Other commercially available processes use sterically hindered amine
formulations (for example, the Mitsubishi Heavy Industries KS-1
solvent) which are less susceptible to degradation and corrosion
issues.
    The DOE/NETL and private industry are continuing to sponsor
research on advanced solvents (including new classes of amines) to
improve the CO2 capture performance and reduce costs.
    As noted in Section V.H.7.d above, SaskPower has created the CCS
Global Consortium to facilitate further knowledge regarding, and use
of, carbon capture technology.\333\ This consortium provides SaskPower
the opportunity to share its knowledge and experience with global
energy leaders, technology developers, and project developers.
SaskPower, in partnership with Mitsubishi and Hitachi, is also helping
to advance CCS knowledge and technology through the creation of the
Shand Carbon Capture Test Facility (CCTF).\334\ The test facility will
provide technology developers with an opportunity to test new and
emerging carbon capture systems for controlling carbon emissions from
coal-fired power plants.
---------------------------------------------------------------------------

    \333\ http://www.saskpowerccs.com/consortium/.
    \334\ http://www.saskpowerccs.com/ccs-projects/shand-carbon-capture-test-facility/.
---------------------------------------------------------------------------

    We also note certain features of the commercial plants already
built that suggest that their costs are uniquely high, and otherwise
not fairly comparable to the costs of plants meeting the NSPS using the
BSER. Most obviously, many of these projects involve deeper capture
than the partial CCS that the EPA assumes in this final action. In
addition, cost overruns at the Kemper facility, mentioned repeatedly in
the public comments, resulted in major part from highly idiosyncratic
circumstances, and are related to the cost of the IGCC system, not to
the cost of CCS.\335\ The EPA does not believe that these unusual
circumstances are a reasonable basis for assessing costs of either CCS
or IGCC here.
---------------------------------------------------------------------------

    \335\ See Independent Monitor's Prudency Evaluation Report for
the Kemper County IGCC Project (prepared for Mississippi Public
Utilities Staff), available at www.psc.state.ms.us/InsiteConnect/InSiteView.aspx?model=INSITE_CONNECT&queue=CTS_ARCHIVEQ&docid=328417
(``Report''). As documented in this Report, costs escalated
significantly because the developers adopted a ``compressed
schedule'' in an attempt to obtain the IRC 48A tax credit, resulting
in ``engineering and design changes which are a normal result of
detailed engineering and design . . . occurring at the same time as,
rather than ahead of, construction activities'', which did not allow
for proper sequencing during construction. This `` 'just-in-time'
approach to engineering and procurement (meaning that the
engineering was often completed shortly before material procurement
and construction activities) resulted in a greater number of
construction work-arounds, congestion of construction craft labor in
the field, inefficiencies and additional steps that became necessary
during construction to cope with this just-in-time engineering,
procurement and construction approach.'' Report, p. 6. Ironically,
work was still completed too late to obtain the tax credit. Id. p.
15.
---------------------------------------------------------------------------

4. Cost Competitiveness of New Coal Units
    As the EPA noted, all indications suggest that very few new coal-
fired power plants will be constructed in the foreseeable future.
Although a small number of new coal-fired power plants have been built
recently, the industry generally is not building these kinds of power
plants at present and is not expected to do so for the foreseeable
future. The reasons include the current economic environment and
improved energy efficiency, which has led to lower electricity demand,
and competitive current and projected natural gas prices. On average,
the cost of generation from a new NGCC power plant is expected to be
lower than the cost of generation from a new coal-fired power plant,
and the EPA has concluded that, even in the absence of the requirements
of this final rule, very few new coal-fired power plants will be built
in the near term.
    Some commenters, however, disagreed with this conclusion. They
contended instead that it is the CCS-based NSPS that would preclude
such new generation. However, as the EPA has discussed, there is
considerable evidence that utilities and project developers are moving
away--or have already moved away--from a long term dependence on coal-
fired generating sources. A review of publicly available integrated
resource plans show that many utilities are not considering
construction of new coal-fired sources without CCS. See Section V. H.3
above. Few new coal-fired generating sources have commenced
construction in the past 5 years and, of the projects that are
currently in the development phase, the EPA is only aware of projects
that will include CCS in the design. As we have noted in this preamble,
the bulk of new

generation that has been added recently has been either natural gas-
fired or renewable sources. Overall, the EPA remains convinced that the
energy sector modeling is reflecting the realities of the market in
predicting very few new coal-fired power plants in the near future--
even in the absence of these final standards.
    In addition, we note that the Administration's CCS Task Force
report recognized that CCS would not become more widely available
without the advent of a regulatory framework that promoted CCS or
provided a strong price signal for CO2. In this regard, we
note American Electric Power's statements regarding the need for
federal requirement for GHG control to aid in cost recovery for CCS
projects, to attract other investment partners, and thereby promote
advancement and deployment of CCS technology: ``as a regulated utility,
it is impossible to gain regulatory approval to recover our share of
the costs for validating and deploying the technology without federal
requirements to reduce greenhouse gas emissions already in place. The
uncertainty also makes it difficult to attract partners to help fund
the industry's share''.\336\ Indeed, AEP has stated that CCS is
important for the very future of the industry: ``AEP still believes the
advancement of CCS is critical for the sustainability of coal-fired
generation.'' \337\ This final rule's action is an important component
in developing that needed regulatory framework.
---------------------------------------------------------------------------

    \336\ www.aep.com/newsroom/newsreleases/?id=1704.
    \337\ ``CCS LESSONS LEARNED REPORT American Electric Power
Mountaineer CCS II Project Phase 1'', prepared for The Global CCS
Institute Project # PRO 004, January 23, 2012, page 2. Available at:
www.globalccsinstitute.com/publications/ccs-lessons-learned-report-american-electric-power-mountaineer-ccs-ii-project-phase-1; See also
AEP FEED Study at pp. 4, 63, Available at:
www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
---------------------------------------------------------------------------

5. Accuracy of Cost Estimates for Transportation and Geologic
Sequestration
    The EPA's estimates of costs take into account the transport of
CO2 and sequestration of captured CO2. Estimates
of transport and sequestration costs--approximately $5-$15 per ton of
CO2--are based on DOE NETL studies and are also consistent
with other published studies.\338\ For transport, costs reflect
pipeline capital costs, related capital expenditures, and O&M costs.
Sequestration cost estimates reflect the cost of site screening and
evaluation, the cost of injection wells, the cost of injection
equipment, operation and maintenance costs, pore volume acquisition
expense, and long term liability protection. These sequestration costs
reflect the regulatory requirements of the Underground Injection
Control Class VI program and GHGRP subpart RR for geologic
sequestration of CO2 in deep saline formations, which are
discussed further in Sections V. M. and N below.\339\
---------------------------------------------------------------------------

    \338\ Updated Costs (June 2011 Basis) for Selected Bituminous
Baseline Cases (DOE/NETL-341/082312); Cost and Performance of PC and
IGCC Plants for a Range of Carbon Dioxide Capture (DOE/NETL-2011/
1498); Cost and Performance Baseline for Fossil Energy Plants (DOE/
NETL-2010/1397); Economic Evaluation of CO2 Storage and
Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI,
December 2002; Carbon Dioxide and Transport and Storage Costs in
NETL Studies (DOE/NETL-2013/1614), March 2013; Carbon Dioxide and
Transport and Storage Costs in NETL Studies (DOE/NETL-2014/1653),
May 2014; Cost and Performance Baseline for Fossil Energy Power
Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to
Electricity (DOE-NETL-2015/1723), July 2015.
    \339\ Carbon Dioxide and Transport and Storage Costs in NETL
Studies. DOE/NETL-2013/1614. March 2013. P. 13.
---------------------------------------------------------------------------

    Based on DOE/NETL studies, the EPA estimated that the total
CO2 transportation, storage, and monitoring (TSM) cost
associated with EGU CCS would comprise less than 5.5 percent of the
total cost of electricity in all capture cases modeled--approximately
$5-$15 per ton of CO2.\340\ The range of TSM costs the EPA
relied on are broadly consistent with estimates provided by the Global
Carbon Capture and Storage Institute as well.\341\ Some commenters
suggested that the EPA underestimated the costs associated with
transporting captured CO2 from an EGU to a sequestration
site.\342\ Specifically, commenters suggested that the EPA's estimated
costs for constructing pipelines were lower than costs based on actual
industry experience. Commenters also opined that the EPA's assumed
length of pipeline needed between the EGU and the sequestration site is
not reasonable and that the DOE/NETL study upon which the EPA relied
does not account for CO2 transport costs when EOR is not
available.
---------------------------------------------------------------------------

    \340\ RIA at section 5.5; proposed rule RIA at 5-30.
    \341\ http://hub.globalccsinstitute.com/sites/default/files/publications/12786/economic-assessment-carbon-capture-and-storage-technologies-2011-update.pdf.
    \342\ See, for example, comments from American Electric Power,
pp 97-8 (Docket entry: EPA-HQ-OAR-2013-0495-10618), Southern
Company, pp. 47-48 (Docket entry: EPA-HQ-OAR-2013-0495-10095), and
Duke Energy p. 28 (Docket entry: EPA-HQ-OAR-2013-0495-9426).
---------------------------------------------------------------------------

    The EPA believes its estimates of transportation and sequestration
costs are reasonable. First, the EPA in fact includes cost estimates
for CO2 transport when EOR opportunities are not available--
consistent with its overall conservative cost methodology of assuming
no revenues from sale of captured CO2. Specifically, the EPA
estimates transport, storage and monitoring (TSM) costs of $5-$15 per
ton of CO2 for non-EOR applications.\343\ This estimate is
reflected in the LCOE comparative costs.\344\
---------------------------------------------------------------------------

    \343\ See RIA at section 5.5 and proposed RIA at 5-30.
    \344\ See RIA at section 5.5.
---------------------------------------------------------------------------

    The EPA also carefully reviewed the assumptions on which the
transport cost estimates are based and continues to find them
reasonable. The NETL studies referenced in Section V.I.2 above based
transport costs on a generic 100 km (62 mi) pipeline and a generic 80
kilometer pipeline.\345\ At least one study estimated that of the 500
largest point sources of CO2 in the United States, 95
percent are within 50 miles of a potential storage reservoir.\346\ As a
point of reference, the longest CO2 pipeline in the United
States is 502 miles.\347\ For new sources, pipeline distance and costs
can be factored into siting and, as discussed in Section V.M, there is
widespread availability of geologic formations for geologic
sequestration (GS). Moreover, data from the Pipeline and Hazardous
Materials Safety Administration show that in 2013 there were 5,195
miles of CO2 pipelines operating in the United States. This
represents a seven percent increase in CO2 pipeline miles
over the previous year and a 38 percent increase in CO2
pipeline miles since 2004. For the reasons outlined above, the EPA
believes its estimates have a reasoned basis. See also Section V.M
below further discussing the current availability of CO2
pipelines.
---------------------------------------------------------------------------

    \345\ The pipeline diameter was sized for this to be achieved
without the need for recompression stages along the pipeline length.
    \346\ JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH
Kim, EL Malone (2006), Carbon Dioxide Capture and Geologic Storage:
A Key Component of a Global Energy Technology Strategy to Address
Climate Change. Joint Global Change Research Institute, Battelle
Pacific Northwest Division. PNWD-3602. College Park, MD.
    \347\ A Review of the CO2 Pipeline Infrastructure in
the U.S., April 21, 2015, DOE/NETL-2014/1681, Office of Fossil
Energy, National Energy Technology Laboratory.
---------------------------------------------------------------------------

    With respect to sequestration, certain commenters argued that the
EPA's cost analysis failed to account for many contingencies and
uncertainties (surface and sub-surface property rights in particular),
ignored the costs of GHGRP subpart RR, and also was not representative
of the costs associated with specific GS site characterization,
development, and operation/injection of monitoring wells. Commenter
American Electric Power (AEP) referred to its own

experience with the Mountaineer demonstration project. AEP noted that
although this project was not full scale, finding a suitable
repository, notwithstanding a generally favorable geologic area, proved
difficult. The company referred to its estimated cost of expanding the
existing Mountaineer plant to a larger scale project, particularly the
cost of site characterization and well construction.\348\
---------------------------------------------------------------------------

    \348\ AEP Comments at pp. 93, 96 (Docket entry: EPA-HQ-OAR-2013-
0495-10618).
---------------------------------------------------------------------------

    The EPA's cost estimates account for the requirements of the
Underground Injection Control Class VI program, and GHGRP subpart RR,
among them site screening and evaluation costs, costs for injection
wells and equipment, O&M costs, and monitoring costs. The estimated
sequestration costs include operational and post-injection site care
monitoring, which are components of the UIC Class VI requirements, and
also reflect costs for sub-surface pore volume property rights
acquisition.\349\ These estimates are consistent with the costs
presented in the study CO2 Storage and Sink Enhancements:
Developing Comparable Economics, which incorporates the costs
associated with site evaluation, well drilling, and the capital
equipment required for transporting and injecting
CO2.350 351 Monitoring costs were evaluated based
on the methodology set forth in the International Energy Agency
Greenhouse Gas R&D Programme's Overview of Monitoring Projects for
Geologic Storage Projects report.\352\
---------------------------------------------------------------------------

