§ 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis 1 The updated Chapter B3: Electricity Market Model Analysis presents a detailed description of the IPM and a discussion of the methodology EPA used to estimate economic impacts using the IPM ( see DCN 5 3002).

2 Note that the number of Phase II facilities and their capacity and operating statistics not sample weighted.

3 The capacity presented is " pre run" capacity, which is defined as the generating units currently operating and those planned units committed to be built by 2013, as identified by the IPM. Pre run capacity, rather than base case capacity, is used for this measure because the base case reflects certain operating decision ( e. g., repowering decisions or facility closures) that may not be taken in the postcompliance scenario. Therefore, the pre run capacity provides a more useful measure of the percentage of currently existing capacity estimated to be affected by the installation of a recirculating wet cooling tower under the waterbody/ capcity based option.

NODA Version   March 12, 2003 B8 1 Chapter B8: Alternative Options

Electricity Market Model Analysis INTRODUCTION This chapter presents EPA's electricity market model analysis using ICF Consulting's Integrated Planning Model ( IPM ® ) for the waterbody/ capacity based option.

B8 1 OVERVIEW OF IPM ANALYSIS OF ALTERNATIVE OPTIONS EPA used the IPM, an integrated energy market model, to analyze two potential effects of the waterbody/ capacity based option: ( 1) potential energy effects at the national and regional levels, as required by Executive Order 13211 (" Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use"); and ( 2) potential economic impacts on in scope facilities. 1 The waterbody/ capacity based option has more stringent compliance technology requirements than the preferred option. Specifically, for the NODA analysis, EPA estimates that this option would require 44 facilities to meet performance standards for impingement mortality and entrainment reduction based on reducing cooling water intake flow to a level commensurate with that which can be attained by a closed cycle, recirculating system. 2 For this analysis, EPA conservatively assumed that all 44 facilities would install a recirculating wet cooling tower. The compliance requirements for all other facilities, with the exception of some minor permitting requirements, are identical to those of the preferred option.

EPA mainly relied on data for 2013 in the analyses of the waterbody/ capacity based option presented in this chapter. 2013 was chosen to represent the effects of the alternative option for a typical year in which all facilities are in compliance ( compliance years for the waterbody/ capacity based option are 2005 to 2013; however, for the purposes of this analysis, all facilities are modeled to comply by 2012). EPA also analyzed potential market level impacts of the alternative waterbody/ capacity based option for a year within the compliance period during which some Phase II facilities experience installation downtimes. This analysis used output from model run year 2008 and is presented in Section B8 4 below.

The framework for the analysis of the waterbody/ capacity based option is identical to that used for the analysis of the preferred option in Chapter B3: Electricity Market Model Analysis. However, it should be noted that the results of the electricity market model analysis for the waterbody/ capacity based option cannot be directly compared to the results of the analysis for the preferred option ( presented in Chapter B3) because ( 1) the two analyses use different base cases with different assumptions about future growth in electricity demand and ( 2) the analyses use output for different model run years ( 2010 for the preferred option and 2013 for the waterbody/ capacity based option).

Table B8 1 below presents the number and steam electric capacity of facilities in each NERC region that EPA estimated would install a cooling tower under the waterbody/ capacity based option. 3 The table also presents total capacity for each region and the percentage of total capacity in each region that was costed with a cooling tower. The final two columns CHAPTER CONTENTS B8 1 Overview of IPM Analysis of Alternative Options . B8 1 B8 2 Market Level Analysis for 2013 . . . . . . . . . . . . . . . B8 2 B8 3 Analysis of Phase II Facilities for 2013 . . . . . . . . . . B8 9 B8 3.1 In Scope Phase II Facilities as a Group . . . . . . . B8 9 B8 3.2 Individual Phase II Facilities . . . . . . . . . . . . . . B8 15 B8 4 Market Level Analysis for 2008 . . . . . . . . . . . . . . B8 15 B8 5 Uncertainties and Limitations . . . . . . . . . . . . . . . . B8 20 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B8 21 § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis B8 2 NODA Version   March 12, 2003 present the total capacity of all facilities subject to Phase II regulation and the percentage of all Phase II capacity that was costed with a cooling tower.

Table B8 1: Distribution of Cooling Towers for the Waterbody/ Capacity Based Option ( by NERC Region)

NERC Region Facilities Estimated to Install a Cooling Tower Total National Capacity ( MW) CT Capacity as % of National Capacity Total Phase II Capacity ( MW) CT Capacity as % of Phase II Capacity Number of Facilities Steam Electric Capacity ( MW)

ECAR   135,107 0% 82,310 0%

ERCOT 2 1,254 83,948 1.5% 43,287 2.9%

FRCC 5 8,578 57,919 14.8% 28,353 30.3%

MAAC 10 9,421 72,414 13.0% 35,744 26.4%

MAIN   72,074 0% 40,595 0%

MAPP   42,206 0% 16,235 0%

NPCC 10 6,695 81,386 8.2% 36,684 18.3%

SERC 7 7,237 220,625 3.3% 107,507 6.7%

SPP   55,711 0% 20,471 0%

WSCC 8 11,980 184,226 6.5% 25,383 47.2%

Total 42 45,164 1,005,617 4.5% 436,569 10.3%

Source: IPM analysis: IPM pre run data, EPA analysis 2003.

Overall, EPA conservatively estimates that 44 facilities would install a cooling tower under this option ( rather than comply by demonstrating that they can achieve comparable reductions in impingement mortality and entrainment using other, lower cost technologies). Two of these facilities are located in Hawaii and are therefore not included in the IPM analysis. Table B8 1 shows that the 42 facilities estimated to install a cooling tower and modeled by the IPM are located in six NERC regions. In aggregate, they operate 45,164 MW of steam electric capacity ( 4.5 percent of the total capacity and 10.3 percent of Phase II capacity). FRCC and MAAC are projected to have the highest percentage of total capacity that was costed with a cooling tower ( 14.8 and 13.0 percent, respectively). In WSCC, only 6.5 percent of total capacity is costed with a cooling tower. However, these eight facilities represent 47.2 percent of all capacity subject to the Phase II rule in WSCC. There are no facilities in ECAR, MAIN, MAPP, and SPP costed with a cooling tower under this option.

