4. EPA Oversight of State-Issued NPDES Permits To Protect Threatened
and Endangered Species
    In 2001, the EPA, FWS, and NMFS signed a Memorandum of Agreement
(MOA), (66 FR 11202, Feb. 22, 2001) with the objective of enhancing
coordination between the agencies and to assist the agencies in
executing their respective responsibilities under the Clean Water Act
and Endangered Species Act. The MOA reflects, in part, the EPA's
longstanding commitment to overseeing the operation of state NPDES
programs to ensure protection of endangered species with existing
regulatory requirements. The EPA reaffirms its commitment to ensure
coordination of the EPA's and Services' programs and appropriate
protection of listed species, and EPA will follow the procedures in the
MOA in overseeing implementation of this rule.
    The MOA committed the EPA to a number of specific actions that are
pertinent to today's rule. Under the MOA, EPA committed, when contacted
by the Services, to coordinate with the Services and the State/Tribe
during the permit development process, in order to ensure that permits
will comply with all applicable CWA requirements. One way in which
coordination between EPA and the Services is facilitated is through the
exchange of information about permits. The MOA facilitates such
information exchange, as do EPA's NPDES permit regulations at 40 CFR
124.10, that preceded the MOA. These regulations require the Director
to provide public notice and a comment period for draft permits, and to
notify persons identified at 40 CFR 124.10(c)(1)(iii) and (iv). Such
persons specifically include Federal and State agencies with
jurisdiction over fish, shellfish, and wildlife resource and over
coastal zone management plans and thus include the U.S. Fish and
Wildlife Service and the National Marine Fisheries Service.
    EPA's commitment to coordinate effectively with the Services
includes following the procedures in section IX.A.6 and 7 of the MOA:
    EPA may make a formal objection, where consistent with its CWA
authority, or take other appropriate action, where EPA finds that a
State or Tribal NPDES permit will likely have more than minor
detrimental effect on Federally-listed species or critical habitat.
    For those NPDES permits with detrimental effects on Federally-
listed species or critical habitat that are minor, it is the intention
of the Services and EPA that the Services will work with the State or
Tribe to reduce the detrimental effects stemming from the permit. For
those NPDES permits that have detrimental effects on Federally-listed
species or critical habitat that are more than minor, including
circumstances where the discharge fails to ensure the protection and
propagation of fish, shellfish and wildlife, and where the State or
Tribe and the Services are unable to resolve the issues, it is the
intention of the Services and EPA that EPA would work with the State or
Tribe to remove or reduce the detrimental impacts of the permit,
including, in appropriate cases, by objecting to and Federalizing the
permit where consistent with EPA's CWA authority.
    EPA will use the full extent of its CWA authority to object to a
State or Tribal permit where EPA finds (taking

into account all available information, including any analysis
conducted by the Services) that a State or Tribal permit is likely to
jeopardize the continued existence of any listed species or result in
the destruction or adverse modification of critical habitat.
    EPA may review or waive review of draft State or Tribal NPDES
permits (40 CFR 123.24(d)). EPA will work with the Services through the
local/regional coordinating teams to help determine which categories of
permits should be reviewed for endangered species concerns. If EPA
finds that a draft permit has a reasonable potential to have more than
a minor detrimental effect on listed species or critical habitat, and
review of a draft permit has been waived, EPA will withdraw this waiver
during the public comment period (see 40 CFR 123.24(e)(1)).
    The grounds for EPA's exercise of its discretionary authority to
object to State or Tribal permits are described in the NPDES
regulations at 40 CFR 123.44. These include that the proposed permit
fails to comply, or to ensure compliance with, any applicable
requirement of this part, for example, that a permit application did
not contain information sufficient to demonstrate that the permit will
ensure compliance with applicable requirements. See 40 CFR
123.44(c)(1).
    If EPA objects to a NPDES permit under the MOA, EPA will follow the
permit objection procedures outlined in 40 CFR 123.44 and coordinate
with the Services in seeking to have the State or Tribe revise its
permit. A State or Tribe may not issue a permit over an outstanding EPA
objection. If EPA assumes permit issuing authority for a NPDES permit,
EPA will consult with the Service prior to issuance of the permit (as a
Federal action) as appropriate under section 7 of the ESA.
    While the MOA was adopted by the agencies in the context of NPDES
permits for discharges of pollutants, it applies equally to NPDES
permits that contain conditions for cooling water intake structures.
Moreover, section 316(b) of the CWA accords EPA broad authority to
protect waters of the United States from adverse environmental impacts
associated with cooling water intake structures, including adverse
effects to Federally-listed species and designated critical habitat. In
implementing this provision, EPA is authorized to consider costs and
benefits of different approaches to minimizing these impacts. The
importance of listed species, and accordingly the benefits associated
with preventing their extinction, animated Congress's enactment of the
Endangered Species Act in 1973. In the case of aquatic organisms that
are listed as endangered or threatened, and designated critical
habitat, EPA has the authority, and will exercise the full extent of
its authority, to object to a permit proposed by a State where EPA
finds (taking into account all available information, and giving, as
appropriate, substantial weight to the views of the Services) that a
State or Tribal permit is likely to jeopardize the continued existence
of such species or result in the destruction or adverse modification of
such critical habitat. If the State permit is not modified to address
EPA's objections, EPA will issue the permit in consultation with the
Services. EPA's commitment to use the full extent of its CWA authority
to object to permits that are likely to jeopardize listed species or
result in the destruction or adverse modification of critical habitat
is a safeguard for the protection of listed species and critical
habitat. Additionally, where the Service communicates in writing to EPA
its conclusion that a proposed State permit is likely to jeopardize the
continued existence of a listed species, EPA will, upon request,
provide the Service a written response. EPA's commitment to use the
full extent of its CWA authority, along with the other provisions of
the rule requiring the EPA, the Services, and State Directors to fully
consider effects to threatened and endangered species and critical
habitat and include appropriate protections in NPDES permits, insures
that the rule is not likely to jeopardize the continued existence of
listed species or result in the destruction or adverse modification of
designated critical habitat.

L. Permits for Existing Facilities Are Subject to Requirements Under
Other Federal Statutes

    EPA's NPDES permitting regulations at Sec.  122.49 list Federal
laws that might apply to the issuance of NPDES permits under the NPDES
rules. These include the Wild and Scenic Rivers Act, 16 U.S.C. 1273 et
seq.; the National Historic Preservation Act of 1966, 16 U.S.C. 470 et
seq.; the Coastal Zone Management Act, 16 U.S.C. 1451 et seq.; and the
National Environmental Policy Act, 42 U.S.C. 4321 et seq. For a brief
description of each of these laws, see Sec.  122.49. The provisions of
the Magnuson-Stevens Fishery Conservation and Management Act, 16 U.S.C.
1801 et seq., relating to essential fish habitat might also be
relevant. EPA's permit application requirements ensure that FWS and
NMFS will have--and other Federal agencies as well, should have--a
broader information base from which to make informed decisions. Note
also that, in the case of EPA-issued permits, EPA's NPDES permitting
regulations specifically require following the requirements of specific
Federal laws that may apply to the issuance of NPDES permits.

IX. Cost Development and Economic Impact Analysis

    This section summarizes EPA's analysis of the social cost and
economic impact for three regulatory options. In addition to today's
rule, referred to as the Final Rule, EPA analyzed two other options
similar to those options at proposal (see section VI.D Other Options
Considered for Today's Final Regulation for more context). The
regulatory options can be described as follows:
     Final Rule: Flexible impingement mortality performance
standard for existing units based on modified traveling screens with
fish returns for all facilities with DIF greater than 2 mgd, closed-
cycle cooling or its equivalent for new units for impingement and
entrainment, and a national BTA standard that requires a site
determination of entrainment BTA for all other existing units at
existing facilities;
     Proposal Option 2: Intake flow commensurate with closed-
cycle cooling for facilities that have a design intake flow of greater
than 125 mgd, flexible impingement mortality limitations based on
modified traveling screens with fish returns for all facilities with
DIF greater than 2 mgd, and closed-cycle cooling or its equivalent for
new units; and
     Proposal Option 4: Flexible impingement mortality
limitations based on modified traveling screens for all facilities with
DIF greater than 50 mgd, closed-cycle cooling or its equivalent for new
units, and a site-specific determination of entrainment BTA for all
other facilities and for impingement mortality controls at facilities
with flow less than or equal to 50 mgd.
    The first part of this section provides an overall summary of the
costs of the regulatory options to regulated facilities and Federal and
State governments. This discussion is followed by a review of the
method for developing compliance cost estimates. The third part
provides an estimate of the total social costs of the regulatory
options. The final part reviews the economic impact of the regulatory
options.

A. Overview of Costs to Regulated Facilities and Federal and State
Governments

    In estimating the total cost of the regulatory options, EPA
estimated costs for the following components: capital costs and other
one-time costs; installation downtime costs; annual operation and
maintenance costs; and recordkeeping, monitoring, entrainment-related
studies, and reporting costs. All of these costs are included in the
economic impact analysis for the final rule. The cost estimates reflect
the incremental costs attributed only to this final rule. For example,
facilities already having closed-cycle recirculating systems as defined
at Sec.  125.92 will meet the impingement mortality and entrainment
standards of today's rule and, therefore, will not incur costs to
retrofit new technologies. These facilities, including those in New
York and California, will still incur permitting costs. EPA has
established that existing closed-cycle recirculating systems will
comply with the impingement BTA requirements.
    For the economic analysis, EPA distinguished between the two
industry groups regulated by the standards for existing facilities as
follows:
     Electric Power Producers (electric generators)--facilities
owned by investor-owned utilities, municipalities, States, Federal
authorities, cooperatives, and nonutilities, whose primary business is
electric power generation or related electric power services.
     Manufacturing and Other Industries (manufacturers)--
facilities in the paper, aluminum, steel, chemicals, petroleum, food
and kindred products (primary manufacturing industries), and other
industries. In addition to engaging in production activities, some of
these facilities also generate electricity for their own use and
occasionally produce excess power for sale.
    For a more detailed discussion of costs to regulated facilities and
costs to Federal, State, and local governments, see Chapter 8 of the
TDD and Chapter 3 of the EA.
    Electric generators incurring costs include facilities owned by
private firms, governments, and electric cooperatives. Manufacturers
incurring costs include facilities owned by private firms only. The
administrative costs to Federal, State, and local governments include
the costs of rule implementation--e.g., permits, monitoring, and
working with facilities subject to the final rule to achieve
compliance.
    In the economic analysis, EPA accounted for these costs on an as-
incurred basis. They are reported on a pre-tax or after-tax basis,
depending on the specific component of the analysis. These costs also
underlie the analysis of the social costs of the regulatory options.

