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1 To: Docket EPA-HQ-OAR-2013-0495 Date: January 8, 2014 Subject: Effect of EPAct05 on BSER for New Fossil F uel-fired Boilers and IGCCs

Introduction and Overview By notice dated January 8, 2014, the Environmental Protection Agency (EPA) published the proposed rule, “Standards of Performance for Gr eenhouse Gas Emissions From New Stationary Sources: Electric Utility Generating Uni ts,” 79 Fed. Reg. 1430 (referred to here as the 2014 Proposal). In this action, the Agency proposes to establish new source standards of performance under Clean Air Act (CAA) §111(b) for f ossil fuel-fired electricity generating units, including a standard of 1,100 pounds of carbon diox ide (CO 2 ) per gross megawatt-hour (lb
CO 2 /MWh) for steam generating boilers and integrated g asification combined cycle (IGCC) units. EPA based this standard on the proposed de termination that new efficient generating technology implementing partial carbon capture and storage technology (CCS) is the best system of emission reduction adequately demonstrate d (BSER) for those sources. EPA based this determination, in turn, on a review of existin g projects that implement CCS, existing projects that implement various components of CCS, planned CCS projects, and scientific and engineering studies of CCS. Some of the projects discussed in the 2014 Proposal received financial assistance under the Energy Policy Act of 2005 (P.L. 109-58) (EPAct0 5). This assistance includes various grants, loan guarantees, and other forms of assistance, as well as the Federal tax credit for investment in clean coal technology under Internal Revenue Cod e (IRC) §48A. Several provisions in EPAct05 explain the relevance of such projects to an EPA de termination of BSER under CAA §111. These provisions are found in several parts of EPAct05: s ections 402(a), 402(i), and 1307(b), as discussed below and 1307(b)(adding IRC §48A(g), as discussed below). Through this technical support document (TSD), EPA solicits comment on its proposed views as to the meaning and significance of relevan t provisions of EPAct05, including how these provisions may affect the rationale for EPA’s propo sed determination that partial CCS is the best system of emission reduction adequately demons trated for fossil fuel-fired utility boilers and IGCC units. This TSD has two parts. In the fir st section, EPA summarizes the rationale it presented in the 2014 Proposal, and describes why t he EPAct05 is most relevant for EPA’s proposed determination that partial CCS is technica lly feasible and of reasonable cost. In the second section, EPA describes the applicable EPAct0 5 provisions, including IRC §48A(g). As discussed in greater detail below, EPA interprets t hese provisions to preclude EPA from relying solely on the experience of facilities that receive d EPAct05 assistance, but not to preclude EPA- TECHNICAL SUPPORT DOCUMENT –

2 from relying on the experience of such facilities i n conjunction with other information. In light of this interpretation, EPA explains its reliance o n other information in making the determination that partial CCS is the BSER. EPA al so explains that IRC §48A(g) presents a number of issues of interpretation that could affec t the applicability and scope of that provision’s limit on the use of information in CAA §111 rulemakings. EPA believes that even if IRC §48A(g) is interpreted to preclude EPA from, un der any circumstances, relying on the experience of facilities that have been identified as having been allocated the IRC §48A tax credit, the remaining information set forth in the 2014 Proposal nonetheless provides an adequate basis for EPA’s proposed determination.

Summary of 2014 Proposal of Rationale for BSER and Factors Affected by EPAct05

Best system of emission reduction adequately demons trated In the preamble for the 2014 Proposal, EPA discusse d in some detail its interpretation of the requirements under CAA §111 f or determining the “standard of performance,” and readers are referred to that disc ussion. For convenience, parts of that discussion are excerpted here. In that discus sion, EPA provided the following overview of its interpretation (citations omitted):

By its terms, the definition of “standard of perfor mance” under CAA section 111(a)(1) provides that the emission limit that the EPA promulgates must be “achievable” and must be based on a system of em ission reduction – generally, but not required to be always, a technol ogical control -- that the EPA determines to be the “best system” that is “adequat ely demonstrated,” “taking into account ... cost ... nonair quality health and env ironmental impact and energy requirements.” The D.C. Circuit has stated that in determining the “best” system, the EPA must also take into account “the am ount of air pollution” and “technological innovation.”

As discussed below, the D.C. Circuit has elaborated on the criteria and process for determining whether a standard is “achi evable,” based on an “adequately demonstrated” technology or system. In addition, the Court has identified limits on the costs and other factors th at are acceptable for the technology or system to qualify as the “best.” The Court has also held that the EPA may consider the costs and other factors on a r egional or national level (e.g., the EPA may consider impacts on the national econom y and the affected industry as a whole) and over time, and not just on a plant-specific level at the time of the rulemaking. In addition, the Court has emphasized that the EPA has a great deal of discretion in weighing the various fa ctors to determine the “best- TECHNICAL SUPPORT DOCUMENT –

3 system.” 1

For present purposes, the technical feasibility and costs are the factors that may be primarily affected by the limits imposed by EPAc t05 on information EPA may rely on under CAA §111 in finding that the BSER is adequate ly demonstrated. In the 2014 Proposal, EPA explained its interpretation of the r equirements concerning technical feasibility as follows (citations omitted):

The D.C. Circuit’s first decision under section 111 , Portland Cement Ass’n v. Ruckelshaus , 486 F.2d 375, 391 (D.C. Cir. 1973), concerned whe ther EPA’s standard of performance for the cement industry met the requirement to be “achievable,” which, in turn, depended on whether t he technology on which EPA based the standard was “adequately demonstrated.” I n this case, the Court interpreted these provisions to require that the te chnology must be technically feasible for the source category, and established c riteria for determining technical feasibility.

The Court explained that a standard of performance is “achievable” if a technology can reasonably be projected to be availa ble to new sources at the time they are constructed that will allow them to m eet the standard. Specifically, the D.C. Circuit explained:

Section 111 looks toward what may fairly be project ed for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants.. ..- It is the “achievability” of the proposed standard that is in issue....

The Senate Report made clear that it did not intend that the technology “must be in actual routine use somew here.” The essential question was rather whether the technolog y would be available for installation in new plants.... The Ad ministrator may make a projection based on existing technology, tho ugh that projection is subject to the restraints of reasonab leness and cannot be based on “crystal ball” inquiry. 2

EPA discussed costs by noting that the D.C. Circuit has elaborated on the cost factor in several cases, and has identified limits to how costly a control technology may be before it no longer qualifies as the BSER. EPA explained that the Court has used various formulations of the cost standard, such as that the costs cannot be “excessive”

1 79 Fed. Reg. at 1463/1.

2 79 Fed. Reg. at 1463/2-3.- TECHNICAL SUPPORT DOCUMENT –

4 or “unreasonable.” EPA added, “For convenience, in this rulemaking, we will use reasonableness as the standard, so that a control t echnology may be considered the “best system of emission reduction ... adequately dem onstrated” if its costs are reasonable, but cannot be considered the best syste m if its costs are unreasonable.” 3

Basis for determination in 2014 Proposal for techni cal feasibility and costs In the 2014 Proposal, the EPA evaluated three alter native control technology configurations as potentially representing the BSER for new fossil fuel-fired boilers and new IGCC units. The three alternatives are: (1) highly efficient new generation technology that does not include any level of CCS, (2) highly efficient new generation technology with “full capture” CCS (capture of at least 90 percent of CO 2 emissions), and (3) highly efficient new generatio n technology with “partial capture” CCS (capture of a smaller portion of the total CO 2 emissions).
EPA discussed each of the alternatives in detail in the proposal and explained why it determined that partial CCS qualifies as the BSER. EPA also included its rationale for selecting 1,100 lb CO 2 /MWh as the emission limitation for these sources a nd we explained its rationale for the requirements for geologic storage of the ca ptured CO 2 . In brief, EPA stated that partial CCS has three cor e components: CO 2 capture, compression and transportation, and injection and s torage of the CO 2 stream. EPA explained that each of these core components has already been implemented. Projects that implement various components of CCS include full commercial s cale projects that implement all three components, full scale projects that implement one or more of the individual components and smaller scale projects that implement one or more o f the components. It is not necessary that the major components be demonstrated in an integrat ed process in order to determine the technical feasibility of each component. Nor is it necessary that all of the components be demonstrated at an electricity generating plant. In particular, EPA based its proposed determination that the technical feasibility of partial CCS is adequately demonstrated on a set of evidence that EPA summarized as follows:

The EPA proposes to find that partial CCS is feasi ble because each step in the process has been demonstrated to be feasible th rough an extensive literature record, fossil fuel-fired industrial pla nts currently in commercial operation and pilot-scale fossil fuel-fired EGUs cu rrently in operation, and the progress towards completion of construction of foss il fuel-fired EGUs implementing CCS at commercial scale. 4

3 79 Fed. Reg. at 1464/2-3

4 79 Fed. Reg. at 1471/2.- TECHNICAL SUPPORT DOCUMENT –

5 In the 2014 Proposal, EPA based its estimation of the costs of partial CCS primarily on a report by the Department of Energy (DOE) National E nergy Technology Laboratory (NETL) 5

. This report identified any new plants as “next of a kind,” and estimated the amount of costs of CCS for such new plants accordingly. EPA based its proposed determination that these costs were reasonable on the fact that they are comparabl e to the costs of new construction of other low-carbon electricity generating power plants, inc luding nuclear power plants.

EPAct05 Provisions, including IRC §48A, and EPA’s i nterpretation The Energy Policy Act of 2005 (EPAct05) addresses e nergy production in the United States, and contains provisions concerning, among o ther things: energy efficiency; renewable energy; oil and gas; coal; Tribal energy; nuclear m atters and security; vehicles and motor fuels, including ethanol; hydrogen; electricity; hydropowe r and geothermal energy; climate change technology; and energy tax incentives, including In ternal Revenue Code (IRC) §48A. Because the relevant provisions of IRC §48A differ from the other relevant provisions in EPAct05, IRC §48A will be discussed after the other relevant EPA ct05 provisions.

