From: Frey, Nathan J. To: Culligan, Kevin ; Hutson, Nick ; Wayland, Robertj Subject: EGU NSPS -- Summary of Interagency Comments under EO 12866 13563 Date: Thursday, September 19, 2013 9:43:48 AM Attachments: Summary of Interagency Comments under EOs 12866_13563 EGU NSPS NPRM.docx 

### Hello all, Attached please find a summary of interagency comments under EO 12866 and 13563 regarding the issue(s) discussed yesterday. Please let me know ASAP if you would like to arrange a call to discuss. Thanks,

Nathan

### Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Subject to Further Policy Review.

1. Cost estimates for implementation of partial CCS The EPA has examined costs of new fossil fueled power generation options. These options are shown in Table 6 below

. The costs in Table 6 table show s are projected for the costs of

new fossil generation with and without various carbon capture options. The costs for new NGCC technology are provided at two different natural gas prices: at $6.11/MMBtu, which is reasonably consistent with current and projected prices; and at $10/MMBtu, which would be well above current and projected natural gas prices. We also show projected costs for SCPC and IGCC units with no CCS (i.e., units that would not meet the proposed emission standard) and for those units with partial capture CCS installed such that their emissions would meet the proposed 1,100 lb CO 2 /MWh standard. We have also included costs for those same units when EOR opportunities are available. We have included a “low EOR” case assuming a low EOR price of $20 per ton of CO 2 , and a “high EOR” of $40/ton. (These EOR prices are net of the costs of transportation, storage, and monitoring (TSM). We also show the projected costs for implementation of full capture CCS (i.e., 90 percent capture).

### Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Subject to Further Policy Review.

**Table 6. Levelized Cost of Electricity for Fossil Fuel**  **Electric Generating Technologies, Excluding Transmission Costs**  1,2

1 These costs come from the following DOE/NETL studies: (1) Cost and Performance Baseline for Fossil Energy Plants Volume 1:Bituminous Coal and Natural Gas to Electricity, Rev 2, DOE/NETL2010/1397 (Nov 2010); (2) Updated Costs (June 2011 Basis) for Selected Bituminous Baseline Cases” DOE/NETL-341/082312 (Aug 2012); (3) Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture, DOE/NETL-2011/1498 (May 2011). Capacity factor are assumed at 85 percent. 2 These costs do not include the impact of subsidies that may potentially be available to developers of new projects that include CCS.

### Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Subject to Further Policy Review.

**Technology Levelized Cost of**  **Electricity ($2011/MWh)**  **3 ,**  4 **, 5**  NGCC @ $6.11/MMBtu 59 NGCC @ $10.0/MMBtu 86

SCPC w/o CCS 6 92 SCPC (1,100 lb/MWh; no EOR) 110 SCPC (1,100 lb/MWh; low EOR) 96 SCPC (1,100 lb/MWh; high EOR) 88 SCPC (full, 90 percent CCS) 147

3 Data for fossil fuel

- fired generation comes from DOE/NETL: (1) Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev 2, DOE/NELT

2010/1397 (Nov 2010); (2) Updated Costs (June 2011 Basis) for Selected Bituminous Baseline Cases” DOE/NETL

- 341/082312 (Aug 2012); (3) Cost and Performance of PC and IGCC Plants for a Range of Carbon Dioxide Capture, DOE/NETL

- 2011/1498 (May 2011). Data for non

- fossil fuel

- fired generation comes from DOE Energy Information Administration ( EIA ) Annual Energy Outlook ( AEO ) 2013

. Levelized Cost of Electricity ( LCOE ) estimates come from http://www.eia.gov/forecasts/aeo/electricity_generation.cfm

. T o maintain consistency with DOE/NETL estimates , EIA estimates provided in this table do not include transmission investment

. 4 LCOE point estimates are provided for coal

- fired capacity types; all other LCOE estimates are presented as a range that reflects EIA’s view on the regional variation in local labor markets, cost and availability of fuel, and renewable resources. The capacity factor ranges for renewable non