B. Development of Compliance Costs

    This section describes the data and methods used to estimate
compliance costs of the options considered for today's final rule.
Costs were developed for technology controls to address impingement
mortality separately from technology controls for entrainment because
the requirements of the various rule options considered may lead to
different technologies being used by each facility to comply. The
options considered may impose different compliance timelines for
impingement mortality and entrainment control technologies, although
decision making has been synchronized to avoid investments in
impingement BTA controls that could later be rendered obsolete by the
BTA requirements for entrainment. Different methodologies were used and
each is briefly described below. More detailed information on these
methodologies and costs of other technologies and regulatory approaches
are available in Chapter 8 of the TDD.
1. Combined Facility-Specific and Model-Facility Approach
    EPA estimated national level costs for regulated facilities under
the final rule and other regulatory options. In general, facility-
specific data can be used to determine the requirements that apply to a
facility and whether that facility already meets the final rule's
requirements. This approach requires facility-specific technical data
for the approximately 1,065 facilities that EPA estimates will be
subject to the final rule. The change in the number of facilities
subject to the final rule compared to the number estimated at proposal
is attributable to changes in how EPA accounted for baseline closures.
See Appendix H of the EA for more details. An alternative approach is
to develop a series of model facilities that exhibit the typical
characteristics of the regulated facilities and calculate costs for
each model facility; EPA would then determine how many of each model
facility would be needed to accurately represent the full universe of
regulated facilities.
    The approach used in this effort involved calculating compliance
technology costs for 338 individual facilities for which EPA had
detailed technical data from its questionnaires regarding the intake
design and technology. Specifically, these are the facilities that
completed the detailed technical questionnaire. Where facilities
reported data for separate cooling water intake structures, EPA derived
compliance technology costs for each intake, and summed these intake
costs to obtain total costs for each facility. EPA used the actual
facility data to construct model facilities. Each model facility's
costs were then multiplied by a specific weighting factor, derived from
a statistical analysis of the industry questionnaire, to obtain
industry-wide costs. The weighting factors are similar to the ones
derived during the development of the 2004 Phase II and 2006 Phase III
rules.
2. Updates to the Survey Data
    For the 2004 Phase II rule analysis, EPA developed facility-
specific cost estimates for all facilities and published those costs in
an appendix (69 FR 41669, July 9, 2004). Since the initial
implementation of the 2004 Phase II rule, EPA identified several
concerns with using only the facility-specific costing approach, and
the use of those costs in Appendix A. Since 2004 EPA has collected data
from industry and other groups as described in Section III of the
proposed rule (76 FR 22183, April 20, 2011). These data generally
reflect changes to actual intake flow, design intake flow, intake
velocity, technology in place, and operational status. EPA developed a
new master database including this new data to supplement the data from
the detailed technical questionnaire. Although it has been more than 10
years since the detailed technical questionnaire was initially
collected, EPA has undertaken more than 50 site visits and reviewed
available literature. In addition, EPA compared its data with that
collected by Edison Electric Institute, Electric Power Research
Institute, and the Energy Information Administration. On the basis of
that review, EPA concluded that the master database is representative
and reasonably reflects costs for all facilities.\102\ The following
section describes how EPA used this new database to estimate compliance
costs.
---------------------------------------------------------------------------

    \102\ EPA notes that, while it has not collected updated
technical information for every facility, it has updated financial
data, as discussed later in this section.
---------------------------------------------------------------------------

3. Tools for Developing Compliance Costs
    During development of the 2004 Phase II rule, EPA began developing
a spreadsheet-based tool that would provide facilities and permit
authorities with a simple and transparent method for calculating
facility-specific

compliance costs. EPA refined the tool in developing the Phase III
regulations. EPA has since made further refinements to the cost tool,
which was used to calculate the compliance costs for impingement
mortality for today's final rule. The cost tool employs a decision tree
(for a graphical presentation of the decision tree, see Chapter 8 of
the TDD) to determine a compliance response for each model facility.
The decision tree assigns a technology costing ``module'' for the
retrofit to a given technology. Impingement cost estimates are derived
through a series of computations that apply facility-specific data
(such as DIF, width of intake screens, and such) to the selected
technology module. Cost tool outputs include capital costs, incremental
operation and maintenance costs, and installation downtime (in weeks).
    To calculate the compliance costs of retrofitting to closed-cycle
cooling for controlling entrainment, EPA used a second tool based on a
cost-estimating spreadsheet using a modified version of a similar tool
developed by the Electric Power Research Institute (EPRI). EPRI's first
draft methodology presented three levels of capital cost according to
the relative difficulty of the retrofit project (easy, average, and
difficult). For electric generators, EPA used costs for the average
level of difficulty because it was developed across a broad spectrum of
facilities and is the most appropriate for estimating national level
costs rather than lower or upper bounds. For manufacturers, EPA used
the difficult level of retrofit costs. This reflects the more complex
water systems and technical challenges to retrofitting closed-cycle
cooling at multiple locations within a manufacturing facility. In site
visits, EPA found the largest manufacturing facilities had multiple
intakes, distributed the water to multiple production processes, have
already significantly increased water reuse as a result of water
audits, and generally operate a complicated water distribution network
at the entire facility, and would therefore require multiple retrofits
to convert the facility to be commensurate with closed-cycle
recirculating system.\103\ Accordingly, EPA determined that the
difficult level of retrofit costs is more representative for purposes
of estimating national level costs. EPA's tool includes additional
modifications to EPRI's methodology, such as increased compliance costs
for approximately 25 percent of facilities to reflect the additional
expense of noise control or plume \104\ abatement, and using only the
cooling water flow rate for non-contact cooling water flow \105\ for
purposes of estimating costs for closed-cycle cooling. EPA has included
the spreadsheet tools in the docket for today's final rule to assist
both facilities and permit authorities in estimating compliance costs
(see DCNs 12-6650 and 12-6651 for the cost tool, as well as and DCN 10-
6930 for EPRI's retrofit analysis).
---------------------------------------------------------------------------

    \103\ A refinery, for example, may have dozens of heat exchange
processes throughout the facility, including a mix of wet and dry
non-contact cooling equipment.
    \104\ The EPRI tool includes drift abatement technologies in its
cost assumptions, so no additional costs were included for drift
eliminators.
    \105\ As described in the TDD, EPA used only non-contact cooling
water flows in determining the proper size for wet cooling towers.
Cooling towers are not widely used for contact cooling or process
water, so these flows were excluded. For electric generators, the
vast majority of flow is non-contact cooling, but manufacturers are
more varied in their water usage.
---------------------------------------------------------------------------

4. Which technologies form the basis for compliance cost estimates?
    EPA identified two broad classes of control technologies that may
be used singularly or in combination to comply with the final rule.
These classes of control technologies are (1) technologies that address
impingement mortality, and (2) technologies that address entrainment.
For further details, see Section VI.
    For the impingement mortality requirements, EPA analyzed data from
a wide variety of technologies and facilities, and concluded that
modified (Ristroph or equivalent) \3/8\'' mesh traveling screens with
fish-friendly fish handling and returns are the most appropriate basis
for determining compliance costs.\106\ As discussed in Section VI of
this preamble, a facility may also comply with impingement mortality
requirements by meeting a low velocity compliance alternative,
operating a closed-cycle recirculating system as defined at Sec.
125.92(c), or employing an existing offshore velocity cap as defined at
Sec.  125.92(v). On the basis of facility-specific data, EPA made a
preliminary assessment of which model facilities would not currently
meet impingement mortality requirements through any of these pre-
approved technologies, and assigned technology costs on the basis of
modified traveling screens with a fish handling and return system if
the existing intake used traveling screens. If the intake does not
currently use traveling screens, EPA assigned costs for installing
technologies that would comply with the low velocity compliance
alternative (larger intakes, wedgewire screens, or variable speed
pumps) based on site-specific conditions. These assigned technologies
will meet the BTA standard (see Sec.  125.94(b)). Although EPA no
longer requires installation of barrier nets or equivalent technologies
to protect shellfish in all tidal waters, EPA included the cost of
barrier net technology at approximately 10 percent of the intakes as a
cost component for the ``systems'' approach to compliance with the IM
standards.
---------------------------------------------------------------------------

    \106\ Note that this does not preclude the use of other
technologies; EPA simply used the available performance data in
deriving the performance requirements. EPA's research has shown that
other technologies may also be capable of meeting the final rule
requirements; however, these technologies are not available at all
facilities.
---------------------------------------------------------------------------

    EPA also analyzed the costs of those options associated with
entrainment requirements based on wet cooling systems. EPA also
evaluated other technologies for reducing entrainment, such as seasonal
operation of cooling towers, partial towers, variable speed pumps, and
fine-mesh screens. The costs of the final rule include but are not
limited to permit applications; characterization of the source water,
intake structures and any technologies in place; studies of impingement
and entrainment; and recordkeeping, monitoring, and reporting. The
costs also include costs of technologies for complying with the BTA for
IM; the cost of additional technologies that may be required to meet
the site-specific BTA for entrainment are not included, nor are costs
for additional measures that may be required for protection of listed
threatened and endangered species. Section VI further describes the
performance of these technologies. A detailed discussion of how the
costs were developed is in Chapter 8 of the TDD.
5. How is installation downtime assessed?
    Installation downtime is the length of time that a facility might
need to shut down for installing a compliance technology. Downtime
estimates primarily assume that the facility would need to completely
shut down operations for some portion of the installation period to
retrofit an intake, such as relocating an intake, connecting wet
cooling systems into the facility, or reinforcing condenser housings.
EPA estimated downtime as incremental outages, taking into account the
periodic outages all facilities incur as part of preventative
maintenance or routinely scheduled outages. For example, nuclear
facilities have refueling outages approximately every 18 months lasting

approximately 40 days.\107\ The entrainment control implementation
periods under Proposal Option 2, 10 years for fossil fuel facilities
and 15 years for nuclear facilities, would provide facilities with an
opportunity to schedule the retrofit when other major upgrades are
being done, thereby significantly reducing downtime.
---------------------------------------------------------------------------

    \107\ Nuclear Energy Institute reported average length of outage
from 2003 to 2009.
---------------------------------------------------------------------------

    For most facilities subject to impingement mortality, EPA assigned
no incremental downtime. Facilities that are replacing or
rehabilitating existing traveling screens typically do so one intake
bay at a time without affecting the overall operations.\108\ EPA has
also found that facilities that need to scrub screens do so during
other routinely scheduled outages. For some compliance technologies,
however, such as relocating an intake or expanding an existing intake
to lower the intake velocity, several weeks of downtime may be incurred
because these are more invasive tasks. See TDD Exhibit 8-4 for EPA's
net construction downtime for the various IM compliance technologies.
---------------------------------------------------------------------------

    \108\ EPA's data shows that facilities have an average of 4 to 5
bays.
---------------------------------------------------------------------------