B8 2 MARKET ANALYSIS FOR 2013 This section presents the results of the IPM analysis for all facilities modeled by the IPM. The market level analysis includes results for all generators located in each NERC region including facilities that are in scope and facilities that are out of scope of Phase II regulation. Market level impacts associated with the waterbody/ capacity based option are assessed using the following six impact measures: ( 1) capacity changes, including changes in existing capacity, new additions, repowering additions, and closures; ( 2) electricity price changes, including changes in energy prices and capacity prices; ( 3) generation changes; ( 4) revenue changes; ( 5) cost changes, including changes in fuel costs, variable O& M costs, fixed O& M costs, and capital costs; ( 6) changes in pre tax income, defined as revenues minus total costs; and ( 7) changes in variable production costs per MWh. For each measure, Table B8 2 presents the results for the base case and the waterbody/ capacity based option, the absolute difference between the two cases, and the percentage difference. A detailed description of each of the impact measures discussed below is presented in Section B3 3.1 of Chapter B3: Electricity Market Model Analysis. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis NODA Version   March 12, 2003 B8 3 Table B8 2: Market Level Impacts of the Waterbody/ Capacity Based Option ( by NERC Regions; 2013)

Economic Measures Base Case WB/ C Based Option Difference % Change National Totals ( 1) Total Domestic Capacity ( MW) 994,126 993,604 ( 522)  0.1%

( 1a) Existing 786,374 780,274 ( 6,100)  0.8%

( 1b) New Additions 182,493 183,708 1,214 0.7%

( 1c) Repowering Additions 25,258 29,622 4,364 17.3% ( 1d) Closures 12,740 15,902 3,162 24.8%

( 2a) Energy Prices ($ 2002/ MWh) n/ a n/ a n/ a n/ a ( 2b) Capacity Prices ($ 2002/ KW/ yr) n/ a n/ a n/ a n/ a ( 3) Generation ( GWh) 4,603,844 4,604,637 793 0.0%

( 4) Revenues ( Millions; $ 2002) $ 166,539 $ 168,246 $ 1,707 1.0%

( 5) Costs ( Millions; $ 2002) $ 105,834 $ 107,858 $ 2,025 1.9%

( 5a) Fuel Cost $ 56,106 $ 57,031 $ 925 1.6%

( 5b) Variable O& M $ 8,575 $ 8,553 ($ 22)  0.3%

( 5c) Fixed O& M $ 24,750 $ 25,544 $ 793 3.2%

( 5d) Capital Cost $ 16,402 $ 16,730 $ 328 2.0%

( 6) Pre Tax Income ( Millions; $ 2002) $ 60,705 $ 60,388 ($ 317)  0.5%

( 7) Variable Production Costs ($/ MWh) $ 13.42 $ 13.59 $ 0.16 1.2%

East Central Area Reliability Coordination Agreement ( ECAR)

( 1) Total Domestic Capacity ( MW) 133,048 133,048 0 0.0%

( 1a) Existing 110,011 110,011 0 0.0%

( 1b) New Additions 22,967 22,967 0 0.0%

( 1c) Repowering Additions 70 70 0 0.0% ( 1d) Closures 0 0 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 24.82 $ 25.01 $ 0.19 0.8%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 54.17 $ 56.97 $ 2.79 5.2%

( 3) Generation ( GWh) 701,807 702,751 944 0.1%

( 4) Revenues ( Millions; $ 2002) $ 24,848 $ 25,137 $ 289 1.2%

( 5) Costs ( Millions; $ 2002) $ 14,458 $ 14,616 $ 157 1.1%

( 5a) Fuel Cost $ 7,110 $ 7,164 $ 54 0.8%

( 5b) Variable O& M $ 1,694 $ 1,700 $ 6 0.4%

( 5c) Fixed O& M $ 3,723 $ 3,818 $ 95 2.6%

( 5d) Capital Cost $ 1,931 $ 1,933 $ 2 0.1%

( 6) Pre Tax Income ( Millions; $ 2002) $ 10,390 $ 10,521 $ 131 1.3%

( 7) Variable Production Costs ($/ MWh) $ 12.55 $ 12.61 $ 0.07 0.5%

Electric Reliability Council of Texas ( ERCOT)

( 1) Total Domestic Capacity ( MW) 86,609 86,589 ( 20) 0.0%

( 1a) Existing 69,832 69,315 ( 517)  0.7% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 2: Market Level Impacts of the Waterbody/ Capacity Based Option ( by NERC Regions; 2013)

Economic Measures Base Case WB/ C Based Option Difference % Change B8 4 NODA Version   March 12, 2003 ( 1b) New Additions 11,353 10,856 ( 497)  4.4%

( 1c) Repowering Additions 5,425 6,418 993 18.3% ( 1d) Closures 0 0 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 26.98 $ 27.44 $ 0.46 1.7%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 35.79 $ 35.33 ($ 0.46)  1.3%

( 3) Generation ( GWh) 388,547 388,582 35 0.0%

( 4) Revenues ( Millions; $ 2002) $ 13,582 $ 13,718 $ 137 1.0%

( 5) Costs ( Millions; $ 2002) $ 9,926 $ 10,068 $ 142 1.4%

( 5a) Fuel Cost $ 6,104 $ 6,190 $ 86 1.4%

( 5b) Variable O& M $ 754 $ 753 $ 0 0.0%

( 5c) Fixed O& M $ 1,858 $ 1,893 $ 35 1.9%

( 5d) Capital Cost $ 1,211 $ 1,232 $ 21 1.8%

( 6) Pre Tax Income ( Millions; $ 2002) $ 3,656 $ 3,651 ($ 5)  0.1%

( 7) Variable Production Costs ($/ MWh) $ 17.65 $ 17.87 $ 0.22 1.2%

Florida Reliability Coordinating Council ( FRCC)

( 1) Total Domestic Capacity ( MW) 57,078 57,011 ( 67)  0.1%

( 1a) Existing 39,238 39,124 ( 114)  0.3%

( 1b) New Additions 17,840 17,887 47 0.3%

( 1c) Repowering Additions 0 0 0 0.0% ( 1d) Closures 812 812 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 29.88 $ 31.03 $ 1.14 3.8%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 42.38 $ 39.70 ($ 2.69)  6.3%

( 3) Generation ( GWh) 218,165 218,162 ( 2) 0.0%

( 4) Revenues ( Millions; $ 2002) $ 8,938 $ 9,032 $ 94 1.0%

( 5) Costs ( Millions; $ 2002) $ 6,669 $ 6,885 $ 217 3.3%

( 5a) Fuel Cost $ 3,747 $ 3,818 $ 71 1.9%

( 5b) Variable O& M $ 408 $ 410 $ 1 0.3%

( 5c) Fixed O& M $ 1,273 $ 1,417 $ 145 11.4%

( 5d) Capital Cost $ 1,240 $ 1,240 $ 0 0.0%

( 6) Pre Tax Income ( Millions; $ 2002) $ 2,270 $ 2,146 ($ 123)  5.4%

( 7) Variable Production Costs ($/ MWh) $ 19.05 $ 19.38 $ 0.33 1.7%

Mid Atlantic Area Council ( MAAC)