    \349\ ``Cost and Performance of PC and IGCC Plants for a Range
of Carbon Dioxide Capture.'' DOE/NETL-2011/1498 (September 2013) p.
49. Specifically, the report estimates the costs associated with
acquiring rights to use the pore space in the geologic formation.
Costs are estimated based on studies of subsurface rights
acquisition for natural gas storage. The report also estimates costs
for land acquisition for surface property rights. Id. p. 48.
    \350\ Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davidson, D.G.
De La Torre Ugarte, and D. Simbeck. (2003). Economic Evaluation of
CO2 Storage and Sink Enhancement Options, Final Technical
Report Prepared by Tennessee Valley Authority for DOE.
    \351\ As noted above, other sequestration-related costs are also
estimated, including injection wells and equipment, pore volume
acquisition, and long-term-liability. ``Cost and Performance
Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and
Natural Gas to Electricity Revision 2a, September 2013 DOE/NETL-
2010/1397, p. 55.
    \352\ ``Overview of Monitoring Requirements for Geologic Storage
Projects'', IEA Greenhouse Gas R&D Programme, Report Number PH4/29,
November 2004.
---------------------------------------------------------------------------

    The EPA's cost estimates for sequestration thus cover all aspects
commenters claimed the EPA disregarded. The EPA believes that the use
of costs and scenarios presented in the studies referenced are
representative for purposes of the cost analysis. The NETL cost
estimates upon which the EPA's costs draw directly from the UIC Class
VI economic impact analysis.\353\ That analysis is based on estimated
characteristics for a representative group of projects over a 50-year
period of analysis, as well as industry averages for several cost
components and sub-components. The EPA also made reasonable assumptions
regarding the assumed injection site: A deep saline formation with
typical characteristics (e.g., representative depth and pressure).\354\
---------------------------------------------------------------------------

    \353\ Cost Analysis for the Federal Requirements Under the
Underground Injection Control Program for Carbon Dioxide Geologic
Sequestration Wells, U.S. Environmental Protection Agency Office of
Water, EPA 816-R10-013, November 2010, pages 3-1, 5-42.
    \354\ Economic Evaluation of CO2 Storage and Sink
Enhancement Options, Tennessee Valley Authority, NETL and EPRI,
December 2002.
---------------------------------------------------------------------------

    With respect to AEP's experience with the Mountaineer demonstration
project, sequestration siting issues are of course site-specific, and
raise individual issues. For this reason, it is inappropriate to
generalize from a particular individual experience. In this regard, as
explained in Section V.N below, the construction permits issued by the
EPA to-date under the Underground Injection Control Class VI
regulations required far fewer wells for site characterization and
monitoring than AEP found to be necessary at its Mountaineer site.
Moreover, notwithstanding difficulties, the company was able to
successfully drill and complete wells, and safely inject captured
CO2. The company also indicated it fully expected to be able
to do so at full scale and explained how.\355\ For discussion of 40 CFR
part 98, subpart RR (the GHGRP requirements for geologic
sequestration), including costs associated with compliance with those
requirements, see Section V.N below.
---------------------------------------------------------------------------

    \355\ See ``CCS front end engineering & design report: American
Electric Power Mountaineer CCS II Project. Phase 1'' at pp. 36-43.
The company likewise explained the monitoring regime it would
utilize to verify containment, and the well construction it would
utilize to guarantee secure sequestration. Id. at pp. 44-54.
Available at: http://www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
---------------------------------------------------------------------------

J. Achievability of the Final Standards

    The EPA finds the final standard of 1,400 lb CO2/MWh-g
to be achievable over a wide range of variable conditions that are
reasonably likely to occur when the system is properly designed and
operated. As discussed elsewhere, the final standard reflects the
degree of emission limitation achievable through the application of the
BSER which we have determined to be a highly efficient SCPC
implementing partial CCS at a level sufficient to achieve the final
standard--for such a unit utilizing bituminous coal that would be
approximately 16 percent. In determining the predicted cost and
performance of such a system, the EPA utilized information contained in
updated DOE/NETL studies that assumed use of bituminous coal and an 85
percent capacity factor. Here we examine the effects of deviating from
those assumed operational parameters on the achievability of the final
standard of performance.\356\ This is in keeping with the requirement
that a standard of performance must be achievable accounting for all
normal operating variability when a control system is properly
designed, maintained, and operated. See Section III.H.1.c above.
---------------------------------------------------------------------------

    \356\ Additional information can be found in a Technical Support
Document (TSD)--``Achievability of the Standard for Newly
Constructed Steam Generating EGUs'' available in the rulemaking
docket.
---------------------------------------------------------------------------

1. Operational Fluctuations, Start-Ups, Shutdowns, and Malfunctions
    Importantly, compliance with the standard must be demonstrated over
a 12-operating-month average. The total CO2 emissions
(pounds of CO2) over 12 operational months are summed and
divided by the total gross output (in megawatt-hours) over the same 12
operational months. Such a compliance averaging period is very
forgiving of short-term excursions that can be associated with non-
routine events such as start-ups, shutdowns, and malfunctions. A new
fossil fuel-fired steam generating EGU--if constructed--would, most
likely, be built to serve base load power demand and would not be
expected to routinely start-up or shutdown or ramp its capacity factor
in order to follow load demand. Thus, planned start-up and shutdown
events would only be expected to occur a few times during the course of
a 12-operating-month compliance period. Malfunctions are unplanned and
unpredictable events and emission excursions can happen at or around
the time of the equipment malfunction. But a malfunctioning EGU that
cannot be operated properly should be shut down until the
malfunctioning equipment can be addressed and the EGU can be restarted
to operate properly.
    The post-combustion capture systems that have been utilized have
proven to be reliable. The Boundary Dam facility has been operating
full CCS successfully at commercial scale since October 2014. As
described earlier, in evaluating results from the Mountaineer slip-

stream demonstration, AEP and Alstom reported robust steady-state
operation during all modes of power plant operation including load
changes, and saw an availability of the CCS system of greater than 90
percent.\357\
---------------------------------------------------------------------------

    \357\ http://www.alstom.com/press-centre/2011/5/alstom-announces-sucessful-results-of-mountaineer-carbon-capture-and-sequestration-ccs-project/. The Boundary Dam facility likewise is
operating reliably (see Section V.D.3.a above). See also ``Cost and
Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous
Coal (PC) and Natural Gas to Electricity, Revision 3'', DOE/NETL-
2015/1723 (July 2015) at p. 36 (``[t]he capture and CO2
compression technologies have commercial operating experience with
demonstrated ability for high reliability'').
---------------------------------------------------------------------------

2. Variations in Coal Type
    The use of specific coal types can affect the amount of
CO2 that is emitted from a new coal-fired power plant. As
previously discussed, the EPA utilized studies by the DOE/NETL to
predict the cost and performance of new steam generating units. Based
on those reports, the EPA predicts that a new SCPC burning low rank
coal (subbituminous coal or dried lignite) would have an uncontrolled
emission rate about 7 percent higher than a similar unit firing typical
bituminous coal.\358\ The EPA predicts that such a highly efficient new
SCPC utilizing subbituminous coal or dried lignite would need to
capture approximately 23 percent of the CO2. The EPA also
believes that it is technically feasible to do so, although additional
cost would be entailed. The EPA has evaluated those costs and finds
them to remain reasonable.\359\ As shown in Table 8 above, the
predicted cost remains within the estimated range for the other
principal base load, dispatchable non-NGCC alternative technologies.
Estimated capital cost using these coal types would also be somewhat
higher, an estimated 23 percent increase.\360\ The EPA finds these
increases to be reasonable because, as discussed earlier, the costs are
reasonably consistent with capital cost increases in previous NSPS. See
Section V.H.4 above.
---------------------------------------------------------------------------

    \358\ For additional detail, see the Technical Support Document
(TSD)--``Achievability of the Standard for Newly Constructed Steam
Generating EGUs''--available in the rulemaking docket.
    \359\ The cost of the lignite drying equipment is assumed to be
low compared to the cost of the carbon capture equipment. Further,
pre-drying of the lignite reduces fuel, auxiliary power consumption
and other O&M costs. www.iea-coal.org.uk/documents/83436/9095/
Techno-economics-of-modern-pre-drying-technologies-for-lignite-
fired-power-plants,-CCC/241.
    \360\ Note that the 23 percent increase in expected capital
costs and the 23 percent CO2 capture needed to meet the
final standard are coincidental and are not correlated.
---------------------------------------------------------------------------

K. Emission Reductions Utilizing Partial CCS

    Although the definition of ``standard of performance'' does not by
its terms identify the amount of emissions from the category of sources
and the amount of emission reductions achieved as factors the EPA must
consider in determining the ``best system of emission reduction,'' the
D.C. Circuit has stated that the EPA must do so. See Sierra Club v.
Costle, 657 F.2d at 326 (``we can think of no sensible interpretation
of the statutory words ``best . . . system'' which would not
incorporate the amount of air pollution as a relevant factor to be
weighed when determining the optimal standard for controlling . . .
emissions'').\361\ This is consistent with the Court's statements in
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 437 that it is
necessary to ``[k]eep[] in mind Congress' intent that new plants be
controlled to the `maximum practicable degree' ''.
---------------------------------------------------------------------------

    \361\ Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was
governed by the 1977 CAAA version of the definition of ``standard of
performance,'' which revised the phrase ``best system'' to read,
``best technological system.'' The 1990 CAAA deleted
``technological,'' and thereby returned the phrase to how it read
under the 1970 CAAA. The Sierra Club v. Costle's interpretation of
this phrase to require consideration of the amount of air emissions
remains valid for the phrase ``best system.''
---------------------------------------------------------------------------

    The final standard of performance will result in meaningful and
significant emission reductions of GHG emissions from a new coal-fired
steam generating unit. The EPA estimates that a new highly efficient
500 MW coal-fired SCPC meeting the final standard of 1,400 lb
CO2/MWh-g will emit about 354,000 fewer metric tons of
CO2 each year than that new highly efficient unit would have
emitted otherwise. That is equivalent to taking about 75,000 vehicles
off the road each year \362\ and will result in over 14,000,000 fewer
metric tons of CO2 in a 40-year operating life. To emphasize
the importance of constructing a highly efficient SCPC unit that
includes partial CCS--the highly efficient 500 MW coal-fired SCPC with
partial CCS would emit about 675,000 fewer metric tons of
CO2 each year than that from a new, less efficient coal-
fired utility boiler with an assumed emission of 1,800 lb
CO2/MWh-g.
---------------------------------------------------------------------------

    \362\ Using U.S. EPA Office of Transportation and Air Quality
(OTAQ) estimate of average vehicle emissions of 4.7 tonnes/year.
---------------------------------------------------------------------------

    For comparison, see Table 12 below which provides the amount of
CO2 emissions captured each year by other CCS projects.
These result show that, even though the emission reductions are
significant, they are reasonably within the range of emission
reductions that are currently being achieved now in existing
facilities. For comparison, approximately 60,000,000 metric tons of
CO2 were supplied to U.S. EOR operations in 2013.\363\
---------------------------------------------------------------------------

    \363\ Greenhouse Gas Reporting Program, data reported as of
August 18, 2014.

