### From: Szabo, Aaron <Aaron_L_Szabo@omb.eop.gov> Sent: Wednesday, July 29, 2015 10:05 PM To: Culligan, Kevin; Vasu, Amy; Harvey, Reid Cc: Frey, Nathan J.; Grossman, Andrea Subject: Summary of Interagency Comments Under EO 12866 and 1356 - GHG Mitigation TSD

Attached please find a summary of interagency comments under EO 12866 and 13563 on the GHG Mitigation TSD.
Thank you and please let know if you have any questions.

<< Summary of Interagency Comments Under_EO 12866_ 13563_GHG_Mitigation_TSD.docx >>Chapter 7: Carbon Capture & Storage

Introduction Another possible approach for reducing CO 2 emissions from exis ting fossil fuel-fired steam generating EGUs is through the application of carbon capture and storage technology (CCS; sometimes also referred to as carbon capture and sequestration). In the final standards of performance for new fossil fuel-fired EGUs, the EPA has determined that the best system of emission reduction (BSER) for new fossil fuel-fired steam generating units is implementation of partial CCS (i.e., capturing a portion of the CO 2 from the emission stream – in contrast to “full CCS” which would involve capturing > 90% of the CO 2 from the emissions). The EPA has determined that that, for new steam generating EGUs (utility boilers and IGCC units), partial CCS has been adequately demonstrated; it is technically feasible; it can be implemented at reasonable costs; it provides meaningful emission reductions; and its implementation will serve to promote further development and deployment of the technology. This chapter examines the potential for implementation of CCS technology at existing fossil fuel-fired steam generating
EGUs.

Carbon Capture Options for Exis ting Fossil Fuel-fired EGUs In general, CO 2 capture technologies applicable to existing fossil fuel-fired powergeneration can be categorized into three approaches – (1) post-combustion capture; (2) precombustion capture; and (3) oxy-combustion. Each of these is described and discussed in more
detail below. Post-combustion Capture
Post-combustion CO 2 capture refers to removal of CO 2 from a combustion flue gas prior to discharging to the atmosphere. Separating CO 2 from such a gas stream can be challenging for
a number of reasons. Because CO 2 is a dilute fraction of the combustion flue gas – typically 13- 15 % in coal-fired systems and 3-4 % in natural gas-fired systems – a large volume of flue gas must be treated. The flue gas from typical combustion systems is usually at near atmospheric pressure. Therefore, most of the available capture systems rely on chemical absorption (chemisorption) options (e.g., using amines) that require added energy to release the captured
CO 2 and regenerate the solvent. Many of the chemical solvents require a flue gas stream that is free of or has very low quantities of components – such as SO 2 and HCl – that can degrade the Commented [A1]: Chapter number doesn’t match what is in the introduction.solvent. The captured CO 2 , if it is to be transported via pipeline for storage or use in enhanced oil recovery (EOR), must then be compressed from near atmospheric pressure to much higher pipeline pressures (about 2,000 psia).

Pre-combustion Capture Pre-combustion capture systems are applicable to fossil fuel gasification power plants (i.e., IGCC units) where coal or other solid fossil fuel (e.g., petroleum coke) is converted into a synthesis gas (or “syngas”) by applying heat under pressure in the presence of steam and limited
O 2 . The product syngas contains primarily H 2 and CO – and, depending on the fuel and gasification system – some lesser amount of CO 2 . The amount of CO 2 in the resulting syngas stream can be increased by “shifting” the composition via the catalytic water-gas shift (WGS) reaction. This process involves the catalytic reaction of steam (“water”) with CO (“gas”) to form
H 2 and CO 2 . The resulting CO 2 contained in the syngas is then captured before combustion of
the H 2 -enriched syngas for power generation in a combined cycle system. Contrary to the postcombustion capture flue gas, the IGCC syngas can contain a high volume of CO 2 and is pressurized. This allows the use of physical absorbents (e.g., SelexolTM, Rectisol®) that require much less added energy to release the captured CO 2 and require less compression to get to pipeline standards.

Oxy-combustion Oxy-combustion systems for CO 2 capture rely on combusting coal or other fuels with relatively pure O 2 diluted with recycled CO 2 or CO 2 /steam mixtures. Under these conditions, the primary products of combustion are water and CO 2 , with the CO 2 purified by condensing the water. Challenges associated with oxy-combustion include the capital cost and energy consumption for a cryogenic air separation unit (ASU) to produce oxygen, introduction of N 2 via boiler air infiltration, and excess O 2 in the CO 2 product stream.