( 1) Total Domestic Capacity ( MW) 71,441 71,228 ( 213)  0.3%

( 1a) Existing 57,426 57,237 ( 189)  0.3%

( 1b) New Additions 12,357 12,340 ( 18)  0.1%

( 1c) Repowering Additions 1,658 1,652 ( 6)  0.4% ( 1d) Closures 1,725 1,725 0 0.0% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 2: Market Level Impacts of the Waterbody/ Capacity Based Option ( by NERC Regions; 2013)

Economic Measures Base Case WB/ C Based Option Difference % Change NODA Version   March 12, 2003 B8 5 ( 2a) Energy Prices ($ 2002/ MWh) $ 27.96 $ 28.35 $ 0.38 1.4%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 52.52 $ 52.56 $ 0.04 0.1%

( 3) Generation ( GWh) 312,432 312,568 136 0.0%

( 4) Revenues ( Millions; $ 2002) $ 12,485 $ 12,600 $ 115 0.9%

( 5) Costs ( Millions; $ 2002) $ 7,670 $ 7,985 $ 314 4.1%

( 5a) Fuel Cost $ 3,687 $ 3,747 $ 59 1.6%

( 5b) Variable O& M $ 633 $ 631 ($ 2)  0.3%

( 5c) Fixed O& M $ 2,165 $ 2,414 $ 249 11.5%

( 5d) Capital Cost $ 1,185 $ 1,192 $ 7 0.6%

( 6) Pre Tax Income ( Millions; $ 2002) $ 4,815 $ 4,616 ($ 199)  4.1%

( 7) Variable Production Costs ($/ MWh) $ 13.83 $ 14.01 $ 0.18 1.3%

Mid America Interconnected Network ( MAIN)

( 1) Total Domestic Capacity ( MW) 66,420 66,385 ( 35)  0.1%

( 1a) Existing 51,122 50,110 ( 1,012)  2.0%

( 1b) New Additions 15,298 16,275 977 6.4%

( 1c) Repowering Additions 0 0 0 0.0% ( 1d) Closures 5,620 6,632 1,012 18.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 24.01 $ 24.39 $ 0.39 1.6%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 56.57 $ 56.65 $ 0.08 0.1%

( 3) Generation ( GWh) 307,839 306,011 ( 1,828)  0.6%

( 4) Revenues ( Millions; $ 2002) $ 11,142 $ 11,220 $ 78 0.7%

( 5) Costs ( Millions; $ 2002) $ 6,743 $ 6,758 $ 15 0.2%

( 5a) Fuel Cost $ 3,358 $ 3,424 $ 65 1.9%

( 5b) Variable O& M $ 622 $ 619 ($ 3)  0.5%

( 5c) Fixed O& M $ 1,724 $ 1,653 ($ 71)  4.1%

( 5d) Capital Cost $ 1,039 $ 1,062 $ 23 2.2%

( 6) Pre Tax Income ( Millions; $ 2002) $ 4,399 $ 4,462 $ 63 1.4%

( 7) Variable Production Costs ($/ MWh) $ 12.93 $ 13.21 $ 0.28 2.2%

Mid Continent Area Power Pool ( MAPP)

( 1) Total Domestic Capacity ( MW) 39,694 39,694 0 0.0%

( 1a) Existing 32,668 32,668 0 0.0%

( 1b) New Additions 7,026 7,026 0 0.0%

( 1c) Repowering Additions 0 0 0 0.0% ( 1d) Closures 476 476 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 22.53 $ 22.95 $ 0.42 1.8%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 55.99 $ 55.95 ($ 0.04)  0.1%

( 3) Generation ( GWh) 201,006 201,091 85 0.0% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 2: Market Level Impacts of the Waterbody/ Capacity Based Option ( by NERC Regions; 2013)

Economic Measures Base Case WB/ C Based Option Difference % Change B8 6 NODA Version   March 12, 2003 ( 4) Revenues ( Millions; $ 2002) $ 6,727 $ 6,810 $ 84 1.2%

( 5) Costs ( Millions; $ 2002) $ 4,011 $ 4,041 $ 29 0.7%

( 5a) Fuel Cost $ 1,982 $ 1,989 $ 7 0.3%

( 5b) Variable O& M $ 406 $ 407 $ 1 0.1%

( 5c) Fixed O& M $ 1,058 $ 1,076 $ 18 1.7%

( 5d) Capital Cost $ 565 $ 569 $ 4 0.7%

( 6) Pre Tax Income ( Millions; $ 2002) $ 2,715 $ 2,770 $ 55 2.0%

( 7) Variable Production Costs ($/ MWh) $ 11.88 $ 11.91 $ 0.03 0.3%

Northeast Power Coordinating Council ( NPCC)

( 1) Total Domestic Capacity ( MW) 77,557 77,574 18 0.0%

( 1a) Existing 59,678 59,462 ( 217)  0.4%

( 1b) New Additions 7,325 7,381 56 0.8%

( 1c) Repowering Additions 10,554 10,732 179 1.7% ( 1d) Closures 4,107 4,107 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 30.53 $ 30.87 $ 0.34 1.1%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 49.98 $ 50.02 $ 0.04 0.1%

( 3) Generation ( GWh) 311,569 312,033 463 0.1%

( 4) Revenues ( Millions; $ 2002) $ 13,102 $ 13,225 $ 124 0.9%

( 5) Costs ( Millions; $ 2002) $ 9,129 $ 9,382 $ 253 2.8%

( 5a) Fuel Cost $ 5,331 $ 5,411 $ 80 1.5%

( 5b) Variable O& M $ 414 $ 411 ($ 3)  0.8%

( 5c) Fixed O& M $ 1,849 $ 2,007 $ 158 8.5%

( 5d) Capital Cost $ 1,535 $ 1,554 $ 19 1.2%

( 6) Pre Tax Income ( Millions; $ 2002) $ 3,973 $ 3,843 ($ 129)  3.3%

( 7) Variable Production Costs ($/ MWh) $ 18.44 $ 18.66 $ 0.22 1.2%

Southeastern Electric Reliability Council ( SERC)