 Table 12--Annual Metric Tons of CO2 Captured (or Predicted to Capture)
    From CCS Projects and From a Model 500 MW Plant Meeting the Final
                                Standard.
------------------------------------------------------------------------
                                                           CO2 captured
                         Project                            tonnes/year
------------------------------------------------------------------------
AES Shady Point.........................................          66,000
AES Warrior Run.........................................         110,000
Southern Company Plant Barry............................         165,000
Searles Valley Minerals.................................         270,000
New 500 MW SCPC EGU (1,400 lb CO2/MWh-g)................         354,000
Coffeyville Fertilizer..................................         700,000
Boundary Dam #3.........................................       1,000,000
Petra Nova/NRG WA Parish................................       1,400,000
Dakota Gasification.....................................       3,000,000
------------------------------------------------------------------------

L. Further Development and Deployment of CCS Technology

    Researchers at Carnegie Mellon University (CMU) have studied the
history and the technological response to environmental
regulations.\364\ By examining U.S. research funding and patenting
activity over the past century, the CMU researchers found that
promulgation of national policy requiring large reductions in power-
plant emissions resulted in a significant upswing in inventive activity
to develop technologies to reduce those emissions. The researchers
found that, following the 1970 Clean Air Act, there was a 10-fold
increase in patenting activity directed at improving the SO2
scrubbers that were needed to comply with stringent federal and state-
level standards.
---------------------------------------------------------------------------

    \364\ See Technical Support Document/Memorandum ``History Of
Flue Gas Desulfurization in the United States'' (July 11, 2015)
summarizing the doctoral dissertation of Margaret R. Taylor, ``The
Influence of Government Actions on Innovative Activities in the
Development of Environmental Technologies to Control Sulfur Dioxide
Emissions from Stationary Sources,'' MA dissertation submitted to
the Carnegie Institute of Technology, Carnegie Mellon University in
partial fulfillment of the requirements for the degree of Doctor of
Philosophy in Engineering and Public Policy, Pittsburgh, PA, January
2001.
---------------------------------------------------------------------------

    Much like carbon capture scrubbers today, the technology to capture
and remove SO2 from power plant flue gases was new to the
industry and was not yet widely deployed at large coal-burning plants
when the EPA first promulgated the 1971 standards.
    Many of the early Flue Gas Desulfurization (FGD) units did not
perform well, as the technology at that time was poorly understood and
there was little or no prior experience on coal-fired power plants. In
contrast, amine-based capture systems have a much longer history of
reliable use at coal-fired plants and other industrial sources. There
is also a better understanding of the amine process chemistry and
overall process design--and project developers have much sophisticated
analytical tools available today than in the 1970s during the
development of FGD scrubber technologies.
    While R&D efforts were essential to achieving improvements in FGD
scrubber technology--and are also very important to improving carbon
capture technologies, the influence of regulatory actions that
establish commercial markets for advanced technologies cannot be
minimized. The existence of national government regulation for
SO2 emissions control stimulated innovation, as shown by the
patent analysis following initial SO2 regulatory
requirements for EGU emissions. The study author further found that
regulatory stringency appears to be particularly important as a driver
of innovation, both in terms of inventive activity and in terms of the
communication processes involved in knowledge transfer and diffusion.
Further, as electric power generation doubled, the operating and
maintenance costs of FGD systems decline to 83 percent of their
original level. This finding, which is very much in line with progress
ratios determined in other industries, shows that quantifiable
technological improvements can be shown to occur solely on the basis of
the experience of operating an environmental control technology forced
into being by government actions.

M. Technical and Geographic Aspects of Disposition of Captured
CO2

    In the following sections of the preamble, we discuss issues
associated with the disposition of captured CO2: the ``S''--
sequestration--in CCS. In this section, we review the existing
processes, technologies, and geologic conditions that enable successful
geologic sequestration (GS). In Section V.N., we discuss in detail the
comprehensive, in-place regulatory structure that is currently
available to oversee GS projects and assure their safety and
effectiveness. Together, these discussions demonstrate that the
technical feasibility of GS, another key component of a partial CCS
unit, is adequately demonstrated. Sequestration is already well proven.
CO2 has been retained underground for eons in geologic
(natural) repositories and the mechanisms by which CO2 is
trapped underground are well understood. The physical and chemical
trapping mechanisms, along with the regulatory requirements and
safeguards of the Underground Injection Control Program and
complementary monitoring and reporting requirements of the GHGRP,
together ensure that sequestered CO2 will remain secure and
provide the monitoring to identify and address potential leakage using
Safe Drinking Water Act (SDWA) and CAA authorities (see Section V.N of
this preamble).\365\
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    \365\ See also Carbon Sequestration Council and Southern Company
Services v. EPA, No. 14-1406 (D.C. Cir. June 2, 2015) at *10
(``[c]arbon capture and storage is an emerging climate change
mitigation program that involves capturing carbon dioxide from
industrial sources, compressing it into a `supercritical fluid,' and
injecting that fluid underground for the purposes of geologic
sequestration, with the goal of preventing the carbon from
reentering the atmosphere. Because the last of these steps--geologic
sequestration of the supercritical carbon dioxide--involves that
injection of fluid into underground wells, it is subject to
regulation under the Safe Drinking Water Act'').
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1. Geologic and Geographic Considerations for GS
    Geologic sequestration (i.e., long-term containment of a
CO2 stream in subsurface geologic formations) is technically
feasible and available throughout most of the United States. GS is
based on a demonstrated understanding of the processes that affect
CO2 fate in the subsurface; these processes can vary
regionally as the subsurface geology changes. GS occurs through a
combination of mechanisms including: (1) Structural and stratigraphic
trapping (generally trapping below a low permeability confining layer);
(2) residual CO2 trapping (retention as an immobile phase
trapped in the pore spaces of the geologic formation); (3) solubility
trapping (dissolution in the in situ formation fluids); (4) mineral
trapping (reaction with the minerals in the geologic formation and
confining layer to produce carbonate minerals); and (5) preferential
adsorption trapping (adsorption onto organic matter in coal and
shale).\366\ These mechanisms are functions of the physical and
chemical properties of CO2 and the geologic formations into
which the CO2 stream is injected. Subsurface formations
suitable for GS of CO2 captured from affected EGUs are
geographically widespread throughout most parts of the United States.
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    \366\ See, e.g., USEPA. 2008. Vulnerability Evaluation Framework
for Geologic Sequestration of Carbon Dioxide.
---------------------------------------------------------------------------

    Storage security is expected to increase over time through post-
closure, resulting in a decrease in potential risks.\367\ This
expectation is based in part on a technical understanding of the
variety of trapping mechanisms that work to reduce CO2
mobility over time.\368\ In addition, site characterization, site
operations, and monitoring strategies can work in combination to
promote storage security.
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    \367\ Report of the Interagency Task Force on Carbon Capture and
Storage (August 2010), page 47.
    \368\ See, e.g., Intergovernmental Panel on Climate Change.
(2005). Special Report on Carbon Dioxide Capture and Storage.

---------------------------------------------------------------------------

    The effectiveness of long-term trapping of CO2 has been
demonstrated by natural analogs in a range of geologic settings where
CO2 has remained trapped for millions of years.\369\ For
example, CO2 has been trapped for more than 65 million years
in the Jackson Dome, located near Jackson, Mississippi.\370\ Other
examples of natural CO2 sources include Bravo Dome and
McElmo Dome in Colorado and New Mexico, respectively. These natural
storage sites are themselves capable of holding volumes of
CO2 that are larger than the volume of CO2
expected to be captured from a fossil fuel-fired EGU. In 2010, the
Department of Energy (DOE) estimated current CO2 reserves of
594 million metric tons at Jackson Dome, 424 million metric tons at
Bravo Dome, and 530 million metric tons at McElmo Dome.\371\
---------------------------------------------------------------------------

    \369\ Holloway, S., J. Pearce, V. Hards, T. Ohsumi, and J. Gale.
2007. Natural Emissions of CO2 from the Geosphere and
their Bearing on the Geological Storage of Carbon Dioxide. Energy
32: 1194-1201.
    \370\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
    \371\ DiPietro, P., Balash, P. & M. Wallace. A Note on Sources
of CO2 Supply for Enhanced-Oil Recovery Operations. SPE
Economics & Management. April 2012.
---------------------------------------------------------------------------

    GS is feasible in different types of geologic formations including
deep saline formations (formations with high salinity formation fluids)
or in oil and gas formations, such as where injected CO2
increases oil production efficiency through a process referred to as
enhanced oil recovery (EOR). Both deep saline and oil and gas formation
types are widely available in the United States. The geographic
availability of deep saline formations and EOR is shown in Figure 1
below.\372\ As shown in the figure, there are 39 states for which
onshore and offshore deep saline formation storage capacity has been
identified.\373\ EOR operations are currently being conducted in 12
states. An additional 17 states have geology that is amenable to EOR
operations. Figure 1 also shows areas that are within 100 kilometers
(62 miles) of where storage capacity has been identified.\374\ There
are 10 states with operating CO2 pipelines and 18 states
that are within 100 kilometers (62 miles) of an active EOR location.
---------------------------------------------------------------------------

    \372\ A color version of the figure, which readers may find
easier to view, can be found in the technical support document on
geographic availability in the rulemaking docket.
    \373\ Alaska is not shown in Figure 1; it has deep saline
formation storage capacity, geology amenable to EOR operations, and
potential GS capacity in unmineable coal seams.
    \374\ The distance of 100 kilometers reflects assumptions in
DOE-NETL cost estimates which the EPA used for cost estimation
purposes. See ``Carbon Dioxide and Transport and Storage Costs in
NETL Studies'', DOE/NETL-2014/1653 (May 2014).
---------------------------------------------------------------------------

    CO2 may also be used for other types of enhanced
recovery, such as for natural gas production. Reservoirs such as
unmineable coal seams also offer the potential for geologic
storage.\375\ Enhanced coalbed methane recovery is the process of
injecting and storing CO2 in unmineable coal seams to
enhance methane recovery. These operations take advantage of the
preferential chemical affinity of coal for CO2 relative to
the methane that is naturally found on the surfaces of coal. When
CO2 is injected, it is adsorbed to the coal surface and
releases methane that can then be captured and produced. This process
effectively ``locks'' the CO2 to the coal, where it remains
stored. DOE has identified over 54 billion metric tons of potential
CO2 storage capacity in unmineable coal across 21
states.\376\ The availability of unmineable coal seams is shown in
Figure 1 below.
---------------------------------------------------------------------------

    \375\ Other types of opportunities include organic shales and
basalt.
    \376\ The United States 2012 Carbon Utilization and Storage
Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil
Energy, National Energy Technology Laboratory (NETL).
---------------------------------------------------------------------------

    As discussed below in Section M.7, a few states do not have
geologic conditions suitable for GS, or may not be located in proximity
to these areas. However, in some cases, demand in those states can be
served by coal-fired power plants located in areas suitable for GS, and
in other cases, coal-fired power plants are unlikely to be built in
those areas for other reasons, such as the lack of available coal or
state law prohibitions and restrictions against coal-fired power
plants.\377\
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    \377\ Similarly, as discussed below, the U.S. territories lack
available coal, do not currently have coal-fired power plants, and,
as a result, are not expected to see new coal-fired power plants.
Hawaii is not expected to constructed new coal plants as it intends
to utilize 100 percent renewable energy sources by 2050.

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[GRAPHIC] [TIFF OMITTED] TR23OC15.000

[GRAPHIC] [TIFF OMITTED] TR23OC15.001

2. Availability of Geologic Sequestration in Deep Saline Formations
---------------------------------------------------------------------------

    \378\ Ventyx Velocity Suite Online. April 2015.
---------------------------------------------------------------------------

    The DOE and the United States Geological Survey (USGS) have
independently conducted preliminary analyses of the availability and
potential CO2 sequestration capacity of deep saline
formations in the United States. DOE estimates are compiled by the
DOE's National Carbon Sequestration Database and Geographic Information
System (NATCARB) using volumetric models and published in a Carbon
Utilization and Storage Atlas.\379\ DOE estimates that areas of the
United States

with appropriate geology have a sequestration potential of at least
2,035 billion metric tons of CO2 in deep saline formations.
According to DOE and as noted above, at least 39 states have geologic
characteristics that are amenable to deep saline GS in either onshore
or offshore locations. In 2013, the USGS completed its evaluation of
the technically accessible GS resources for CO2 in U.S.
onshore areas and state waters using probabilistic assessment.\380\ The
USGS estimates a mean of 3,000 billion metric tons of subsurface
CO2 sequestration potential, including saline and oil and
gas reservoirs, across the basins studied in the United States.
---------------------------------------------------------------------------

    \379\ The United States 2012 Carbon Utilization and Storage
Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil
Energy, National Energy Technology Laboratory (NETL).
    \380\ U.S. Geological Survey Geologic Carbon Dioxide Storage
Resources Assessment Team, 2013, National assessment of geologic
carbon dioxide storage resources--Results: U.S. Geological Survey
Circular 1386, p. 41, http://pubs.usgs.gov/circ/1386/ 1386/.
---------------------------------------------------------------------------

    The DOE has created a network of seven Regional Carbon
Sequestration Partnerships (RCSPs) to deploy large-scale field projects
in different geologic settings across the country to demonstrate that
GS can be achieved safely, permanently, and economically at large
scales. Collectively, the seven RCSPs represent regions encompassing 97
percent of coal-fired CO2 emissions, 97 percent of
industrial CO2 emissions, 96 percent of the total land mass,
and essentially all the geologic sequestration sites in the United
States potentially available for GS.\381\ The seven partnerships
include more than 400 organizations spanning 43 states (and four
Canadian provinces).\382\ RCSP project objectives are to inject at
least one million metric tons of CO2. In April 2015, DOE
announced that CCS projects supported by the department have safely and
permanently stored 10 million metric tons of CO2.\383\
---------------------------------------------------------------------------