Provisions in EPAct05 other than IRC §48A EPAct05 authorized a number of coal-related program s. Title IV authorized $200 million annually for the Clean Coal Power Initiative betwee n fiscal year (FY) 2006 through FY2014. Of this amount, 70% was designed for funding coal-base d gasification technologies. Section 402(i) of the EPAct05, codified at 42 USC s ection 15962(i), limits the use of information from facilities that receive assistance under the Act in CAA §111 rulemaking, as follows: “No technology, or level of emission reduction, sol ely by reason of the use of the technology, or the achievement of the em ission reduction, by 1 or more facilities receiving assistance under this Act , shall be considered to be adequately demonstrated for purposes of section 111 of the Clean Air Act.... “ (Emphasis added).

In addition, EPAct05 §421(a) amended the Energy Pol icy Act of 1992 (42 U.S.C. 13201 et seq.) (EPAct92) by adding the “Clean Air C oal Program” to support and promote the production and generation of clean coal -based power, including supporting air pollution control technologies. EPAct05 §421(a) included a constraint similar to EPAct05 §402(i). 6 EPAct05 offered other benefits to coal-fired power plants, including

5 The “Cost and Performance Baseline” reports are a series of reports by DOE/NETL that establish estima tes for the cost and performance of combustion- and gasificatio n-based power plants - all with and without CO 2 capture and storage. Available at http://netl.doe.gov/research/ energy-analysis/energy-baseline-studies;“Cost and P erformance of PC and IGCC Plants for a Range of Carbon Dioxide Capture”, DOE/NETL-2011/1498, May 27, 2011.

6 As amended by EPAct05 §421(a), EPAct92 §3103(e) (4 2 U.S.C. 13573(e)) and EPAct92 §3104(d) (42 U.S.C. 13574(d)), provide:- TECHNICAL SUPPORT DOCUMENT –

6 loan guarantees under Title XVII (42 U.S.C. 16511-1 6514), research and development (R&D) grants under Title IX, and a tax credit for i ndustrial facilities, IRC §48B. 7 By their terms, EPAct05 §§402(i) and 421(a) prohibi t EPA from relying exclusively – “solely” – on facilities that receive assistance un der EPAct05 when determining whether a particular technology, or level of emission reducti on, is adequately demonstrated for purposes of section 111 of the Clean Air Act. EPA thus may rely on such projects for its BSER determination if there is additional evidence suppo rting such a determination. EPA solicits comment on the meaning of EPAct05 §§40 2(i) and 421(a). In particular, does the partial prohibition apply to any technolog y or emissions reduction by any facility receiving any form of assistance, regardless of whe ther the assistance relates to the technology or emission reductions; or, instead, does the prohi bition apply to only the technology or emissions reduction for which the assistance was gi ven. EPA believes that a reasonable reading is that the prohibition relates only to the technol ogy or emissions reduction for which assistance was given. This reading is not only a n atural one, but the other reading – under which there would be no connection between the gove rnment assistance and the technology/performance which is the subject of the partial prohibition—is strained. If the provision is ambiguous, EPA’s interpretation would be accorded deference. 8 In the 2014 Proposal and in this TSD, EPA relies o n a wide range of information to support the proposed determination that partial CCS is the best system of emission reduction adequately demonstrated. This includes literature reviews, the experience of facilities that predate EPAct05, the experience of facilities in forei gn nations, and projects that have been developed after the enactment of EPAct05, only some of which have received assistance under EPAct05. Accordingly, the proposed determination is not “solely” based on information about facilities that received assistance under EPAct05. EPA solicits comment on all aspects of EPAct05 §402 (i) and §421(a) as they related to the 2014 Proposal and this TSD, including the prope r interpretation of those provisions, their application to EPA’s proposed determination that pa rtial CCS is the best system of emission reduction adequately demonstrated, and the types of assistance provided under EPAct05. EPA also requests that the owners or operators of facil ities identified in the 2014 Proposal and this

Applicability. -- No technology, or level of emissi on reduction ... shall be treated as adequately demonstrated for purpose of section 111 of the Clea n Air Act (42 U.S.C. 7411), achievable for purposes of section 169 of that Act (42 U.S.C. 7479 ), or achievable in practice for purposes of section 171 of that Act (42 U.S.C. 7501) solely by reason of the use of such technology, or the achievement of such emission reduction, by one or m ore facilities receiving assistance under [section 3102(a)(1) or (2) of the Energy Policy Ac t of 1992, as amended (42 U.S.C. 13572(a)(1))].

7 It should be noted that IRC §48B does not itself c ontain any provision, comparable to EPAct 05 §402(i ) or as discussed below, IRC §48A(g), limiting the use of i nformation for purposes of determinations under the Clean Air
Act.
8 EPA would be the agency authorized to interpret 42 USC section 15962 because it involves the meaning of the Clean Air Act, and substantial deference would be a ccorded EPA’s interpretation. See **Pension Benefit Guar. Corp. v. LTV Corp.,**  496 U.S. 633, 651-52 (1990) (" practical agency expertise is one of the principal justifications behind **Chevron** deference.")

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7 TSD as part of EPA’s basis for that proposed determ ination confirm, during the comment period, whether they did or did not receive assista nce under EPAct05. EPA solicits comment on whether, if it does not receive information confirm ing that a particular facility received assistance under EPAct05, EPA may treat that facili ty as not having received any such assistance for purposes determining, in this rulemaking, the b est system of emission reduction adequately demonstrated.

IRC §48A Section 1307(b) of the EPAct05 amends the Internal Revenue Code to add §48A, which creates, as an investment tax credit, the “qualifyi ng advanced coal project credit.” In accordance with IRC §48A(d)(1), the Secretary of th e Treasury (hereinafter referred to as the IRS), in consultation with the Secretary of Energy, established a “qualifying advanced coal project program” for the allocation of the authoriz ed tax credits to projects. As noted below, subsequent congressional amendments added two more phases to this program, so that the original program may be referred to as Phase I. Acc ording to an IRS notice describing §48A (as enacted in EPAct05) and this (Phase I) program:

.02 The qualifying advanced coal project credit is provided under [IRC] § 48A.... Section 48A(a) provides that the qualifying advanced coal p roject credit for a taxable year is an amount equal to (1) 20 percent of the qualified inv estment (as defined in § 48A(b)) for that taxable year in certified qualifying advanced coal projects (as defined in § 48A(c)(1) and (e)) using an integrated gasification combined cycle (IGCC) (as defined in § 48A(c)(7)), and (2) 15 percent of the qualified i nvestment for that taxable year in other certified qualifying advanced coal projects.

.03 Section 48A(d)(3)(A) provides that the aggregat e credits allowed under § 48A(a) may not exceed $1.3 billion. Section 48A(d )(3)(B) provides that (i) $800 million of credits are to be allocated to IGCC proj ects, and (ii) $500 million of credits are to be allocated to projects that use ot her advanced coal-based generation technologies (as defined in § 48A(c)(2) and (f)).

.04 Section 48A(e)(3)(A) provides that the credits for IGCC projects must be allocated in accordance with the procedures set for th in § 48A(d), and in relatively equal amounts to (i) projects using bitu minous coal as a primary feedstock, (ii) projects using subbituminous coal a s a primary feedstock, and (iii) projects using lignite as a primary feedstock. Furt her, § 48A(e)(3)(B) provides that IGCC projects that include (i) greenhouse gas capture capability (as defined in § 48A(c)(5)), (ii) increased by-product utilizat ion, and (iii) other benefits must be given high priority in the allocation of credits for IGCC projects.- TECHNICAL SUPPORT DOCUMENT –

8 .05 The at-risk rules in [IRC] § 49 and the recaptu re and other special rules in [IRC] § 50 apply to the qualifying advanced coal pr oject credit. Further, the qualifying advanced coal project credit generally i s allowed in the taxable year in which the eligible property (as defined in § 48A(c) (3)) is placed in service by the taxpayer. Pursuant to § 48A(D)(2)(E), a taxpayer th at receives a certification under § 48A(d)(2)(D) has 5 years from the date of i ssuance of the certification to place the qualifying advanced coal project in servi ce. 9

A project is a “qualifying advanced coal project” t hat the IRS may certify (under §48A(d)(2)) if it meets the requirements of §48A(e) , which include, among other things, that the project must “use[] an advanced coal-based generati on technology” to power a new, or to retrofit or repower an existing, “electric generati on unit” (as defined in §48A(c)(6)); the fuel input for the project must be at least 75% coal; th e project must be of at least a specified size; the majority of the project’s output must reasonabl y be expected to be acquired or utilized; and the project must be located in the U.S. Under §48A(f), an electric generation unit uses an “advanced coal-based generation technology” if the unit uses either integrated gasification combined cycle (IGCC) technology or has a design ne t heat rate of a specified amount, and if the unit meets other requirements, including being designed to attain specified standards for
emissions or removal of certain criteria and hazard ous air pollutants. The term “qualified investment” is defined, under §48A(b)(1) as, for any taxable year, “the basis of eligible property placed in service b y the taxpayer during such taxable year.” In turn, “eligible property” is defined as – (A) in the case of any qualifying advanced coal pr oject using an integrated gasification combined cycle, any property which is a part of such project and is necessary for the gasification of coal, including a ny coal handling and gas separation equipment, and (B) in the case of any other qualifying advanced c oal project, any property which is part of such project.