    EPA reviewed historical retrofit data and site visits conducted
since 2004 and has largely retained its assumptions for downtime from
the Phase II and Phase III rules for facilities retrofitting to closed-
cycle cooling. On average, EPA assumes the net installation downtime
for retrofitting to closed-cycle cooling for non-nuclear electric
generators is 4 weeks. This total downtime allows for the tie-in of the
closed-cycle system to the existing cooling water system. The refueling
outage downtime, the safety-sensitive nature of nuclear facility
retrofits, and other data in EPA's record supports 28 weeks as the net
construction downtime for nuclear facilities. EPA converted downtime
for manufacturing facilities that use cooling water for power and steam
generation into the incremental cost for purchasing electricity during
the outage. For individual process units other than power generation
units at a manufacturing facility, on average the downtime was assumed
to be zero. In EPA's extensive experience with manufacturers, EPA's
record reflects that manufacturers are generally able to shut down
individual intakes for specific process lines, use inventory approaches
such as temporary increases of intermediate products, and develop other
workarounds without interrupting the production of the entire facility.
For further discussion of how EPA accounted for installation downtime
in estimating national costs, see below.
6. How is the energy penalty assessed?
    The term energy penalty in relation to a conversion to closed-cycle
cooling has a number of different interpretations. The first is the
extra power required to operate fans at a mechanical draft cooling
tower and additional pumping requirements (sometimes referred to as
auxiliary energy requirements or parasitic loads). The second is the
lost power output because of the reduction in steam turbine efficiency
from an increase in cooling water temperature relative to once-through
cooling (often referred to as the turbine efficiency penalty or turbine
backpressure penalty). EPA is clarifying that it views the former as
incremental O&M costs, and the latter is EPA's interpretation of the
energy penalty. Energy penalty costs apply only to facilities
retrofitting to closed-cycle cooling without replacing the condenser.
Facilities installing a new impingement mortality technology will not
generally face an energy penalty and will generally see little or no
measureable change in auxiliary power consumption. EPA's national-level
costs include both these costs. The auxiliary power consumption was
included as a separate component in the operation and maintenance costs
and was assessed for all facilities. The turbine efficiency penalty was
typically expressed as a percentage of power output. EPA estimates the
turbine efficiency energy penalty for nuclear and non-nuclear power
generation would be 2.5 and 1.5 percent, respectively (see Chapter 8 of
the TDD). For most manufacturers generating their own electricity, EPA
assumed the same energy penalty for turbine efficiency loss as
estimated for non-nuclear power facilities (i.e., 1.5 percent).
7. How did EPA assess facility-level costs for the national and
regional economic impacts analysis?
    As part of the economic impact analysis, EPA assessed the impact of
the final rule's requirements on electric generators in the context of
national and regional electricity markets. For this analysis, EPA used
the Integrated Planning Model (IPM[supreg]), a comprehensive
electricity market optimization model that assesses such impacts within
the context of regional and national electricity markets. EPA has used
IPM to analyze the impacts of various regulatory actions affecting the
electric power sector over the last decade, particularly Clean Air Act
regulations.
    Because IPM requires facility-specific costs for each analyzed
facility, yet compliance costs were developed as weighted sums of model
facility costs, EPA developed a method to distribute the aggregate
costs to facilities that were not themselves model facilities. For
these facilities, EPA converted facility-level costs developed for
model facilities to a cost per mgd DIF and then averaged these values
to derive cost equations using DIF as the independent variable. These
cost equations provide average costs that can be applied to any
facility by simply scaling to that facility's DIF. For details on the
IPM analysis, see the EA, Chapter 6. For details on facility cost
development, see the TDD, Chapter 8.
8. How did EPA assess costs for new units?
    Power generation and manufacturing units that are a new unit as
defined at Sec.  125.92(u) must meet an entrainment reduction
performance standard based on closed-cycle cooling or an equivalent
reduction in entrainment for the cooling water component of the intake
flow based on the DIF. This section briefly describes the data and
methods used to estimate compliance costs for new units at existing
electric generators and manufacturers. Chapter 8 of the TDD has a
complete description of the methodology.
a. New Units at Existing Electric Generators
    Compliance costs for new units at existing electric generators are
estimated using a similar methodology to that used for estimating
compliance costs for existing facilities. As described in Chapters 6
and 8 of the TDD, however, there are a number of differences in costs
between a closed-cycle cooling retrofit at an existing facility
compared to installing closed-cycle cooling at a new unit. In general,
these differences result in lower costs for the installation of a
closed-cycle recirculating system at a new unit (as compared to a
retrofit scenario), due to improved efficiency of the turbine, the
elimination of construction downtime, greater ease of integrating the
closed-cycle system into the design and construction of the new unit,
offsetting costs of certain system and construction components, and
greater overall system optimization.
    EPA could not determine precisely which facilities will construct
new units. Instead, EPA used an approach to estimate what portion of
the new capacity (i.e., additional megawatts capacity to be constructed
each year) would be subject to the final rule. Using national
projections of increased

generating capacity,\109\ EPA categorized the new capacity into three
groups for 316(b) compliance purposes: (1) Subject to the Phase I
rule,\110\ (2) subject to today's final rule, but projected to install
a cooling system that complies with the rule regardless of the rule
requirements,\111\ and (3) subject to today's rule and projected to
incur compliance costs. Exhibit IX-1 presents the estimated total new
capacity and the estimated capacity for new stand-alone units.
---------------------------------------------------------------------------

    \109\ Capacity increases include considerations for fuel type.
See Chapter 8 of the TDD for details.
    \110\ New capacity that is part of a new facility (as defined by
the Phase I rule) is subject to separate requirements not addressed
by today's rule. Today's requirements for new units require flow
reduction commensurate with a closed-cycle recirculating cooling
system.
    \111\ Data in the record show a marked increase in the use of
closed-cycle cooling in facilities constructed in recent years and
for those projected to be constructed in the near future. These data
indicate that in the 1990s (prior to the Phase I rule), 83 percent
of new cooling systems installed were closed-cycle cooling systems
and that the current trend was approximately 97 percent. Based on
these data EPA assumed that 75 percent to 90 percent of new units
will be designed with a closed-cycle recirculating cooling system
regardless of the requirements of today's rule. See DCN 12-6672. As
a result, this category of new capacity was not assigned any
compliance costs.

                              Exhibit IX-1
------------------------------------------------------------------------
                                                   Total       Existing
                                                 including     facility
                                                  Phase I     new units
                   Fuel type                   -------------     only
                                                    New     ------------
                                                  Capacity   Stand-Alone
                                                    (MW)         (MW)
------------------------------------------------------------------------
Fossil Fuel...................................          295           80
Combined Cycle................................        3,264          147
                                               -------------------------
    Total.....................................        3,559          227
------------------------------------------------------------------------

    Costs for closed-cycle cooling are assigned to a portion of new
stand-alone units, as shown the generating capacities in Exhibit IX-3.

                              Exhibit IX-3
------------------------------------------------------------------------
                                                Annual only    24-year
                                               -------------  total only
                   Fuel type                                ------------
                                                Stand-Alone  Stand-Alone
                                                     MW           MW
------------------------------------------------------------------------
Fossil Fuel...................................            8          191
Combined Cycle................................           15          353
                                               -------------------------
    Total.....................................           23          544
------------------------------------------------------------------------

    EPA then estimated the total costs for the third group (i.e., those
units that would incur compliance costs) to comply with requirements
for new units. EPA used certain assumptions regarding cooling system
design to modify cost equations used for estimating closed-cycle
retrofit costs at existing units and then applied the cost equations to
the portion of projected new unit generating capacities that would be
subject to the new unit provisions of today's rule. These costs include
capital \112\ and O&M costs, as well as a reduction in net generating
capacity due to auxiliary power consumption to operate the closed-cycle
recirculating system. Due to the complex nature of constructing a new
unit, there is no increase in the length of the construction project as
a result of employing a closed-cycle system; similarly, there is no
downtime, as the unit has not yet begun operating. See Chapter 8 of the
TDD for more information.
---------------------------------------------------------------------------

    \112\ The record indicates that the total estimated capital cost
for installing a closed-cycle recirculating system at a new unit to
comply with today's rule ranges from a negative value (as compared
to the cost for installing a once-through system) to a positive
value that could approach the cost of an existing facility retrofit.
Said differently, if one assumes that the new unit would have
constructed a new intake structure, EPA's record shows that the
capital costs for the new unit once-through system would be greater
than if the new unit installs a closed-cycle recirculating system.
(See DCN 10-6650.) Alternatively, if the new unit did not require
modification of the existing cooling system infrastructure, then the
capital costs for installing a closed-cycle recirculating system
would be similar to an existing facility retrofit minus some tie-in
costs since the condenser is being replaced. While EPA envisions
that the actual costs will vary (i.e., some will be in the negative
portion of the range and others will be in the positive), EPA is
also unable to project what cooling water intake arrangements a new
unit will use. Consequently, for all new units, EPA selected a
capital cost equal to the midpoint between the tower only and the
easy retrofit costs. As a result, EPA assumed that the capital costs
for these units was $154 per gpm in 2009 dollars which converts to
$30,800 to $60,060 per MW capacity depending on fuel type. For a
more detailed discussion, see TDD Chapter 8.
---------------------------------------------------------------------------

b. New Units at Existing Manufacturers
    On the basis of site visits to manufacturing facilities, EPA has
observed that manufacturers are increasingly taking advantage of water
conservation and reuse measures as a means of cost-cutting. EPA also
notes that manufacturers are subject to a wide variety of ELGs and
that, in the course of complying with requirements for those ELGs, a
facility may also reduce its intake flow. (See Chapter 4 of the TDD.) A
new unit provides the opportunity to employ such measures to the
fullest extent in designing the new unit. The availability of water
conservation and reuse opportunities, coupled with operational
flexibility at facilities with multiple industrial processes, leads EPA
to conclude that facilities installing new units at existing
manufacturers will comply with the new unit provisions through
achieving the 90 percent reduction required at Sec.  125.94(e)(2).
Thus, EPA concluded that the new unit provisions would result in no
additional compliance costs for achieving flow commensurate with
closed-cycle cooling at new units.\113\
---------------------------------------------------------------------------

    \113\ EPA also notes that some manufacturers may also be able to
increase reuse to a degree where the facility no longer meets the
applicability thresholds of today's rule.
---------------------------------------------------------------------------

    To the extent that manufacturers are not able to incorporate water
reuse measures as a means of complying with the new unit provision,
EPA's estimate of new unit costs for manufacturers may be an
underestimate. Manufacturers generally withdraw less water than
electric generators (including manufacturers who generate their own
electricity). Thus EPA has concluded that any underestimation would be
insignificant.

C. Social Costs

    EPA assessed the costs to society resulting from the final rule and
other options considered in development of this rule. The findings
presented in this section assume that facilities with impoundments will
qualify as having closed-cycle recirculating systems in the
baseline.\114\ As a result, EPA assigned no compliance technology costs
to these facilities; however, these facilities remain subject to
today's rule and are assigned administrative costs. To the extent that
some of these facilities do not qualify as having closed-cycle
recirculating systems in the baseline, the costs reported in this
section may be underestimates. The social cost of regulatory actions
includes costs to electric generators and manufacturers to comply with
the final rule, and costs to States and the Federal government to
administer the rule. These costs are the opportunity costs to society
of employing scarce resources to prevent the environmental damage that
would occur without today's rule. EPA estimated total social costs for
existing and new units at existing facilities.
---------------------------------------------------------------------------

    \114\ In other words, EPA assumed facilities indicating use of
an impoundment in response to their technical survey have lawfully
created such impoundments for the purposes of cooling water.
---------------------------------------------------------------------------

    In estimating social costs, EPA assumed that the final rule and
other options considered in development of this rule will not affect
the aggregate quantity of electricity or other affected goods and
services sold to consumers. Thus, the social cost of regulatory
requirements includes no loss in consumer and producer surplus from
reduced sales of electricity or other goods and services produced by
regulated facilities. The Agency calculated the social cost of the
final

rule and the other options considered using two discount rates: 3
percent and 7 percent.
    For existing facilities, EPA assumes that all facilities subject to
the final rule will begin bearing costs associated with today's rule
beginning as soon as 2014, and likely complete investments associated
with today's rule by 2030, depending on the technology-installation
schedules for the final rule and other regulatory options
considered.\115\ EPA performed the social cost analysis over a 51-year
period to reflect (1) the last year in which individual facilities are
expected to achieve compliance (2030) under the final rule or any of
the options considered, (2) the life of the longest-lived compliance
technology installed at any facility (30 years), and (3) a period of
five years after the last year of compliance technology operation
during which benefits continue to accrue. Under this framework, the
last year for which EPA has calculated projected costs is 2059, with
benefits continuing beyond 2059, though on a diminishing basis, through
2064.\116\
---------------------------------------------------------------------------