    \381\ http://energy.gov/fe/science-innovation/carbon-capture-and-storage-research/regional-partnerships.
    \382\ http://energy.gov/fe/science-innovation/carbon-capture-and-storage-research/regional-partnerships.
    \383\ http://energy.gov/articles/milestone-energy-department-projects-safely-and-permanently-store-10-million-metric-tons.
---------------------------------------------------------------------------

    Eight RCSP ``Development Phase'' projects have been initiated and
five of the eight projects are injecting or have completed
CO2 injection into deep saline formations. Three of these
projects have already injected more than one million metric tons each,
and one, the Cranfield Site, injected over eight million metric tons of
CO2 between 2009 and 2013.\384\ Various types of
technologies for monitoring CO2 in the subsurface and air
have been employed at these projects, such as seismic methods
(crosswell seismic, 3-D and 4-D seismic, and vertical seismic
profiling), atmospheric CO2 monitoring, soil gas sampling,
well and formation pressure monitoring, and surface and ground water
monitoring.\385\ No CO2 leakage has been reported from these
sites, which further supports the availability of effective GS.
---------------------------------------------------------------------------

    \384\ U.S. Department of Energy, National Energy Technology
Laboratory, Project Facts, Southeast Regional Carbon Sequestration
Partnership--Development Phase, Cranfield Site and Citronelle Site
Projects, NT42590, October 2013. Available at: http://www.netl.doe.gov/publications/factsheets/project/NT42590.pdf.
    \385\ A description of the types of monitoring technologies
employed at RCSP projects can be found here: http://www.netl.doe.gov/research/coal/carbon-storage/carbon-storage-infrastructure/regional-partnership-development-phase-iii.
---------------------------------------------------------------------------

3. Availability of CO2 Storage via EOR
    Although the determination that the BSER is adequately demonstrated
and the regulatory impact analysis for this rule relies on GS in deep
saline formations, the EPA also recognizes the potential for securely
sequestering CO2 via EOR.
    EOR is a technique that is used to increase the production of oil.
Approaches used for EOR include steam injection, injection of specific
fluids such as surfactants and polymers, and gas injection including
nitrogen and CO2. EOR using CO2, sometimes
referred to as ``CO2 flooding'' or CO2-EOR,
involves injecting CO2 into an oil reservoir to help
mobilize the remaining oil to make it more amenable for recovery. The
crude oil and CO2 mixture is then recovered and sent to a
separator where the crude oil is separated from the gaseous
hydrocarbons, native formation fluids, and CO2. The gaseous
CO2-rich stream then is typically dehydrated, purified to
remove hydrocarbons, re-compressed, and re-injected into the reservoir
to further enhance oil recovery. Not all of the CO2 injected
into the oil reservoir is recovered and re-injected. As the
CO2 moves from the injection point to the production well,
some of the CO2 becomes trapped in the small pores of the
rock, or is dissolved in the oil and water that is not recovered. The
CO2 that remains in the reservoir is not mobile and becomes
sequestered.
    The amount of CO2 used in an EOR project depends on the
volume and injectivity of the reservoir that is being flooded and the
length of time the EOR project has been in operation. Initially, all of
the injected CO2 is newly received. As discussed above, as
the project matures, some CO2 is recovered with the oil and
the recovered CO2 is separated from the oil and recycled so
that it can be re-injected into the reservoir in addition to new
CO2 that is received. If an EOR operator will not require
the full volume of CO2 available from an EGU, the EGU has
other options such as sending the CO2 to other EOR
operators, or sending it to deep saline formation GS facilities.
    CO2 used for EOR may come from anthropogenic or natural
sources. The source of the CO2 does not impact the
effectiveness of the EOR operation. CO2 capture, treatment
and processing steps provide a concentrated stream of CO2 in
order to meet the needs of the intended end use. CO2
pipeline specifications of the U.S. Department of Transportation
Pipeline Hazardous Materials Safety Administration found at 49 CFR part
195 (Transportation of Hazardous Liquids by Pipeline) apply regardless
of the source of the CO2 and take into account
CO2 composition, impurities, and phase behavior.
Additionally, EOR operators and transport companies have specifications
related to the composition of the CO2 stream. The regulatory
requirements and company specifications ensure EOR operators receive a
known and consistent CO2 stream.
    EOR has been successfully used at numerous production fields
throughout the United States to increase oil recovery. The oil industry
in the United States has over 40 years of experience with EOR. An oil
industry study in 2014 identified more than 125 EOR projects in 98
fields in the United States.\386\ More than half of the projects
evaluated in the study have been in operation for more than 10 years,
and many have been in operation for more than 30 years. This experience
provides a strong foundation for demonstrating successful
CO2 injection and monitoring technologies, which are needed
for safe and secure GS (see Section N below) that can be used for
deployment of CCS across geographically diverse areas.
---------------------------------------------------------------------------

    \386\ Koottungal, Leena, 2014, 2014 Worldwide EOR Survey, Oil &
Gas Journal, Volume 112, Issue 4, April 7, 2014 (corrected tables
appear in Volume 112, Issue 5, May 5, 2014).
---------------------------------------------------------------------------

    Currently, 12 states have active EOR operations and most have
developed an extensive CO2 infrastructure, including
pipelines, to support the continued operation and growth of EOR. An
additional 18 states are within 100 kilometers (62 miles) of current
EOR operations. See Figure 1 above. The vast majority of EOR is
conducted in oil reservoirs in the Permian Basin, which extends through
southwest Texas and southeast New Mexico. States where EOR is utilized
include Alabama, Colorado, Louisiana, Michigan,

Mississippi, New Mexico, Oklahoma, Texas, Utah, and Wyoming. Several
commenters raised concerns about the volume of CO2 used in
EOR projects relative to the scale of EGU emissions and the demand for
CO2 for EOR projects. At the project level, the volume of
CO2 already injected for EOR and the duration of operations
are of similar magnitude to the duration and volume of CO2
expected to be captured from fossil fuel-fired EGUs. The volume of
CO2 used in EOR operations can be large (e.g., 55 million
tons of CO2 were stored in the SACROC unit in the Permian
Basin over 35 years), and operations at a single oil field may last for
decades, injecting into multiple parts of the field.\387\ According to
data reported to the EPA's GHGRP, approximately 60 million metric tons
of CO2 were supplied to EOR in the United States in
2013.\388\ Approximately 70 percent of this total CO2
supplied was produced from natural (geologic) CO2 sources
and approximately 30 percent was captured from anthropogenic
sources.\389\
---------------------------------------------------------------------------

    \387\ Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F
P. ``Evaluation of CO2 trapping mechanisms at the SACROC
northern platform, Permian basin, Texas, site of 35 years of
CO2 injection.'' American Journal of Science 310. (2010):
282-324.
    \388\ Greenhouse Gas Reporting Program, data reported as of
August 18, 2014.
    \389\ Greenhouse Gas Reporting Program, data reported as of
August 18, 2014.
---------------------------------------------------------------------------

    A DOE-sponsored study has analyzed the geographic availability of
applying EOR in 11 major oil producing regions of the United States and
found that there is an opportunity to significantly increase the
application of EOR to areas outside of current operations.\390\ DOE-
sponsored geologic and engineering analyses show that expanding EOR
operations into areas additional to the capacity already identified and
applying new methods and techniques over the next 20 years could
utilize 18 billion metric tons of anthropogenic CO2 and
increase total oil production by 67 billion barrels. The study found
that one of the limitations to expanding CO2 use in EOR is
the lack of availability of CO2 in areas where reservoirs
are most amenable to CO2 flooding.\391\ DOE's Carbon
Utilization and Storage Atlas identifies 29 states with oil reservoirs
amenable to EOR, 12 of which currently have active EOR operations. A
comparison of the current states with EOR operations and the states
with potential for EOR shows that an opportunity exists to expand the
use of EOR to regions outside of current areas. The availability of
anthropogenic CO2 in areas outside of current sources could
drive new EOR projects by making more CO2 locally available.
---------------------------------------------------------------------------

    \390\ ``Improving Domestic Energy Security and Lowering
CO2 Emissions with ``Next Generation'' CO2-
Enhanced Oil Recovery'', Advanced Resources International, Inc.
(ARI), 2011. Available at: http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-04a505a19185.
    \391\ ``Improving Domestic Energy Security and Lowering
CO2 Emissions with ``Next Generation'' CO2-
Enhanced Oil Recovery'', Advanced Resources International, Inc.
(ARI), 2011. Available at: http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-04a505a19185.
---------------------------------------------------------------------------

    Some commenters raised concerns that data are extremely limited on
the extent to which EOR operations permanently sequester
CO2, and the efficacy of long term storage, or that the EOR
industry does not have the requisite experience with and technical
knowledge of long-term CO2 sequestration. The EPA disagrees
with these commenters. Several EOR sites, which have been operated for
years to decades, have been studied to evaluate the viability of safe
and secure long-term sequestration of injected CO2. Examples
are identified below.
    CO2 has been injected in the SACROC Unit in the Permian
basin since 1972 for EOR purposes. One study evaluated a portion of
this project, and estimated that the injection operations resulted in
final sequestration of about 55 million tons of CO2.\392\
This study used modeling and simulations, along with collection and
analysis of seismic surveys, and well logging data, to evaluate the
ongoing and potential CO2 trapping occurring through various
mechanisms. The monitoring at this site demonstrated that
CO2 can become trapped in geologic formations. In a separate
study in the SACROC Unit, the Texas Bureau of Economic Geology
conducted an extensive groundwater sampling program to look for
evidence of CO2 leakage in the shallow freshwater aquifers.
No evidence of leakage was detected.\393\
---------------------------------------------------------------------------

    \392\ Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F
P. ``Evaluation of CO2 trapping mechanisms at the SACROC
northern platform, Permian basin, Texas, site of 35 years of
CO2 injection.'' American Journal of Science 310. (2010):
282-324.
    \393\ Romanak, K.D., Smyth, R.C., Yang, C., and Hovorka, S.,
Detection of anthropogenic CO2 in dilute groundwater:
field observations and geochemical modeling of the Dockum aquifer at
the SACROC oilfield, West Texas, USA: presented at the 9th Annual
Conference on Carbon Capture & Sequestration, Pittsburgh, PA, May
10-13, 2010. GCCC Digital Publication Series #10-06.
---------------------------------------------------------------------------

    The International Energy Agency Greenhouse Gas Programme conducted
an extensive monitoring program at the Weyburn oil field in
Saskatchewan between 2000 and 2010 (the site receiving CO2
captured by the Dakota Gasification synfuel plant discussed in Section
V.E.2.a above). During that time over 16 million metric tons of
CO2 were safely sequestered as evidenced by soil gas
surveys, shallow groundwater monitoring, seismic surveys and wellbore
integrity testing. An extensive shallow groundwater monitoring program
revealed no significant changes in water chemistry that could be
attributed to CO2 storage operations.\394\ The International
Energy Agency Greenhouse Gas Programme developed a best practices
manual for CO2 monitoring at EOR sites based on the
comprehensive analysis of surface and subsurface monitoring methods
applied over the 10 years.\395\
---------------------------------------------------------------------------

    \394\ Roston, B., and S. Whittaker (2010), 10+ years of the IEA-
GHG Weyburn-Midale CO2 monitoring and storage project;
success and lessons learned from multiple hydrogeological
investigations, to be published in Energy Procedia, Elsevier,
Proceedings of 10th International Conference on Greenhouse Gas
Control Technologies, IEA Greenhouse Gas Programme, Amsterdam, The
Netherlands.
    \395\ Hitchon, B. (Editor), 2012, Best Practices for Validating
CO2 Geological Storage: Geoscience Publishing, p. 353.
---------------------------------------------------------------------------

    The Texas Bureau of Economic Geology also has been testing a wide
range of surface and subsurface monitoring tools and approaches to
document sequestration efficiency and sequestration permanence at the
Cranfield oilfield in Mississippi (see Section L.1 above).\396\ As part
of a DOE Southeast Regional Carbon Sequestration Partnership study,
Denbury Resources injected CO2 into a depleted oil and gas
reservoir at a rate greater than 1.2 million tons/year. Texas Bureau of
Economic Geology is currently evaluating the results of several
monitoring techniques employed at the Cranfield project and preliminary
findings indicate no impact to groundwater.\397\ The project also
demonstrates the availability and effectiveness of many different
monitoring techniques for tracking CO2 underground and
detecting CO2 leakage to ensure CO2 remains
safely sequestered.
---------------------------------------------------------------------------

    \396\ http://www.beg.utexas.edu/gccc/cranfield.php.
    \397\ http://www.beg.utexas.edu/gccc/cranfield.php.
---------------------------------------------------------------------------