As described in more detail below, the IRS allocate d the credit available under §48A – as enacted by EPAct05 – to a number of projects. Howev er, under the taxpayer privacy rules, no information about any of these projects was made pu blicly available unless a recipient waived its privacy rights. In light of subsequent modifica tions to IRC §48A, discussed next, the program as enacted by EPAct05 became known as the Phase I p rogram. IRC §48A was expanded and modified by the Energy Im provement and Extension Act of

9 Internal Revenue Bulletin: 2006-11 (Notice 2006-24, March 13, 2006). http://www.irs.gov/irb/2006- 11_IRB/ar09.html- TECHNICAL SUPPORT DOCUMENT –

9 2008, Pub. L. 110-343, 122 Stat. 3765 (October 3, 2 008) , which established Phase II of the program. According to an IRS notice –

Section 111 of that Act amended § 48A to provide fo r a second phase of the qualifying advanced coal project program in which $ 1.25 billion of additional credits are authorized (“the Phase II advanced coal program” and “the Phase II advanced coal credit”). 10

As further described by the IRS, the revisions to IRC §48A –

provide[] that the qualifying advanced coal project credit for a taxable year is an amount equal to (1) 20 percent of the qualified inv estment (as defined in § 48A(b)) for that taxable year in qualifying advan ced coal projects (as defined in § 48A(c)(1) and (e)) described in § 48A(d)(3)(b)(i) , (2) 15 percent of the qualified investment for that taxable year in qualified advan ced coal projects described in § 48A(d)(3)(b)(ii), and (3) 30 percent of the quali fied investment for that taxable year in qualifying advanced coal projects described in § 48A(d)(3)(B)(iii). Section 48A(d)(3)(b)(i) describes integrated gasification c ombined cycle (“IGCC”) projects (as defined in § 48A(c)(7)) for which applications were submitted during the Phase I application period (“Phase I IGCC projects” ). Section 48A(d)(3)(b)(ii) describes projects that use other advanced coal-bas ed generation technologies (as defined in § 48A(c)(2) and (f)) and for which a pplications were submitted during the Phase I application period (“other Phase I advanced coal projects”). Section 48A(d)(3)(b)(iii) describes projects that u se advanced coal-based generation technologies and for which applications are submitted during the Phase II application period (“Phase II advanced coa l projects”). Phase II advanced coal projects include both IGCC projects and projec ts that use other advanced coal-based technologies. For this purpose, the Phas e I application period is the 3- year period following the establishment of the qual ifying advanced coal program on March 13, 2006, and the Phase II application per iod is the 3-year period beginning on March 13, 2009.

.04 Section 48A(d)(3)(A) provides that the aggregat e credits allowed under § 48A(a) may not exceed $2.55 billion. Section 48A( d)(3)(B) provides that (1) $800 million of credits are to be allocated to Phas e I IGCC projects, (2) $500 million of credits are to be allocated to other Pha se I advanced coal projects, and (3) $1.25 billion of credits are to be allocated to Phase II advanced coal projects.

10 Internal Revenue Bulletin: 2009-16 (Notice 2009-24 , April 20, 2009) http://www.irs.gov/irb/2009- 16_irb/ar07.html- TECHNICAL SUPPORT DOCUMENT –

10 .05 Section 48A(d)(2)(A) provides that (i) applicat ions for the credits allocated to Phase I IGCC projects and other Phase I advanced co al projects may be submitted only during the Phase I application perio d, and (ii) applications for the credits allocated to Phase II advanced coal project s may be submitted only during the Phase II application period.

.06 Section 48A(d)(5) provides that the Secretary [ of the Treasury] shall, upon making a certification under § 48A(d), publicly dis close the identity of the applicant and the amount of the credit certified wi th respect to such applicant.

.07 Section 48A(e)(1)(G) provides that any project the application for which is submitted during the Phase II application period mu st include equipment that separates and sequesters—

(1) At least 65 percent of such project’s total car bon dioxide (“CO 2 ”) emissions in the case of an application other than an applicatio n for reallocated credits under § 48A(d)(4); and

(2) At least 70 percent of such project’s total CO 2 emissions in the case of an application for reallocated credits under § 48A(d)( 4)....

.11 Section 48A(i) provides that the Secretary shal l provide for recapturing the benefit of any credit allowable under § 48A(a) with respect to any project that fails to attain or maintain the separation and sequ estration requirements of § 48A(e)(1)(G). 11

In 2012, the IRS established Phase III of this pro gram, which, according to the IRS, was designed “to distribute the §48A Phase I c redits that are available for allocation after the conclusion of the §48A Phase I program.” 12 The following information has been made publicly av ailable about the taxpayers who have been allocated the §48A tax credits in the three phases of the program: For Phase I, in 2006, the IRS and the DOE announced tha t nine clean coal and advanced gasification projects had been awarded 13 tax credits under IRC §48A or §48B. (As noted above, unlike IRC §48A, IRC §48B does not itself co ntain any provision that limit the use of information about recipients of the §48B tax cre dit.) According to the IRS, the awards involved two IGCC bituminous coal projects, one IGC C lignite project, two non-IGCC

11 Id.

12 Internal Revenue Bulletin: 2012-33 (Notice 2012-51 , August 13, 2012). http://www.irs.gov/irb/2012- 33_IRB/ar05.html#d0e358

13 In its announcements, the IRS sometimes describes the allocations as “awards.” Those two terms – all ocation and award – are synonymous.- TECHNICAL SUPPORT DOCUMENT –

11 advanced coal electricity generation projects, and four gasification projects. 14 The following information as to seven of these sources was made publicly available by the DOE. 15 (It should be noted that the information from the IRS and DOE does not explicitly state which facilities were allocated the tax credi t under IRC§48A and which under IRC §48B.)

Technology Recipient Location Output Tax Credit IGCC Bituminous Duke Energy –

Edwardsport IGCC Project Edwardsport, IN 795 MW $133.5 million

IGCC Bituminous Tampa Electric Polk County, FL 789 MW $133.5 million IGCC Lignite Mississippi Power Company Kemper County, MS 700 MW $133 million

Advanced Coal Duke Energy Cliffside Modernization projects Cleveland and

Rutherford Counties, NC 1600 MW $125 million

Advanced Coal E.ON U.S., Kentucky

Utilities Co. and Louisville Gas and Electric Bedford, KY 1744 MW $125 million

Gasification Carson Hydrogen

Power, LLC: Carson Hydrogen Power Project Carson, CA Hydrogen and 390 MW of electricity N/A

Gasification TX Energy, LLC: Longview Gasification and Refueling Project Longview, TX Synthetic gas for chemical feedstock N/A

For Phase II, according to the IRS, the following i nformation is available as to the awards of credits, which concerned the 2009-10 and 2011-12 allocation rounds. 16

14 IRS Press Release IR-2006-184 (Nov. 30, 2006).

15 “Fact Sheet: Clean Coal Technology Ushers In New E ra in Energy,” U.S. Department of Energy, http://energy.gov/downloads/fact-sheet-clean-coal-t echnology-ushers-new-era-energy

16 IRS Announcement 2010-56, 2010-39 I.R.B. 398 (Sept ember 27, 2010) and IRS Announcement 2013-2, 2013-2 I.R.B 271 (January 7, 2013). During the 2009-10 all ocation round, the IRS also awarded §48B tax credit s to Faustina Hydrogen Products ($121,660,000) and Lake Charles G asification, LLC ($128,340,000). IRS Announcement 2010- 56. On October 3, 2011, the Service issued Announc ement 2011-62, 2011-40 I.R.B. 483, announcing that the second allocation round in 2010-11 did not result i n any allocation of the qualifying advanced coal pr oject credit,- TECHNICAL SUPPORT DOCUMENT –

12 Program Taxpayer Amount of Credit Awarded Total Credit Awarded

§48A Christian County Generation, LLC $417,000,000 Summit Texas Clean Energy LLC $313,436,000 Mississippi Power Company $279,000,000 Hydrogen Energy California LLC $103,564,000 $1,113,000,000

For Phase III, according to the IRS, the following information is available as to the awards of credits, which concerned the 2012-13 allo cation round: 17 (It should be noted that this information from the IRS does not explicitly state which facilities received the tax credit under IRC§48A and which under IRC §48B.)

Program Taxpayer Amount of Credit Awarded Total Cre dit Awarded

Phase III STCE Holdings, LLC $324,000,000 SCS Energy California, LLC $334,500,000 $658,500,000

IRC §48A(g) limits information concerning the use o f technology or level of emission
reduction from EGU facilities 18 for which a tax credit is allowed, 19 which prohibition is similar to those in the other EPAct05 provisions noted above. Specifically, §48A(g) provides (for purposes relevant here):

No use of technology (or level of emission reductio n solely by reason of the use of the technology), and no achievement of a ny emission reduction by the demonstration of any technology or performance leve l, by or at one or more facilities with respect to which a credit is allowe d under this section, shall be considered to indicate that the technology or perfo rmance level is adequately demonstrated for purposes of section 111 of the Cle an Air Act....

EPA solicits comment on the proper interpretation o f all aspects of this provision,

17 IRS Announcement 2013-43. http://www.irs.gov/pub/irs-drop/a-13-43.pdf The IRS stated that “The 2012-2013 allocation round is the only allocation round under the Phase III program.” Id.

18 An “electric generation unit” is defined as “any f acility at least 50 percent of the total annual net output of which is electrical power, including an otherwise eligibl e facility which is used in an industrial applicati on.”IRC section 48A(c)(6).