CO 2 Transportation and Storage
CO 2 Pipeline Infrastructure Carbon dioxide has been transported via pipelines in the U.S. for nearly 40 years. Approximately 50 million metric tons of CO 2 are transported each year through 3,600 miles ofpipelines. Moreover, a review of the 500 largest CO 2 point sources in the U.S. shows that 95 percent are within 50 miles of a possible geologic sequestration site, which would lower transportation costs. There are multiple factors that contribute to the cost of CO 2 transportation via pipelines including but not limited to: availability and acquisition of rights-of-way for new pipelines, capital costs, operating costs, length and diameter of pipeline, terrain, flow rate of
CO 2 , and the number of sources utilizing the pipeline.

Geologic Storage Existing project and regulatory experience, research, and analogs (e.g. naturally existing
CO 2 sinks, natural gas storage, and acid gas injection), indicate that geologic sequestration is a viable long term CO 2 storage option. The viability of geologic sequestration of CO 2 is based on a demonstrated understanding of the fate of CO 2 in the subsurface. Geologic storage potential for
CO 2 is widespread and available throughout the U.S. and Canada. Nearly every state in the U.S. has or is in close proximity to formations with carbon storage potential including vast areas offshore. Estimates based on DOE studies indicate that areas of the U.S. with appropriate geology have a storage potential of 2,300 billion to more than 20,000 billion metric tons of CO 2 in deep saline formations, oil and gas reservoirs and un-mineable coal seams. 1 Other types of geologic formations such as organic rich shale and basalt may also have the ability to store CO 2 ; and the DOE is currently evaluating their potential storage capacity. Further evidence of the widespread availability of CO 2 storage reserves in the U.S. comes from the Department of Interior’s U.S. Geological Survey (USGS) which has recently completed a comprehensive evaluation of the technically accessible storage resource for carbon storage for 36 sedimentary basins in the onshore areas and State waters of the United
States. 2 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 annual U.S. energy-related CO 2 emissions of 5.5 Gigatons (Gt). 3

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

. 3 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment of geologic carbon dioxide storage resources – Summary: U.S. Geological Survey Factsheet 2013-3020, 6p.http://pubs.usgs.gov/fs/2013/3020/.Enhanced Oil Recovery (EOR) Geologic storage options also include use of CO 2 in EOR, which is the injection of fluids into a reservoir to increase oil production effi ciency. EOR is typically conducted at a reservoir after production yields have decreased from primary production. 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 remaining oil and make it available for recovery. The crude oil and CO 2 mixture is produced, and sent to a separator where the crude oil is separated from the gaseous hydrocarbons
and CO 2 . The gaseous CO 2 -rich stream then is typically dehydrated, purified to remove hydrocarbons, recompressed, and re-injected into the oil or natural gas reservoir to further 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 industry 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 experience provides a strong foundation for the injection and monitoring technologies that will be needed for successful deployment of CCS.

Evaluation of Retrofit CCS as BSER for Existing Fossil Fuel-fired EGUs Technical Feasibility In evaluating partial CCS as the BSER for new fossil fuel-fired boilers and IGCC units, the EPA determined that the technology is feasible and adequately demonstrated for new units because the major components of CCS – the capture, the transportation, and the storage – are all proven technologies that have been demonstrated at large scale. While the EPA found that partial CCS is technically feasible for new fossil fuel-fired boilers and IGCC units, it is more difficult to make that determination for the entire fleet of existing fossil fuel-fired EGUs. Developers of new generating facilities can select a physical location that is more amenable to CCS – such as a site that is near an existing CO 2 pipeline or an existing oil field. Existing sources do not have the advantage of pre-selecting an appropriate location. Some existing facilities are located in areas
where CO 2 storage is not geologically favorable and are not near an existing CO 2 pipeline. Developers of new facilities also have the advantage of integrating the partial CCS system into the original design of the new facility. Integrating a retrofit CCS system into an existing facility Deleted: ’CO 2can be more challenging. Some existing sources have a limited footprint and may not have the land or space available to add the equipment needed to implement CO 2 capture, compression, and transportation. Integration of the existing steam system with a retrofit CCS system can be particularly challenging.Partial CCS has been demonstrated at existing EGUs. It has been demonstrated at a pilotscale at Southern Company’s Plant Barry and it is being installed for large-scale demonstration at NRG’s WA Parish facility. SaskPower’s Boundary Dam Unit #3, a 110 MW coal-fired utilityboiler in Saskatchewan, began operations in October 2014. The facility has retrofit postcombustion carbon capture technology that is capturing approximately 90 % of the CO2 from flue gas stream. All of these facilities are located in areas that are either near an existing oil field or in an area that is geologically favorable for CO 2 storage. Thus, at some existing facilities, the implementation of partial CCS may be a preferred compliance option. However, for the reasons stated above, CCS as a system of emission reduction would be much more easily implemented at some existing plants relative to others, and for some would be precluded due to limited space