    As discussed in Section M.1 above and as shown in Figure 1, the
United States has widespread potential for storage, including in deep
saline formations and oil and gas formations. However, some commenters
maintained that the EPA's information regarding availability of GS
sites is overly general and ignores important individual
considerations. A number of commenters, for example, maintained that
site conditions often make monitoring difficult or impossible, so

that sites are not available as a practical matter.\398\ Commenter
American Electric Power pointed to its own experience in siting
monitoring wells for its pilot plant Mountaineer CCS project, which
involved protracted time and expense to eventually site monitoring
wells.\399\ Other commenters noted significant geographic disparity in
GS site availability, claiming absence of sites in southeastern areas
of the country.\400\
---------------------------------------------------------------------------

    \398\ Comments of Southern Co., p. 38 (Docket entry: EPA-HQ-OAR-
2013-0495-10095).
    \399\ Comments of AEP pp. 93, 96 (Docket entry: EPA-HQ-OAR-2013-
0495-10618).
    \400\ Comments of Duke Energy, pp. 24-5 Docket entry: EPA-HQ-
OAR-2013-0495-9426); UARG, pp. 53, 57 (Docket entry: EPA-HQ-OAR-
2013-0495-9666) citing Cichanowicz (2012).
---------------------------------------------------------------------------

    Project- and site-specific factors do influence where
CO2 can be safely sequestered. However, as outlined above,
there is widespread potential for GS in the United States. If an area
does not have a suitable GS site, EGUs can either transport
CO2 to GS sites via CO2 pipelines (see Section
M.5 below), or they may choose to locate their units closer to GS sites
and provide electric power to customers through transmission lines (see
Figure 2 and Section M.7). In addition, there are alternative means of
complying with the final standards of performance that do not
necessitate use of partial CCS, so any siting difficulties based on
lack of a CO2 repository would be obviated. See Portland
Cement Ass'n v. EPA, 665 F. 3d 177, 191 (D.C. Cir. 2011), holding that
the EPA could adopt section 111 standards of performance based on the
performance of a kiln type that kilns of older design would have great
difficulty satisfying, since, among other things, there were
alternative methods of compliance available should a new kiln of this
older design be built.
4. Alternatives to Geologic Sequestration
    Potential alternatives to sequestering CO2 in geologic
formations are emerging. These relatively new potential alternatives
may offer the opportunity to offset the cost of CO2 capture.
For example, captured anthropogenic CO2 may be stored in
solid carbonate materials such as precipitated calcium carbonate (PCC)
or magnesium or calcium carbonate, bauxite residue carbonation, and
certain types of cement through mineralization. PCC is produced through
a chemical reaction process that utilizes calcium oxide (quicklime),
water, and CO2. Likewise, the combination of magnesium oxide
and CO2 results in a precipitation reaction where the
CO2 becomes mineralized. The carbonate materials produced
can be tailored to optimize performance in specific industrial and
commercial applications. These carbonate materials have been used in
the construction industry and, more recently and innovatively, in
cement production processes to replace Portland cement.
    The Skyonics Skymine project, which opened its demonstration
project in October 2014, is an example of captured CO2 being
used in the production of carbonate products. This plant converts
CO2 into commercial products. It captures over 75,000 tons
of CO2 annually from a San Antonio, Texas, cement plant and
converts the CO2 into other products, including sodium
carbonate, sodium bicarbonate, hydrochloric acid and bleach.\401\
---------------------------------------------------------------------------

    \401\ http://skyonic.com/technologies/skymine.
---------------------------------------------------------------------------

    A few commenters suggested that CO2 utilization
technologies alternative to GS are being commercialized, and that these
should be included as compliance options for this rule. The rule
generally requires that captured CO2 be either injected on-
site for geologic sequestration or transferred offsite to a facility
reporting under 40 CFR subpart RR. The EPA does not believe that the
emerging technologies just discussed are sufficiently advanced to
unqualifiedly structure this final rule to allow for their use. Nor are
there plenary systems of regulatory control and GHG reporting for these
approaches, as there are for geologic sequestration. Nonetheless, as
stated above, these technologies not only show promise, but could
potentially be demonstrated to show permanent storage of
CO2.
    In the January 2014 proposal, the EPA noted that it would need to
adopt a mechanism to evaluate these alternative technologies before any
could be used in lieu of geologic sequestration. 79 FR at 1484. The EPA
is establishing such a mechanism in this final rule. See Sec.
60.5555(g). The rule provides for a case-by-case adjudication by the
EPA of applications seeking to demonstrate to the EPA that a non-
geologic sequestration technology would result in permanent confinement
of captured CO2 from an affected EGU. The criteria to be
addressed in the application, and evaluated by the EPA, are drawn from
CAA section 111(j), which provides an analogous mechanism for case-by-
case approval of innovative technological systems of continuous
emission reduction which have not been adequately demonstrated.
Applicants would need to demonstrate that the proposed technology would
operate effectively, and that captured CO2 would be
permanently stored. Applicants must also demonstrate that the proposed
technology will not cause or contribute to an unreasonable risk to
public health, welfare or safety. In evaluating applications, the EPA
may conduct tests itself or require the applicant to conduct testing in
support of its application. Any application would be publicly noticed,
and the EPA would solicit comment on the application and on intended
action the EPA might take. The EPA could also provide a conditional
approval of an application on operating results from a proscribed
period. The EPA could also terminate an approval, including a
termination based on operating results calling into question a
technology's effectiveness.
    As noted at proposal, given the unlikelihood of new coal-fired EGUs
being constructed, the EPA does not expect there to be many (if any)
applications for use of non-geologic sequestration technology. 79 FR at
1484.
5. Availability of Existing or Planned CO2 Pipelines
    CO2 pipelines are the most economical and efficient
method of transporting large quantities of CO2.\402\
CO2 has been transported via pipelines in the United States
for nearly 40 years. Over this time, the design, construction,
operation, and safety requirements for CO2 pipelines have
been proven, and the U.S. CO2 pipeline network has been
safely used and expanded. The Pipeline and Hazardous Materials Safety
Administration (PHMSA) reported that in 2013 there were 5,195 miles of
CO2 pipelines operating in the United States. This
represents a seven percent increase in CO2 pipeline miles
over the previous year and a 38 percent increase in CO2
pipeline miles since 2004.\403\
---------------------------------------------------------------------------

    \402\ Report of the Interagency Task Force on Carbon Capture and
Storage (August 2010), page 36.
    \403\ ``Annual Report Mileage for Hazardous Liquid or Carbon
Dioxide Systems'', U.S. Pipeline and Hazardous Materials Safety
Administration, March 2, 2015. Available at: http://www.phmsa.dot.gov/pipeline/library/data-stats.
---------------------------------------------------------------------------

    Some commenters argued that the existing CO2 pipeline
capacity is not adequate and that CO2 pipelines are not
available in a majority of the United States.
    The EPA does not agree. The CO2 pipeline network in the
United States has almost doubled in the past ten years in order to meet
growing demands for CO2 for EOR. CO2 transport
companies have recently proposed initiatives to expand the
CO2 pipeline network. Several hundred miles of dedicated
CO2 pipeline are under construction, planned, or proposed,
including

projects in Colorado, Louisiana, Montana, New Mexico, Texas, and
Wyoming.
    Examples are identified below.
    Kinder Morgan has reported several proposed pipeline projects
including the proposed expansion of the existing Cortez CO2
pipeline, crossing Colorado, New Mexico, and Texas, to increase the
CO2 transport capacity from 1.35 billion cubic feet per day
(Bcf/d) to 1.7 Bcf/d, to support the expansion of CO2
production capacity at the McElmo Dome production facility in Colorado.
The Cortez pipeline expansion is expected to be placed into service in
2015.\404\
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    \404\ ``Form 10-K: Annual Report Pursuant to Section 13 or 15(d)
of the Security and Exchange Act of 1934, For the Fiscal Year Ended
December 31, 2014'', Kinder Morgan, February 2015. Available at:
http://ir.kindermorgan.com/sites/kindermorgan.investorhq.businesswire.com/files/report/additional/KMI-2014-10K_Final.pdf.
---------------------------------------------------------------------------

    Denbury reported that the company utilized approximately 70 million
cubic feet per day of anthropogenic CO2 in 2013 and that an
additional approximately 115 million cubic feet per day of
anthropogenic CO2 may be utilized in the future from
currently planned or future construction of facilities and associated
pipelines in the Gulf Coast region.\405\ Denbury also initiated
transport of CO2 from a Wyoming natural gas processing plant
in 2013 and reported transporting approximately 22 million cubic feet
per day of CO2 in 2013 from that plant alone.\406\
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    \405\ ``2013 Annual Report'', Denbury, April 2014. Available at
http://www.denbury.com/files/doc_financials/2013/Denbury_Final_040814.pdf.
    \406\ ``CO2 Sources'', Denbury, 2015. Available at:
http://www.denbury.com/operations/rocky-mountain-region/co2-sources-and-pipelines/default.aspx.
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    Denbury completed the final section of the 325-mile Green Pipeline
for transporting CO2 from Donaldsonville, Louisiana, to EOR
oil fields in Texas.\407\ Denbury completed construction and commenced
operation of the 232-mile Greencore Pipeline in 2013; the Greencore
pipeline transports CO2 to EOR fields in Wyoming and
Montana.\408\
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    \407\ http://www.denbury.com/operations/gulf-coast-region/Pipelines/default.aspx.
    \408\ ``CO2 Pipelines'', Denbury, 2014. Available at:
http://www.denbury.com/operations/rocky-mountain-region/COsub2-sub-Pipelines/default.aspx.
---------------------------------------------------------------------------

    A project being constructed by NRG and JX Nippon Oil & Gas
Exploration (Petra Nova) would capture CO2 from a power
plant in Fort Bend County, Texas for transport to EOR sites in Jackson
County, Texas through an 82-mile CO2 pipeline.\409\ The
project is anticipated to commence operation in 2016.\410\
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    \409\ ``The West Ranch CO2-EOR Project, NRG Fact
Sheet'', NRG, 2014. Available at: www.nrg.com/documents/business/pla-2014-west-ranch-fact-sheet.pdf.
    \410\ ``WA Parish Carbon Capture Project'', NRG, 2015. Available
at: www.nrg.com/sustainability/strategy/enhance-generation/carbon-capture/wa-parish-ccs-project/.
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    Some commenters suggested that there may be challenges associated
with the safety of transporting supercritical CO2 over long
distances, or that the EPA did not adequately consider the potential
non-air environmental impacts of the construction of CO2
pipelines.
    The EPA has carefully evaluated the safety of pipelines used to
transport captured CO2 and determined that pipelines can
indeed convey captured CO2 to sequestration sites with
certainty and provide full protection of human health and the
environment. 76 FR at 48082-83 (Aug. 8, 2011); 79 FR 352, 354 (Jan. 3,
2014). Existing and new CO2 pipelines are comprehensively
regulated by the Department of Transportation's Pipeline Hazardous
Material Safety Administration. The regulations govern pipeline design,
construction, operation and maintenance, and emergency response
planning. See generally 49 CFR 195.2. Additional regulations address
pipeline integrity management by requiring heightened scrutiny to
assure the quality of pipeline integrity in areas with a higher
potential for adverse consequences. See 49 CFR 195.450 and 195.452. On-
site pipelines are not subject to the Department of Transportation
standards, but rather adhere to the Pressure Piping standards of the
American Society of Mechanical Engineers (ASME B31), which the EPA has
found would ensure that piping and associated equipment meet certain
quality and safety criteria sufficient to prevent releases of
CO2, such that certain additional requirements were not
necessary (See 79 FR 358-59 (Jan. 3, 2014)).\411\ These existing
controls over CO2 pipelines assure protective management,
guard against releases, and assure that captured CO2 will be
securely conveyed to a sequestration site.
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    \411\ See the B31 Code for pressure piping, developed by the
American Society of Mechanical Engineers, Pipeline Transportation
Systems for liquid hydrocarbons and other liquids.
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6. States With Emission Standards That Would Require CCS
    Several states have established emission performance standards or
other measures to limit emissions of GHGs from new EGUs that are
comparable to or more stringent than the final standard in this
rulemaking. For example, in September 2006, California Governor
Schwarzenegger signed into law Senate Bill 1368. The law limits long-
term investments in base load generation by the state's utilities to
power plants that meet an emissions performance standard jointly
established by the California Energy Commission and the California
Public Utilities Commission. The Energy Commission has designed
regulations that establish a standard for new and existing base load
generation owned by, or under long-term contract to publicly owned
utilities, of 1,100 lb CO2/MWh.
    In May 2007, Washington Governor Gregoire signed Substitute Senate
Bill 6001, which established statewide GHG emissions reduction goals,
and imposed an emission standard that applies to any base load electric
generation that commenced operation after June 1, 2008 and is located
in Washington, whether or not that generation serves load located
within the state. Base load generation facilities must initially comply
with an emission limit of 1,100 lb CO2/MWh.
    In July 2009, Oregon Governor Kulongoski signed Senate Bill 101,
which mandated that facilities generating base load electricity,
whether gas- or coal-fired, must have emissions equal to or less than
1,100 lb CO2/MWh, and prohibited utilities from entering
into long-term purchase agreements for base load electricity with out-
of-state facilities that do not meet that standard.
    In 2012 New York established emission standards of CO2
at 925 lb CO2/MWh for new and expanded base load fossil
fuel-fired plants.
    In May 2007, Montana Governor Schweitzer signed House Bill 25,
adopting a CO2 emissions performance standard for EGUs in
the state. House Bill 25 prohibits the state Public Utility Commission
from approving new EGUs primarily fueled by coal unless a minimum of 50
percent of the CO2 produced by the facility is captured and
sequestered.
    On January 12, 2009, Illinois Governor Blagojevich signed Senate
Bill 1987, the Clean Coal Portfolio Standard Law. The legislation
establishes emission standards for new power plants that use coal as
their primary feedstock. From 2009-2015, new coal-fueled power plants
must capture and store 50 percent of the carbon emissions that the
facility would otherwise emit; from 2016-2017, 70 percent must be
captured and stored; and after 2017, 90 percent must be captured and
stored.
7. Coal-by-Wire
    In addition, as discussed in the proposal, electricity demand in
states