19 Only an “electric generation unit” may receive the section 48A tax credit. See sections 48A (e)(1)(A ) and (f)(1).- TECHNICAL SUPPORT DOCUMENT –

13 including several in particular. The first is the p hrase “considered to indicate.” In the present context, does the term “considered” mean “referred to”, or “deemed,” 20 or something else? In addition, does the term “indicate” mean “support” o r “prove,” or something else? Depending on the answers to these questions, the phrase, “con sidered to indicate,” could preclude only information providing the sole basis for a determin ation that a particular technology is the best system of emission reduction adequately demonstrate d, or it could also preclude information which is only corroborative or is otherwise only pa rt of the basis for the determination. That is, the phrase could have any one of three different me anings: (i) Information about a particular technology from certain facilities may not be used at all in a determination of whether that technology is the best system of emission reduction adequately demonstrated; (ii) such information may be used to corroborate such a deter mination, when that determination is based on other information; or (iii) such informati on may be used along with other information to make such a determination, but may not be used a s the only basis. EPA’s proposed interpretation 21 of this provision is the third, that use of techno logy, or emission performance, from a facility for which the credit is allowed cannot, by itself, support a finding that the technology or performance level is adequately demonstrated, but the information can corroborate an otherwise supported determination or otherwise provide part
of the basis for such a determination. EPA notes t hat this reading would parallel the meaning of the related provisions in EPAct05 §§402(i) and 4 02(a), including, e.g., 42 USC 15962(i). Since all of these provisions were part of the same legis lation and address the same issue, and since there is no legislative history indicating that the y were meant to have different meanings, this interpretation is reasonable. This interpretation a lso is consistent with the apparent purpose of IRC §48A – as well as the other types of assistance in EPAct05 -- which is to encourage the development of technology so that it can be used on a widespread commercial basis. As discussed in the preamble for the 2014 Proposal, CA A §111 is an important vehicle for promoting widespread commercial use of technology. In addition, EPA interprets other terms in IRC §48 A(g) as limiting the scope of the information preclusion. Importantly, §48A(g) raise s an issue as to whether the limit on use of information applies to the evaluation of any techno logy or emissions reduction by any facility allowed the tax credit, regardless of whether the t ax credit relates to the technology at issue in the determination of the best system of emission re duction adequately demonstrated or, instead, the limit applies to only the technology o r emissions reduction for which the tax credit

20 Under this view, in the intransitive form that se ction 48A(g) uses the verb “consider,” the verb may be a synonym for “deemed,” as in the phrase, “the accuse d shall be considered innocent until proven guilty. ”

21 As with the related provisions of EPAct05, because 26 USC section 48A(g) involves the meaning of the Clean Air Act, EPA would be the agency authorized to interpre t it.- TECHNICAL SUPPORT DOCUMENT –

14 was allowed. Specifically, does the phrase “with re spect to which a credit is allowed under this section” refer to (i) the entire phrase “use of tec hnology (or level of emission reduction ...) and ... achievement of any emission reduction..., by or at one or more facilities,” or (ii) only “one or more facilities?” This distinction is important be cause the tax credit is available only for “eligible property,” as defined under §48A(c)(3), a nd not for all technology that EPA may evaluate as part of the BSER. For example, as note d, for projects using IGCC, “eligible property” is defined as “any property which is a part of such project and is necessary for the gasification of coal, including any coal handling and gas separa tion equipment.” The most natural interpretation appears to be the first of those noted above, so that the phrase “with respect to which a credit is allow ed under this section” refers to the entire phrase “use of technology (or level of emission red uction ...) and ... achievement of any emission reduction..., by or at one or more facilitie s.” This reading also is consistent with the apparent purpose of the provision of not basing dem onstrations of technology and performance solely on federally subsidized levels o f performance. Under this interpretation, the prohibition in section 48A(g) would appear to be li mited to the “eligible property” for which the tax credit is allowed. That is, if a unit is allow ed the tax credit only with respect to technology A (for example, IGCC technology, as defined), then EP A is prohibited from reviewing the use of that technology in assessing the best system of emi ssion reduction adequately demonstrated for purposes of CAA §111, but may review use of any other technology at the facility (for example, transportation or sequestration-related te chnology) in making that assessment. EPA solicits comment on all aspects of this issue of wh ich technology at a facility that is allowed the §48A tax credit EPA may review in determining BSER. In addition, EPA solicits comment on the meaning of the phases, “level of emission reduction solely by reason of the use of the technology” and “achievement of any emission reduct ion by the demonstration of any technology or performance level.” EPA also solicits comment on questions as to the ap plicability of IRC§ 48A(g). Does the limitation occur only if and at the time when the t ax credit “is allowed under [section 48A]” (and not before), and if so, when is that time? Th e IRS, in consultation with DOE, has set up a process, as part of the §48A(d) program, for admini stering the credit, under which a taxpayer may submit an application for the credit, the IRS a nd DOE may issue certifications, and the IRS may issue an allocation of the credit to the taxpay er. But these events are not the same as
when the credit “is allowed.” Section 48A does not , by its terms, specify the time when the
credit “is allowed.” The IRS has stated that “the ... credit generally is allowed in the taxable year in which the eligible property ... is placed in servi ce by the taxpayer.” 22 Under the Treasury

22 IRB 2006-11 Notice 2006-24, section 2.05; IRB 200 9-16, Notice 2009-24, section 2.12. There is case l aw and other IRS documents that address placed in service questions in the context of electric power plants. See, e.g.,- TECHNICAL SUPPORT DOCUMENT –

15 regulations, the taxable year in which property is “placed in service” is “the earlier of the following taxable years: (i) The taxable year in wh ich, under the taxpayer’s depreciation practice, the period for depreciation with respect to such property begins; or (ii) The taxable year in which the property is placed in a condition or state of readiness and availability for a specifically assigned function ....” 26 CFR §1.46-3(d )(1). 23 We solicit comment on issues associated with determining when the §48A credit “i s allowed.” For example, if EPA may review technology at a particular facility in a rul emaking that is finalized before such technology is placed in service at that facility, if the techn ology is subsequently placed in service – either in the same year in which the rulemaking is finalized or a later year – does the fact that the credit
has been allowed become relevant? 24
In addition, EPA solicits comment on a set of issue s that arise due to taxpayer privacy rights. Because of those rights, there is a limite d amount of information about the facilities affected by IRC §48A that is available to EPA. EPA does not have complete information as to
which of the facilities were allocated the tax cred it during Phase I (2006-2009); as noted above, EPA is aware of only the facilities that waived pri vacy rights. Moreover, EPA does not have specific information as to which of each facility’s property is treated as the “eligible property”
for which the tax credit was allocated. Nor does E PA have complete information as to the actual “use of [the] technology (or level of emissi on reduction solely by reason of the use of the technology)” or the actual “achievement of any emis sion reduction by the demonstration of [such] technology or performance level.” Nor does EPA have complete information as to whether, for any facility allocated the tax credit, (i) the allocated tax credit was forfeited because the eligible property was not placed in ser vice by the applicable deadline or (ii) the tax credit was allowed within the meaning of IRC §48A(g ). EPA solicits comment on all aspects of §48A(g), inc luding the interpretation of the provisions noted above. In addition, EPA invites f acilities affected by IRC §48A to submit, during the public comment period for the 2014 Proposal, re levant information, including information described in the immediately preceding paragraph, a s is consistent with their privacy concerns. Further, EPA solicits comment on how it should proc eed with its determination of the best

Olgethorpe Power Corp. v. Commissioner , T.C. Memo. 1990-505; Consumers Power Co. v. Commi ssioner , 89 T.C. 710 (1987); Rev. Rul. 76-256, 1976-2 C.B. 46.

23 The Treasury regulations provide “examples of case s where property shall be considered in a condition or state of readiness and availability for a specifically as signed function.” 26 CFR §1.46-3(d)(2).

24 As another matter of timing, the EPA solicits comm ent on whether the references to “use of technology ” and “achievement of ... emission reduction” mean that the only information that is precluded is information that the facility is **actually**

using the technology or is **actually** achieving emission reductions, as opposed to other information, such as that the facility is **planning** to use the technology. Arguably, interpreting the limitation to apply only to actual use may be consistent with int erpreting the limitation to apply only when the tax credit is allowed, which, as noted, is when the property is p laced in service.- TECHNICAL SUPPORT DOCUMENT –

16 system of emission reduction adequately demonstrate d under CAA §111(a)(1) if, by the time of the final rulemaking, it lacks relevant information – such as that described above -- with respect to facilities affected by IRC §48A. In particular, should EPA be precluded from relying on the “use of technology (or level of emission reduction solely by reason of the use of the technology)” or “achievement of any emission reduct ion by the demonstration of any technology or performance level” by or at any parti cular facility only if EPA has sufficient information concerning such technology or emission reduction for which the §48A tax credit was allocated, and that the §48A tax credit has bee n “allowed?” 25

Determination that Partial CCS is the Best System o f Emission Reduction
The EPA evaluated three alternative control technol ogy configurations as potentially representing the best system of emission reduction adequately demonstrated (BSER) for new
fossil fuel-fired boilers and IGCC units. The three alternatives are: (1) highly efficient new generation technology that does not include any lev el of CCS, (2) highly efficient new generation technology with “full capture” CCS (capt ure of at least 90 percent of CO 2 emissions), and (3) highly efficient new generation technology with “partial capture” CCS (capture of a smaller portion of the total CO 2 emissions). EPA discussed each of the alternative s in greater detail in the proposal, and explained why it determ ined that partial CCS qualifies as the BSER. EPA also included its rationale for selecting 1,100 lb CO 2 /MWh as the emission limitation for these sources and explained its rationale for the r equirements for geologic storage of the captured CO 2 .

Technical Feasibility The EPA proposed to find that partial CCS is techni cally feasible because each of its major components – the CO 2 capture, the compression and transportation, and t he injection and storage of CO 2 – has been demonstrated to be technically feasible . This is noted in examples of facilities currently in operation or un der development as well as an extensive literature record. These examples include both foss il fuel-fired EGUs and other industrial plants with characteristics very similar to EGUs currently in commercial operation, pilot-scale fossil fuel-fired EGUs currently in operation, and the pro gress towards completion of construction of fossil fuel-fired EGUs implementing CCS at commerci al scale designed to achieve limits significantly below the proposed standard. In discussing the rationale for the determination o f BSER and the resulting proposed

25 It should also be noted that credits are recapture d “with respect to any project which fails to attai n or maintain the separation and sequestration requirements” of 6 5% or 70%. IRC §48A(i). EPA does not have complete information as to whether, for any taxpayer, the be nefit of the tax credit was recaptured.- TECHNICAL SUPPORT DOCUMENT –

17 emission standards, the Agency referenced some plan ts and demonstration projects that have
received financial assistance under the EPAct05 or that have been allocated an investment tax credit under IRC§ 48A. As noted, the purpose of this TSD and the NODA it accompanies is to solicit comment on whether any pieces of the evidence presented in the 2014 Proposal may not be evaluated due to the limits imposed by the applicable EPAct05 pro visions, including IRC §48A(g), and, if so, whether the remaining evidence is sufficient to sup port a finding that partial CCS is technically feasible. As further discussed below, if the EPAct0 5 limits have any significance, it is with respect to the capture component. The compression and transport as well as injection and storage components have long been well-established. This TSD also notes additional evidence, indicated below, that has come to our attention sin ce the Administrator signed the 2014 Proposal. In light of the forward-looking nature o f the determination of technical feasibility,
based on information available to us as to which fa cilities have been allocated the §48A tax credit, even if we are obliged to exclude any infor mation about those facilities, we retain an adequate basis for our determination of technical f easibility based on other available information, as explained below.