( 1) Total Domestic Capacity ( MW) 220,567 220,497 ( 70) 0.0%

( 1a) Existing 164,552 164,421 ( 131)  0.1%

( 1b) New Additions 56,015 56,076 61 0.1%

( 1c) Repowering Additions 0 0 0 0.0% ( 1d) Closures 0 0 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 25.63 $ 26.00 $ 0.37 1.4%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 49.31 $ 49.22 ($ 0.09)  0.2%

( 3) Generation ( GWh) 1,069,471 1,071,276 1,806 0.2%

( 4) Revenues ( Millions; $ 2002) $ 38,278 $ 38,693 $ 415 1.1%

( 5) Costs ( Millions; $ 2002) $ 24,452 $ 24,836 $ 385 1.6%

( 5a) Fuel Cost $ 12,571 $ 12,731 $ 159 1.3% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 2: Market Level Impacts of the Waterbody/ Capacity Based Option ( by NERC Regions; 2013)

Economic Measures Base Case WB/ C Based Option Difference % Change NODA Version   March 12, 2003 B8 7 ( 5b) Variable O& M $ 1,940 $ 1,949 $ 9 0.5%

( 5c) Fixed O& M $ 5,558 $ 5,739 $ 181 3.3%

( 5d) Capital Cost $ 4,382 $ 4,418 $ 36 0.8%

( 6) Pre Tax Income ( Millions; $ 2002) $ 13,827 $ 13,857 $ 30 0.2%

( 7) Variable Production Costs ($/ MWh) $ 13.57 $ 13.70 $ 0.13 1.0%

Southwest Power Pool ( SPP)

( 1) Total Domestic Capacity ( MW) 55,711 55,712 2 0.0%

( 1a) Existing 48,956 48,956 0 0.0%

( 1b) New Additions 6,755 6,756 2 0.0%

( 1c) Repowering Additions 0 0 0 0.0% ( 1d) Closures 0 0 0 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 24.53 $ 24.91 $ 0.38 1.5%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 49.30 $ 49.23 ($ 0.07)  0.1%

( 3) Generation ( GWh) 244,192 244,263 71 0.0%

( 4) Revenues ( Millions; $ 2002) $ 8,732 $ 8,821 $ 89 1.0%

( 5) Costs ( Millions; $ 2002) $ 5,072 $ 5,115 $ 43 0.8%

( 5a) Fuel Cost $ 3,051 $ 3,072 $ 21 0.7%

( 5b) Variable O& M $ 441 $ 442 $ 1 0.2%

( 5c) Fixed O& M $ 1,104 $ 1,119 $ 15 1.4%

( 5d) Capital Cost $ 476 $ 482 $ 6 1.4%

( 6) Pre Tax Income ( Millions; $ 2002) $ 3,661 $ 3,706 $ 45 1.2%

( 7) Variable Production Costs ($/ MWh) $ 14.30 $ 14.38 $ 0.08 0.6%

Western Systems Coordinating Council ( WSCC)

( 1) Total Domestic Capacity ( MW) 186,001 185,866 ( 135)  0.1%

( 1a) Existing 152,891 148,972 ( 3,920)  2.6%

( 1b) New Additions 25,558 26,144 586 2.3%

( 1c) Repowering Additions 7,552 10,750 3,198 42.4% ( 1d) Closures 0 2,150 2,150 0.0%

( 2a) Energy Prices ($ 2002/ MWh) $ 26.27 $ 26.65 $ 0.38 1.4%

( 2b) Capacity Prices ($ 2002/ KW/ yr) $ 37.38 $ 37.34 ($ 0.04)  0.1%

( 3) Generation ( GWh) 848,817 847,901 ( 915)  0.1%

( 4) Revenues ( Millions; $ 2002) $ 28,705 $ 28,989 $ 284 1.0%

( 5) Costs ( Millions; $ 2002) $ 17,704 $ 18,173 $ 469 2.6%

( 5a) Fuel Cost $ 9,164 $ 9,487 $ 323 3.5%

( 5b) Variable O& M $ 1,263 $ 1,232 ($ 31)  2.5%

( 5c) Fixed O& M $ 4,439 $ 4,407 ($ 32)  0.7%

( 5d) Capital Cost $ 2,838 $ 3,047 $ 209 7.4% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 2: Market Level Impacts of the Waterbody/ Capacity Based Option ( by NERC Regions; 2013)

Economic Measures Base Case WB/ C Based Option Difference % Change B8 8 NODA Version   March 12, 2003 ( 6) Pre Tax Income ( Millions; $ 2002) $ 11,001 $ 10,816 ($ 185)  1.7%

( 7) Variable Production Costs ($/ MWh) $ 12.28 $ 12.64 $ 0.36 2.9%

Source: IPM analysis: Model runs for Section 316( b) NODA Base Case ( AEO electricity demand) and the waterbody/ capacity based option.

Summary of Market Results at the National Level. The results presented in Table B8 2 show that capacity closures would increase by 3,162 MW, which represents less than 0.4 percent of total baseline capacity. An increase in new capacity additions ( 1,214 MW) and repowering additions ( 4,364 MW) would compensate for this loss. Total domestic capacity would decrease by 0.1 percent due to other capacity losses, primarily the energy penalties associated with the installation of cooling towers. Revenues are expected to increase by $ 1.7 billion ( 1.0 percent) under this option. However, total costs would increase by a greater amount, $ 2.0 billion, leading to a loss in total pre tax income of $ 317 million ( 0.5 percent). The increase in cost is driven by higher fuel cost ( by 1.6 percent) and fixed O& M costs ( by 3.2 percent) which include the annualized capital cost of compliance with the waterbody/ capacity based option.