that may not have geologic sequestration sites may be served by coal-
fired electricity generation built in nearby areas with geologic
sequestration, and this electricity can be delivered through
transmission lines. This method, known as ``coal-by-wire,'' has long
been used in the electricity sector because siting a coal-fired power
plant near the coal mine and transmitting the generation long distances
to the load area is generally less expensive than siting the plant near
the load area and shipping the coal long distances.
    For example, we noted in the proposal that there are many examples
where coal-fired power generated in one state is used to supply
electricity in other states. In the proposal we specifically noted that
historically nearly 40 percent of the power for the City of Los Angeles
was provided from two coal-fired power plants located in Arizona and
Utah and Idaho Power, which serves customers in Idaho and Eastern
Oregon, meets its demand in part from coal-fired power plants located
in Wyoming and Nevada. 79 FR at 1478.
    In the Technical Support Document on Geographic Availability
(Geographic Availability TSD), we explore in greater detail the issue
of coal-by-wire and the ability of demand in areas without geologic
sequestration to be served by coal generation located in areas that
have access to geologic sequestration. Figure 1 of this preamble (a
color version of which is provided as Figure 1 of the Geographic
Availability TSD) depicts areas of the country with: (1) existing
CO2 pipeline; (2) probable, planned, or under study
CO2 pipeline; (3) counties with active CO2-EOR
operations; (4) oil and natural gas reservoirs; (5) deep saline
formations; (6) unmineable coal seams; and (7) areas 100 kilometers
from geologic sequestration. As demonstrated by Figure 1, the vast
majority of the country has existing or planned CO2
pipeline, active CO2-EOR operations, the necessary geology
for CO2 storage, or is within 100 kilometers of areas with
geologic sequestration.\412\ A review of Figure 1 indicates limited
areas that do not fall into these categories.
---------------------------------------------------------------------------

    \412\ The NETL cost estimates for CO2 transport
assume a pipeline of 100 kilometers. NETL (2015) at p. 44.
---------------------------------------------------------------------------

    As an initial matter, we note that the data included in Figure 1 is
a conservative outlook of potential areas available for the development
of CO2 storage in that we include only areas that have been
assessed to date. Portions of the United States--such as the State of
Minnesota--have not yet been assessed and thus are depicted as not
having geological formations suitable for CO2 storage, even
though assessment could in fact reveal additional formations.\413\
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    \413\ The data in Figure 1 is based on estimates compiled by the
DOE's National Carbon Sequestration Database and Geographic
Information System (NATCARB) and published in the United States 2012
Carbon Utilization and Storage Atlas, Fourth Edition. As discussed
in the TSD, deep saline formation potential was not assessed for
Alaska, Connecticut, Hawaii, Massachusetts, Nevada, Rhode Island,
and Vermont. Oil and gas storage potential was not assessed for
Alaska, Washington, Nevada, and Oregon. Unmineable coal seams were
not assessed for Nevada, Oregon, California, Idaho, and New York. We
are assuming for purposes of our analysis here that they do not have
storage potential in those formations.
---------------------------------------------------------------------------

    As one considers the areas on the map depicted in Figure 1 that
fall outside of the above enumerated categories, in many instances, we
find areas with low population density, areas that are already served
by transmission lines that could deliver coal-by-wire, and/or areas
that have made policy or other decisions not to pursue a resource mix
that includes coal. In many of these areas, utilities, electric
cooperatives, and municipalities have a history of joint ownership of
coal-fired generation outside the region or contracting with coal and
other generation in outside areas to meet their demand. Some of the
relevant areas are in RTOs \414\ which engage in planning across the
RTO, balancing supply and demand in real time throughout the RTO.
Accordingly, generating resources in one part of the RTO such as a coal
generator can serve load in other parts of the RTO, as well as load
outside of the RTO. As we consider each of these geographic areas in
the Geographic Availability TSD, we make key points as to why this
final rule does not negatively impact the ability of these regions to
access new coal generation to the extent that coal is needed to supply
demand and/or those regions want to include new coal-fired generation
in their resource mix.
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    \414\ In this discussion, we use the term RTO to indicate both
ISOs and RTOs.
---------------------------------------------------------------------------

N. Final Requirements for Disposition of Captured CO2

    This section discusses the different regulatory components, already
in place, that assure the safety and effectiveness of GS. This section,
by demonstrating that GS is already covered by an effective regulatory
structure, complements the analysis of the technical feasibility of GS
contained in Sec. V.M. Together, these sections affirm that the
technical feasibility of GS is adequately demonstrated.
    In 2010, the EPA finalized an effective and coherent regulatory
framework to ensure the long-term, secure and safe storage of large
volumes of CO2. The EPA developed these Underground
Injection Control (UIC) Class VI well regulations under authority of
the Safe Drinking Water Act (SDWA) to facilitate injection of
CO2 for GS, while protecting human health and the
environment by ensuring the protection of underground sources of
drinking water (USDWs). The Class VI regulations are built upon 35
years of federal experience regulating underground injection wells, and
many additional years of state UIC program expertise. The EPA and
states have decades of UIC experience with the Class II program, which
provides a regulatory framework for the protection of USDWs for
CO2 injected for purposes of EOR.
    In addition, to complement both the Class VI and Class II rules,
the EPA used CAA authority to develop air-side monitoring and reporting
requirements for CO2 capture, underground injection, and
geologic sequestration through the GHGRP. Information collected under
the GHGRP provides a transparent means for the EPA and the public to
continue to evaluate the effectiveness of GS.
    As explained below, these requirements help ensure that sequestered
CO2 will remain in place, and, using SDWA and CAA
authorities, provide the monitoring mechanisms to identify and address
potential leakage. We note the near consensus in the public responses
to the Class VI rulemaking that saline and oil and gas reservoirs
provide ready means for secure GS of CO2.\415\
---------------------------------------------------------------------------

    \415\ In that rulemaking, we stated that ``most commenters
encouraged the EPA not to automatically exclude any potential
injection formations for GS at this stage of deployment.'' We added
that commenters suggested, in particular, ``that there is sufficient
technical basis and scientific evidence to allow GS in depleted oil
and gas reservoirs and in saline formations, noting that there is
consensus on how to inject into these formation types.'' 75 FR at
77252 (Dec. 10, 2010).
---------------------------------------------------------------------------

1. Requirements for UIC Class VI and Class II Wells
    Under SDWA, the EPA developed the UIC Program to regulate the
underground injection of fluids in a manner that ensures protection of
USDWs. UIC regulations establish six different well classes that manage
a range of injectates (e.g., industrial and municipal wastes; fluids
associated with oil and gas activities; solution mining fluids; and
CO2 for geologic sequestration) and which accommodate
varying geologic, hydrogeological, and other conditions. The standards
apply to injection into any type of formation that meets the rule's
rigorous criteria, and so apply not only to injection into deep

saline formations, but also can apply to injection into unmineable coal
seams and other formations. See 75 FR 77256 (Dec. 10, 2010).
    The EPA's UIC regulations define the term USDWs to include current
and future sources of drinking water and aquifers that contain a
sufficient quantity of ground water to supply a public water system,
where formation fluids either are currently being used for human
consumption or that contain less than 10,000 ppm total dissolved
solids.\416\ UIC requirements have been in place for over three decades
and have been used by the EPA and states to manage hundreds of
thousands of injection wells nationwide.
---------------------------------------------------------------------------

    \416\ 40 CFR 144.3.
---------------------------------------------------------------------------

a. Class VI Requirements
    In 2010, the EPA established a new class of well, Class VI. Class
VI wells are used to inject CO2 into the subsurface for the
purpose of long-term sequestration. See 75 FR 77230 (Dec. 10, 2010).
This rule accounts for the unique nature of CO2 injection
for large-scale GS. Specifically, the EPA addressed the unique
characteristics of CO2 injection for GS including the large
CO2 injection volumes anticipated at GS projects, relative
buoyancy of CO2, its mobility within subsurface geologic
formations, and its corrosivity in the presence of water. The UIC Class
VI rule was developed to facilitate GS and ensure protection of USDWs
from the particular risks that may be posed by large scale
CO2 injection for purposes of long-term GS. The Class VI
rule establishes technical requirements for the permitting, geologic
site characterization, area of review (i.e., the project area) and
corrective action, well construction, operation, mechanical integrity
testing, monitoring, well plugging, post-injection site care, site
closure, and financial responsibility for the purpose of protecting
USDWs.\417\ Notably:
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    \417\ The Class VI rule rests on a robust technical and
scientific foundation, reflecting scientific oversight and peer
review. In developing these Class VI rules, the EPA engaged with the
SAB, providing detailed information on key issues relating to
geologic sequestration--including monitoring schemes; methods to
predict and verify capacity, injectivity, and effectiveness of
subsurface CO2 storage; and characterization and
management of risks associated with plume migration and pressure
increases in the subsurface. See: http://yosemite.epa.gov/sab/sabproduct.nsf/0/AD09B42B75D9E36D85257704004882CF?OpenDocument. In
addition, the EPA developed a peer reviewed Vulnerability Evaluation
Framework, which served as a technical support document for both the
Class VI and Subpart RR rules. See: http://www.epa.gov/climatechange/Downloads/ghgemissions/VEF-Technical_Document_072408.pdf. In the section 111(b) rulemaking
here, the SAB Work Group, in a letter endorsed by the full SAB
Committee, found that ``while the scientific and technical basis for
carbon storage provisions is new and emerging science, the agency is
using the best available science and has conducted peer review at a
level required by agency guidance.'' Memorandum of Jan. 7, 2014,
from SAB Work Group Chair to Members of the Chartered SAB and SAB
Liaisons, p. 3. The letter was subsequently endorsed by the full
SAB. Work Group Letter of Jan. 24, 2014, as edited by the full
Committee.
---------------------------------------------------------------------------

    Site characterization includes assessment of the geologic,
hydrogeologic, geochemical, and geomechanical properties of a proposed
GS site to ensure that Class VI wells are sited in appropriate
locations and CO2 streams are injected into suitable
formations with a confining zone or zones free of transmissive faults
or fractures to ensure USDW protection.418 419 Site
characterization is designed to eliminate unacceptable sites that may
pose risks to USDWs. Generally, injection of CO2 for GS
should occur beneath the lowermost formation containing a USDW.\420\ To
increase the availability of Class VI sites in geographic areas with
very deep USDWs, waivers from the injection depth requirements may be
sought where owners or operators can demonstrate USDW protection.\421\
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    \418\ 75 FR 77240 and 75 FR 77247 (December 10, 2010).
    \419\ 40 CFR 146.82 and 146.83. Comments indicating that EPA
rules have not considered issues of exposure pathways such as
abandoned wells or formation fissures are mistaken. (See, e.g.,
Comments of UARG, p. 52 (Docket entry: EPA-HQ-OAR-2013-0495-9666).)
    \420\ 40 CFR 146.81(d).
    \421\ 40 CFR 146.95.
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    Owners or operators of Class VI wells must delineate the project
area of review using computational modeling that accounts for the
physical and chemical properties of the injected CO2 and
displaced fluids and is based on an iterative process of available site
characterization, monitoring, and operational data.\422\ Within the
area of review, owners or operators must identify and evaluate all
artificial penetrations to identify those that need corrective action
to prevent the movement of CO2 or other fluids into or
between USDWs.423 424 Due to the potentially large size of
the area of review for Class VI wells, corrective actions may be
conducted on a phased basis during the lifetime of the project.\425\
Periodic reevaluation of the area of review is required and enables
owners or operators to incorporate previously collected monitoring and
operational data to verify that the CO2 plume and the
associated area of elevated pressure are moving as predicted within the
subsurface.\426\
---------------------------------------------------------------------------

