources. Section 111(d)
provides states with significant flexibility in determining how
to develop a plan that meets EPA’s guidelines. The CAA points
to the Section 110 State Implementation Plan Process as the
model for the Section 111(d) process. This approach gives
states some authority over a few aspects of the rule applicable
to existing EGUs. First, states can control the manner
of regulation if the minimum standards of the guidelines are
met. This means that as “long as the ultimate effect of a State’s
choice of emission limitations is complian[t] with . . . standards,
the State is at liberty to adopt whatever mix of emission limitations
it deems best suited to its particular situation.” 128 Second,
states can likely use the flexible program elements delineated
in Section 110: economic incentives such as fees, marketable
permits, and auctions of emissions rights.” 129 Third, states may
create more stringent standards than the emissions guidelines
for existing sources.130
EPA Approval of State Plans Under CAA Section 111(d)
Section 111(d) of the CAA requires EPA to “prescribe regulations
which shall establish a procedure similar to that provided
by [CAA Section 110 relating to National Ambient Air Quality
Standards] under which each State shall submit to [EPA] a
plan which . . . establishes standards of performance for any
existing source for any air pollutant . . . to which a standard of
performance under this section would apply if such existing
source were a new source . . . .” 131 After EPA receives a state
plan or a revision to a state plan, EPA must approve or disapprove
the plan “within four months after the date required for
submission of a plan.” 132 A state plan is “satisfactory” if the
plan includes emissions standards that “prescribe allowable
rates of emission except when it is clearly impracticable.” 133
EPA may not disapprove a state plan simply because it prefers
alternative approaches. Instead, EPA may disapprove a state’s
implementation plan only if the plan is “unsatisfactory” according
to the metrics of the Section 111(d) regulations.134
If a state fails to submit a plan within the default timeline of
nine months, or within an alternative timeline approved by
EPA, or if EPA disapproves the state plan, EPA must “prepare
and publish proposed regulations setting forth a plan” for the
state within six months after the state’s submission deadline
for the plan.135 If the state submits a plan that EPA determines
is satisfactory before the six months pass, EPA is no longer
obligated to issue a replacement plan.136 EPA’s replacement
plan will require full compliance with the emissions guidelines
of all covered EGUs unless an owner or operator of a facility
applies for individual relief.137 In those limited circumstances,
EPA will consider whether to grant relief based upon the factors
in 40 C.F.R. Section 60.24(f).138
• The CAA grants EPA significant authority to directly
regulate GHG emissions from new EGUs and indirectly
regulate existing EGUs as they are already designated
sources under Section 111(b).
• The 2009 Endangerment Finding may be a sufficient
basis for EPA to regulate CO2 emissions unless the
Supreme Court determines that EPA must also demonstrate
for each existing category of EGUs that the
category contributes significantly to GHG pollution.
Depending on the outcome of Utility Air Regulatory
Group v. EPA, EPA may be forced to rely on the 2014
Proposed Rule as the endangerment finding for stationary
• U nder its Section 111(b) authority, EPA maintains discretion
to subcategorize sources and propose emissions
limitations or standards for new sources in those
• EPA has substantial discretion to determine if an emissions
reduction system is adequately demonstrated.
EPA may predict future technological advances and
require new, modified, and reconstructed EGUs to adopt
the unproven technology at a specified future date.
Historically, EPA has received considerable deference in
its BSER determinations. The 2014 Proposal may stretch
this deference beyond its limits because of the unproven
nature of commercial CCS, the high costs, and the dismissal
of alternative BSER options.
• Past experience indicates that EPA will likely use a ratebased
approach to regulate new, modified, or reconstructed
sources. If the TTTT category is selected, it is
possible that existing sources could be subject to a novel
market-wide averaging scheme.
• The existence of a HAP regulation for EGUs under
Section 112 could circumscribe EPA’s authority to use
Section 111(d) to regulate CO2 emissions from existing
EGUs. The scope of this limitation ultimately could be
decided in court.