Technical Feasibility of CO 2 Capture Technology Capture of CO 2 from industrial gas streams has occurred since the 1930s, 26 through use of a variety of approaches to separate CO 2 from other gases. In general, CO 2 capture technologies applicable to coal-fired power generat ion can be categorized into three approaches: (1) post-combustion systems that are de signed to separate CO 2 from the flue gas produced by fossil-fuel combustion in air; (2) pre -combustion systems that are designed to separate CO 2 from the high-pressure syngas produced at IGCC pow er plants; and (3) oxycombustion systems that use high-purity O 2 , rather than air, to combust fossil fuel and there by produce a highly concentrated CO 2 stream. Each of these three carbon capture approac hes is technologically feasible and has been demonstrated in other industries. Examples of each are
summarized below.

Post-combustion capture With regards to post-combustion CCS, in the 2014 Pr oposal, we relied on three types of projects: (1) small-scale capture projects operated commercially at coal-fired power plants, (2) demonstration projects at existing power plants, an d (3) large-scale projects in advanced stages of development at commercial power plants. EPA cite d in the preamble three projects that fall

26 A process for capturing CO 2 from flue gas was granted a patent in 1930. “Proc ess for Separating Acidic Gases”, US Patent 1,783,901 (December 2, 1930).- TECHNICAL SUPPORT DOCUMENT –

18 into the first category: The AES Warrior Run (Cumb erland, MD) and Shady Point (Panama, OK) coal-fired power plants are equipped with post-comb ustion amine scrubbers developed by ABB/Lummus to capture CO 2 for use in the food processing industry. 27 The Searles Valley Minerals soda ash plant (Trona, CA) has captured CO 2 from the flue gas of a coal-fired power plant via amine scrubbing for use in the production of soda ash. 28 In each of these cases, small amounts of flue gas are treated, but a large percen tage of CO 2 is removed (generally 90% or more) from the treated gas stream. The technologie s used in these plants are the same types
that would be evaluated for use at a new convention al coal-fired power plant. All three of these projects were developed and operated prior to EPAct05. These projects show that the technology can be designed, constructed and operate d in a commercial power plant environment at smaller scales. While those project s entail relatively small amounts of CO 2 removal (the two largest projects are designed to c apture about 800 tons CO 2 per day, about 13% of the amount a 500 MW coal plant would need to achieve a limit of 1,100 lb CO 2 /MWh), the technology used can be scaled up. As noted abo ve, under the case law, the determination of technical feasibility is forward-looking and may be based on reasonable projections, and here, EPA believes it is reasonable to project that the technology used by these projects can be scaled up. In particular, EPA believes the efforts at the Boundary Dam project alone demonstrate that companies are willing to pursue fu ll-scale projects at this time. Other projects described below further validate this beli ef. Further, comments by vendors indicate that they believe they are capable of scaling up th e technology. For instance, one vendor indicated as far back as 2009, the ability to suppl y a capture unit capable of capturing about 3,000 tons of CO 2 per day 29 , approximately half the amount needed to meet the requirements of the proposed rule for a new 500 MW coal plant. Building a system with two of these units would meet the requirements of the proposed rule. Projects that fall into the second category (demons tration projects) would include the 20 MW slip stream CCS demonstration at the AEP Moun taineer Plant in New Haven, WV. The demonstration using Alstom’s patented chilled ammon ia CO 2 achieved capture rates from 75 percent (design value) to as high as 90 percent, an d produced CO 2 at purity of greater than 99 percent, with energy penalties within a few percent of predictions. The facility reported robust steady-state operation during all modes of power pl ant operation including load changes, and saw an availability of the CCS system of greater th an 90 percent and captured and sequestered approximately 7,000 tons CO 2 per month during the period it operated. In addi tion to building

27 Dooley, J. J., et al. (2009). An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. U.S. DOE, Pacific Nor thwest National Laboratory, under Contract DE-AC05- 76RL01830.
28 IEA (2009), World Energy Outlook 2009, OECD/IEA, P aris.
29 From Page 12 of Dooley, J. J., et al. (2009).- TECHNICAL SUPPORT DOCUMENT –

19 and operating a 20 MW slip stream, a significantly larger 240 MW project has been designed for the site (further indication of an ability to scale up the technology). At this time AEP has stated that it is not moving forward with the project, not due to technical concerns, but rather
because AEP believes that the lack of a national CO 2 policy does not provide the necessary regulatory support for a project of this scale. 30,31 Another project is the 25 MW slip stream postcombustion capture project at Southern Company’s co al-fired Plant Barry near Mobile, AL. The project uses a commercially available Mitsubishi He avy Industries amine scrubbing system to capture CO 2 at a rate of over 90 percent. The captured CO 2 from Plant Barry is being transported to a nearby site for injection into a d eep saline geologic formation. Projects that fall into the third category (commerc ial scale) would include SaskPower’s Boundary Dam CCS Project which is being constructed in Estevan, a city in Saskatchewan, Canada. The project is the world’s largest commerci al-scale CCS project of its kind. The project will fully integrate the rebuilt 110 MW coal-fired Unit #3 with available post-combustion CCS technology to capture 90 percent of its CO 2 emissions. The captured CO 2 will be utilized for enhanced oil recovery (EOR) operations in nearby oi l fields. The facility is currently under construction with full operation expected in 2014. To EPA’s knowledge, the Boundary Dam project has not received any assistance under EPAct 05. Finally, NRG Energy is developing a commercial-scal e post-combustion carbon capture project at the company's W.A. Parish generating sta tion southwest of Houston, Texas. This project, which has received financial assistance fr om the EPAct05 CCPI, is expected to be operational in 2015 and provides a third example th at the technology can be scaled up. The information on which the 2014 Proposal relies, in conjunction with the literature and other information noted below, is by no means l imited to facilities that received assistance under EPAct05 and, as result, the limitations on th e use of information from such facilities do not preclude EPA from relying on such facilities, a long with other information, to determine that post-capture is technically feasible. As note d above, EPA has incomplete information as to the facilities affected by the §48A tax credit. How ever, even if EPA cannot rely, in any manner,

30 AEP “is placing its plans to advance carbon dioxide cap ture and storage ( CCS ) technology to commercial scale on hold, citing the current uncertain status of U.S. c limate policy and the continued weak economy as con tributors to the decision”. From a July 17, 2011 AEP press release ( www.aep.com/newsroom/newsreleases/?id=1704 ).

31 As part of Phase I, AEP and its partners developed a front-end engineering and design package for the commercial-scale that incorporated knowledge gained and lessons learned (construction and operations r elated) from the pilot system and the design package also e stablished the fit, form, and function of the proje ct including design criteria, mass and energy balances, plot pla ns, general arrangement drawings, electrical one-li nes, flow diagrams, P&IDs, etc. AEP Report prepared for The Global CCS Institute, Project #PRO 004, January 201 2, “CCS Lessons Learned Report, American Electric Power Mou ntaineer CCS II Project Phase 1”. Available at http://cdn.globalccsinstitute.com/sites/default/fil es/publications/32871/ccs-lessons-learned-report-gc csi-final-01- 23-2012.pdf- TECHNICAL SUPPORT DOCUMENT –

20 on information from such facilities, the informatio n available from other facilities, noted above, that do not appear to have been affected by the tax credit, along with the literature, is sufficient to demonstrate technical feasibility.

Pre-combustion Capture In the proposed rule, we prominently discussed the development of the Kemper County Energy Center, the Texas Clean Energy Project, and the Hydrogen Energy California projects – all IGCC units that will capture at least 65 percen t CO 2 capture for EOR operations. All of these facilities have received EPAct05 CCPI funding and h ave been allocated IRC section 48A tax credits. However, the technology that will be used in these projects – pre-combustion CO 2 capture from a syngas stream – is very well demonst rated technology. As a result, even if EPA is unable to rely in any manner on information from th ose facilities, EPA has sufficient information to determine that pre-combustion is tec hnically feasible. One of the best examples of pre-combustion CO 2 capture from a coal gasification stream is at the Dakota Gasification Company’s Great Plain s Synfuels Plant located in Beulah, North Dakota. While the facility is not an EGU, it is fu nctionally very similar to an electric power producing IGCC plant. The plant is a coal gasificat ion facility that uses North Dakota lignite to produce a syngas stream that is catalytically shift ed to the desired composition of CO 2 , CO and
H 2 . The facility then uses a pre-combustion Rectisol® system to capture the CO 2 before the syngas is converted to synthetic natural gas (i.e., methane) via a methanation process. The captured CO 2 is purified, compressed and transported via a 200- mile pipeline for use in EOR operations and storage in the Weyburn oil field in Saskatchewan, Canada. The facility began sending captured CO 2 to Canada in October 2000, reducing CO 2 emissions from the plant by about 45 percent. As of December 31, 2012, the fac ility had captured more than 24.5 million
metric tons of CO 2 . If the synthetic natural gas produced by the fac ility were utilized on-site in a combined cycle unit for power production, then the facility would be, for all practical purposes, an IGCC unit. This project demonstrates the abilit y of carbon capture and sequestration to be utilized with a fossil fuel gasification system cre ating synthetic natural gas that is compatible with existing natural gas combined cycle (NGCC) tec hnology. These are all of the major components that would be needed at a new IGCC unit that was designed to meet the requirements of the proposed standards. From a cap ture standpoint, this project demonstrates the ability to separate and capture gas from a gasi fication system that could be used at an IGCC facility. The transportation, injection and storag e components of this project are also directly applicable to an IGCC. The only part of an IGCC wi th CCS process that this project does not demonstrate is the integration of the gasification system with the combined cycle unit power block – a technology that is very well demonstrated . A number of existing IGCC projects without CCS (e.g., the Wabash River and Polk IGCC facilitie s) demonstrate the ability to construct and- TECHNICAL SUPPORT DOCUMENT –