    \422\ 40 CFR 146.84(a).
    \423\ 40 CFR 146.84(c)(1)(3) and 146.90(d)(1).
    \424\ 40 CFR 146.81(d) and 146.84.
    \425\ 40 CFR 146.84(b)(2)(iv).
    \426\ 40 CFR 146.84(e)(1).
---------------------------------------------------------------------------

    Well construction must use materials that can withstand contact
with CO2 over the operational and post-injection life of the
project.\427\ These requirements address the unique physical
characteristics of CO2, including its buoyancy relative to
other fluids in the subsurface and its potential corrosivity in the
presence of water.
---------------------------------------------------------------------------

    \427\ 40 CFR 146.86(b).
---------------------------------------------------------------------------

    Requirements for operation of Class VI injection wells account for
the unique conditions that will occur during large-scale GS including
buoyancy, corrosivity, and high sustained pressures over long periods
of operation.428 429
---------------------------------------------------------------------------

    \428\ 75 FR 77250-52 (December 10, 2010); see also id. at 77234-
35. Commenters were mistaken in asserting (without reference to
Class VI provisions) that the EPA had ignored issues relating to
CO2 properties when injected in large volumes in
supercritical state into geologic formations.
    \429\ 40 CFR 146.88.
---------------------------------------------------------------------------

    Owners or operators of Class VI wells must develop and implement a
comprehensive testing and monitoring plan for their projects that
includes injectate analysis, mechanical integrity testing, corrosion
monitoring, ground water and geochemical monitoring, pressure fall-off
testing, CO2 plume and pressure front monitoring and
tracking, and, at the discretion of the Class VI director, surface air
and/or soil gas monitoring.\430\ Owners and operators must periodically
review the testing and monitoring plan to incorporate operational and
monitoring data and the most recent area of review reevaluation.\431\
Robust monitoring of the CO2 stream, injection pressures,
integrity of the injection well, ground water quality and geochemistry,
and monitoring of the CO2 plume and position of the pressure
front throughout injection will ensure protection of USDWs from
endangerment, preserve water quality, and allow for timely detection of
any leakage of CO2 or displaced formation fluids.
---------------------------------------------------------------------------

    \430\ 40 CFR 146.90.
    \431\ 40 CFR 146.90(j).
---------------------------------------------------------------------------

    Although subsurface monitoring is the primary and effective means
of determining if there are any risks to a USDW, the Class VI rule also
authorizes the UIC Program Director to require surface air and/or soil
gas monitoring on a site-specific basis. For example, the Class VI
Director may require surface air/soil gas monitoring of the flux of
CO2 out of the subsurface, with elevation of CO2
levels above background serving as

an indicator of potential leakage and USDW endangerment.\432\
---------------------------------------------------------------------------

    \432\ 40 CFR 146.90(h)(1) and 75 FR at 77259 (Dec. 10, 2010).
---------------------------------------------------------------------------

    Class VI well owners or operators must develop and update a site-
specific, comprehensive emergency and remedial response plan that
describes actions to be taken (e.g., cease injection) to address
potential events that may cause endangerment to a USDW during the
construction, operation, and post-injection site care periods of the
project.\433\
---------------------------------------------------------------------------

    \433\ 40 CFR 146.94.
---------------------------------------------------------------------------

    Financial responsibility demonstrations are required to ensure that
funds will be available for all area of review corrective action,
injection well plugging, post-injection site care, site closure, and
emergency and remedial response.\434\
---------------------------------------------------------------------------

    \434\ 40 CFR 146.85.
---------------------------------------------------------------------------

    Following cessation of injection, the operator must conduct
comprehensive post-injection site care activities to show the position
of the CO2 plume and the associated area of elevated
pressure to demonstrate that neither poses an endangerment to
USDWs.\435\ The injection well also must be plugged, and following a
demonstration of non-endangerment of USDWs by the Class VI owner or
operator, the site must be closed.436 437 The default
duration for the post-injection site care period is 50 years, with
flexibility for demonstrating that an alternative period is appropriate
if it ensures non-endangerment of USDWs.\438\ Following successful
closure, the facility property deed must record that the underlying
land is used for GS.\439\
---------------------------------------------------------------------------

    \435\ 40 CFR 146.93.
    \436\ 40 CFR 146.92.
    \437\ 40 CFR 146.93.
    \438\ 40 CFR 146.93(b).
    \439\ 40 CFR 146.93(c).
---------------------------------------------------------------------------

    The EPA has completed technical guidance documents on Class VI well
site characterization, area of review and corrective action, well
testing and monitoring, project plan development, well construction,
and financial responsibility.440 441 442 443 444 445 The EPA
has also issued guidance documents on transitioning Class II wells to
Class VI wells; well plugging, post-injection site care, and site
closure; and recordkeeping, reporting, and data
management.446 447 448 449
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    \440\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r13004.pdf.
    \441\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r13005.pdf.
    \442\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r13001.pdf.
    \443\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r11017.pdf.
    \444\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r11020.pdf.
    \445\ http://water.epa.gov/type/groundwater/uic/class6/upload/uicfinancialresponsibilityguidancefinal072011v.pdf.
    \446\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13004.pdf. See also 40 CFR 144.19 and ``Key Principles in
EPA's Underground Injection Control Program Class VI Rule Related to
Transition of Class II Enhanced Oil Recovery or Gas Recovery Wells
to Class VI'', April 23, 2015, Available at: http://water.epa.gov/type/groundwater/uic/class6/upload/class2eorclass6memo.pdf.
    \447\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13005.pdf.
    \448\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13001.pdf.
    \449\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13002.pdf.
---------------------------------------------------------------------------

    To inform the development of the UIC Class VI rule, the EPA
solicited stakeholder input and reviewed ongoing domestic and
international GS research, demonstration, and deployment projects. The
EPA also leveraged injection experience of the UIC Program, such as
injection via Class II wells for EOR. A description of the work
conducted by the EPA in support of the UIC Class VI rule can be found
in the preamble for the final rule (see 75 FR 77230 and 77237-
240(December 10, 2010)).
    The EPA has issued Class VI permits for six wells under two
projects. In September 2014, a UIC Class VI injection well permit (to
construct) was issued by the EPA to Archer Daniels Midland for an
ethanol facility in Decatur, Illinois. The goal of the project is to
demonstrate the ability of the Mount Simon geologic formation, a deep
saline formation, to accept and retain industrial scale volumes of
CO2 for permanent GS. The permitted well has a projected
operational period of five years, during which time 5.5 million metric
tons of CO2 will be injected into an area of review with a
radius of approximately 2 miles.\450\ Following the operational period,
Archer Daniels Midland plans a post-injection site care period of ten
years.\451\ In September 2014, the EPA also issued four Class VI
injection well permits (to construct) to the FutureGen Industrial
Alliance project in Jacksonville, Illinois, which proposed to capture
CO2 emissions from a coal-fired power plant in Meredosia,
Illinois and transport the CO2 by pipeline approximately 30
miles to the deep saline GS site.\452\ The Alliance proposed to inject
a total of 22 million metric tons of CO2 into an area of
review with a radius of approximately 24 miles over the 20-year life of
the project, with a post-injection site care period of fifty
years.\453\
---------------------------------------------------------------------------

    \450\ http://www.epa.gov/region5/water/uic/adm/. In addition,
Archer Daniels Midland received a UIC Class VI injection well permit
for a second well in December 2014. Archer Daniels Midland had been
injecting CO2 at this well since 2011 under a UIC Class I
permit issued by the Illinois EPA.
    \451\ http://www.epa.gov/region5/water/uic/adm/.
    \452\ After permit issuance, and for reasons unrelated to the
permitting proceeding, DOE initiated a structured closeout of
federal support for the FutureGen project in February 2015. However,
these are still active Class VI permits.
    \453\ http://www.epa.gov/r5water/uic/futuregen/.
---------------------------------------------------------------------------

    Both permit applicants addressed siting and operational aspects of
GS (including issues relating to volumes of the CO2 and
nature of the CO2 injectate), and included monitoring that
helps provide assurance that CO2 will not migrate to
shallower formations. The permits were based on findings that regional
and local features at the site allow the site to receive injected
CO2 in specified amounts without buildup of pressure which
would create faults or fractures, and further, that monitoring provides
early warning of any changes to groundwater or CO2
leakage.\454\
---------------------------------------------------------------------------

    \454\ http://www.epa.gov/r5water/uic/futuregen/; http://www.epa.gov/region5/water/uic/adm/.
---------------------------------------------------------------------------

    The permitting of these projects illustrates that permit applicants
were able to address perceived challenges to issuance of Class VI
permits. These permits demonstrate that these projects are capable of
safely and securely sequestering large volumes of CO2--
including from steam generating units--for long-term storage since the
EPA would not otherwise have issued the permits.
b. Class II Requirements
    As explained in Section M.3 above, CO2 has been injected
into the subsurface via injection wells for EOR, boosting production
efficiency by re-pressurizing oil and gas reservoirs and increasing the
mobility of oil. There are decades of industry experience in operating
EOR projects. The CO2 injection wells used for EOR are
regulated through the UIC Class II program.\455\ CO2 storage
associated with Class II wells is a common occurrence and
CO2 can be safely stored where injected through Class II-
permitted wells for the purpose of enhanced oil or gas-related
recovery.
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    \455\ 40 CFR 144.6(b).
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    UIC Class II regulations issued under section 1421 of SDWA provide
minimum federal requirements for site characterization, area of review,
well construction (e.g., casing and cementing), well operation (e.g.,
injection pressure), injectate sampling, mechanical integrity testing,
plugging and abandonment, financial responsibility, and reporting.
Class II wells must undergo periodic mechanical integrity testing which
will detect well construction and operational