• EPA’s role in regulating existing sources is mainly limited
to issuing guidance that sets a minimum emissions
standard. With EPA’s specific statement that the 2014
Proposed Rule does not apply to modified or reconstructed
sources, the current rule has little direct impact
on existing sources.
• States retain significant discretion to adopt technology
and policy that meets the minimum requirements of EPA’s
emissions guidelines. However, with little precedent in
developing guidelines under Section 111(d), it is possible
that EPA will attempt to curb state discretion in favor of
the most uniform national standard allowable under the
• Performance guidelines provided to states in developing
their state plans are more flexible than those EPA may
adopt in regulating new, modified, and reconstructed
sources. EPA’s discretion related to existing sources is
significantly circumscribed compared to new sources.
• Congressional members have repeatedly expressed dismay
and frustration with the 2014 Proposed Rule for new
sources and the impending proposed rule for existing
sources for a variety of economic and political reasons.
Various bills have been introduced and letters sent to EPA.
President’s Timeline for EPA Action
New Proposed Rule for New
September 20, 2013:
Final Rule for New EGUs Not specified
Proposed Rule for Existing
June 1, 2014
Final Rule for Existing EGUs June 1, 2015
Proposed Rule for
Modified / Reconstructed
June 1, 2014
Final Rule for Modified/
June 1, 2015
For further information, please contact your principal Firm representative
or one of the lawyers listed below. General email
messages may be sent using our “Contact Us” form, which can
be found at www.jonesday.com.
Mary Beth Deemer
Thomas M. Donnelly
G. Graham Holden
Kevin P. Holewinski
John A. Rego
Sharyl A. Reisman
Thomas V. Skinner
Charles T. Wehland
Jennifer M. Hayes
1 In materials supporting the reproposed rule, EPA identified five EGUs
incorporating CCS on a commercial scale. Three of the CCS projects
are in the planning state, and the two under construction have
exceeded projected costs. James McCarthy, Cong. Research Serv.,
R43127, EPA Standards for Greenhouse Gas Emissions from Power
Plants: Many Questions, Some Answers 9–10 (2013).
2 “Standards of Performance for Greenhouse Gas Emissions from
New Stationary Sources: Electric Utility Generating Units,” 79 Fed.
Reg. 1429, 1433 (to be codified as 40 C.F.R. pts 60, 70, 71 and 98),
available at http://www.gpo.gov/fdsys/pkg/FR-2014-01-08/pdf/2013-
28668.pdf [hereinafter “2014 Proposed Rule”].
3 Id. at 1446.
4 This standard would require capture, compression and storage of
about 40% of produced CO2 from affected plants. McCarthy, supra
note 1, at 5.
5 B arack Obama, Memorandum for the Administrator of The
Environmental Protection Agency, “Power Sector Carbon Pollution
Standards” (June 25, 2013), available at http://www.whitehouse.gov/
7 “Standards of Performance for Greenhouse Gas Emissions for New
Stationary Sources: Electric Utility Generating Units,” 77 Fed. Reg.
22392, 22394 (proposed Apr. 13, 2012, withdrawn Sept. 20, 2013) (to
be codified as 40 C.F.R. pt 60), available at http://epa.gov/carbonpollutionstandard/
pdfs/20120327proposal.pdf [hereinafter “2012
8 C.F.R. at 29 (“This proposed standard is based on the demonstrated
performance of natural gas combined cycle (NGCC) units, which . . .
are likely to be the predominant fossil fuel-fired technology for new
generation in the future . . . NGCC qualifies as the ‘best system’ of
emission reduction . . . that the EPA has determined has been adequately
demonstrated because NGCC emits the least amount of
CO2 and does so at the least cost.”).
9 B arack Obama, Memorandum for the Administrator of the
Environmental Protection Agency, Power Sector Carbon Pollution
Standards, supra note 5.