    \115\ EPA conducted the cost and economic impact analyses on a
calendar-year basis. For these analyses, EPA used calendar year 2013
as the promulgation year of today's rule and 2014 as the first post-
promulgation analysis year. This slight difference from the actual
promulgation year of 2014 results from the fact that EPA completed
its cost and economic impact analyses for the final rule and
alternative options before EPA decided to delay promulgation from
2013 to 2014. Because the rule is being promulgated during the first
half of 2014, EPA concluded that it would be reasonable to continue
using 2013 as the assumed promulgation year for the regulatory
analysis. EPA expects the differences in the estimated costs and
benefits of the rule due to this slight imprecision to be minimal.
    \116\ For this analysis, EPA assumed that the last year of
technology installation for all regulated facilities under any of
the regulatory options--i.e., 2030--is also the first year of
steady-state compliance with regulatory requirements.
---------------------------------------------------------------------------

    To estimate social costs for existing facilities, EPA developed a
year-explicit schedule of compliance outlays over the 46-year period
from 2014 to 2059 according to cost-incurrence assumptions (for details
on cost-incurrence assumptions, see EA, Chapter 3). EPA then adjusted
these costs for predicted real change (i.e., adjusted for inflation) to
the year of their incurrence and discounted all costs to the beginning
of 2013, the promulgation year used for the analysis. Because the
analysis period extends beyond the useful life of some compliance
equipment, the social cost analysis accounts for re-installation of
impingement mortality compliance technologies after the end of their
initial useful life periods. However, for the regulatory option that
requires a specific entrainment control technology (e.g., wet cooling
systems)--Proposal Option 2--EPA does not expect regulated facilities
to completely rebuild these systems (components such as piping and the
concrete basin can be reused). EPA accounted for other technology
replacement costs (such as pumps and fill material) as part of ongoing
operations and maintenance expenses.
    For new units at existing electric generators, EPA calculated an
average annual amount of new capacity to be constructed during the 46-
year social cost analysis period, beginning in 2014. While EPA does not
expect the annual construction of new units to be constant, predicting
the year-to-year fluctuations would be resource intensive. On average,
EPA assumes that its estimate of new unit costs is reasonable. EPA
accounted for compliance costs for these units on an as-incurred basis,
as done for existing facilities. Similar to compliance costs for
facilities subject to the final rule, EPA analyzed costs incurred by
State and Federal governments for administering the regulation on a
year-explicit basis over the 46-year social cost analysis period.
    Exhibit IX-4 presents social costs for existing units at existing
facilities under the final rule and other options considered,
calculated using 3 percent and 7 percent discount rates. At the 3
percent discount rate, EPA estimates total annualized social costs of
$272 million for the existing unit provision of today's rule, $252
million for Proposal Option 4, and $3,643 million for Proposal Option
2. At the 7 percent discount rate, these costs are $295 million for
today's rule, $272 million for Proposal Option 4, and $3,583 million
for Proposal Option 2.\117\ See the EA (Chapter 7) for an explanation
of why the annualized costs at the 3 percent discount rate are lower
than the annualized costs at the 7 percent discount rate for the final
rule and Proposal Option 4, while the inverse is the case for Proposal
Option 2 (annualized costs at the 3 percent discount rate are higher
than at the 7 percent discount rate). The largest component of social
cost is the cost of regulatory compliance incurred by regulated
facilities (as opposed to administrative costs estimated for States and
the Federal government). These costs include (1) one-time technology
and other initial costs of complying with the rule, (2) one-time costs
of installation downtime, (3) annual fixed and variable operating and
maintenance costs, including auxiliary energy requirement, (4) value of
energy penalty from operation of compliance technology, and (5)
permitting costs (initial and follow-up start-up costs, initial permit
costs, annually recurring costs associated with monitoring, and non-
annually recurring permitting costs).
---------------------------------------------------------------------------

    \117\ Because EPA was unable to identify those facilities for
which entrainment control technology would be established as BTA
standards on a site-specific basis, the Agency did not analyze
technology costs associated with these site-specific requirements.
Consequently, the cost and economic analyses conducted in support of
today's rule assume that under the existing unit provision of the
final rule and Proposal Option 4, Electric Generators and
Manufacturers install IM technology only. These analyses also assume
that under Proposal Option 2, Electric Generators with DIF exceeding
125 mgd install only cooling towers and all other Electric
Generators install only IM technologies. Under Proposal Option 2, a
small number of Manufacturers are assigned both IM and entrainment
control technologies because of engineering issues associated with
maintaining separation of contact and non-contact cooling water in
some manufacturing operations. Although EPA did not estimate
technology costs for facilities for which entrainment technology is
established as BTA on a site-specific basis, EPA did include the
costs for data collection and studies that facilities will need to
perform in order to provide information to Directors to make these
site-specific determinations. EPA included these costs in the
administrative costs that are estimated for the final rule and other
options considered.
---------------------------------------------------------------------------

    Compliance costs estimated for electric generators account for the
largest share of total compliance-related social cost and direct
compliance cost under all three options. On a per-facility basis and at
the 3 percent discount rate, the annualized pre-tax compliance costs
for the electric generators segment under today's final rule are $0.4
million, $0.4 million under Proposal Option 4, and $6 million under
Proposal Option 2.\118\ For manufacturers, the average cost per
regulated facility at the 3 percent discount rate is $0.1 million under
the final rule and Proposal Option 4, and $0.4 million under Proposal
Option 2.\119\ EPA's analysis found a similar profile of per facility
costs using the 7 percent discount rate (see EA Chapter 7 for
additional detail). EPA's estimate of Federal and State government
costs for administering this rule is small in relation to the estimated
direct cost of regulatory compliance. EPA estimates $1 million in
annual administrative costs to States and Federal government for the
final rule, using both the 3 and 7 percent discount rates. These cost
values are the same for Proposal Option 4. EPA estimates $0.7 million
in annual administrative costs to States and the

Federal government for Proposal Option 2, regardless of the discount
rate used.
---------------------------------------------------------------------------

    \118\ Calculated by dividing direct compliance costs for each
type of facility by the total of 544 electric generators subject to
today's rule on the basis of facility count-based weights (see EA
Appendix H).
    \119\ Calculated using the total of 521 manufacturers subject to
today's rule on the basis of technical weights (see EA Appendix H).

 Exhibit IX-4--Total Annualized Social Costs--Existing Units at Existing
                               Facilities
                     [in millions, 2011 dollars] \a\
------------------------------------------------------------------------
                                     Proposal                  Proposal
                                     option 4    Final rule    option 2
------------------------------------------------------------------------
                      Using 3 percent discount rate
------------------------------------------------------------------------
Direct Compliance Costs:
    Electric Generators..........       $202.9       $203.7     $3,413.3
    Manufacturers................         47.8         67.7        229.2
Total Direct Compliance Cost.....        250.7        271.4      3,642.5
State and Federal Administrative           1.0          1.0          0.7
 Costs...........................
Total Social Costs...............        251.8        272.4      3,643.2
------------------------------------------------------------------------
                      Using 7 percent discount rate
------------------------------------------------------------------------
Direct Compliance Cost:
    Electric Generators..........        219.2        220.0      3,339.3
    Manufacturers................         51.9         74.2        243.0
Total Direct Compliance Cost.....        271.1        294.3      3,582.3
State and Federal Administrative           1.0          1.0          0.7
 Costs...........................
Total Social Costs...............        272.1        295.3      3,583.0
------------------------------------------------------------------------
\a\ Cost estimates exclude costs associated with baseline closure
  facilities.

    EPA also estimated the cost for installing closed-cycle
recirculating systems at new units at existing electric generators, to
reflect the costs of today's rule. As shown in Exhibit IX-5, EPA
estimated that the new unit provision of the final rule will result in
an annualized cost of $2.5 million and $2.0 million using 3 percent and
7 percent discount rates, respectively, including compliance costs to
facilities and administrative costs to States and Federal government.
    The Agency estimated that at a 3 percent discount rate, the total
social cost of the final rule, including the existing and new unit
provisions, will be $275 million. At a 7 percent discount rate, this
cost is $297 million.

 Exhibit IX-5--Annualized Total Social Cost of the Final Rule--Existing
                  and New Units at Existing Facilities
                   [In millions, 2011 dollars] \a\ \b\
------------------------------------------------------------------------
                                                        3%         7%
                                                     Discount   Discount
                                                       rate       rate
------------------------------------------------------------------------
New Units.........................................       $2.5       $2.0
Existing Units....................................      272.4      295.3
Existing and New Units............................      274.9      297.3
------------------------------------------------------------------------
\a\ Cost estimates exclude costs associated with baseline closure
  facilities.
\b\ Values may not add due to rounding.

D. Economic Impacts

    EPA used several analytic approaches to assess the economic impact
of today's rule and the other options considered, on electric
generators and manufacturers. EPA conducted separate analyses for
electric generators and manufacturers using different methodologies for
each regulated facilities segment. The following sections summarize the
methodologies EPA used to conduct the economic impact analyses and the
findings of these analyses. EPA conducted the economic impact analyses
discussed in this section for existing facilities; the Agency used
compliance cost estimates from the EPA engineering analysis (see TDD
Section X.B).
1. Electric Generators
    For the electric generators segment, EPA assessed the economic
impact of the existing unit provision of the final rule and other
options it considered in three ways: (1) The financial burden
associated with a particular regulatory option on facilities and
entities that own them, (2) how potential changes in the price of
electricity would affect electricity consumers, in general, and
residential households, in particular, and (3) broader economic impacts
on the electricity market, taking into account the interconnectedness
of regional and national electricity markets. In preparing the first
two sets of analyses, EPA developed and used sample weights to
extrapolate impacts assessed initially at the level of sample of
facilities, to the full population of facilities subject to the final
rule. For information on how EPA developed and used sample weights, see
the EA, Appendix H.
    In addition, EPA assessed the impact of the new unit provision of
the final rule on decisions of existing facilities to construct stand-
alone new units that would be subject to the new unit provision. EPA
made this assessment in two ways: (1) On the basis of comparison, on a
per MW basis, of compliance costs for new units to the overall cost of
building and operating generating units and (2) as is the case with the
existing unit provision, in the context of regional and national
electricity markets, taking into account their interconnectedness.
a. Cost-to-Revenue Analysis for Regulated Facilities and Their Parent
Entities--Existing Unit Provision of the Final Rule
    EPA assessed the cost to regulated facilities and their parent
entities on the basis of a cost-to-revenue analysis. For each analysis
level (facility and parent entity), the Agency assumed, for analytic
convenience and as a worst-case scenario, that none of the compliance
costs would be passed on to consumers through electricity rate
increases and, instead, would be absorbed by regulated facilities and
their parent entities.\120\ EPA developed

this analysis for 544 electric generators.\121\
---------------------------------------------------------------------------

    \120\ As discussed in EA Chapter 2A: Industry Profiles, the
majority of regulated electric generators operate in States with
regulated electricity markets. EPA estimates that facilities located
in these States may be able to recover compliance cost-based
increases in their production costs through increased electricity
prices. This depends on the business operation model of the facility
owner(s), the ownership and operating structure of the facility
itself, and the role of market mechanisms used to sell electricity.
In contrast, in States where electric power generation has been
deregulated, cost recovery is less certain. While facilities
operating within deregulated electricity markets may be able to
recover some of their additional production costs through increased
revenue, EPA cannot determine the extent of cost recovery ability
for each facility.
    \121\ EPA calculated this number as a weighted estimate using
facility count-based weights. This number excludes facilities
assumed either to have already retired their steam operations or
expected to do so in the future.
---------------------------------------------------------------------------

i. Cost-to-Revenue Analysis for Regulated Facilities
    To provide insight into the potential significance of the
compliance costs to regulated facilities, EPA calculated the ratio of
annualized after-tax compliance costs to baseline annual facility-level
revenues. In the cost-to-revenue comparisons, EPA used cost-to-revenue
thresholds of 1 and 3 percent to categorize facilities according the
potential economic impact of the rule. EPA concludes that facilities
incurring costs below 1 percent of revenue will not face significant
economic impacts, while facilities with costs of at least 1 percent but
less than 3 percent of revenue have a chance of facing economic
impacts, and facilities incurring costs of at least 3 percent of
revenue have a higher probability of significant economic impacts. For
a more detailed discussion of the methodology EPA used for the
facility-level cost-to-revenue analysis, see EA Chapter 4.
    Exhibit IX-6 presents a summary of the facility-level cost-to-
revenue analysis results for the final rule and other options
considered. EPA estimates that overall, under the final rule, 86
percent of regulated facilities will incur compliance costs of less
than 1 percent of revenue. Under Proposal Option 4, 87 percent of
regulated facilities would also incur costs of less than 1 percent of
revenue. EPA estimates that Proposal Option 2 would result in 42
percent of facilities incurring costs exceeding 1 percent of revenue,
and 43 percent incurring costs exceeding 3 percent of revenue.