21 operate an integrated gasification and combined cyc le unit. Collectively, these projects demonstrate the operation and integration of all of the major components of an IGCC with CCS. All of the major core components of CCS – the captu re, the compression and transportation, and the injection and storage – have been successfu lly demonstrated at the Great Plains Synfuels Plant and the Weyburn oil field; and, as s tated earlier, it is not necessary that all of those components be demonstrated at an electricity generating plant. Thus, the EPA believes that the experience at the Dakota Gasification Grea t Plains Synfuels Plant adequately demonstrates the technical feasibility of pre-combu stion capture CCS and all of its core
components. The Coffeyville Gasification Plant in Coffeyville, Kansas is another example of industrial fossil-fuel gasification with subsequent CO 2 capture. The facility converts petroleum coke into a hydrogen-rich synthetic gas that is used to produce ammonia, urea and ammonium nitrate
fertilizers as well as other chemicals. The CO 2 captured at the facility has been used internally for fertilizer production. Recently the capture ca pacity was increased and the additional captured CO 2 is being transported by pipeline to oil fields in Osage County, Oklahoma for use in EOR operations. The project, which commenced operat ion in 2013, is expected to capture nearly 1 million tonnes of CO 2 per year. As with post-combustion capture, the above-describe d information, in conjunction with the literature and other information noted below, i s not limited to technology from facilities that received assistance under EPAct05 and, as resu lt, the limitations on the use of such information do not preclude EPA from relying on suc h information, along with other information, to determine that post-combustion capt ure is technically feasible. And also as with post-combustion capture, although EPA has inco mplete information as to the facilities affected by the §48A tax credit, even if EPA cannot rely, in any manner, on information from such facilities, the information available from oth er facilities, noted above, that do not appear to have been affected by the tax credit, in conjunc tion with the literature and other information described below, is sufficient to demonstrate techn ical feasibility.

Oxy-combustion In the 2014 Proposal, we relied on the technical fe asibility and availability of post- and pre-combustion capture as the basis for our BSER de termination. In addition, we also noted the additional option of oxy-combustion. Oxy-combustion of coal is being demonstrated in a 10 MWe pilot facility in Germany. The Vattenfall Schwa rze Pumpe Power Station in eastern Germany has been operating since September 2008 and plans to operate for at least 10 years. It is designed to capture 70,000 tonnes of CO 2 per year.- TECHNICAL SUPPORT DOCUMENT –

22 A larger scale project – the FutureGen 2.0 Project – is in advanced stages of planning in
the U.S. 32 This project is being jointly developed by DOE an d industry partners and has received funding under provisions of EPAct05.

Carbon Capture and Mineralization
Other novel CO 2 capture and storage technologies are in the advanc ed stages of development and demonstration. For example, Skyoni c 33 has developed a technology for the capture and permanent sequestration of CO 2 in mineral form (i.e., as carbonates). The company recently broke ground on a commercial-scale carbon capture and mineralization plant
– the SkyMine 

## ® process – at a cement factory in San Antonio, TX. The facility, which will be completed and operational in 2014, will use proven chemical engineering components to capture CO 2 from a coal-fired boiler at the cement plant and s equester the CO 2 through
mineralization. This process transforms the captured CO 2 into solid products, effectively storing
CO 2 and generating revenue. The process is applicable to a wide variety of CO 2 gas streams and has been piloted at several coal-fired power plants

.

Literature The current status of CCS technology was described and analyzed by the 2010 Interagency Task Force on CCS, established by Presi dent Obama on February 3, 2010, cochaired by the DOE and the EPA, and composed of 14 executive departments and federal agencies. The Task Force was charged with proposing a plan to overcome the barriers to the widespread, cost-effective deployment of CCS within 10 years, with a goal of bringing five to ten commercial demonstration projects online by 201 6. The Task Force found that, although early CCS projects face economic challenges related to climate policy uncertainty, first-of-a-kind technology challenges, and the current cost of CCS relative to other technologies, there are no insurmountable technological barriers that prevent CCS from playing a role in reducing GHG
emissions. 34 The Pacific Northwest National Laboratory (PNNL) re cently prepared a study that evaluated the development status of various CCS tec hnologies for the DOE 35 . The study

32 In cooperation with the U.S. Department of Energy (DOE), the FutureGen 2.0 project partners will upgr ade a power plant in Meredosia, IL with oxy-combustion te chnology to capture approximately more than 90 perc ent of the plant’s carbon emissions. http://www.futuregena lliance.org/

. 33 http://skyonic.com/

34 Report of the Interagency Task Force on Carbon Cap ture and Storage (August 2010), page 7.

35 Dooley, J. J., et al. (2009). An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009. U.S. DOE, Pacific Nor thwest National Laboratory, under Contract DE-AC05- 76RL01830.- TECHNICAL SUPPORT DOCUMENT –

23 addressed the availability of capture processes, tr ansportation options (CO 2 pipelines), injection technologies, and measurement, verification and mon itoring technologies. The study concluded that, in general, CCS is technically viable today a nd that key component technologies of complete CCS systems have been deployed at scales l arge enough to meaningfully inform discussions about CCS deployment on large commercia l fossil-fired power plants. In addition, DOE’s National Energy Technology Laboratory (NETL) has prepared other reports – in particular their “Cost and Performance Baseline” reports, 36 including one on partial capture 37 -- that further support our proposed determination of the t echnical feasibility of partial capture. The latter DOE-NETL report includes schematic diagrams and descriptions of both post-combustion and pre-combustion partial capture systems. It sho uld be noted that while some literature may
refer to facilities that have received assistance u nder EPAct05, a great deal of literature does

not.

Other Industrial CCS Projects The DOE/NETL currently lists three active projects under its Industrial Carbon Capture and Storage (ICCS) program. While none of these pl ants are EGUs, they are demonstrating the core components of CCS that could be directly appli cable to a new fossil fuel-fired EGU – the capture, the compression and transportation, and th e injection and storage. Air Products and Chemicals, Inc. (Allentown, PA) ha s retrofitted its two Port Arthur, TX steam methane reformers (SMRs) with a vacuum swing adsorption (VSA) system to separate
the CO 2 from the process gas stream, followed by compressi on and drying processes. This process, which began operation in May 2013, will co ncentrate the initial stream containing from 10-20 percent CO 2 to greater than 97 percent CO 2 purity. Archer Daniels Midland Company (ADM, Decatur, IL) w ill demonstrate an integrated system for collecting CO 2 from an ethanol production plant and geologically sequester it in the Mt. Simon Sandstone, a saline reservoir in the Illi nois Basin. Leucadia Energy, LLC (Lake Charles, LA) will demons trate the capture of CO 2 from an industrial petroleum coke gasification facility (th at produces methanol and other chemicals). The captured CO 2 will be transported to oil fields in Texas for use in EOR operations.

36 The “Cost and Performance Baseline” reports are a series of reports by DOE/NETL that establish estima tes for the cost and performance of combustion- and gasific ation-based power plants - all with and without CO 2 capture and storage. Available at http://netl.doe.gov/resea rch/energy-analysis/energy-baseline-studies.

37 “Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture”, DOE/NETL-2011/149 8, May 27, 2011.- TECHNICAL SUPPORT DOCUMENT –

24 Global CCS Institute Assessment
In its most recent “Global Status of CCS 2013: A Su mmary,” 38 the Global CCS Institute 39 found that “CCS technology is well understood, and a reality.” They also stated that “CCS is often mistakenly perceived as an unproven or experi mental technology. In reality, the technology is generally well understood and has bee n used for decades at a large scale in certain applications.” The report noted that CCS i s happening now and continuing to grow at a strong pace, with 12 large–scale integrated project s in operation. These projects are listed in the table below. Again, while none of these plants are EGUs, they are demonstrating the core components of CCS that could be directly applicable to a new fossil fuel-fired EGU – the capture, the compression and transportation, and th e injection and storage.

Worldwide Large-scale Integrated CCS Projects in Op eration Identified by Global CCS Institute

Project Location Storage Industry Air Products Steam Methane Reformer EOR Project USA EOR Hydrogen Production

Century Plant USA EOR Natural Gas Processing Coffeyville Gasification Plant USA EOR Fertilizer P roduction

Enid Fertilizer CO 2 -EOR Project USA EOR Fertilizer Production Great Plains Synfuel Plant and Weyburn-Midale

Project USA/Canada EOR Synthetic Natural Gas

In Salah CO 2 Storage Africa Deep saline injection Natural Gas Processing

Lost Cabin Gas Plant USA EOR Natural Gas Processing Petrobras Lula Oil Field CCS Project Brazil EOR Nat ural Gas Processing Shute Creek Gas Processing Facility USA EOR Natural Gas Processing Sleipner CO 2 Injection Europe Deep saline injection Natural Gas Processing

Snøhvit CO 2 Injection Europe Deep saline injection Natural Gas Processing

Val Verde Natural Gas Plants USA EOR Natural Gas Proc essing

38 Available at http://www.globalccsinstitute.com/publications/glob al-status-ccs-2013

39 The Global Carbon Capture and Storage (CCS) Instit ute (www.globalccsinstitute.com) is an independent, not-forprofit company registered under the (Australian) Co rporations Act 2001 (Cth). The Institute’s mission is to accelerate the development, demonstration and deplo yment of CCS globally. The Institute was launched with strong and widespread support from governments, cor porations, industry bodies and research organizatio ns from key markets around the globe, and has built a diver sified membership profile that represents a healthy crosssection of these international stakeholders. The di versity in membership ensures the Institute’s endea vors and services provided reflect the varied and evolving n ature of the challenges faced by the industry.- TECHNICAL SUPPORT DOCUMENT –

25 Summary of CO 2 Capture
There is an extensive amount of information availab le supporting the technical feasibility of post-combustion capture, pre-combust ion capture, and oxy-combustion capture. For each type of capture, there is information othe r than from facilities that received any DOE assistance under EPAct05, including facilities that pre-date EPAct05, literature that does not rely on facilities that have received assistance un der EPAct05, and foreign facilities. Accordingly,
none of the facilities that received EPAct05 assist ance must be precluded from EPA’s basis due to EPAct05 §§402(i) or 421(a). We also solicit comm ent on whether there is a sufficient basis for our proposed determination of technical feasibility even without any reference to any facility receiving assistance under EPAct05. With respect to the limits imposed by IRC §48A(g), if that provision is interpreted narrowly, to be consistent with EPAct05 §402(i) – a nd putting aside, for present purposes, the other questions of interpretation of §48A, discusse d above -- then, as with EPAct05 §402(i), for each type of capture, there is evidence from other facilities and the literature that is not affected by §48A(g), and as a result, none of the f acilities that were allocated the §48A tax credit must be precluded from EPA’s analysis. If, o n the other hand, §48A(g) is interpreted to preclude any reliance on any information from facil ities that have been allocated the credit, it is possible that some of this evidence may be preclude d from analysis, but, as noted, the remaining evidence is sufficient to support the det ermination of technical feasibility. We solicit
comment on what evidence suffices to demonstrate te chnical feasibility of CO 2 capture technology.