11 Clean Air Act § 111(b), 42 U.S.C. § 7411(b) (1990).
12 Id. at § 111(d), § 7411(d).
13 American Electric Power Co., Inc. v. Connecticut, 131 S. Ct. 2527,
2537–38 (2011). Eight states, one city, and three land trusts brought
suit against electric companies for their alleged contributions to the
public nuisance of global warming. The first district court opinion,
Connecticut v. American Electric Power Co., Inc., No. 04 Civ.5669
LAP, 04 Civ.5670 LAP, 2005 WL 2249748 (S.D.N.Y. Sep. 15, 2005),
was amended and superseded by a second opinion, Connecticut
v. American Electric Power Co., Inc., 406 F.Supp.2d 265, (S.D.N.Y.
Sep. 22, 2005) (dismissing the complaint because the Court believed
the complaint raised several nonjusticiable political questions).
The second district court opinion was vacated and remanded by
Connecticut v. American Electric Power Co., Inc., 582 F.3d 309 (2d Cir.
2009). The Second Circuit held that the district court erred in dismissing
the complaints on political question grounds. Furthermore, the
circuit court found that all Plaintiffs had standing and that they had
stated a claim under the federal common law of nuisance. Certiorari
was granted by American Electric Power Co., Inc. v. Connecticut, 131
S. Ct. 813 (Dec. 6, 2010). The Supreme Court affirmed the Second
Circuit’s ruling on standing but held that “The Clean Air Act and the
EPA action the Act authorizes displace any federal common-law right
to seek abatement of carbon-dioxide emissions from fossil-fuel fired
power plants.” American Electric Power Co., Inc. v. Connecticut, 131
S. Ct. 2527 (2011). The Court reversed and remanded the case to
determine whether the Plaintiffs have state law claims that are not
preempted by the CAA.
14 CAA § 111(b)(1)(A), 42 U.S.C. § 7411(b)(1)(A).
15 EPA, Background on Establishing New Source Performance
Standards (NSPS) Under the Clean Air Act, 40 C.F.R. § 60.14; 40 C.F.R.
§ 60.15, available at http://epa.gov/carbonpollutionstandard/
pdfs/111background.pdf [hereinafter “Background on Establishing
16 Id. at n. 1.
18 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999).
21 Standards of Performance for New Stationary Sources (NSPS),
40 C.F.R. pt. 60 subpart Da (1979); 44 FR 33580( June 11, 1979).C.F.R.
Additionally, “[N]othing in the language of section 111(b) precludes
EPA from issuing additional standards of performance for other pollutants,
including HAP, emitted from new Utility Units.” Standards
of Performance for New and Existing Stationary Sources: Electric
Utility Steam Generating Units, 40 CFR pt 60, 72 and 75, 70 Fed.
Reg at 28613. “EPA listed electric utility steam generating boilers,
including coal-fired boilers, and initially regulated them in subpart
D of its regulations under CAA section 111. Subsequent regulation
of utility boilers has been under subpart Da. The EPA listed stationary
combustion turbine engines and initially regulated them under
subpart GG. The stationary combustion turbine engine portions of
combined cycle facilities were also regulated under subpart GG.
Heat recovery steam generators (HRSG) associated with combined
cycle facilities with duct burners were regulated under either subpart
Da or one of the industrial boiler regulations, depending on the
specific characteristics of the HRSG. To minimize the compliance
burden for owners/operators of combined cycle facilities, some
monitoring harmonization was done, but the two subparts were still
applicable. In 2005, EPA proposed subpart KKKK as a replacement
for subpart GG and specifically covered the entire combined cycle
facility under subpart KKKK such that only a single set of requirements
would apply. In that same year, EPA proposed to include
Integrated Gasification Combined Cycle (IGCC) facilities under the
applicability of subpart Da. Notice of Standards of Performance for
Greenhouse Gas Emissions for New Stationary Sources: Electric
Utility Generating Units 27–29 (Mar. 27, 2012) available at http://www.
22 549 U.S. 497 (2007).