                      Exhibit IX-6-- Facility-Level Cost-to-Revenue Analysis Results for the Final Rule and Options Considered \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                            Number of facilities with cost-to-revenue ratio
                                             -----------------------------------------------------------------------------------------------------------
                   Option                                    < 1%                           >= 1% and < 3%                           >= 3%
                                             -----------------------------------------------------------------------------------------------------------
                                                               %                          %                          %
--------------------------------------------------------------------------------------------------------------------------------------------------------
Proposal Option 4...........................               475              87.4                35               6.5                31               5.7
Final Rule..................................               470              86.5                40               7.4                31               5.7
Proposal Option 2...........................               228              41.9                79              14.5               235              43.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Facility counts exclude baseline closures.
\b\ EIA reports no revenue for 1 facility (2 on a weighted basis). Therefore, EPA conducted this analysis for 339 facilities (542 on a weighted basis).
  For more information on facility sample weights see EA Appendix H.

ii. Cost-to-Revenue Analysis for Regulated Parent Entities
    EPA also assessed the economic impact using the cost-to-revenue
metric at the level of the parent entity. This analysis, which focuses
on domestic parent entities with the largest ownership share in the
facility, provides insight on the impact of compliance requirements on
those entities that own more than one regulated facility. The analysis
helps to answer the question of whether owning multiple facilities that
are required to comply with today's rule causes financial stress at the
entity level. For each identified parent entity, EPA aggregated
facility-level, annualized, after-tax compliance costs to the level of
the parent entity and compared these entity-level costs to entity-level
revenue.
    Similarly to the facility-level analysis, EPA used cost-to-revenue
thresholds of 1 and 3 percent to categorize facilities according the
potential economic impact of the rule. EPA used two weighting
approaches for this analysis: (1) Facility-level weights, but without
entity-level weights and (2) entity-level weights, but without
facility-level weights. These approaches, which are described in
Appendix H of the EA, provide a range of estimates for the number of
entities incurring compliance costs and the costs incurred by any
entity that owns a regulated facility. (For a more detailed discussion
of the methodology used for the entity-level cost-to-revenue analysis,
see EA Chapter 4).
    Exhibit IX-7 presents results for the entity-level analysis for the
two weighting approaches. EPA estimates that between 123 and 159
entities own regulated facilities. Further, the Agency estimates that
between 91 and 94 percent of parent entities will incur annualized
costs of less than 1 percent of revenues under the final rule. This
finding also holds under the two other options EPA considered, with
between 91 and 94 percent of entities incurring costs of less than 1
percent of revenue under Proposal Option 4 and between 70 and 78
percent under Proposal Option 2.

                                             Exhibit IX-7--Entity-Level Cost-to-Revenue Analysis Results \b\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Number of entities with cost-to-revenue ratio of
                                                         Total   ---------------------------------------------------------------------------------------
                  Parent entity type                   number of          < 1%             >= 1% and < 3%             >= 3%              Unknown \a\
                                                        entities ---------------------------------------------------------------------------------------
                                                                        %            %            %            %
--------------------------------------------------------------------------------------------------------------------------------------------------------
Using Facility-Level Weights:
    Proposal Option 4................................        123        112       91.1          3        2.4          0        0.0          8        6.5
    Final Rule.......................................        123        112       91.1          3        2.4          0        0.0          8        6.5
    Proposal Option 2................................        123         86       69.9         17       13.8         12        9.8          8        6.5
Using Entity-Level Weights:
    Proposal Option 4................................        159        150       94.2          0        0.0          0        0.0          9        5.8

    Final Rule.......................................        159        150       94.2          0        0.0          0        0.0          9        5.8
    Proposal Option 2................................        159        124       78.1         18       11.6          7        4.4          9        5.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ EPA was unable to determine revenues for 8 parent entities (9 weighted).
\b\ This analysis assumes no cost pass-through to electricity consumers.

b. Potential Electricity Price Effects--Existing Unit Provision of the
Final Rule
    As an additional measure of economic impact, EPA conducted two
assessments of the potential price effects on electricity of today's
rule: (1) The annual increase in electricity costs per MWh (megawatt
hour) of total electricity sales and (2) the potential annual increase
in household electricity costs. For analytic convenience and as a
worst-case scenario, these assessments assume that all compliance costs
will be passed through on a pre-tax basis to consumers as increased
electricity prices. This full cost pass-through assumption represents a
``worst-case'' impact scenario from the perspective of electricity
consumers. Facilities that are merchant providers can pass along costs
only to the degree that they are competitive with other generators in
the dispatch process.\122\ This assumption is the opposite of EPA's
assumption in the facility- and entity-level analyses discussed above--
that facilities will pass none of the compliance costs through to
consumers in electricity rate increases. If facilities are able to pass
through all costs, the impacts in the previous subsection would not
occur. The two conditions (no cost pass-through and full cost pass-
through) could not occur at the same time. Thus, the results of the
electricity price-effects analyses discussed in this section, and of
the facility- and entity-level analyses discussed in Section IX.D.a.1,
should not be combined. EPA conducted this analysis for 544 electric
generators.
---------------------------------------------------------------------------

    \122\ As discussed earlier in Section X.D.b.1, even though
individual regulated facilities may not be able to recover all of
their compliance costs through increased revenues, the market-level
effect may still be that consumers will see higher overall
electricity prices because of changes in the cost structure of
electricity supply and resulting changes in market-clearing prices
in deregulated electricity markets.
---------------------------------------------------------------------------

i. Compliance Cost per Unit of Electricity Sales
    EPA assessed the potential increase in electricity rates by NERC
region based on the annual cost of the regulatory options per unit of
electricity sold. The Agency used two data inputs: (1) Total pre-tax
compliance cost by NERC region, and (2) estimated total electricity
sales in the year 2020, to gauge the full effects of the rule. To
calculate the total estimated annual cost in each NERC region, the
Agency summed sample-weighted, pre-tax annualized compliance costs over
regulated facilities by region. EPA then calculated the approximate
average price impact per unit of electricity consumption by dividing
total compliance costs by the reported total MWh of sales in each NERC
region. (Details of this analysis are presented in the EA, Chapter 4.)
    As reported in Exhibit IX-8, under the existing unit provision of
the final rule, annualized compliance costs (in cents per kWh sales)
range from nearly $0.00 in the WECC region to $0.040 in the HICC
region. EPA reached the same findings for Proposal Option 4. Under
Proposal Option 2, costs range from $0.00 in the WECC region to $0.351
in the HICC region. On average, across the United States, the final
rule and Proposal Option 4 result in a cost of $0.009 per kWh, while
Proposal Option 2 results in a higher cost of $0.155 per kWh.

 Exhibit IX-8--Compliance Cost per Unit of Electricity Sales in 2020 by
                    Regulatory Option and NERC Region
                     [2011 [cent]/KWh sales] \a\ \b\
------------------------------------------------------------------------
                                     Proposal                  Proposal
       NERC region \c\ \d\           option 4    Final rule    option 2
------------------------------------------------------------------------
ASCC.............................        0.000        0.000        0.000
FRCC.............................        0.014        0.014        0.171
HICC.............................        0.040        0.040        0.351
MRO..............................        0.010        0.010        0.174
NPCC.............................        0.008        0.008        0.126
RFC..............................        0.011        0.011        0.200
SERC.............................        0.013        0.013        0.219
SPP..............................        0.009        0.009        0.078
TRE..............................        0.008        0.008        0.206
WECC.............................        0.000        0.000        0.000
United States....................        0.009        0.009        0.155
------------------------------------------------------------------------
\a\ This analysis assumes full pass-through of all compliance costs to
  electricity consumers.
\b\ Cost values exclude baseline closures.
\c\ ASCC--Alaska Systems Coordinating Council; FRCC--Florida Reliability
  Coordinating Council; HICC--Hawaii Coordinating Council; MRO--Midwest
  Reliability Organization; NPCC--Northeast Power Coordinating Council;
  RFC--ReliabilityFirst Corporation; SERC--Southeastern Electric
  Reliability Council; SPP--Southwest Power Pool; TRE--Texas Reliability
  Entity, and WECC--Western Energy Coordinating Council.
\d\ No explicitly analyzed facilities are in the ASCC region. For more
  information on explicitly and implicitly analyzed regulated
  facilities, see EA Appendix H.

ii. Cost to Households
    As an additional measure of the potential electricity price effects
associated with the final rule, EPA estimated the potential annual
increase in electricity costs per household and by NERC region. EPA
used total annualized pre-tax compliance cost per MWh of sales, as
estimated for the electricity rate impact analysis discussed above and
the quantity of residential electricity sales per household as reported
in the 2011 EIA database. To calculate the potential annual cost impact
per household, EPA multiplied the average cost per kWh by the average
kWh per household estimated for each NERC region. (Chapter 4 of the EA
presents details of this analysis.)
    As presented in Exhibit IX-9, under the existing unit provision of
the final rule, the average annual cost per residential household
varies across NERC regions, ranging from $0.01 in WECC to $2.82 in
HICC. EPA reached the same findings for Proposal Option 4. Under
Proposal Option 2, the average annual cost per residential household
also varies across NERC regions, ranging from $0.01 in WECC to $31.72
in SERC. EPA estimated that on average, for a typical U.S. household,
the final rule will result in an annual cost of $1.03 in higher
electricity rates per household. EPA estimates that this cost would be
$1.03 per household under Proposal Option 4 and $17.23 per household
under Proposal Option 2.

  Exhibit IX-9--Average Annual Cost Burden per Residential Household in
   2020 for the Final Rule and Options Considered, and by NERC Region
                         [2011 dollars] \a\ \b\
------------------------------------------------------------------------
                                     Proposal                  Proposal
       NERC region \c\ \d\           option 4    Final rule    option 2
------------------------------------------------------------------------
ASCC.............................        $0.00        $0.00        $0.00
FRCC.............................         1.91         1.91        23.15
HICC.............................         2.82         2.82        24.61
MRO..............................         0.99         1.02        18.10
NPCC.............................         0.61         0.62         9.52
RFC..............................         1.10         1.10        20.64
SERC.............................         1.96         1.96        31.72
SPP..............................         1.30         1.30        10.71
TRE..............................         1.15         1.15        30.59
WECC.............................         0.01         0.01         0.01
United States....................         1.03         1.03        17.23
------------------------------------------------------------------------
\a\ The rate impact analysis assumes full pass-through of all compliance
  costs to electricity consumers.
\b\ Cost estimates exclude baseline closures.
\c\ ASCC--Alaska Systems Coordinating Council; FRCC--Florida Reliability
  Coordinating Council; HICC--Hawaii Coordinating Council; MRO--Midwest
  Reliability Organization; NPCC--Northeast Power Coordinating Council;
  RFC--ReliabilityFirst Corporation; SERC--Southeastern Electric
  Reliability Council; SPP--Southwest Power Pool; TRE--Texas Reliability
  Entity, and WECC--Western Energy Coordinating Council.
\d\ No explicitly analyzed facilities are in the ASCC region. For more
  information on explicitly and implicitly analyzed regulated
  facilities, see EA Appendix H.