Technical Feasibility of CO 2 Compression and Transportation Carbon dioxide has been compressed and transported via pipelines in the U.S. for nearly 40 years 40 . Approximately 50 million metric tons of CO 2 are transported each year through 3,600 miles of pipelines. The majority of this CO 2 has been transported for use in EOR operations. Much of this CO 2 was supplied by facilities other than EGUs, but th e compression and transportation technology is the same as the te chnology used by EGUs. For these reasons, EPA determines that the compression and transportat ion component of CCS is well-established as technically feasible; and that determination doe s not depend solely on information from projects receiving assistance under the EPAct05, an d remains valid even if facilities allocated the IRC §48A tax credit are excluded (again, puttin g aside for present purposes the other questions of interpretation of §48A, discussed abov e).

40 “Comparing Existing Pipeline Networks with Potenti al Scale of Future U.S. CO 2 Pipeline Networks”, PNNL Report PNNL-17381, February, 2008.- TECHNICAL SUPPORT DOCUMENT –

26 Technical Feasibility of CO 2 Injection and Storage Scientific understanding, coupled with existing pro ject and regulatory experience (including EOR), research, and analogs (e.g. natura lly existing CO 2 sinks, natural gas storage, and acid gas injection), demonstrate that geologic sequ estration is a viable long term CO 2 storage option. The first part of this basis is a demonstra ted understanding of the fate of CO 2 in the subsurface. Geologic sequestration occurs through a combination of structural and stratigraphic trapping (trapping below a low permeability confini ng layer), residual CO 2 trapping (retention as an immobile phase trapped in the pore spaces of the storage formation), solubility trapping (dissolution in the in situ formation fluids), mine ral trapping (reaction with the minerals in the storage formation and confining layer to produce ca rbonate minerals), and preferential adsorption trapping (adsorption onto organic matter in coal and shale). 41,42 These mechanisms are functions of the physical and chemical properti es of CO 2 and the geologic formations into
which the CO 2 is injected. Project and research experience adds to the confid ence in geologic sequestration as a
viable CO 2 reduction technology. There are four existing comm ercial CCS facilities in other countries, 43 and in addition, multiple studies have been comple ted that have demonstrated geologic sequestration of CO 2 as well as have improved technologies to monitor a nd verify that
the CO 2 remains sequestered. 44 For example, CO 2 has been injected in the SACROC Unit in the Permian basin since 1972 for enhanced oil recovery purposes. A study evaluated this project, and estimated that from 1972 to 2005, about 93 mill ion metric tons of CO 2 were injected and
about 38 million metric tons of CO 2 were produced, resulting in a geologic CO 2 accumulation of
55 million metric tons of CO 2 . 45 This study evaluated the ongoing and potential CO 2 trapping occurring through various mechanisms using modeling and simulations, and collection and analysis of seismic surveys and well logging data. The monitoring at this site confirmed that CO 2 can become trapped in geologic formations. Studies on the permanence of CO 2 storage in geologic sequestration have been conducted internat ionally as well. For example, the Gorgon Carbon Dioxide Injection Project and Collie-South W est CO 2 Geosequestration Hub project in

41 Intergovernmental Panel on Climate Change. (2005). **Special Report on Carbon Dioxide Capture and Storag e.**  Retrieved from http://www.ipcc.ch/pdf/special-repor ts/srccs/srccs_chapter5.pdf

42 Benson, Sally M. and David R. Cole. (2008). **CO 2**  **Sequestration in Deep Sedimentary Formations** . Elements , Vol. 4, pp. 325–331.
43 Sleipner in the North Sea, Snøhvit in the Barents Sea, In Salah in Algeria, and Weyburn in Canada.

44 Report of the Interagency Task Force on Carbon C apture and Storage (August 2010).

45 Han, Weon Shik et al. (2010). **Evaluation of trapping mechanisms in geologic CO 2**  **sequestration: Case study of SACROC northern platform, a 35-year CO**  **2 injection site**  . American Journal of Science Online April 2010 vol . 310 no. 4 282-324. Retrieved from: http://www.ajsonline.org /content/310/4/282.abstract- TECHNICAL SUPPORT DOCUMENT –

27 Australia have both demonstrated geologic CO 2 trapping mechanisms. 46 As with compression and transportation, much of the technology for inje ction and sequestration has been used for
CO 2 emitted by facilities other than EGUs, but the inj ection and sequestration technology is the same as the technology used by EGUs. In addition, CO 2 storage reserves are available throughout the U.S. The Department of Interior’s U.S. Geological Survey (USGS) has recent ly completed a comprehensive evaluation of the technically accessible storage resource for car bon storage for 36 sedimentary basins in the
onshore areas and State waters of the United States

. 47 The USGS assessment estimates a mean of 3,000 billion metric tons of subsurface CO 2 storage potential across the United States. For comparison, this amount is 500 times the 2011 annua l U.S. energy-related CO 2 emissions of 5.5 Gigatons (Gt). 48 According to the USGS assessment, nearly every st ate in the U.S. has or is in close proximity to formations with carbon storage p otential, including vast areas offshore. Geologic storage options also include use of CO 2 in EOR, which is the injection of fluids into a reservoir to increase oil production efficie ncy. EOR is typically conducted at a reservoir after production yields have decreased from primary production. Fluids commonly used for EOR include brine, fresh water, steam, nitrogen, alkali solutions, surfactant solutions, polymer solutions, and CO 2 . EOR using CO 2 , sometimes referred to as ”CO 2 flooding” or CO 2 -EOR, involves injecting CO 2 into an oil reservoir to help mobilize the remainin g oil and make it available for recovery. A crude oil and CO 2 mixture is produced, and sent to a separator where the crude oil is separated from the gaseous hydroca rbons and CO 2 . The gaseous CO 2 -rich stream then is typically dehydrated, purified to re move hydrocarbons, recompressed, and reinjected into the oil or natural gas reservoir to f urther enhance recovery.
CO 2 -EOR has been successfully used at many production fields throughout the U.S. to increase oil recovery. The oil and natural gas indu stry in the United States has over 40 years of experience of injection and monitoring of CO 2 in the deep subsurface for the purposes of enhancing oil and natural gas production. This expe rience provides a strong foundation for the injection and monitoring technologies that will be needed for successful deployment of CCS. Monitoring CO 2 at EOR sites can be an important part of the petro leum reservoir

46 Sewell, Margaret, Frank Smith and Dominique Van Gen t. Western Australia Greenhouse Gas Capture and Storage: A tale of two projects. (2012) Australian Department of Resources, Energy and Tourism and Wes tern Australia Government of Western Australia. Retrieve d from http://cdn.globalccsinstitute.com/sites/default/fil es/publications/39961/ccsinwareport-opt.pdf

47 U.S. Geological Survey Geologic Carbon Dioxide Sto rage Resources Assessment Team, 2013, National asse ssment of geologic carbon dioxide storage resources – Resu lts: U.S. Geological Survey Circular 1386, 41 p., http://pubs.usgs.gov/fs/2013/1386/.

48 U.S. Geological Survey Geologic Carbon Dioxide Sto rage Resources Assessment Team, 2013, National asse ssment of geologic carbon dioxide storage resources – Summ ary: U.S. Geological Survey Factsheet 2013-3020, 6p.http://pubs.usgs.gov/fs/2013/3020/.- TECHNICAL SUPPORT DOCUMENT –

28 management system to ensure the CO 2 is effectively sweeping the oil zone, and can be supplemented by techniques designed to detect CO 2 leakage. Recently, many studies have been conducted to better understand the fate of injected CO 2 at well-established, operational EOR sites. A large number of methods are available to m onitor surface and subsurface leakage at EOR sites. Some recent studies are presented below. At the SACROC field in the Permian Basin, the Texas Bureau of Economic Geology conducted an extensive groundwater sampling program to look for evidence of CO 2 leakage in the shallow freshwater aquifers. At the time of the study (2011), the SACROC field had injected
175 million metric tons of CO 2 over 37 years. No evidence of leakage was detected

. 49

An extensive CO 2 leakage monitoring program was conducted by a thir d party (International Energy Agency Greenhouse Gas Program me) for 10 years at the Weyburn oil field in Saskatchewan, during which time over 16 million tonnes of CO 2 have been stored. A comprehensive analysis of surface and subsurface mo nitoring methods was conducted and resulted in a best practices manual for CO 2 monitoring at EOR sites. 50 The Texas Bureau of Economic Geology has also been testing a wide range of surface and subsurface monitoring tools and approaches to d ocument storage efficiency and storage permanence at a CO 2 EOR site in Mississippi. 51 The Cranfield Field, under CO 2 flood by Denbury Onshore LLC, is a depleted oil and gas reservoir th at injected greater than 1.2 million tons/year during the tests. The preliminary findings demonstr ate the availability and effectiveness of many different monitoring techniques for tracking C O 2 underground and detecting CO 2 leakage. The Department of Energy has conducted numerous eva luations of CO 2 monitoring techniques at EOR pilot sites throughout the U.S. a s part of the Regional Sequestration Partnership Phase II and III programs and have crea ted a ‘Best Practices’ guide for monitoring, verification, and accounting of CO 2 stored in deep geologic formations from that exper ience. 52