Summary of Market Results at the Regional Level. At the regional level, potential impacts under the waterbody/ capacitybased option vary by NERC region. Two principal factors appear to influence the results: ( 1) the requirement for facilities in some regions to install relatively high cost recirculating cooling towers and ( 2) incremental capacity closures. Both factors are discussed below:

< Regions with cooling towers. Six of the 10 analyzed NERC regions ( ERCOT, FRCC, MAAC, MPCC, SERC, and WSCC) have facilities costed with a cooling tower under the waterbody/ capacity based option. The remaining four regions ( ECAR, MAIN, MAPP, SPP) do not have any facilities with a cooling tower requirement ( see also Table B8 1 above). In general, the largest increases in costs as a result of this option would be to fixed O& M and fuel costs in regions where facilities have to install cooling towers under this option. These findings are not surprising. Capital costs of compliance are modeled as fixed O& M costs, and cooling towers have relatively high capital costs compared to other compliance technologies. In addition, the energy penalty associated with the operation of cooling towers would lead to an increase in the facility's heat rate: more fuel would be required to generate the same quantity of electricity. The increased costs of generation in these regions would lead to a rise in energy prices, which in turn would increase revenues. However, pre tax income would decrease as the increased cost of production would more than offset increased revenues associated with higher energy prices. < Incremental capacity closures. The early retirement of capacity and the simultaneous addition of new or repowered capacity to replace the retired capacity have the potential to change regional cost accounts, depending on the relative efficiencies of the retired and the new capacities. Under the waterbody/ capacity based option, two regions ( MAIN and WSCC) experience closures of nuclear capacity. Both regions are projected to experience decreases in total fixed O& M because nuclear facilities, in general, have substantially higher fixed O& M costs when compared to other plant types. As a result, at the regional level, decreases in these costs due to the retirement of nuclear capacity would more than offset the increases associated with compliance costs. These retirements would also contribute to an increase in total fuel costs, as nuclear facilities have lower average fuel costs than facilities fired by other fuels. These regions would also experience increases in energy prices and revenues, as facilities pass a portion of the increased fuel and compliance costs on to consumers.

Notable results of EPA's analysis of the waterbody/ capacity based option for the 10 NERC regions are: < ECAR, MAPP, and SPP do not have facilities estimated to install cooling towers. These three regions also do not experience incremental closures due to the waterbody/ capacity based option. As a result, changes in their operating conditions are generally smaller than for the other seven regions. In all three regions, prices would increase, leading to increases in revenues of between 1.0 and 1.2 percent. Fixed costs would also increase, but the rise in overall costs would be smaller than the increase in revenues, leading to higher pre tax income ( between 1.2 and 2.0 percent). Changes in variable production costs in these regions are less than 1.0 percent and smaller than in the other seven regions. < MAIN also does not have facilities estimated to install cooling towers. However, MAIN would experience an increase in post compliance capacity retirements due to two nuclear facilities reaching the end of their nuclear operating licenses. In the base case, these facilities would have extended their licenses and continued operation. Under the waterbody/ capacity based option, however, these facilities would retire part or all of their capacity by 2013. The resulting 1,012 MW increase in capacity closures ( 1.5 percent of baseline capacity) would be offset in part by a 977 MW increase in new capacity additions. Since nuclear facilities have substantially higher fixed O& M costs when compared to § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis 4 Note that of the 540 surveyed facilities subject to the section 316( b) Phase II Rule, nine are not modeled in the IPM. Three facilities are in Hawaii, one is in Alaska. Neither state is represented in the IPM. One facility is identified as an " Unspecified Resource" and does not report on any EIA forms. Four facilities are on site generators that do not provide electricity to the grid. Note that the facility level numbers presented in this section are not sample weighted.

NODA Version   March 12, 2003 B8 9 other plant types, the closure of nuclear capacity in this region would result in a 4.1 percent decrease in post compliance fixed O& M costs. This closure would also contribute to a 1.9 percent increase in average fuel costs and a 2.2 percent increase in variable production cost per MWh ( the second highest of any region), as nuclear facilities have lower fuel costs than most other plant types. While revenues in MAIN would only increase by 0.7 percent in response to the 1.6 percent increase in energy prices, pre tax income would increase by 1.4 percent, due in part to the reduction in fixed costs. < FRCC and MAAC would experience the largest increases in fixed O& M costs ( 11.4 and 11.5 percent, respectively) as both regions would incur relatively high compliance costs associated with the installation of cooling towers. Fuel costs in these regions would increase due to the energy penalty also associated with the operation of cooling towers. These increased costs would contribute to an increase in energy prices of 3.8 percent in FRCC ( the highest of any region) and 1.4 percent in MAAC. While these higher energy prices would lead to increases in revenues of approximately one percent, both regions would experience a decrease in pre tax income in excess of four percent ( the largest of all regions) as the increased cost of production would more than offset increased revenues. < In ERCOT, NPCC and SERC, changes similar to those in FRCC and MAAC would occur, but the magnitude of these changes would generally be smaller as total compliance costs in NPCC and ERCOT are lower. SERC would experience an 0.2 increase in pre tax income as a result of a larger increase in revenues ($ 415 million) compared to costs ($ 385 million). < WSCC, besides MAIN, is the only region to experience incremental closures under the waterbody/ capacity based option: one large nuclear facility with a capacity of 2,150 MW is expected to close. An increase in repowering additions of 3,198 MW would compensate for this loss. Similar to MAIN, the closure of nuclear capacity would result in a decrease in fixed O& M costs and an increase in fuel costs. However, unlike MAIN, which does not have any facilities with a cooling tower requirement, eight facilities in WSCC are estimated to install cooling towers under this option. The relatively high cost of these cooling towers would offset the reduction in total fixed O& M costs while the energy penalties associated with their operation would contribute to the 3.5 percent increase in fuel costs and a 2.9 percent increases in variable production cost per MWh ( the highest of any region). Energy prices would increase, leading to a 1.0 percent increase in revenues. Despite this increase, pre tax income would decline as a result of the rise in fuel costs and a 7.5 percent increase in capital costs associated with repowering additions and other investments.

B8 3 ANALYSIS OF PHASE II FACILITIES FOR 2013 This section presents the results of the IPM analysis for the in scope Phase II facilities that are modeled by the IPM. 4 Nine of the 531 Phase II facilities are closures in the base case, and 12 facilities are closures under the waterbody/ capacity based option. These facilities are not represented in the results described in this section.

EPA used the IPM results to analyze impacts on Phase II facilities at two levels: ( 1) potential changes in the economic and operational characteristics of the in scope Phase II facilities as a group and ( 2) potential changes to individual facilities within the group of Phase II facilities.