    As noted above, this analysis assumes that facilities will pass
through to consumers all compliance costs through increased electricity
rates. However, facilities and owner entities might not be able to
recover all these costs through rate increases, thereby reducing the
impact of today's rule on electricity consumers. At the same time, EPA
recognizes that electric generators that operate as regulated public
utilities will generally recover environmental compliance costs through
rate increases to consumers.
c. Barrier-To-Development Analysis--New Unit Provision of the Final
Rule
    EPA assessed the impact of the new unit provision of the final rule
on decisions of existing facilities to construct stand-alone new units
that would be subject to the new unit provision. As discussed earlier
in this preamble, under this provision, electric power generating units
that meet the definition of a new unit will be required to achieve
intake flow commensurate with closed-cycle cooling. The question of
potential impact of this provision on the construction of new stand-
alone units is important because new stand-alone units will generally
operate with higher energy efficiency and lower environmental impact
than older electric generating capacity, which the new units would tend
to displace as a source of electric power generation. As such, EPA
sought to ensure that the new unit provision would not impede
construction of stand-alone new units.
    For this analysis, EPA compared the compliance costs for new units
to the overall cost of building and operating generating units, on a
per MW basis. The purpose of this analysis is to determine whether the
required addition of a closed-cycle recirculating system (CCRS) as part
of a new unit would substantially increase the cost for the new stand-
alone unit, and adversely affect the decision to construct the new
stand-alone unit. This analysis showed that given the low cost of CCRS
in relation to the cost of new capacity, the CCRS requirement will not
pose a barrier to development of new stand-alone units.
    EPA also assessed the costs associated with the new unit provision
of the final rule as part of its electricity market analysis, as
discussed in the following section (Section IX.D). This analysis tests
the impact of the new unit requirements on electricity markets
accounting for the expected number and timing of new unit
installations, and provides additional insight on whether the costs of
complying with the new unit provision of the final rule would affect
future capacity additions. This analysis found no material effect of
the final rule's new unit provision on the number and type of new units
that would be constructed. This finding also supports EPA's conclusion
that the new unit provision will not be a barrier to development of new
capacity.
d. Impacts in the Context of Electricity Markets--Existing and New Unit
Provisions of the Final Rule
    In the analyses for the previous 316(b) regulations, including the
proposed rule, EPA used the Integrated Planning Model
(IPM[supreg]),\123\ a comprehensive electricity market optimization
model, to assess the economic impact of regulatory options within the
context of

regional and national electricity markets. To assess facility and
market-level effects of the final rule, EPA used an updated version of
this same analytic system, the Integrated Planning Model Version 4.10
MATS (IPM V4.10--MATS) platform.
---------------------------------------------------------------------------

    \123\ Developed by ICF, Inc.
---------------------------------------------------------------------------

    Use of a comprehensive, market analysis system is important in
assessing the potential impact of the final rule because of the
interdependence of electricity generating units in supplying power to
the electric transmission grid. Increases in electricity production
costs and potential reductions in electricity output at regulated
facilities--due to the temporary shutdown of existing electric
generating units during technology installation--can have a range of
broader market impacts that extend beyond the effect on regulated
facilities and their direct customers. In addition, the impact of
compliance requirements on regulated facilities may be seen differently
when the analysis considers the impact on those facilities in the
context of the broader electricity market instead of looking at the
impact on a stand-alone, single-facility basis.
    The IPM V4.10--MATS platform provides outputs for the NERC regions
that lie within the continental United States. This IPM platform does
not analyze electric power operations in Alaska and Hawaii because
these operations are not connected to the continental U.S. power grid.
The IPM V4.10--MATS platform is based on an inventory of U.S. utility-
and non-utility-owned boilers and generators that provide power to the
integrated electric transmission grid, as recorded in the EIA 860
(2006) and EIA 767 (2005) databases.\124\ IPM does not include electric
power facilities that do not provide power to the U.S. power grid
(e.g., some generating units at industrial facilities). The IPM V4.10--
MATS universe consists of 14,920 generating units at 4,910 existing
electric power facilities, including 520 of the 544 regulated electric
power facilities subject to the final rule.\125\
---------------------------------------------------------------------------

    \124\ In some instances, facility information has been updated
to reflect known material changes in a facility's generating
capacity since 2006.
    \125\ Facilities excluded from the IPM analysis include three
facilities in Hawaii and one facility in Alaska (i.e., areas that
are outside the geographic scope of the model), four on-site
facilities that are not connected to the integrated electric
transmission grid, four facilities excluded from the IPM baseline as
the result of custom adjustments made by ICF, and 12 facilities that
did not respond to the 316(b) survey.
---------------------------------------------------------------------------

    This IPM V4.10--MATS platform embeds a baseline energy demand
forecast from the Department of Energy's Annual Energy Outlook 2010
(AEO2010), with adjustments by EPA to account for the effect of certain
voluntary energy efficiency programs. This platform also incorporates
in its analytic baseline the expected compliance response to existing
regulatory requirements for the following promulgated air regulations
affecting the power sector: the final Mercury and Air Toxics Standards
(MATS) rule; the final Cross-State Air Pollution Rule (CSAPR); \126\
regulatory SO2 emission rates arising from State
Implementation Plans (SIP); Title IV of the Clean Air Act Amendments;
NOX SIP Call trading program; Clean Air Act Reasonable
Available Control Technology requirements and Title IV unit specific
rate limits for NOX; the Regional Greenhouse Gas Initiative;
Renewable Portfolio Standards; New Source Review Settlements; and
several state-level regulations affecting emissions of SO2,
NOX, and mercury that are already in place or expected to
come into force by 2017.
---------------------------------------------------------------------------

    \126\ EPA's Cross-State Air Pollution Rule (CSAPR) was
promulgated to replace EPA's Clean Air Interstate Rule (CAIR), which
had been remanded to EPA in 2008. However, on December 30, 2011, the
U.S. Court of Appeals for the D.C. Circuit stayed CSAPR pending
judicial review and left CAIR in place. On August 21, 2012 the Court
issued an opinion vacating CSAPR and again leaving CAIR in place
pending development of a valid replacement. On March 29, 2013, the
United States filed a petition asking the Supreme Court to review
the D.C. Circuit's opinion. Nevertheless, as explained above, CAIR
remains in effect at this time. In light of the continuing
uncertainty on CAIR and CSAPR, EPA determined it would not be
appropriate or possible at this time to adjust emission projections
on the basis of speculative alternative emission reduction
requirements in 2020. EPA expects that the decision vacating CSAPR
and leaving CAIR in place has minimal effect on the results of the
analysis conducted in support of the final rule.
---------------------------------------------------------------------------

    In contrast to the screening-level analyses described earlier,
which are static analyses and do not account for interdependence of
electric generating units in supplying power to the electric
transmission grid, IPM accounts for potential changes in the generation
profile of individual electric power facilities and consequent changes
in market-level generation costs, as a result of the final rule. The
model is dynamic in that the analysis covers a multiple-decade period
with information and decisions in any specific period depending on the
analysis information and optimization results for the entire analysis
period. The model is also forward-looking in that it uses forecasts of
future conditions to make decisions for the present. Finally, in
contrast to the screening-level analyses in which EPA assumed either no
pass through of compliance costs (facility and entity cost-to-revenue
analyses discussed in Section IX.D.a.1) or full cost pass-through
(analysis of potential electricity price effects, Section IX.D.b.1),
IPM assesses price and revenue effects from increased costs in
competitive wholesale electricity markets, where some recovery of
compliance costs through increased electricity prices is possible but
not guaranteed.
    In performing analyses based on the IPM V4.10--MATS platform, EPA
used as its baseline a projection of electricity markets and facility
operations without the final rule requirements (baseline case). As
discussed above, this baseline accounts for compliance with the
recently promulgated Federal air rules. EPA then overlaid this baseline
with the estimated compliance costs and other operating effects--
downtime for installation of IM technologies at existing units and
auxiliary energy requirement to operate cooling towers at new units--
for regulated facilities under the policy case.
    As discussed in Appendix P of the EPA report, the IPM V4.10--MATS
platform models the electric power market over the 43-year period from
2012 to 2054. Within this total analysis period, EPA looked at shorter
IPM analysis periods (run-year windows) \127\ to assess the effect of
the final rule on national and regional electricity markets.
Specifically, to assess the impact of the final rule during the period
when regulated facilities temporarily suspend their operation to
install compliance technologies--the short-term effects analysis or the
downtime effects analysis--EPA used results reported for the 2020 IPM
run year, which represent an 8-year window of 2017 through 2024.\128\
The incurrence of downtime may lead to higher electricity generation
costs overall, as generating units at regulated facilities are taken
out of service to complete technology installation and other generating
units, presumably with higher production costs, are dispatched to meet
electricity demand. Because of the potential resulting increase in
electricity generation costs, it is

important to examine market-level effects during the period in which
downtime would occur.
---------------------------------------------------------------------------

    \127\ Due to the highly data- and calculation-intensive
computational procedures required for the IPM dynamic optimization
algorithm, IPM is run only for a limited number of years. Run years
are selected based on analytical requirements and the necessity to
maintain a balanced choice of run years throughout the modeled time
horizon. Each run year represents adjacent years in addition to the
run year itself.
    \128\ As discussed earlier in this document, for the cost and
economic impact analyses, EPA assumed that electric generators will
install IM technologies during the 5-year window of 2018 through
2022. Because this technology-installation window falls within the
time period captured by the 2020 run year (i.e., 2017 through 2024),
EPA judges that 2020 is an appropriate year to capture the effects
of technology-installation downtime.
---------------------------------------------------------------------------

    To assess the longer term effect of the final rule on electricity
markets during the period after compliance technology is installed at
all regulated facilities--the steady-state post-compliance period--EPA
analyzed results reported for the IPM 2030 run year, which represents a
10-year window of 2025 through 2034.\129\ Effects that may occur during
this steady-state period include increased electricity production costs
at regulated facilities and potential permanent losses in generating
capacity from early retirement (closure) of generating units. Both
effects may lead to higher overall electricity generation costs through
not only the increased production cost in regulated facilities, but
also through dispatch of higher production cost units to offset
capacity losses, reflecting the general upward shift in production
costs.\130\
---------------------------------------------------------------------------

    \129\ EPA expects this steady-state period to begin in the last
year of the technology-installation window, i.e., 2022, and continue
into the future. The 2022 analysis year is captured in the IPM 2020
run year, as opposed to the 2030 run year. However, because all
analysis years represented by the 2030 run year (i.e., 2025-2034)
fall outside the technology-installation window of 2018 through
2022, EPA judges that 2030 is an appropriate year to capture longer
term, steady-state effects of the final rule.
    \130\ In seeking to minimize the cost of meeting electricity
demand, IPM will tend to shift production away from regulated
facilities that incur compliance costs, and will shift production to
either non-regulated facilities, which incur no compliance costs, or
to regulated facilities that incur relatively lower compliance
costs. Any of these changes--whether a simple increase in production
costs for previously dispatched units or changes in the profile of
generating unit dispatch--mean increased total costs for electricity
generation, compared to the pre-regulation baseline.
---------------------------------------------------------------------------