23 Standards of Performance for New and Existing Stationary Sources:
Electric Utility Steam Generating Units Clean Air Mercury Rule,
40 C.F.R. pts. 60, 72, 75 (2005); 70 Fed. Reg. 28,606 (May 18, 2005),
available at http://www.epa.gov/ttn/oarpg/t3/fr_notices/27982camr111.
pdf [hereinafter Clean Air Mercury Rule].
24 2012 Proposed Rule, supra note 7, at 22394.
25 2014 Proposed Rule, supra note 2, at 1433.
26 Id. at 1445–46.
27 Id. at 1454.
28 Id. at 1454–55
30 2012 Proposed Rule, supra note 7, at 22397.
31 2012 Proposed Rule, supra note 7, at 22397.
32 In Utility Air Regulatory Group v. EPA, No. 12-1146, cert. granted
Oct. 15, 2013, the U.S. Supreme Court elected to hear challenges to
EPA’s greenhouse gas permitting program for stationary sources in
February 2014. Despite numerous and varied challenges to EPA’s
greenhouse gas regulations, the Court granted review only of
whether EPA permissibly determined that its regulation of greenhouse
gas emissions from new motor vehicles triggered the permitting
requirement under the CAA for stationary sources. The limited
nature of the Supreme Court’s review of EPA’s greenhouse gas permitting
program could have little impact on whether large emissions
sources will face regulation that will effectively curb greenhouse gas
emissions. Because the Court is reviewing only whether regulating
vehicles mandates stationary sources to obtain permits for greenhouse
gas emissions, a ruling against EPA would limit the need
for stationary, industrial sources to obtain prevention of significant
deterioration and Title V operating permits for their greenhouse gas
Furthermore, EPA indicates that the evidence cited in the 2014
Proposed Rule about the impacts of GHGs and the contribution of
EGUs to GHGs provides a sufficient independent basis for an endangerment
finding for CO2 from stationary sources. 2014 Proposed
Rule at 1452–53.
33 2012 Proposed Rule, supra note 7, at 22397.
34 American Electric Power Co., Inc. v. Connecticut, 131 S. Ct. 2527,
35 See, e.g., Clean Air Mercury Rule.
36 Clean Air Act, 42 U.S.C. § 7602 (1990).
37 CAA § 111(a)(1); 42 U.S.C. § 7411(a)(1).
38 Background on Establishing NSPS, supra note 15.
39 R egulating Greenhouse Gas Emissions Under the Clean Air Act, 73
Fed. Reg. 44,354, 44,486–87 (advanced notice of proposed rulemaking,
July 30, 2008).
40 Background on Establishing NSPS, supra note 15.
41 See Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C.
Cir. 1973) (“We begin by rejecting the suggestion of the cement
manufacturers that the Act’s requirement that emission limitations
be ‘adequately demonstrated’ necessarily implies that any cement
plant now in existence be able to meet the proposed standards.
Section 111 looks toward what may fairly be projected for the regulated
future, rather than the state of the art at present, since it is
addressed to standards for new plants.”).
42 See, e.g., Sierra Club v. Costle, 657 F.2d 298, 347 (D.C. Cir. 1981) (“balancing
of cost, energy, and nonair quality health and environmental
factors embraces consideration of technological innovation as part
of that balance. The statutory factors which EPA must weigh are
broadly defined and include within their ambit subfactors such as
43 CAA § 111(a)(1) (directing EPA to take into account the costs of any
proposed emissions reduction system).
44 See Sierra Club, 657 F.2d at 326 (“we can think of no sensible interpretation
of the statutory words “best . . . system” which would not
incorporate the amount of air pollution as a relevant factor to be
weighed when determining the optimal standard for controlling . . .
45 2014 Proposed Rule, supra note 2, at 1485.
46 Lignite Energy Council v. EPA, 198 F.3d 930, 934 (D.C. Cir. 1999)
(quoting Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391
47 Id. EPA relies on this decision to argue that a standard of performance
is “achievable” if the technology that will allow them to meet
the standard is adequately demonstrated. This results in a paradigm
where the achievability of a standard is based solely on its technical
feasibility, effectively reducing two requirements into one.