B8 3.1 In Scope Phase II Facilities as a Group This section presents the analysis of the potential impacts of the alternative waterbody/ capacity based option on the in scope Phase II facilities as a group. This analysis is similar to the market level analysis described above but is limited to facilities subject to the requirements of the section 316( b) rule. Table B8 3 presents the impact measures for the in scope Phase II facilities as a group: ( 1) capacity changes, including changes in the number and capacity of closure facilities; ( 2) generation changes; ( 3) revenue changes; ( 4) cost changes, including changes in fuel costs, variable O& M costs, fixed O& M costs, and capital costs; ( 5) changes in pre tax income, defined as revenues minus total costs; and ( 6) changes in variable production costs per MWh of generation, where variable production cost is defined as the sum of fuel cost and variable O& M cost. For each measure, the table presents the results for the base case and the waterbody/ capacity based option, the absolute difference between the two cases, and the percentage difference. A detailed description of each of the impact measures discussed below is presented in Section B3 3.2 of Chapter B3: Electricity Market Model Analysis. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis B8 10 NODA Version   March 12, 2003 Table B8 3: Facility Level Impacts of the Waterbody/ Capacity Based Option ( NERC Regions; 2013)

Economic Measures Base Case WB/ C Based Option Difference % Change National Totals ( 1) Total Domestic Capacity ( MW) 432,776 428,165 ( 4,611)  1.1%

( 1a) Closures  Number of Facilities 9 12 3 33.3%

( 1b) Closures  Capacity ( MW) 12,741 15,903 3,162 24.8%

( 2) Generation ( GWh) 2,319,049 2,270,627 ( 48,422)  2.1%

( 3) Revenues ( Millions; $ 2002) $ 80,517 $ 79,758 ($ 759)  0.9%

( 4) Costs ( Millions; $ 2002) $ 47,819 $ 47,759 ($ 60)  0.1%

( 4a) Fuel Cost $ 24,214 $ 23,686 ($ 528)  2.2%

( 4b) Variable O& M $ 5,171 $ 5,088 ($ 83)  1.6%

( 4c) Fixed O& M $ 15,103 $ 15,851 $ 748 5.0%

( 4d) Capital Cost $ 3,331 $ 3,133 ($ 198)  5.9%

( 5) Pre Tax Income ( Millions; $ 2002) $ 32,698 $ 31,999 ($ 699)  2.1%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.67 $ 12.67 $ 0.00 0.0%

East Central Area Reliability Coordination Agreement ( ECAR)

( 1) Total Domestic Capacity ( MW) 82,258 82,258 0 0.0%

( 1a) Closures  Number of Facilities 0 0 0 0.0%

( 1b) Closures  Capacity ( MW) 1 1 0 0.0%

( 2) Generation ( GWh) 537,822 538,244 422 0.1%

( 3) Revenues ( Millions; $ 2002) $ 17,747 $ 17,947 $ 200 1.1%

( 4) Costs ( Millions; $ 2002) $ 9,822 $ 9,944 $ 123 1.3%

( 4a) Fuel Cost $ 5,052 $ 5,071 $ 19 0.4%

( 4b) Variable O& M $ 1,320 $ 1,326 $ 6 0.4%

( 4c) Fixed O& M $ 2,991 $ 3,085 $ 94 3.1%

( 4d) Capital Cost $ 458 $ 463 $ 4 0.9%

( 5) Pre Tax Income ( Millions; $ 2002) $ 7,926 $ 8,003 $ 77 1.0%

( 6) Variable Production Costs ($ 2002/ MWh) $ 11.85 $ 11.88 $ 0.04 0.3%

Electric Reliability Council of Texas ( ERCOT)

( 1) Total Domestic Capacity ( MW) 44,400 44,419 19 0.0%

( 1a) Closures  Number of Facilities 0 0 0 0.0%

( 1b) Closures  Capacity ( MW) 0 0 0 0.0%

( 2) Generation ( GWh) 158,578 157,576 ( 1,001)  0.6%

( 3) Revenues ( Millions; $ 2002) $ 5,867 $ 5,882 $ 15 0.3%

( 4) Costs ( Millions; $ 2002) $ 3,894 $ 3,919 $ 25 0.6%

( 4a) Fuel Cost $ 2,034 $ 2,014 ($ 20)  1.0%

( 4b) Variable O& M $ 423 $ 421 ($ 2)  0.5%

( 4c) Fixed O& M $ 1,196 $ 1,235 $ 38 3.2%

( 4d) Capital Cost $ 240 $ 249 $ 9 3.7% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 3: Facility Level Impacts of the Waterbody/ Capacity Based Option ( NERC Regions; 2013)

Economic Measures Base Case WB/ C Based Option Difference % Change NODA Version   March 12, 2003 B8 11 ( 5) Pre Tax Income ( Millions; $ 2002) $ 1,973 $ 1,963 ($ 10)  0.5%

( 6) Variable Production Costs ($ 2002/ MWh) $ 15.49 $ 15.46 ($ 0.04)  0.3%

Florida Reliability Coordinating Council ( FRCC)

( 1) Total Domestic Capacity ( MW) 27,513 27,399 ( 114)  0.4%

( 1a) Closures  Number of Facilities 0 0 0 0.0%

( 1b) Closures  Capacity ( MW) 812 812 0 0.0%

( 2) Generation ( GWh) 80,229 77,384 ( 2,845)  3.5%

( 3) Revenues ( Millions; $ 2002) $ 3,532 $ 3,469 ($ 63)  1.8%

( 4) Costs ( Millions; $ 2002) $ 1,943 $ 2,047 $ 104 5.3%

( 4a) Fuel Cost $ 1,035 $ 998 ($ 37)  3.6%

( 4b) Variable O& M $ 196 $ 194 ($ 2)  1.2%

( 4c) Fixed O& M $ 682 $ 826 $ 144 21.1%

( 4d) Capital Cost $ 30 $ 29 ($ 1)  2.1%

( 5) Pre Tax Income ( Millions; $ 2002) $ 1,589 $ 1,422 ($ 167)  10.5%

( 6) Variable Production Costs ($ 2002/ MWh) $ 15.35 $ 15.41 $ 0.05 0.3%

Mid Atlantic Area Council ( MAAC)

( 1) Total Domestic Capacity ( MW) 34,696 34,501 ( 195)  0.6%

( 1a) Closures  Number of Facilities 1 1 0 0.0%

( 1b) Closures  Capacity ( MW) 1,725 1,725 0 0.0%

( 2) Generation ( GWh) 176,909 175,119 ( 1,790)  1.0%

( 3) Revenues ( Millions; $ 2002) $ 6,720 $ 6,737 $ 17 0.3%

( 4) Costs ( Millions; $ 2002) $ 3,794 $ 4,038 $ 244 6.4%

( 4a) Fuel Cost $ 1,688 $ 1,686 ($ 1)  0.1%

( 4b) Variable O& M $ 366 $ 362 ($ 4)  1.1%

( 4c) Fixed O& M $ 1,509 $ 1,757 $ 248 16.4%

( 4d) Capital Cost $ 232 $ 233 $ 1 0.5%

( 5) Pre Tax Income ( Millions; $ 2002) $ 2,926 $ 2,700 ($ 226)  7.7%

( 6) Variable Production Costs ($ 2002/ MWh) $ 11.61 $ 11.69 $ 0.09 0.8%

Mid America Interconnected Network ( MAIN)