As with CO 2 compression and transportation, EPA determines tha t the injection and

49 K.D. Romanak, R.C. Smyth, C. Yang, S.D. Hovorka, M . Rearick, J. Lu. (2011). **Sensitivity of groundwater systems to CO2: Application of a site-specific analysis of car**  **bonate monitoring parameters at the SACROC CO 2**  **-enhanced oil field**  . GCCC Digital Publication Series #12-01. Retrieved from http://www.beg.utexas.edu/gccc/forum/codexdownloadp df.php?ID=190

50 Geoscience Publishing. (2012). **Best Practices for Validating CO 2**  **Geological Storage: Observations and Guidance from the IEAGHG Weyburn-Midale CO**  **2 Monitoring and Storage Project**  . Brian Hitchon (Ed.),

51 Hovorka, S.D., et al. (2011). **Monitoring a large volume CO 2**  **injection: Year two results from SECARB project at Denbury’s Cranfield, Mississippi, USA**  : Energy Procedia, v. 4, Proceedings of the 10th In ternational Conference on Greenhouse Gas Control Technologies GHGT10, Septemb er 19-23, 2010, Amsterdam, The Netherlands, p. 3478

- 3485. GCCC Digital Publication #11-16. Retrieved fr om http://www.sciencedirect.com/science/article/pii/S1 876610211004711
52 DOE/NETL. (2012). **Best Practices for: Monitoring, Verification, and Ac counting of CO**  **2 Stored in Deep Geologic**  **Formations – 2012 Update** . DOE/NETL-2012/1568. Retrieved from http://www.netl.doe.gov/technologies/carbon_seq/ref shelf/BPM-MVA-2012.pdf

.- TECHNICAL SUPPORT DOCUMENT –

29 storage component of CCS is well-established as tec hnically feasible; and that determination does not depend solely on information from projects receiving assistance under the EPAct05,
and remains valid even if facilities allocated the IRC §48A tax credit are excluded (again, putting aside for present purposes the other questions of i nterpretation of §48A, discussed above).

Costs As noted in the preamble for the 2014 Proposal and summarized above, according to the D.C. Circuit case law, control costs are treate d as acceptable as long as they are reasonable (which, as noted above, is EPA’s shorthand for the various formulations the Court has used, including, among others, that costs cannot be “exc essive” or “unreasonable”) 53

. . In determining the amount of costs for partial CCS, the EPA relied on DOE/NETL “Cost and Performance” reports 54 . DOE/NETL established the costs of new coal-fired electric power plants with partial CCS on a “next-of-a-kind” basis , so that those new plants would not bear the higher, “first-of-a-kind” costs. Those next-of-a-k ind cost estimates remain valid, notwithstanding any limitations imposed by any of t he provisions of EPAct05. 55 In this rulemaking, EPA is authorized to base cost estimate s on that premise – that new plants will be the next-of-a-kind – because that is factually true , and there is no reasonable reading of IRC §48(g) or any of the other EPAct05 provisions that would mandate that new plants be treated as having first-of-a-kind costs. In this context, nothing in IRC §48A(g) or the other relevant EPAct provisions precludes the recognition that new plants follow ones currently under construction or in the planning stages -- such as K emper, TCEP, and HECA – and therefore that new plants must be treated as next-of-a-kind. To r equire that new plants be treated as first-ofa-kind on grounds that, for example, under IRC §48A (g), Kemper, TCEP, and HECA, cannot form part of the basis for the cost analysis because the y have been allocated the §48A credit, 56 would be contrary to the clear facts. In any event , as discussed above, even without referring to any plant that has been allocated the credit, ot her plants have sufficiently demonstrated the technology so that, on those grounds, too, new plan ts must be considered next-of-a-kind. As discussed in the 2014 Proposal, the EPA examined costs of new fossil fueled power

53 79 FR 1464
54 The ‘‘Cost and Performance Baseline’’ reports are a series of reports by DOE/NETL that establish esti mates for the cost and performance of combustion- and gasifi cation-based power plants— all with and without CO 2 capture and storage. Available at http://netl.doe.gov/resea rch/energy-analysis/energy-baseline-studies

55 It should also be noted that the NETL studies did not take into account the possibility that a coal-f ired electric power plant with partial CCS may receive assistance under EPAct05, including the IRC §48A tax credit. By the same token, EPA, in the 2014 Proposal, also explicitly n oted that the estimated costs “do not include the i mpact of subsidies that may potentially be available to deve lopers of new projects that include CCS.”

56 Here again, for convenience, we will put aside for the moment the other issues of interpretation of I RC §48A described above.- TECHNICAL SUPPORT DOCUMENT –

30 generation options – including for new NGCC units, for new supercritical and IGCC units with no CCS, and for those units with partial capture CCS i nstalled such that their emissions would meet the proposed 1,100 lb CO 2 /MWh standard. We determined that, while new coal- fired generation that includes partial CCS is more expens ive than either new NGCC generation or new coal-fired generation without CCS, it is compet itive with new nuclear power, which, besides natural gas combustion turbines, is the pri ncipal other option often considered for providing new base load power with a lower carbon f ootprint. It is also competitive with biomass-fired generation, which is another generati on technology often considered for low carbon base load power. Because the costs are comp arable, the EPA determined that, at the proposed emission limitation of 1,100 lb CO 2 /MWh, the cost of new coal-fired generation that includes partial CCS is not unreasonable. 57 It should be noted that even without comparison to such other electricity generation, the costs are acceptable because (i) they meet the D.C. Circuit’s standards for acceptable costs (e.g., as noted above, not excessive or unreasonabl e), and (ii) EPA exercises its authority in determining the best system of emission reduction a dequately demonstrated to, in this case, give greater weight to the need to promote CCS tech nology, notwithstanding its higher costs.

Amount of Emission Reductions and Promotion of Tech nology Although this TSD and the accompanying NODA focus o n the technical feasibility and cost components of the BSER determination – because it is those components that are primarily affected by the EPAct05 provisions – we r eiterate our views in the 2014 Proposal that the other components of that determination support identifying partial CCS as the BSER. As discussed in the 2014 Proposal, EPA has discretion in weighing the various components, and for this rulemaking, an important component is the amou nt of reductions achieved. For post combustion capture, all of the projects cited above are designed to capture 90% or more of the
CO 2 from the flue gas treated. The projects currently operating are capturing from approximately 200 tons per day to 800 tons per day. Projects cited above under development
demonstrate the industries’ belief that the technol ogy can be designed and operated at larger scales necessary to capture 50+% of the CO 2 from a 500 MW coal-fired power plant. Another particularly important component for this r ulemaking is to advance technology. Identifying partial CCS as the BSER does so by prom oting the utilization of CCS. This is because any new fossil fuel-fired utility boiler or IGCC un it will need to install partial capture CCS in order to meet the emission standard. Particularly b ecause the technology is relatively new, additional utilization is expected to result in imp rovements in the performance technology and in cost reductions. Moreover, identifying partial c apture CCS as the BSER will encourage

57 79 FR 1477- TECHNICAL SUPPORT DOCUMENT –

31 continued research and development efforts, such as those sponsored by the DOE/NETL. In contrast, not identifying partial CCS as the BSER c ould potentially impede further utilization and development of CCS. It is important to promote depl oyment and further development of CCS technologies because they are the only technologies that are currently available or are expected to be available in the foreseeable future that can make meaningful reductions in CO 2 emissions from fossil fuel-fired utility boilers an d IGCC units.

.- TECHNICAL SUPPORT DOCUMENT –

32 Appendix Summary of Key Projects Considered and EPA’s Unders tanding of Use of Financial Incentives
under EPAct05

Project
Name Location Overview Funding under
EPAct05? 58 Allocation of

tax credit
under IRC §48A? Post Combustion Capture
Searless Valley
Mineral Soda
Ash Trona, CA 800 tons per day, began operating in 1976 No No

AES - Warrior
Run Cumberland, MD 200 tons per day, began operating in 2000 No No

AES - Shady
Point Panama, OK 800 tons per day, began operating in 2001 No No

AEP
Mountaineer New Haven, WV 7,000 tons/month, began operating in 2009 (operated for 12-18 months) Yes No

Southern Company, Plant Barry Mobile, AL 500 tons/day, began operating in 2011 Yes No

SaskPower, Boundary Dam Estevan, SK,

Canada 1,000,000 ton/year,

scheduled to come on line in April 2014 No No

NRG (Petra Nova) – WA
Parish Plant Houston, TX 1,400,000 tons/year, scheduled start date,
2016 Yes No

Pre-combustion Capture

Dakota
Gasification Company –
Great Plains Synfuels Beulah, ND Over 2,000,000 tons/year on average
since 2000. No No

Coffeyville
Gasification
Plant Coffeyville, KS Separated about 850,000 tons of CO 2 per year. Until 2013, small
amounts were used for Yes No

58 This category includes allocation of the tax credi t under IRC §48B.- TECHNICAL SUPPORT DOCUMENT –

33 fertilizer production and
most was vented to the air. In 2013, began capturing an additional 650,000 tons/year for

EOR
Southern Company – Kemper County Energy Facility Kemper County,
MS Scheduled to commence

operation in late 2014. Deigned to capture 65%
of CO 2 , approximately 3,500,000 tons/year CO 2 Yes Yes

Summit
Power’s Texas Clean Energy Project Odessa, TX In advanced stages of financing (have contracts for electricity, CO 2 and fertilizer production). Designed to capture. Designed to capture 90%
of CO 2 (approximately 3,000,000 tons/year) Yes Yes

Hydrogen Energy
California Kern County, CA In advanced stages of project development Designed to capture 90%
of CO 2 (approximately 3,000,000 tons/year Yes Yes