48 Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1054 n. 70 (D.C. Cir. 1978). In
Lignite Energy Council v. EPA, 198 F.3d at 934 , EPA’s use of emissions
data from two high-sulfur coal-fired utility boilers and foreign utility
boilers because of an inability to collect emissions data for any
coal-fired industrial boilers was reasonable because EPA had demonstrated
that the emissions-reducing technology could be successfully
applied to coal-fired utility boilers under a “‘wide range of
operating conditions’ including those analogous to the load cycles
of industrial boilers.”
49 Lignite Energy Council v. EPA, 198 F.3d at 934 (citing National Asphalt
Pavement Ass’n, 539 F.2d 775, 787 (D.C. Cir. 1976). See also Portland
Cement Ass’n v. Ruckelshaus, 486 F.2d at 391–92 (“The Administrator
may make a projection based on existing technology, though that
projection is subject to the restraints of reasonableness and cannot
be based on ‘crystal ball’ inquiry”).
50 See S. Rep. No. 91-1196, at 16 (1970) (“[l]and use policies must be
developed to prevent location of facilities which are not compatible
with implementation of national standards.”); see also Sierra Club,
657 F.2d at 330 (“[The] EPA must examine the effects of technology
on the grand scale in order to decide which level of control is best.”).
51 See International Harvester Co. v. EPA, 478 F.2d 615, 640 (D.C. Cir.
1973) (“ . . . as long as feasible technology permits the demand for
new passenger automobiles to be generally met, the basic requirements
of the Act would be satisfied, even though this might occasion
fewer models and a more limited choice of engine types.”);
NRDC v. EPA, 489 F.3d 1364, 1376 (D.C. Cir. 2007) the D.C. Circuit
upheld EPA’s decision to apply the same hazardous air pollutant
requirements to different types of wood products facilities because
the facilities (i) used the same inputs, (ii) “compet[ed] in the same
markets,” and (iii) had similar HAP emissions.
52 See, e.g., Standards of Performance for New Stationary Sources,
Primary Copper, Zinc, and Lead Smelters, 40 C.F.R. pt. 60 (1976); 41
FR 2331, 2333 (Jan. 15, 1976) (a single standard for SO2 emissions for
new construction or modifications of reverberatory, flash, and electric
smelting furnaces in primary copper smelters was reasonable
as to flash and electric, but not reverberating smelters.) [hereinafter
Copper, Zinc, and Lead Smelters].
55 2014 Proposed Rule, supra note 2, at 1471. On November 12, 2013 the
Chair of the Scientific Advisory Board (“SAB”) of EPA’s Office of the
Administrator issued a memorandum calling into question the adequacy
of peer review of materials relied upon by EPA in setting CCS
as a BSER. James R. Mihelcic, Preparations for Chartered Science
Advisory Board (SAB) December 4–5, 2013 Discussions of EPA
Planned Agency Actions and their Supporting Science in the Spring
2013 Regulatory Agenda, available at http://yosemite.epa.gov/sab/
Wk+GRP+Memo+Spring+2013+Reg+Rev+131213.pdf. Specifically, the
The SAB Work Group recommends that the SAB review
the science supporting the [2014 Proposed Rule] . . .
EPA stated that the science and technical bases of this
action do not rely on new science, are based on the Best
System of Emission Reduction, and the action is technology
based. In contrast, the Work Group notes that this
action involves precedential and novel issues that rely
on new technologies and science for carbon capture
and storage (CCS). EPA Staff explained that the CCS
provisions would only be binding to coal fired EGUs and
are based on three examples of implementing partial
CCS. They stated that the strong demonstration these
facilities make for the technology . . . and this proposal
relies on existing sequestration studies and reporting
requirements for carbon capture. The Work Group finds
that the scientific and technical basis for carbon storage
provisions is new science and the rulemaking would
benefit from additional review . . . EPA staff explained that
the NETL studies were all peer reviewed and EPA did
not conduct additional peer review(s). However, based
on additional information provided to the Work Group
from NETL, the peer review appears to be inadequate
56 2014 Proposed Rule, supra note 2, at 1434–35, 1442, 1468, 1475, 1479
(Southern Company’s Kemper County (Mississippi) Energy Facility);
id. at 1434–35, 1475 (SaskPower’s Boundary Dam CCS Project); id.