    EPA measured the impacts of the final rule as the difference
between key economic and operational impact metrics between the
baseline case and the policy case. All analysis results presented below
are representative of modeled market conditions in the years 2017-2034.
While costs are in 2011 dollars, they are reflective of costs in the
modeled years and are not discounted to the start of EPA's analysis
period of 2013.\131\ In contrast to the earlier statement that the cost
and economic impact analysis findings presented in this preamble may be
underestimates because EPA assumed that no facilities with impoundments
will install compliance technology, the market-based analysis presented
in this section reflects the opposite assumption. Namely, despite the
final rule's treatment of impoundments, for purposes of this analysis,
none of the facilities with impoundments are treated as having closed-
cycle cooling in the baseline. As a result, to the extent that some of
these facilities may qualify as having closed-cycle recirculating
systems in the baseline, and thus would not need to install compliance
technology, the costs and economic impacts reported in this section may
be overestimated.
---------------------------------------------------------------------------

    \131\ In contrast, the social cost estimated in Section IX.C
reflects the discounted value of compliance costs over the entire
51-year analysis period, as of 2013. Additionally, screening-level
analyses presented in earlier sections are static analyses and do
not account for interdependence of electric generating units in
supplying power to the electric transmission grid. In contrast, IPM
accounts for potential changes in the generation profile of steam
electric and other units and consequent changes in market-level
generation costs, as the electric power market responds to higher
generation costs for steam electric units due to the final rule.
---------------------------------------------------------------------------

i. Analysis Results for the Year 2030--To Reflect Steady State, Post-
Compliance Operations
    For the steady-state analysis (2030), EPA considered impact metrics
of interest at three levels of aggregation: (1) Impact on national and
regional electricity markets, (2) impact on the group of 520 regulated
facilities modeled in IPM, and (3) impact on individual 520 regulated
facilities.

Impact on National and Regional Electricity Markets

    For the assessment of market-level impacts, EPA considered six
output metrics: (1) Incremental capacity retirements (closures); (2)
changes in capacity retirements as a percent of total baseline capacity
(3) changes in new capacity additions; (4) changes in variable
production costs per MWh, calculated as the sum of total fuel and
variable O&M costs divided by net generation; (5) changes in total
generation costs (fuel, variable O&M, fixed O&M, and capital); and (6)
changes in wholesale electricity prices.
    As shown in Exhibit IX-10, the final rule has small effects on the
electricity market, on both the national and regional sub-market basis,
in 2030. At the national level, the analysis shows a total net increase
in retired capacity of approximately 1 GW, or less than 0.1 percent of
the total baseline capacity in 2030 (capacity retirements are discussed
in greater detail in the next section, Impact on Regulated Facilities
as a Group). This 1 GW of net capacity loss reflects a combination of
closures and avoided closures of generating units. ``Avoided closure''
means a generating unit that was projected to close in the baseline
case but remains open in the policy case because of changes in the
relative operating economics of generating capacity. In some instances
an avoided closure can result in an avoided full facility closure.
Overall, the final rule will lead to early retirement of approximately
4 GW of generating capacity and approximately 3 GW of avoided closure
of capacity otherwise projected to retire by 2030, resulting in a net
closure of approximately 1 GW of generating capacity. With only one
exception, these retirements involve older, less efficient generating
units with very low capacity utilization rates.
    Five of the eight analyzed NERC regions record modest increases in
retired capacity, with the largest increase, 0.8 percent of baseline
retired capacity, projected to occur in TRE. One NERC region--SPP--
avoids capacity closures, where 1.5 percent of capacity otherwise
projected to retire in the baseline, becomes a more economically viable
source of electricity in the policy case due to changes in the relative
economics of electricity production across the full market, and thus
avoids closure.\132\ Consequently, the final rule is not expected to
have a material ongoing effect on capacity availability and supply
reliability at either the national or the NERC region level.
---------------------------------------------------------------------------

    \132\ Avoided closures may occur among facilities that incur no
compliance costs under the final rule or for which compliance costs
are low relative to the costs estimated for other regulated
facilities.
---------------------------------------------------------------------------

    The 1 GW of retired capacity is replaced by new, more efficient,
and less polluting capacity. Because the new capacity is more efficient
and less costly to run than the retired capacity, it will run at a
higher capacity utilization rate than the retired capacity; less new
capacity is required to meet electricity demand than the retired
capacity that it replaces. As shown in Exhibit IX-11, under the final
rule, new capacity additions increase by 1 GW at the national level;
this increase represents 0.5 percent of new baseline capacity and 0.1
percent of total baseline capacity (see Exhibit IX-10). This increase
in new capacity is mostly comprised of combined cycle capacity followed
by other non-steam capacity, with coal steam capacity additions
remaining zero in both the baseline case and the policy case.
Consequently, this analysis shows that the final rule is not likely to
impede construction of new combined cycle and coal steam generating
units.\133\
---------------------------------------------------------------------------

    \133\ As described earlier in this preamble, under the new unit
provision of the final rule, new units as defined at 125.92 include,
stand-alone fossil fuel and combined cycle units. As described in
Chapter 6 of the EA, the IPM analysis accounts only for compliance
costs associated with new units. Further, EPA assigned these costs
only to coal steam and combined cycle capacity.
---------------------------------------------------------------------------

    As reported in Exhibit IX-10, overall, the final rule has only a
slight impact on electricity prices. For three out of eight NERC
regions, electricity prices decline

slightly--by no more than $0.05 per MWh (0.1 percent) in TRE.
Electricity prices increase in the remaining five NERC regions, with
the largest increase, $0.29 per MWh (0.4 percent), occurring in NPCC.
These very small estimated changes in electricity prices are
essentially within the analytic ``noise'' of the electricity market
modeling system.
    At the national level, total generation costs increase by 0.3
percent of the baseline value--again, a very modest amount. Across
regions, no NERC region records an increase in total costs exceeding
0.5 percent. The change in variable production costs ($/MWh)--a
specific measure of the effect of the final rule on short-run
electricity generation costs--is nearly zero with no NERC region
recording a consequential change.

                               Exhibit IX-10--Impact of the Final Rule on National and Regional Markets, at the Year 2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                    Net changes in early       Changes in variable     Changes in total costs    Changes in electricity
                                        Total            retirements                  costs          --------------------------           price
                                       baseline  ----------------------------------------------------                          -------------------------
          NERC region \a\              capacity                % of  total                                             % of
                                         (GW)          GW        baseline    $2011/MWh       % of      Mill 2011$    baseline    $2011/MWh       % of
                                                                 capacity                  baseline                                            baseline
--------------------------------------------------------------------------------------------------------------------------------------------------------
FRCC...............................           68            0         0.30       -$0.03        -0.10          $51         0.30        -0.01         0.00
MRO................................           76            0         0.00         0.01         0.10           62         0.40         0.21         0.30
NPCC...............................           73            0         0.50         0.00         0.00           28         0.20         0.29         0.40
RFC................................          237            0         0.10         0.01         0.00          157         0.30         0.15         0.20
SERC...............................          274            0         0.10         0.02         0.10          182         0.30         0.08         0.10
SPP................................           59           -1        -1.50         0.02         0.10           31         0.30        -0.01         0.00
TRE................................           98            1         0.80        -0.01         0.00           48         0.30        -0.05        -0.10
WECC...............................          220            0         0.00         0.00         0.00            9         0.00         0.03         0.00
                                    --------------------------------------------------------------------------------------------------------------------
    Total..........................        1,106            1         0.10         0.00         0.00          568         0.30  ...........          N/A
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ FRCC (Florida Reliability Coordinating Council), MRO (Midwest Reliability Organization), NPCC (Northeast Power Coordination Council), RFC
  (ReliabilityFirst Corporation), SERC (Southeastern Electricity Reliability Council), SPP (Southwest Power Pool), TRE (Texas Reliability Entity), and
  WECC (Western Electricity Coordinating Council).

                 Exhibit IX-11--Impact of the Final Rule on New Capacity (GW), at the Year 2030
----------------------------------------------------------------------------------------------------------------
                                                                                Final rule
                  Capacity type                   Baseline value -----------------------------------------------
                                                                       Value        Difference       % Change
----------------------------------------------------------------------------------------------------------------
Coal Steam......................................               0               0               0              NA
Combined Cycle..................................              75              76               1             0.8
Combustion Turbine..............................               6               6               0             0.0
Hydro...........................................               0               0               0              NA
Nuclear.........................................               0               0               0              NA
O/G Steam.......................................               0               0               0              NA
Other Non-Steam \a\.............................              25              25               0             0.1
Other Steam \b\.................................               9               9               0             0.0
                                                 ---------------------------------------------------------------
    Total.......................................             114             115               1             0.5
----------------------------------------------------------------------------------------------------------------
\a\ Other non-steam capacity includes wind, solar, pumped storage, and fuel cell.
\b\ Other steam capacity includes biomass, geothermal, municipal solid waste, fossil waste, landfill gas, tires,
  and non-fossil waste.

Impact on Regulated Facilities as a Group
    EPA used the same IPM V4.10--MATS analysis results for 2030 as
those used to assess market-level impacts described above; however,
this analysis considers the effect of the final rule only on regulated
facilities modeled in IPM (i.e., 520 facilities). For this analysis,
EPA considered four output metrics: (1) Incremental capacity closures;
(2) changes in capacity closures as a percent of total baseline
capacity; (3) changes in total generation; and (4) changes in variable
production costs per MWh.
    As shown in Exhibit IX-12, for the group of regulated facilities,
the impact of the final rule is overall slightly greater than that
observed over all generating units in the IPM universe (i.e., market-
level analysis discussed in the preceding section). This difference is
due to the fact that in the electricity market as a whole, impacts on
regulated facilities, which become less competitive compared to
facilities that do not incur compliance costs, are offset by changes in
capacity and energy production at the other electric power facilities.
Nevertheless, the impact on the group of regulated facilities remains
small. For instance, while there is essentially no change in total
available capacity for the overall electricity market at the national
level, for the group of regulated facilities, total available capacity
falls by only 0.4 percent (2 GW). At the regional level, five NERC
regions incur loss in total capacity, with the largest percentage loss
of 2.8 percent and the largest absolute loss of 0.9 GW occurring in the
NPCC region.
    The 2 GW of capacity loss at regulated facilities reflects a
combination of closures and avoided closures of generating units in the
universe of regulated facilities. Some unit closures result in full
facility closures (i.e., all generating units at a facility close),
while others result in only partial facility closures (i.e., some, but
not all, generating units at a facility close). For avoided closures, a
generating unit projected to close in the baseline case but remains
open under the policy case,

in some instances resulting in an avoided full facility closure.
Overall, 22 generating units close (4 GW) and 12 generating units avoid
closure (2 GW) in the policy case, resulting in net closure of 10
generating units (approximately 2 GW) in Electricity Market Analysis--
Final Rule analysis. The 22 generating unit closures reflect retirement
of nine units at six full-closure facilities (2 GW) and retirement of
13 units at six partial-closure facilities (2 GW). With only one
exception, these retirements involve older, less efficient generating
units with very low capacity utilization rates.
    At the national level, for the group of regulated facilities, total
generation at regulated facilities declines by less than 2 GWh or
approximately 0.1 percent of baseline generation in these facilities.
The MRO and SERC regions record slight increases in generation
essentially amounting to zero percent of baseline generation at
regulated facilities in these regions, with the remaining five NERC
regions recording a reduction in electricity generation of no more than
0.4 percent in FRCC.
    Over all regulated facilities, there is essentially no change in
variable production costs ($/MWh) at the national level, while at the
NERC region level, the change does not exceed 0.2 percent for any of
the regions. These findings of very small effects confirm EPA's
assessment that the assessed capacity closures among regulated
facilities are of little economic consequence at both the national and
regional levels.