. Therefore, identification of CCS as the best system of emission reduction for existing fossil fuel fired EGUs would require subcategorization of EGUs based on such factors

.

Reasonableness of Cost In the proposed standard of performance for new fossil fuel-fired EGUs (79 FR 1430), the EPA proposed that the costs to implement partial CCS (to a level to meet the proposedemission standard of 1,100 lb/MWh-gross) were consistent with costs for other non-natural gasfired generating technologies – such as nuclear, biomass and geothermal – that utilities are considering for new intermediate and base load generating capacity. The EPA also noted in the proposal, that most of the relatively few new projects that are in the development phase are already planning to implement CCS; and, as a result, the standard would not have a significant impact on nationwide energy pr ices. In issuing the final NSPS for new fossil fuel-fired EGUs, the EPA – in response to public comments and updated cost information – reevaluated the cost to implement partial CCS and adjusted the final emission limitation to a standard of 1,400
lb s /MWh-gross. In contrast, the EPA did not propose to identify full or partial CCS as BSER for new natural gas-fired stationary combustion turbines noting technical challenges to implementation of Deleted: viable
Deleted: GHG mitigation
Deleted: and some utilities may choose to pursue that option
Deleted: the EPA does not believe that it can serve as the best system of emission reduction as a broadly applicable GHG mitigation program
Deleted: the EPA did not propose to find that CCS is a component of the best system of emission reduction for CO 2 emissions from existing fossil fuel-fired EGUsCCS at NGCC units as compared to implementation at new solid fossil fuel-fired sources. The EPA also noted that, because virtually all new fossil fuel-fired generating capacity is projected to use NGCC technology, requiring full or partial CCS would have more of an impact on the price of electricity than the few projected coal plants with CCS
, and the number of projects would make it difficult to implement in the short term. An emission standard for existing units based on CCS (or even partial CCS) would most certainly have an even more significant effect on nationwide electricity prices. Importantly, the approach identified as the best system of emission reduction will achieve equivalent or greater emission reductions at a far lower cost and provide sources and states with greater flexibility to ensure reliability. Therefore, as stated earlier, the EPA did not find partial CCS to be an appropriate component of the best system of emission reduction for CO 2 emissions from existing
fossil fuel-fired EGUs.

Emission Reductions and Promot ion of Advanced Technology An emission standard for existing units based on CCS (or even partial CCS) would clearly result in significant emission reductions and would certainly serve to promote further deployment, development and improvement in the most advanced technology. However, the EPA has determined that such an emission standard may not be feasible in a number of cases and would involve higher costs (and less flexibility) than the approach identified as the best system
of emission reduction

.

CCS and CCU in State Plans Affected EGUs may utilize retrofit CCS technology to reduce reported stack CO 2 emissions from the EGU. 4 Affected EGUs that apply CCS under a state plan must meet the same monitoring, recordkeeping and reporting requirements for sequestered CO 2 as new units with CCS capability subject to the final CAA section 111(b) rule for new EGUs. 5 Specifically, the final CAA section 111(b) rule for new sources requires that, if a new affected EGU uses CCS to

4 Addition of retrofit CCS technology should not trigger CAA section 111(b) applicability for modified or reconstructed sources. Pollution control projects do not trigger NSPS modifications and addition of CCS technology does not count toward the capital costs of reconstruction. 5 Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units. Deleted: and could affect the reliability of the supply of electricity

Deleted: that the cost to implement
Deleted: at existing source emission standards to be reasonable, which further s upports the determination that
Deleted: CCS is not