at 1434, 1442 (Summit Power’s Texas Clean Energy Project); id. at
1435, 1436 n. 13 (Hydrogen Energy California Project); id. at 1434, 1476
(N.R.G. Energy at W.A. Parish).
57 On November 15, 2013, members of the House Committee on Energy
and Commerce called for EPA to withdraw its Proposed Rule as
being prohibited by the Energy and Policy Act. They argue this law
explicitly prohibits EPA from setting new source performance standards
under Section 111 of the Clean Air Act based on the emissions
reductions achieved at facilities receiving assistance from the
Energy Department’s Clean Coal Power Initiative or advanced coal
project tax credits. Letter from the House of Representatives Comm.
on Energy and Commerce to Gina McCarthy, Administrator for EPA
(Nov. 15, 2013), available at http://energycommerce.house.gov/sites/
pdf. EPA has not responded to the letter.
58 Sierra Club, 657 F.2d at 341, n. 157.
59 EPA refers to other CCS projects — domestic and worldwide — that
are helping to further develop the CCS technology. 2014 Proposed
Rule, supra note 2, at 1475. EPA quotes an industry leader arguing
that CCS in part is not commercially feasible because there are
yet to be regulations making it worthwhile to attempt to make CCS
commercially feasible. Id. at 1469 (citing AEP Places Carbon Capture
Commercialization On Hold, Citing Uncertain Status Of Climate
Policy, Weak Economy, American Electric Power (July 14, 2011), http://
60 2014 Proposed Rule, supra note 2, at 21–22, 28–29, 236–37.
61 Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir.
1973) (to be “adequately demonstrated,” the system must be “reasonably
reliable, reasonably efficient, and . . . reasonably expected
to serve the interests of pollution control without becoming exorbitantly
costly in an economic or environmental way.”); see also Lignite
Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) (“EPA’s choice
will be sustained unless the environmental or economic costs of
using the technology are exorbitant.”).
62 Sierra Club v. Costle, 657 F.2d 298, 383 (D.C. Cir. 1981).
63 Sierra Club, 657 F.2d at 383, 313.
64 2012 Proposed Rule, supra note 7, at 22415–16.
65 McCarthy, supra note 1, at 10.
66 See Regulatory Impact Analysis for the Proposed Standards of
Performance for Greenhouse Gas Emissions for New Stationary
Sources: Electric Utility Generating Units 5-54 (2013), available
documents/20130920proposalria.pdf. In analyzing the 2013 proposal,
EPA reused the 2012 Proposed Rule Integrated Planning Model
results with review through the Energy Information Administration’s
most recent Annual Energy Outlook to confirm its projection that
industry would construct new coal-fired units.
67 2014 Proposed Rule, supra note 2, at 1464.
68 See, e.g., 2017 and Later Model Year Light-Duty Vehicle Greenhouse
Gas Emissions and Corporate Average Fuel Economy Standards,
40 C.F.R. pts 85, 86, 600 (2012); 77 Fed. Reg. 62,624 (October 15,
2012) (rulemaking setting GHG emissions standards for Light-Duty
Vehicles for Model Years 2017–2025).
69 See Portland Cement Ass’n v. EPA, 513 F.2d 506 (D.C. Cir. 1975)
(demand is inelastic); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir.
1981) (consumers can bear costs).
70 In noting the construction costs, EPA does not evaluate the environmental
risks and resulting costs potentially linked to injection of CO2
underground. The National Academy of Sciences published a study
abstract in November 2013 that concludes that the underground
injection of carbon dioxide in Texas may have spurred earthquakes.