( 1) Total Domestic Capacity ( MW) 34,944 33,932 ( 1,012)  2.9%

( 1a) Closures  Number of Facilities 3 5 2 66.7%

( 1b) Closures  Capacity ( MW) 5,620 6,632 1,012 18.0%

( 2) Generation ( GWh) 219,900 214,425 ( 5,475)  2.5%

( 3) Revenues ( Millions; $ 2002) $ 7,133 $ 7,030 ($ 103)  1.4%

( 4) Costs ( Millions; $ 2002) $ 3,965 $ 3,813 ($ 151)  3.8%

( 4a) Fuel Cost $ 2,000 $ 1,976 ($ 24)  1.2%

( 4b) Variable O& M $ 498 $ 489 ($ 9)  1.9% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 3: Facility Level Impacts of the Waterbody/ Capacity Based Option ( NERC Regions; 2013)

Economic Measures Base Case WB/ C Based Option Difference % Change B8 12 NODA Version   March 12, 2003 ( 4c) Fixed O& M $ 1,334 $ 1,255 ($ 79)  5.9%

( 4d) Capital Cost $ 133 $ 94 ($ 39)  29.4%

( 5) Pre Tax Income ( Millions; $ 2002) $ 3,168 $ 3,217 $ 48 1.5%

( 6) Variable Production Costs ($ 2002/ MWh) $ 11.36 $ 11.49 $ 0.13 1.2%

Mid Continent Area Power Pool ( MAPP)

( 1) Total Domestic Capacity ( MW) 15,723 15,723 0 0.0%

( 1a) Closures  Number of Facilities 1 1 0 0.0%

( 1b) Closures  Capacity ( MW) 476 476 0 0.0%

( 2) Generation ( GWh) 111,302 111,376 74 0.1%

( 3) Revenues ( Millions; $ 2002) $ 3,331 $ 3,378 $ 46 1.4%

( 4) Costs ( Millions; $ 2002) $ 1,964 $ 1,983 $ 19 1.0%

( 4a) Fuel Cost $ 1,016 $ 1,017 $ 1 0.1%

( 4b) Variable O& M $ 229 $ 230 $ 0 0.2%

( 4c) Fixed O& M $ 599 $ 617 $ 18 2.9%

( 4d) Capital Cost $ 120 $ 120 $ 0 0.0%

( 5) Pre Tax Income ( Millions; $ 2002) $ 1,367 $ 1,395 $ 27 2.0%

( 6) Variable Production Costs ($ 2002/ MWh) $ 11.19 $ 11.19 $ 0.00 0.0%

Northeast Power Coordinating Council ( NPCC)

( 1) Total Domestic Capacity ( MW) 37,219 37,139 ( 81)  0.2%

( 1a) Closures  Number of Facilities 4 4 0 0.0%

( 1b) Closures  Capacity ( MW) 4,107 4,107 0 0.0%

( 2) Generation ( GWh) 159,927 159,005 ( 921)  0.6%

( 3) Revenues ( Millions; $ 2002) $ 6,635 $ 6,653 $ 18 0.3%

( 4) Costs ( Millions; $ 2002) $ 4,964 $ 5,136 $ 172 3.5%

( 4a) Fuel Cost $ 2,681 $ 2,694 $ 13 0.5%

( 4b) Variable O& M $ 269 $ 264 ($ 5)  1.8%

( 4c) Fixed O& M $ 1,238 $ 1,396 $ 157 12.7%

( 4d) Capital Cost $ 774 $ 782 $ 7 0.9%

( 5) Pre Tax Income ( Millions; $ 2002) $ 1,671 $ 1,518 ($ 154)  9.2%

( 6) Variable Production Costs ($ 2002/ MWh) $ 18.45 $ 18.61 $ 0.16 0.8%

Southeastern Electric Reliability Council ( SERC)

( 1) Total Domestic Capacity ( MW) 107,458 107,327 ( 131)  0.1%

( 1a) Closures  Number of Facilities 0 0 0 0.0%

( 1b) Closures  Capacity ( MW) 0 0 0 0.0%

( 2) Generation ( GWh) 639,694 640,168 473 0.1%

( 3) Revenues ( Millions; $ 2002) $ 21,421 $ 21,644 $ 222 1.0%

( 4) Costs ( Millions; $ 2002) $ 12,075 $ 12,305 $ 230 1.9% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 3: Facility Level Impacts of the Waterbody/ Capacity Based Option ( NERC Regions; 2013)

Economic Measures Base Case WB/ C Based Option Difference % Change NODA Version   March 12, 2003 B8 13 ( 4a) Fuel Cost $ 5,878 $ 5,925 $ 47 0.8%

( 4b) Variable O& M $ 1,370 $ 1,377 $ 7 0.5%

( 4c) Fixed O& M $ 3,984 $ 4,158 $ 174 4.4%

( 4d) Capital Cost $ 842 $ 845 $ 3 0.3%

( 5) Pre Tax Income ( Millions; $ 2002) $ 9,347 $ 9,339 ($ 8)  0.1%

( 6) Variable Production Costs ($ 2002/ MWh) $ 11.33 $ 11.41 $ 0.08 0.7%

Southwest Power Pool ( SPP)

( 1) Total Domestic Capacity ( MW) 20,471 20,471 0 0.0%

( 1a) Closures  Number of Facilities 0 0 0 0.0%

( 1b) Closures  Capacity ( MW) 0 0 0 0.0%

( 2) Generation ( GWh) 109,024 108,345 ( 679)  0.6%

( 3) Revenues ( Millions; $ 2002) $ 3,595 $ 3,616 $ 20 0.6%

( 4) Costs ( Millions; $ 2002) $ 1,878 $ 1,873 ($ 5)  0.3%

( 4a) Fuel Cost $ 1,076 $ 1,059 ($ 16)  1.5%

( 4b) Variable O& M $ 240 $ 240 ($ 1)  0.2%

( 4c) Fixed O& M $ 557 $ 570 $ 13 2.4%

( 4d) Capital Cost $ 5 $ 4 ($ 1)  22.2%

( 5) Pre Tax Income ( Millions; $ 2002) $ 1,718 $ 1,742 $ 25 1.4%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.07 $ 11.99 ($ 0.08)  0.7%

Western Systems Coordinating Council ( WSCC)