                   Exhibit IX-12--Impact of Electricity Market Analysis Options on the Group of Regulated Facilities, at the Year 2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               Net change in early      Change in generation       Change in variable
                                                                 Baseline     retirements/closures   --------------------------      production cost
                       NERC region \a\                           capacity  --------------------------                          -------------------------
                                                                   (MW)       Capacity       % of         GWh          % of                      % of
                                                                                (MW)       baseline                  baseline    $2011/MWh     baseline
--------------------------------------------------------------------------------------------------------------------------------------------------------
FRCC.........................................................       30,794          203          0.7         -527         -0.4        -0.08         -0.2
MRO..........................................................       31,747            0          0.0           30          0.0         0.01          0.1
NPCC.........................................................       30,977          855          2.8          -25          0.0         0.00          0.0
RFC..........................................................      126,905          223          0.2         -619         -0.1         0.00          0.0
SERC.........................................................      142,840          476          0.3            3          0.0         0.02          0.1
SPP..........................................................       24,487         -530         -2.2         -411         -0.3         0.01          0.0
TRE..........................................................       38,378          808          2.1         -163         -0.1        -0.02         -0.1
WECC.........................................................       34,788            0          0.0           -8          0.0         0.00          0.0
                                                              ------------------------------------------------------------------------------------------
    Total....................................................      460,917        2,035          0.4       -1,721         -0.1         0.00          0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ FRCC (Florida Reliability Coordinating Council), MRO (Midwest Reliability Organization), NPCC (Northeast Power Coordination Council), RFC
  (ReliabilityFirst Corporation), SERC (Southeastern Electricity Reliability Council), SPP (Southwest Power Pool), TRE (Texas Reliability Entity), and
  WECC (Western Electricity Coordinating Council).

Impact on Individual Regulated Facilities
    Results for the group of 520 regulated facilities as a whole may
mask shifts in economic performance among individual facilities
incurring compliance costs under the final rule. To assess potential
facility-level effects, EPA analyzed facility-specific changes between
the baseline case and the final rule for the following metrics: (1)
Capacity utilization (defined as annual generation (in MWh) divided by
[capacity (MW) times 8,760 hours]) (2) electricity generation, and (3)
variable production costs per MWh.
    Exhibit XI-13 presents the estimated number of regulated facilities
with specific degrees of change in operations and financial
performance. Under the final rule, this analysis shows that most
facilities experience only slight effects--i.e., no change or less than
a 1 percent reduction or 1 percent increase. Only six facilities are
estimated to incur a reduction in capacity utilization and 13
facilities a reduction in generation of at least 1 percent, with only
five facilities estimated to incur an increase in variable production
costs per MWh of at least 1 percent. These facilities represent
approximately 1 percent of 520 regulated facilities analyzed in IPM.

                Exhibit IX-13--Impact of the Electricity Market Analysis--Final Rule on Individual Regulated Facilities at the Year 2030
                                                 [Number of regulated facilities with indicated effect]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Reduction                                    Increase
                                                                 ---------------------------------           ---------------------------------  N/A \b\
                        Economic measures                                     >=1 and              No Change              >=1 and                 \c\
                                                                     >=3%       <3%        <1%                   <1%        <3%        >=3%
--------------------------------------------------------------------------------------------------------------------------------------------------------
Change in Capacity Utilization \a\..............................          1          5         45        340         35          2          0         92
Change in Generation............................................          9          4         37        345         29          2          2         92
Change in Variable Production Costs/MWh.........................          2          1         70         86        242          4          1        114
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The change in capacity utilization is the difference between the capacity utilization percentages in the baseline and policy cases. For all other
  measures, the change is expressed as the percentage change between the baseline and post-compliance values.
\b\ Facilities with status changes in either the baseline case or the policy case were excluded from these calculations. Specifically, there are 17 full
  baseline facility closures, 59 partial baseline facility closures, four avoided partial facility closures, six partial policy facility closures, and
  six partial policy facility closures.
\c\ The change in variable production cost per MWh could not be developed for 22 facilities with zero generation in either the baseline case or the
  policy case.

ii. Analysis Results for 2020--To Capture the Effect of Technology-
Installation Downtime
    This section presents market-level results for the final rule for
the 2020 IPM run year, which represents 2017 through 2024. As discussed
above, this IPM run year captures the period when regulated facilities
are expected to install compliance technologies under the final rule.
Of particular importance as a potential impact, the additional downtime
from installation of compliance technologies could manifest as
increased electricity production costs resulting from the dispatch of
higher-production-cost generating units during the period when units
are taken offline to install compliance technologies. Because these
effects are of most concern in terms of potential impact on national
and regional electricity markets, this section presents results only
for the overall electricity market and does not present results for the
subset of regulated facilities.
    As shown in Exhibit IX-14, the estimated effects of technology-
installation downtime under the final rule are small. At the national
level, total production costs increase by 0.4 percent. At the regional
level, these costs increase in all NERC regions, with MRO and SPP
recording the largest increase of 0.6 percent.
    At the national level, variable production costs ($/MWh) increase
by approximately 0.2 percent. While the effect on variable production
costs varies across NERC regions, this effect is small overall, with
the largest increase of less than 0.4 percent occurring in FRCC. While
electricity prices increase in all NERC regions, the magnitude of that
increase is generally small, ranging from $0.15 per MWh (0.3 percent)
in MRO and WECC to $0.56 per MWh (0.9 percent) in FRCC.

             Exhibit IX-14--Short-Term Effect of Technology Installation Downtime on National Electricity Market Under the Final Rule--2020
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                    Change in generation       Change in variable       Change in total costs     Change in electricity
                                                 --------------------------      production cost     --------------------------           price
                 NERC Region \a\                                           --------------------------                          -------------------------
                                                   2011$/MWh       % of                      % of       Million        % of                      % of
                                                                 baseline    2011$/MWh     baseline      2011$       baseline    2011$/MWh     baseline
--------------------------------------------------------------------------------------------------------------------------------------------------------
FRCC............................................         -108          0.0         0.13          0.4           51          0.5         0.56          0.9
MRO.............................................           52          0.0         0.03          0.2           64          0.6         0.15          0.3
NPCC............................................          -88          0.0         0.05          0.2           31          0.3         0.18          0.3
RFC.............................................          447          0.0         0.03          0.1          164          0.4         0.19          0.4
SERC............................................         -369          0.0         0.04          0.1          185          0.4         0.27          0.6
SPP.............................................          -53          0.0         0.08          0.3           56          0.6         0.18          0.4
TRE.............................................            0          0.0         0.08          0.3           64          0.5         0.21          0.4
WECC............................................           33          0.0         0.04          0.2           39          0.1         0.15          0.3
                                                 -------------------------------------------------------------------------------------------------------
    Total.......................................          -88          0.0         0.05          0.2          652          0.4                       N/A
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ FRCC (Florida Reliability Coordinating Council), MRO (Midwest Reliability Organization), NPCC (Northeast Power Coordination Council), RFC
  (ReliabilityFirst Corporation), SERC (Southeastern Electricity Reliability Council), SPP (Southwest Power Pool), TRE (Texas Reliability Entity), and
  WECC (Western Electricity Coordinating Council).

EPA recognizes any capacity outages estimated to occur in conjunction
with installation of compliance technologies at existing units will
require outage coordination by the system operator or other planning
authority. Where possible, these outages would be scheduled in
concurrence with normal scheduled maintenance outages. Permit
authorities are provided flexibility to tailor compliance timelines.
This flexibility will ensure that any adverse impact on local electric
reliability as a result of this rule will be avoided. Facilities would
receive workable construction schedules from permit writers that will
allow schedule outages for installation without adversely affecting
electric supply reliability.
2. Manufacturers
    This section presents EPA's estimated economic impacts on
manufacturers for the final rule and the other options EPA considered.
These analyses assess the impact of regulatory requirements on the
financial performance of regulated facilities (facility-level analysis)
and the entities that own them (entity-level analysis). Similarly to
the electric generators analysis, for the manufacturers facility-level
and entity-level analyses, the Agency assumed that facilities would
pass none of their compliance costs forward to customers as price
increases, i.e., all compliance costs will be absorbed by regulated
facilities and their parent entities. For details on the cost-pass-
through (CPT) analysis for information on this assumption, see the EA,
Appendix K. EPA developed and used sample weights to extrapolate
impacts assessed initially at the level of a sample of facilities to
the full population of regulated facilities. For information on the
development and use of sample weights, see EA Appendix H.
a. Facility-Level Impact Analysis for Manufacturers
    EPA conducted two separate facility-level analyses for
manufacturers: (1) A stand-alone cost-to-revenue screener analysis and
(2) a facility closure and financial stress short of closure test. For
the cost-to revenue screener test, shown in Exhibit IX-15, EPA divided
the after-tax, annualized compliance cost by facility-level revenue.
Under the final rule, EPA found that of 500 Primary Manufacturing
Industry facilities, 496 incur costs less than one percent of revenue,
four incur costs between one and three percent, and none incur costs
greater than 3 percent. For the nine Other Industries facilities, EPA
estimated that eight facilities would incur costs less than one percent
and one would incur costs between one and three percent of revenue. For
Proposal Option 4, all Primary Manufacturing Industry facilities (500
facilities) and Other Industry facilities (nine facilities) incur costs
less than one percent of revenue. Under Proposal Option 2, 491 Primary
Manufacturing Industry facilities incur costs less than one percent and
nine facilities incur costs between one and three percent, while seven
Other Industry facilities incur costs less than one percent, one
facility incurs costs between one and three percent, and one facility
incurs costs greater than three percent.

     Exhibit IX-15--Facility-Level Cost-To-Revenue Analysis Results
------------------------------------------------------------------------
                                    Number of facilities with a cost-to-
                                            revenue ratio of \a\
              Option              --------------------------------------
                                       <1%      >=1 and <3%      >=3%
------------------------------------------------------------------------
                    Primary manufacturing industries
------------------------------------------------------------------------
Proposal Option 4................          500            0            0
Final Rule.......................          496            4            0
Proposal Option 2................          491            9            0
------------------------------------------------------------------------
                            Other industries
------------------------------------------------------------------------
Proposal Option 4................            9            0            0
Final Rule.......................            8            1            0
Proposal Option 2................            7            1            1
------------------------------------------------------------------------
\a\ EPA conducted this analysis for 579 facilities in the Primary
  Manufacturing Industries and 10 facilities in the Other Industries.
  Note, these facility counts and analysis exclude facilities identified
  as baseline closures in the severe impact analysis, which is described
  below.

    For the second analysis, EPA assessed how compliance costs would
likely affect financial performance and condition of the 509
manufacturers \134\ using two measures: (1) Facility closures (severe
impacts) and associated losses in revenue and employment, and (2)
financial stress short of closure (moderate impacts).
---------------------------------------------------------------------------

    \134\ This is a sample-weighted estimate of the number of
manufacturers, calculated using economic weights. This number
excludes 70 facilities estimated to be at substantial risk of
financial failure regardless of any additional financial burden that
might result from the final rule or other options considered in
development of this rule. For details see EA Appendix H.
---------------------------------------------------------------------------

    For the analysis of severe impacts, EPA identified a facility as a
regulatory closure if it would have operated under baseline conditions
but would not be financially viable under the new regulatory
requirements and the costs of the final rule leading to that finding
exceeded a threshold of 0.1 percent of revenue. Specifically, the
Agency examined the facility's going-concern value before and after
meeting regulatory requirements. EPA used a discounted cash flow