- dispatchable technologies are as follows: Wind

– 30% to 39%, Wind Offshore

– 3 3% to 42%, Solar PV

- 22% to 32%, and Solar Thermal

– 11% to 26%. Capacity factors for dispatchable technologies are as follows: Coal and NGCC

– 85%, Nuclear

– 90%, Biomass

– 83%, Geothermal

– 92%, and Combustion Turbine

– 30%. There is no capacity credit provided to dispatchable resources. 5 These costs do not include the impact of subsidies that may potentially be available to developers of new projects that include CCS. 6 SCPC LCOE includes a 3% increase to the weighted average cost of capital to reflect EIA’s climate uncertainty adder (CUA).

### Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Subject to Further Policy Review.

IGCC w/o CCS 97 IGCC (1,100 lb/MWh; no EOR) 109 IGCC (1,100 lb/MWh; low EOR) 101 IGCC (1,100 lb/MWh; high EOR) 97 IGCC (full, 90 percent CCS) 136

The cost estimates from the DOE/NETL studies carry an accuracy of

- 15% ± 30%, consistent with a “feasibility study” level of design engineering applied to the various cases in this study The DOE/NETL report cites an accuracy range of -15% to +30% for the central point estimates shown in Table 6, which are based on many assumptions, including: an EPCM contracting methodology, ISO ambient conditions , Midwest merit-shop labor costs, and a level greenfield site in the United States Midwest with no unusual characteristics (e.g., flood plain, seismic zones, environmental remediation). For specific sites that differ from this generic description, plant costs could exceed the quoted range. DOE/NET L explain that there are a range of future potential costs that are up to 15% below, or 30% above a central estimate. We have presented that central estimate above. Also note that the DOE/NETL studies were not generally calculated in year (x) dollars. We have adjusted them all to year y dollars using Bureau of Economic Indicator factors, to make consistent with other costs used throughout today’s preamble. (i.e., the LCOE values can range from 15 percent less to as much as 30 percent higher than the valu e provide in Table 6)

. The value of the DOE/NETL studies lies not

### Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Subject to Further Policy Review.

in the absolute accuracy of the individual case results but in

the fact that all cases were evaluated under the same set of technical and economic assumptions. This consistency of approach allows meaningful comparisons among the cases evaluated. For an emerging technology like CCS, costs can be estimated for a “first-of-a-kind” (FOAK) plant or an “n th -of-a-kind” (NOAK) plant, the latter of which has lower costs due to the “learning by doing” and risk reduction benefits that result from serial deployments as well as from continuing research, development and demonstration projects. 7 The estimates provided in Table 6 for a new NGCC unit and for a SCPC plant without CO 2 capture are based on mature technologies and are thus NOAK costs. For plants that utilize technologies that are not yet fully mature and/or which have not yet been serially deployed in a commercial context , such as the IGCC or any plant that includes CO 2 capture, the cost estimates in Table 4 6 represent a plant that is somewherebetween FOAK and NOAK, sometimes referred to as “next-of-akind” , or “next commercial offering”. These cost estimates for

7 Elsewhere in this preamble, we describe the evidence that as technology matures, its costs decrease. Note also that EPA regulations of mobile source air emissions incorporate the decreasing costs of technology over time. See, e.g., “2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards – Final Rule,” 77 Fed. Reg. 62624, 62984/1 to 62985/1 (October 15, 2012) (incorporating “cost reductions, due to learning effects”).

### Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Subject to Further Policy Review.

next commercial offerings do not include the unique cost premiums associated with first-of-a-kind (FOAK) plants that must demonstrate emerging technologies and iteratively improve upon initial plant designsand rectify the initial iterations of emerging tec hnologies . However, these costs do utilize currently available cost bases for emerging technologies with associated process contingencies applied at the appropriate subsystem levels. Despite the application of process contingencies and other best efforts to realistically project the cost of emerging technologies, it should be noted that such cost projections are often shown to be optimistic when compared to actual “next commercial offering”

costs are realized . Accordingly, the "next commercial offering" cost estimates in Table 6, while intended for plants that lie somewhere between FOAK and NOAK in the maturity spectrum, are expected to be closer to NOAK plant costs given the inherent "technology optimism" associated with projecting costs for emerging technologies

. Because there are a number of projects currently under development, the EPA believes it is reasonable to focus on the next-of-a-kind costs provided in Table 6. The lessons learned from design, construction and operation of those projects, as well as for that of Duke Energy’s Edwardsport IGCC (which does

### Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Subject to Further Policy Review.

not include CCS) will help lower costs for future gasification facilities implementing CCS. The TCEP project and the HECA project are both in advanced stages of design and development. Summit Power, the developer of TCEP, is also pursuing a number of additional projects that would benefit from lessons learned from TCEP. These include the Captain CleanEnergy Project in the United Kingdom (UK) and another polygeneration project in Texas. 8 For a new conventional PC plant implementing post-combustion CCS, the Boundary Dam project will perhaps represent a FOAK project while the W.A. Parish project may represent a second-of-a-kind project - or perhaps even a next-of-a-kind project. Further, as discussed elsewhere in this preamble, many of the individual components of a new generation project with CCS have been previously demonstrated. For example, capturing CO 2 from a coal gasification syngas stream has been occurring for more than ten years at the Dakota Gasification facility. Experience gained at that facility can inform design and operational choices of a new IGCC implementing partial CCS. For all these reasons, the next IGCC and SCPC facilities with CCS can be expected to be less expensive than the current

8 (http://ghgnews.com/index.cfm/summit-even-without-uk-demofunding-project-will-move-forward/?mobileFormat=true ).

### Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Subject to Further Policy Review.

FOAK projects, if somewhat but more expensive than the NOAK facilities with CCS that construct when CCS has become a fullymature technology. The costs in Table 6 reflect those next-of-akind costs. The EPA has also examined costs of new non-fossil fueled power generation options. These options are shown in Table 6 below.

**Table 7. Range of Levelized Cost of Electricity for Non-Fossil Fuel Electric Generating Technologies, Excluding Transmission**  **Costs 9,10** 

**Technology Levelized Cost of**  **Electricity ($2011/MWh)**  Nuclear 103 - 114

9 Data for non-fossil fuel-fired generation comes from DOE Energy Information Administration (EIA) Annual Energy Outlook (AEO) 2013. Levelized Cost of Electricity (LCOE) estimates come from http://www.eia.gov/forecasts/aeo/electricity_generation.cfm

. To maintain consistency with DOE/NETL estimates in Table 6, the EIA estimates provided in this table do not include transmission investment. 10 The LCOE estimates in Table 7 are presented as a range that reflects EIA’s view on the regional variation in local labor markets, cost and availability of fuel, and renewable resources. The capacity factor ranges for renewable non-dispatchable technologies are as follows: Wind – 30 to 39 percent, Wind Offshore – 33 to 42 percent, Solar PV- 22 to 32 percent, and Solar Thermal – 11 to 26 percent. Capacity factors for dispatchable non-fossil fueled technologies are as follows: Nuclear – 90 percent, Biomass – 83 percent, and Geothermal – 92 percent. There is no capacity credit provided to dispatchable resources. Formatted: Indent: First line: 0.5"

### Summary of Interagency Working Comments on Draft Language under EO12866 Interagency Review.  Subject to Further Policy Review.

Biomass 97 - 130 Geothermal 80 – 99 Combustion Turbine 87 – 116 Onshore Wind 70 – 97 Offshore Wind 177 – 289 Solar PV 11 109 – 220 Solar Thermal 184 – 412 Nuclear 103 - 114 Biomass 97 - 130 Geothermal 80 – 99

11 Costs are expressed in terms of net AC power available to the grid for the installed capacity.