Wei Gan and Cliff Frohlich, Gas Injection May Have Triggered
Earthquakes in the Cogdell Oil Field, Texas, available at http://www.
71 Id. at 218, 232.
72 See 2014 Proposed Rule, supra note 2, at 1476.
73 See supra note 57 discussing Congressional concern over EPA’s
misuse of government-funded projects in its BSER analysis.
74 Mississippi Power Wants Rate Hike, Mainly for Kemper Plant,
Mississippi Business Journal (Nov. 17, 2013) available at http://
76 657 F.2d 298 (D.C. Cir. 1981).
77 486 F.2d 427 (D.C. Cir. 1973).
78 2014 Proposed Rule, supra note 2, at 1463–64.
79 Id. at 1468.
81 See 40 C.F.R. § 60.82 (2011) for an example of a traditional emissions
rate mechanism wherein each covered sulfuric acid production unit
is subject to an emissions rate of 4 pounds SO2 per ton of acid
produced. See 40 C.F.R. § 60.33b(d)(1) (2011) for an example of allowing
compliance with NOX emissions for municipal waste combustors
based on a plant-wide, not individual, unit average.
82 New Jersey v. EPA, 517 F.3d 574, 578 (D.C. Cir. 2008) (vacated CAMR
on other grounds without reaching the question of whether the
proposed cap-and-trade program and its design parameters were
within the agency’s authority).
83 See, e.g., National Emission Standards for Hazardous Air Pollutants
From Coal- and Oil-Fired Electric Utility Steam Generating Units
and Standards of Performance for Fossil-Fuel-Fired Electric
Utility, Industrial-Commercial-Institutional, and Small Industrial-
Commercial-Institutional Steam Generating Units, 40 C.F.R. pts 60,
63 (2011); 76 FR 24976, 25062 (May 3, 2011).
84 Id. at 25062–63.
86 2012 Proposed Rule, supra note 7, at 22418.
87 2014 Proposed Rule, supra note 2.
88 In PPG Indus., Inc. v. Harrison, 660 F.2d 628, 636 (5th Cir. 1981), the
court granted a petition to set aside EPA’s determination that a plant
had to meet a new emissions standard because the court agreed
with petitioner that EPA was effectively forbidding a certain type of
fuel: “EPA attempts to achieve indirectly in this case what it could not
do directly under the Clean Air Act: require the use of a certain type
of fuel in order to comply with a performance standard.” Importantly,
this case based its decision in part on the fact that Section 7411(h),
allowing for EPA to establish “design, equipment, work practice, or
operational standards,” was not operational at the time of EPA’s
determination in this case, whereas it is in effect today.
89 See Primary Copper, Zinc, and Lead Smelters, supra note 52, at
2333–34 (reverberatory smelting furnaces for copper were found to
be inferior at controlling emissions, and so flash and electric smelters
were preferred; however, the rule exempted reverberatory smelting
furnaces when one was using “high levels of volatile impurities,”
because using other types of smelting furnaces had not yet been
90 McCarthy, supra note 1, at 13.
91 Background on Establishing NSPS, supra note 15.
92 2014 Proposed Rule, supra note 2, at 1446.
93 The proposal to exclude modifications and reconstructions from the
new source performance standards has drawn negative comment.
See American Public Power Association, Comments on Proposed
New Source Performance Standards (NSPS) for Electric Generating
Units (EGUs), available at http://www.publicpower.org/files/PDFs/
groups contend that excluding modifications and reconstructions is
against statutory language, congressional intent, and past agency
practice. They point to the exclusion as evidence that CCS is not a
BSER for new sources as EPA admits there is insufficient evidence
to apply the CCS BSER to existing sources undergoing upgrades.