conditions that could lead to loss of injectate and migration into
USDWs.
    Section 1425 of SDWA allows states to demonstrate that their
program is effective in preventing endangerment of USDWs. These
programs must include permitting, inspection, monitoring, record-
keeping, and reporting components.
2. Relevant Requirements of the GHGRP
    The GHGRP requires reporting of facility-level GHG data and other
relevant information from large sources and suppliers in the United
States. The final rules under 40 CFR part 60 specifically require that
if an affected EGU captures CO2 to meet the applicable
emissions limit, the EGU must report in accordance with 40 CFR part 98,
subpart PP (Suppliers of Carbon Dioxide) and the captured
CO2 must be injected at a facility or facilities that
reports in accordance with 40 CFR part 98, subpart RR (Geologic
Sequestration of Carbon Dioxide). See Sec.  60.5555(f). Taken together,
these requirements ensure that the amount of captured and sequestered
CO2 will be tracked as appropriate at project- and national-
levels, and that the status of the CO2 in its sequestration
site will be monitored, including air-side monitoring and reporting.
    Specifically, subpart PP provides requirements to account for
CO2 supplied to the economy. This subpart requires affected
facilities with production process units that capture a CO2
stream for purposes of supplying CO2 for commercial
applications or that capture and maintain custody of a CO2
stream in order to sequester or otherwise inject it underground to
report the mass of CO2 captured and supplied to the
economy.\456\ CO2 suppliers are required to report the
annual quantity of CO2 transferred offsite and its end use,
including GS.\457\
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    \456\ 40 CFR 98.420(a)(1).
    \457\ 40 CFR 98.426.
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    This rule finalizes amendments to subpart PP reporting
requirements, specifically requiring that the following pieces of
information be reported: (1) the electronic GHG Reporting Tool
identification (e-GGRT ID) of the EGU facility from which
CO2 was captured, and (2) the e-GGRT ID(s) for, and mass of
CO2 transferred to, each GS site reporting under subpart
RR.\458\
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    \458\ 40 CFR 98.426(h).
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    As noted, this final rule also requires that any affected EGU unit
that captures CO2 to meet the applicable emissions limit
must transfer the captured CO2 to a facility that reports
under GHGRP subpart RR. In order to provide clarity on this
requirement, the EPA reworded the proposed language under Sec.
60.5555(f) to use the phrase ``If your affected unit captures
CO2'' in place of the phrase ``If your affected unit employs
geologic sequestration''. This revision is not a change from the EPA's
initial intent.
    Reporting under subpart RR is required for all facilities that have
received a Class VI UIC permit for injection of CO2.\459\
Subpart RR requires facilities meeting the source category definition
(40 CFR 98.440) for any well or group of wells to report basic
information on the mass of CO2 received for injection;
develop and implement an EPA-approved monitoring, reporting, and
verification (MRV) plan; report the mass of CO2 sequestered
using a mass balance approach; and report annual monitoring
activities.460 461 462 463 Although deep subsurface
monitoring is the primary and effective means of determining if there
are any leaks to a USDW, the monitoring employed under a subpart RR MRV
Plan can be utilized, if required by the UIC Program Director, to
further ensure protection of USDWs.\464\ The subpart RR MRV plan
includes five major components:
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    \459\ 40 CFR 98.440.
    \460\ 40 CFR 98.446.
    \461\ 40 CFR 98.448.
    \462\ 40 CFR 98.446(f)(9) and (10).
    \463\ 40 CFR 98.446(f)(12).
    \464\ See 75 FR at 77263 (Dec. 10, 2010).
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    A delineation of monitoring areas based on the CO2 plume
location. Monitoring may be phased in over time.\465\
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    \465\ 40 CFR 98.448(a)(1).
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    An identification and evaluation of the potential surface leakage
pathways and an assessment of the likelihood, magnitude, and timing, of
surface leakage of CO2 through these pathways. The
monitoring program will be designed to address the risks
identified.\466\
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    \466\ 40 CFR 98.448(a)(2).
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    A strategy for detecting and quantifying any surface leakage of
CO2 in the event leakage occurs. Multiple monitoring methods
and accounting techniques can be used to address changes in plume size
and risks over time.\467\
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    \467\ 40 CFR 98.448(a)(3).
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    An approach for establishing the expected baselines for monitoring
CO2 surface leakage. Baseline data represent pre-injection
site conditions and are used to identify potential anomalies in
monitoring data.\468\
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    \468\ 40 CFR 98.448(a)(4).
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    A summary of considerations made to calculate site-specific
variables for the mass balance equation. Site-specific variables may
include calculating CO2 emissions from equipment leaks and
vented emissions of CO2 from surface equipment, and
considerations for calculating CO2 from produced
fluids.\469\
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    \469\ 40 CFR 98.448(a)(5).
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    Subpart RR provides a nationally consistent mass balance framework
for reporting the mass of CO2 that is sequestered. Certain
monitoring and operational data for a GS site is required to be
reported to the EPA annually. More information on the MRV plan and
annual reporting is available in the subpart RR final rule (75 FR
75065; December 1, 2010) and its associated technical support
document.\470\
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    \470\ Technical Support Document: ``General Technical Support
Document for Injection and Geologic Sequestration of Carbon Dioxide:
Subparts RR and UU'' (Docket EPA-HQ-OAR-2009-0926), November 2010.
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    Under this final rule, any well receiving CO2 captured
from an affected EGU, be it a Class VI or Class II well, must report
under subpart RR.\471\ As explained below in Section V.N.5.a, a Class
II well's UIC regulatory status does not change because it receives
such CO2. Nor does it change by virtue of reporting under
subpart RR.
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    \471\ See Sec.  60.5555(f).
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3. UIC and GHGRP Rules Provide Assurance To Prevent, Monitor, and
Address Releases of Sequestered CO2 to Air
    Together the requirements of the UIC and GHGRP programs help ensure
that sequestered CO2 will remain secure, and provide the
monitoring mechanisms to identify and address potential leakage using
SDWA and CAA authorities. The EPA designed the GHGRP subpart RR
requirements for GS with consideration of UIC requirements. The
monitoring required by GHGRP subpart RR is complementary to and builds
on UIC monitoring and testing requirements. 75 FR 77263. Although the
regulations for Class VI and Class II injection wells are designed to
ensure protection of USDWs from endangerment the practical effect of
these complementary technical requirements, as explained below, is that
they also prevent releases of CO2 to the atmosphere.
    The UIC and GHGRP programs are built upon an understanding of the
mechanisms by which CO2 is retained in geologic formations,
which are well understood and proven.
    Structural and stratigraphic trapping is a physical trapping
mechanism that occurs when the CO2 reaches a stratigraphic
zone with low permeability (i.e., geologic confining

system) that prevents further upward migration.
    Residual trapping is a physical trapping mechanism that occurs as
residual CO2 is immobilized in formation pore spaces as
disconnected droplets or bubbles at the trailing edge of the plume due
to capillary forces.
    Adsorption trapping is another physical trapping mechanism that
occurs when CO2 molecules attach to the surfaces of coal and
certain organic rich shales, displacing other molecules such as
methane.
    Solubility trapping is a geochemical trapping mechanism where a
portion of the CO2 from the pure fluid phase dissolves into
native ground water and hydrocarbons.
    Mineral trapping is a geochemical trapping mechanism that occurs
when chemical reactions between the dissolved CO2 and
minerals in the formation lead to the precipitation of solid carbonate
minerals.
a. Class VI Wells
    As just discussed in Section V.N.1, the UIC Class VI rule provides
a framework to ensure the safety of underground injection of
CO2 such that USDWs are not endangered. As explained below,
protection against releases to USDWs likewise assures against releases
to ambient air. Through the injection well permit application process,
the Class VI permit applicant (i.e., a prospective Class VI well owner
or operator) must demonstrate that the injected CO2 will be
trapped and retained in the geologic formation, and not migrate out of
the injection zone or the approved project area (i.e., the area of
review). To assure that CO2 is confined within the injection
zone, major components to be considered and included in Class VI
permits are site characterization, area of review delineation and
corrective action, well construction and operation, testing and
monitoring, financial responsibility, post-injection site care, well
plugging, emergency and remedial response, and site closure as
described in Section V.N.1.
    Site characterization provides the foundation for successful GS
projects. It includes evaluation of the chemical and physical
mechanisms that will occur in the subsurface to immobilize and securely
store the CO2 within the injection zone over the long-term
(see above). Site characterization requires a detailed assessment of
the geologic, hydrogeologic, geochemical, and geomechanical properties
of the proposed GS site to ensure that wells are sited in suitable
locations.\472\ Data and information collected during site
characterization are used in the development of injection well
construction and operating plans; provide inputs for modeling the
extent of the injected CO2 plume and related pressure front;
and establish baseline information to which geochemical, geophysical,
and hydrogeologic site monitoring data collected over the life of the
injection project can be compared.
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    \472\ 40 CFR 146.82(a) and (c).
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    The Class VI rules contain rigorous subsurface monitoring
requirements to assure that the chosen site is functioning as
characterized. This subsurface monitoring should detect leakage of
CO2 before CO2 would reach the atmosphere. For
example, when USDWs are present, they are generally located above the
injection zone. If CO2 were to reach a USDW prior to being
released to the atmosphere, the presence of CO2 or
geochemical changes that would be caused by CO2 migration
into unauthorized zones would be detected by a UIC Class VI monitoring
program that is approved and periodically evaluated/adjusted based on
permit conditions.
    Likewise, UIC Class VI mechanical integrity testing requirements
are designed to confirm that a well maintains internal and external
mechanical integrity. Continuous monitoring of the internal mechanical
integrity of Class VI wells ensures that injection wells maintain
integrity and serves as a way to detect problems with the well system.
Mechanical integrity testing provides an early indication of potential
issues that could lead to CO2 leakage from the confining
zone, providing assurance and verification that CO2 will not
reach the atmosphere.
    Further assurance is provided by the regulatory requirement that
injection must cease if there is evidence that the injected
CO2 and/or associated pressure front may cause endangerment
to a USDW.\473\ Once the anomalous operating conditions are verified,
the cessation of injection, as required by UIC permits, will minimize
any risk of release to air.
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    \473\ 40 CFR 146.94(b).
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    Following cessation of injection, the operator must conduct
comprehensive post-injection site care to show the position of the
CO2 plume and the associated area of elevated pressure to
demonstrate that neither poses an endangerment to USDWs--also having
the practical effect of preventing releases of CO2 to the
atmosphere. Post-injection site care includes appropriate monitoring
and other needed actions (including corrective action). The default
duration for the post-injection site care period is 50 years, with
flexibility for demonstrating that an alternative period is appropriate
if it ensures non-endangerment of USDWs.
    As the EPA has found, the UIC Class VI injection well requirements
protect against releases from all exposure pathways. Specifically, the
EPA stated that the Class VI rules ``[are] specifically designed to
ensure that the CO2 (and any incidental associated
substances derived from the source materials and the capture process)
will be isolated within the injection zone.'' The EPA further stated
that ``[t]he EPA concluded that the elimination of exposure routes
through these requirements, which are implemented through a SDWA UIC
permit, will ensure protection of human health and the environment. .
.''.\474\
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    \474\ 79 FR at 353 (January 3, 2014) (Final Hazardous Waste
Management System: Conditional Exclusion for Carbon Dioxide
(CO2) Streams in Geologic Sequestration Activities under
subtitle C of RCRA). See Section N.5.c below.
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    GHGRP subpart RR complements these UIC Class VI requirements.
Requirements under the UIC program are focused on demonstrating that
USDWs are not endangered as a result of CO2 injection into
the subsurface, while requirements under the GHGRP through subpart RR
enable accounting for CO2 that is geologically sequestered.
A methodology to account for potential leakage is developed as part of
the subpart RR MRV plan (see Section V.N.2). The MRV plan submitted for
subpart RR may describe (or provide by reference to the UIC permit) the
relevant elements of the UIC permit (e.g. assessment of leakage
pathways in the monitoring area) and how those elements satisfy the
subpart RR requirements. The MRV plan required under subpart RR may
rely upon the knowledge of the subsurface location of CO2
and site characteristics that are developed in the permit application
process, and operational monitoring results for UIC Class VI permitted
wells.
    In summary, there are well-recognized physical mechanisms for
storing CO2 securely. The comprehensive and rigorous site
characterization requirements of the Class VI rules assure that sites
with these properties are selected. Subsurface monitoring serves to
assure that the sequestration site operates as intended, and this
monitoring continues through a post-closure period. Although release of
CO2 to air is unlikely and should be detected prior to
release by subsurface monitoring, the subpart RR air-side monitoring
and reporting regime

provides back up assurance that sequestered CO2 has not been
released to the atmosphere.
b. Class II Wells
    The Class II rules likewise are designed to protect USDWs during
EOR operation, including the injection of CO2 for EOR. For
example, UIC Class II minimum federal requirements promulgated under
SDWA address site characterization, area of review, well construction
(e.g., casing and cementing), well operation (e.g., injection
pressure), injectate sampling, mechanical integrity testing, plugging
and abandonment, financial responsibility, and reporting. Class II
wells must undergo periodic mechanical integrity testing which will
detect well construction and operational conditions that could lead to
loss of injectate and migration into USDWs. The establishment of
maximum injection pressures, designed to ensure that the pressure in
the injection zone during injection does not initiate new fractures or
propagate existing fractures in the confining zone, prevents injection
from causing the movement of fluids into an underground source of
drinking water. The safeguards that protect USDWs also serve as an
early warning mechanism for releases of CO2 to the
atmosphere.
    CO2 injected via Class II wells becomes sequestered by
the trapping mechanisms described above in this Section V.N.3. As with
Class VI wells, for Class II wells that report under subpart RR, there
is monitoring to evaluate whether CO2 used for EOR will
remain safely in place both during and after the injection period.
Subpart RR provides a CO2 accounting framework that will
enable the EPA to assess both the project-level and national efficacy
of geologic sequestration to determine whether additional requirements
are necessary and, if so, inform the design of such regulations.
c. Response to Comments
    Commenters maintained that GS was not demonstrated for
CO2 captured from EGUs. In addition, commenters noted that
the volumes of captured CO2 would be considerably larger
than from existing GS sites, and could quadruple amounts injected into
Class II EOR wells. In addition to volumes of CO2 to be
injected, commenters opined on the possibility of sporadic
CO2 supply due to the nature of EGU operation.\475\
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    \475\ See, e.g. Comments of Southern Company, p. 41 (Docket
entry: EPA-HQ-OAR-2013-0495-10095).
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    The EPA does not agree. CO2 capture from EGUs is
demonstrated as discussed in Sections V.D and V.E. As discussed below,
the volumes of CO2 are comparable to the amounts that have
been injected at large scale commercial operations. The EPA also
disagrees that the volume of CO2 would quadruple amounts
injected into Class II EOR wells because CO2 may be
sequestered in deep saline formations, which have widespread geographic
availability (see Section M.1). The BSER determination and regulatory
impact analysis for this rule relies on GS in deep saline
formations.\476\ However, the EPA also recognizes the potential for
sequestering CO2 via EOR and allows the use of EOR as a
compliance option. According to data reported to the GHGRP,
approximately 60 million metric tons of CO2 were supplied to
EOR in the United States in 2013.\477\ Approximately 70 percent of
total CO2 supplied in the United States was produced from
geologic (natural) CO2 sources and approximately 30 percent
was captured from anthropogenic sources. CO2 pipeline
systems, such as those serving the Permian Basin, have multiple sources
of CO2 that serve to levelize the pipeline supply, thus
minimizing the effect of supply on the EOR operator.
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    \476\ The EPA anticipates EOR projects may be early GS projects
because these formations have been previously well characterized for
hydrocarbon recovery, likely already have suitable infrastructure
(e.g., wells, pipelines, etc.), and have an associated economic
benefit of oil production.
    \477\ Greenhouse Gas Reporting Program, data reported as of
August 18, 2014.
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    GS of anthropogenic CO2 in deep saline formations is