Deleted: technically or logistically

Deleted: cannot be broadly implemented at a reasonable cost at this timemeet the applicable CO 2 emission limit, the EGU must report in accordance with 40 CFR part 98 subpart PP (Suppliers of Carbon Dioxide), and the captured CO 2 must be injected at a facility or facilities that report in accordance with 40 CFR part 98 subpart RR (Geologic Sequestration of Carbon Dioxide). 6,7 See 40 CFR part 60.46Da(h)(5) and part 60.5555(d). Taken together, these requirements ensure that the amount of captured and sequestered CO 2 will be tracked as appropriate at project- and national-levels, and that the status of the CO 2 in its sequestration site will be monitored, including air-side monitoring and reporting. As detailed in the preamble for the CAA section 111(b) standards for new EGUs, the EPA is convinced that there is ample evidence that CCS is technically feasible and that partial CCS can be implemented at a new fossil fuel-fired steam generating EGU at a cost that is consistent with the cost of other dispatchable, non-NGCC generating options. The EPA received comments suggesting that carbon capture and utilization (CCU) technologies should also be allowed as a CO 2 emission rate adjustment measure for affected EGUs. Potential alternatives to storing CO 2 in geologic formations are emerging and these relatively new potential alternatives may offer the opportunity to offset the cost of CO 2 capture. For example, captured anthropogenic CO 2 may be stored in solid ca rbonate materials such as precipitated calcium carbonate (PCC) or magnesium or calcium carbonate, bauxite residue carbonation, and certain types of cement through mineralization. The carbonate materials produced can be tailored to optimize performance in specific industrial and commercial applications. For example, these carbonate materials have been used in the construction industry and, more recently and innovatively, in cement production processes to replace Portland cement. The Skyonics Skymine® project, which opened its demonstration project in October 2014, is an example of captured CO 2 being used in the production of carbonate products. This plant converts CO 2 into commercial products. It captures over 75,000 tons of CO 2 annually from a San Antonio, Texas, cement plant and converts the CO 2 into other products including sodium

6 The final CAA section 111(b) rule finalizes amendments to subpart PP reporting requirements, specifically requiring that the following pieces of information be reported: (1) the electronic GHG Reporting Tool identification (e-GGRT ID) of the EGU facility from which CO 2 was captured, and (2) the e-GGRT ID(s) for, and mass of CO 2 transferred to, each GS site reporting under subpart RR. As noted, the final 111(b) rule also requires that any affected EGU unit that captures CO 2 to meet the applicable emissions limit must transfer the captured CO 2 to a facility that reports under 40 CFR part 98 subpart RR.
7 Under final requirements in the CAA 111(b) NSPS, any well receiving CO 2 captured from an affected source, be it a Class VI or Class II well, must report under subpart RR. A UIC Class II well’s regulatory status does not change because it receives such CO 2 , nor does it change by virtue of reporting under subpart RR.carbonate and sodium bicarbonate. 8 Other companies – including Calera 9 and New Sky 10 – also offer commercially available technology for the beneficial use of captured CO 2 . These processes can be utilized in a variety of industrial applications – including at fossil fuel-fired power plants. However, consideration of how these emerging alternatives could be used to meet CO 2 emission performance rates or state CO 2 emission goals would require a better understanding of the ultimate fate of the captured CO 2 and the degree to which the method permanently isolates the captured CO 2 or displaces other CO 2 emissions from the atmosphere. Several commenters also suggested that algae-based CCU (i.e., the use of algae to convert captured CO 2 to useful products – especially biofuels) should be recognized for its potential to reduce emissions from existing fossil-fueled EGUs. Unlike geologic sequestration, there are currently no uniform monitoring and reporting mechanisms to demonstrate that these alternative end uses of captured CO 2 result in overall
reductions of CO 2 emissions to the atmosphere. As these alternative technologies are developed, the EPA is committed to work collaboratively with stakeholders to evaluate the efficacy of alternative utilization technologies, to address any regulatory hurdles, and to develop appropriate monitoring and reporting protocols to demonstrate CO 2 reductions. In the meantime, the EPA has specified that state plans may allow affected EGUs to use qualifying CCU technologies to reduce CO 2 emissions that are subject to an emission standard, or those that are counted when demonstrating achievement of the CO 2 emission performance
rates or a state rate-based or mass-based CO 2 emission. Approvable state plans must include analysis supporting how the proposed qualifying CCU technology results in CO 2 emission mitigation and provide monitoring, reporting, and verification requirements to demonstrate the reductions. The EPA would then review the appropriateness and basis for the analysis and the verification requirements in the course of its review of the state plan.

8 http://skyonic.com/technologies/skymine. 9 http://www.calera.com/beneficial-reuse-of-co2/process.html. 10 http://www.newskyenergy.com/index.php/products/carboncycle.