94 Clean Air Act Amendments, Pub. L. No. 101-549, § 108(g) 104 Stat. 2467
95 Clean Air Act Amendments, Pub. L. No. 101-549, § 302(a) 104 Stat.
96 CAA §111(d)(1), 42 U.S.C. § 7411(d)(1) (2006).
97 Id. at §7411(d).
99 Adoption and Submittal of State Plans for Designated Facilities,
40 C.F.R. § 60.24(c)(3).
100 CAA § 111(d)(2)(A).
101 40 C.F.R. Part 60, 60.20–60.29.
102 Id. at § 60.22.
103 Id. at § 60.27, § 60.21(a). “Designated pollutant means any air pollutant,
the emissions of which are subject to a standard of performance
for new stationary sources, but for which air quality criteria
have not been issued and that is not included on a list published
under section 108(a) or section 112(b)(1)(A) of the Act.”
104 Id. at § 60.22.
106 Id.; EPA’s regulations established under § 111(d) are in 40 C.F.R.
Part 60, Subpart B, §§ 60.20–60.29.
107 See Chevron U.S.A. v. Natural Res. Def. Council, Inc., 467 U.S. 837
108 Background on Establishing NSPS, supra note 15.
109 New Jersey v. EPA, 517 F.3d at 578.
110 2014 Proposed Rule, supra note 2, at 1454–55.
111 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999).
112 Subfactors EPA will consider include: “different sizes, types, and
classes of designated facilities when costs of control, physical
limitations, geographical location, or similar factors . . . .” 40 C.F.R.
113 McCarthy, supra note 1 (citing EPA, Rulemaking for Greenhouse Gas
Emissions from Electric Utility Steam Generating Units (May 2011),
available at http://www.epa.gov/air/tribal/pdfs/presentation-ghggasemissionsutility05-
114 See id. Even if EPA promulgates final performance standards for
new or modified sources, the regulatory language does not contain
a deadline for publication of a final emissions guideline document.
115 40 C.F.R. § 60.22.
116 40 C.F.R. Part 60, subparts Cb through Ce; 40 C.F.R. Part 62.
117 40 C.F.R. § 60.22.
118 See CAA §111(d), 42 U.S.C. § 7411(d) (2006) language directing submission
of state plans be “similar to that provided by [Section 110],”
which allows for “economic incentives such as fees, marketable permits,
and auctions of emissions rights.” Examples of existing state
actions that may be sufficient or equivalent to EPA guidance issued
under §111(d) include the nine-state Regional Greenhouse Gas
Initiative for the power sector, California’s economy-wide emissions
trading program, Colorado’s Clean Air–Clean Jobs Act, renewable
portfolio standards, and energy-efficiency programs.
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119 40 C.F.R. § 60.23(a). If a different deadline is specified in the regulation
or if EPA determines it is necessary, EPA may “extend the period
for submission of any plan or plan revision or portion thereof.” C.F.R.
120 Id. at § 60.23(b).
121 Id. at § 60.24–60.25.
122 Id. at § 60.23(c)(1).
123 Id. at § 60.24(c).
124 Id. at § 60.24(f).
125 40 C.F.R. § 60.24.
126 CAA § 111(g), 42 U.S.C. § 7410(g).
128 Virginia v. EPA, 108 F. 3d 1397, 1407–08 (D.C. Cir. 1997) (citing Train v.
Natural Resources Defense Council, Inc., 421 U.S. 60, 79 (1975)).
129 CAA § 111, 42 U.S.C. § 7410(a)(2)(A).
130 40 C.F.R. § 60.24(g).
131 CAA § 111(d)(1).
132 40 C.F.R. § 60.27(b).
133 Id. at § 60.24(b).
134 Id. at § 60.27(c).
135 Id. at § 60.27(c), (d).
137 Id. at § 60.27(e)(2).
138 These include: “[u]nreasonable cost of control resulting from plant
age, location, or basic process design;” “[p]hysical impossibility of
installing necessary control equipment”; and “[o]ther factors specific
to the facility (or class of facilities) that make application of a
less stringent standard or final compliance time significantly more