( 1) Total Domestic Capacity ( MW) 28,093 24,997 ( 3,096)  11.0%

( 1a) Closures  Number of Facilities 0 1 1 n/ a ( 1b) Closures  Capacity ( MW) 0 2,150 2,150 n/ a ( 2) Generation ( GWh) 125,663 88,984 ( 36,680)  29.2%

( 3) Revenues ( Millions; $ 2002) $ 4,534 $ 3,402 ($ 1,132)  25.0%

( 4) Costs ( Millions; $ 2002) $ 3,522 $ 2,701 ($ 821)  23.3%

( 4a) Fuel Cost $ 1,753 $ 1,246 ($ 508)  29.0%

( 4b) Variable O& M $ 258 $ 186 ($ 73)  28.1%

( 4c) Fixed O& M $ 1,013 $ 953 ($ 60)  5.9%

( 4d) Capital Cost $ 497 $ 316 ($ 181)  36.4%

( 5) Pre Tax Income ( Millions; $ 2002) $ 1,012 $ 701 ($ 311)  30.7%

( 6) Variable Production Costs ($ 2002/ MWh) $ 16.01 $ 16.09 $ 0.08 0.5%

Source: IPM analysis: Model runs for Section 316( b) NODA Base Case ( AEO electricity demand) and the waterbody/ capacity based option.

Summary of Phase II Facility Results at the National Level. The results presented in Table B8 3 show that under the alternative waterbody/ capacity based option capacity closures within the group of Phase II facilities would increase by 3,162 MW, which represents less than one percent of baseline Phase II capacity. This increase in capacity closures would § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis B8 14 NODA Version   March 12, 2003 contribute to a 4,611 MW decrease in total Phase II capacity ( 1.1 percent of baseline capacity). The balance of this reduction in total Phase II capacity is largely due to energy penalties associated with the operation of cooling towers. Total Phase II generation would decrease by 2.1 percent under this option ( in part due to the reduction in total capacity), leading to a reduction in Phase II fuel costs, variable O& M costs, and revenues. Revenues would decrease by a smaller amount than generation ( 0.9 percent), because of price increases in many regions. Fixed O& M costs, which include the annualized capital cost of compliance with the waterbody/ capacity based option, would increase by 5.0 percent. Overall, revenues would decrease by $ 759 million and costs would decrease by $ 60 million. Pre tax income for the group of Phase II facilities would be reduced by approximately $ 700 million ( 2.1 percent) under this option compared to a reduction of $ 317 million ( 0.5 percent) at the market level.

Summary of Phase II Facility Results at the Regional Level. At the regional level, potential impacts under the waterbody/ capacity based option vary by NERC region. Two principal factors appear to influence the results: ( 1) the requirement for facilities in some regions to install relatively high cost recirculating cooling towers and ( 2) incremental capacity closures. For a discussion of these factors, please refer to section B8 2 above. Notable results of the regional analysis of impacts on the group of Phase II facilities under the waterbody/ capacity based option are: < No Phase II facilities in ECAR, MAPP, and SPP are estimated to install cooling towers. These three regions also do not experience incremental closures due to the waterbody/ capacity based option. As a result, changes in their operating conditions are generally smaller than for the other NERC regions. < MAIN also does not have facilities estimated to install cooling towers. However, two facilities in MAIN, accounting for 1,012 MW, would close under this option. Both are nuclear facilities which, in the base case, would have extended their licenses and continued operation. Under the waterbody/ capacity based option, however, these facilities would retire part or all of their capacity by 2013. As a result of this net loss in capacity, generation, revenues, and all cost accounts for Phase II facilities in MAIN would experience reductions. However, costs decrease more than revenues, resulting in a small increase in pre tax income. Since nuclear facilities have substantially lower fuel and variable O& M costs when compared to other plant types, the closure of nuclear capacity in this region would result in an increase in variable production cost of 1.2 percent. < FRCC and MAAC would experience the largest increases in fixed O& M costs ( 21.1 and 16.4 percent, respectively) as more than 26 percent of Phase II capacity in each region would install cooling towers under this option leading to relatively high compliance costs. Phase II facilities in these regions would experience decreased generation and revenues when compared to market level trends as the group of Phase II facilities becomes less competitive due to the costs of compliance. At the market level, revenues increase, indicating that facilities not subject to Phase II regulation benefit under this option. Similarly, reductions in pre tax income for the group of Phase II facilities in the two regions exceed losses at the market. < In ERCOT, NPCC, and SERC, changes similar to those in FRCC and MAAC would occur, but the magnitude of these changes would generally be smaller because the percent of Phase II capacity installing cooling towers and total compliance costs in these regions are lower. < The group of Phase II facilities in WSCC would experience larger impacts than any other region under the waterbody/ capacity based option. This is largely due to the fact that 47.2 percent of Phase II capacity in WSCC is projected to install cooling towers under this option. One nuclear facility would close, contributing to an 11 percent loss of total Phase II capacity in the region. Generation would decrease by 29.2 percent. Similarly, revenues and all cost accounts, except for fixed O& M cost, would decrease by over 20 percent. Fixed O& M costs decrease by a small amount because of the relatively high compliance costs associated with the installation of eight cooling towers in this region.

B8 3.2 Individual Phase II Facilities In addition to effects of the waterbody/ capacity based option on the in scope Phase II facilities as a group, there may be shifts in economic performance among individual facilities subject to Phase II regulation. To assess such potential shifts, EPA analyzed the same facility specific changes as for the preferred option: changes in ( 1) capacity utilization ( defined as generation divided by capacity times 8,760); ( 2) generation; ( 3) revenue; ( 4) variable production costs per MWh of generation ( defined as variable O& M cost plus fuel cost divided by generation); ( 5) fuel cost per MWh of generation; and ( 6) pre tax income. For each measure, EPA determined the number of Phase II facilities that experience no changes, or an increase or a reduction within three ranges: 1 percent or less, 1 to 3 percent, and 3 percent or more.

Table B8 4 presents the total number of Phase II facilities with different degrees of change in each of these measures. This table excludes 30 in scope facilities with significant status changes ( nine facilities are baseline closures, three facilities are policy closures, and 18 facilities changed their repowering decision between the base case and the policy case). These facilities are either not operating at all in either the base case or the post compliance case, or they experience fundamental changes in the type of units they operate; therefore, the measures presented below would not be meaningful for these facilities. In addition, the changes in production cost per MWh and fuel cost per MWh could not be developed for 62 § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis NODA Version   March 12, 2003 B8 15 facilities with zero generation in either the base case or post compliance scenario. For these facilities, the change in production cost per MWh and fuel cost per MWh is indicated as " n/ a."

Table B8 4: Number of Individual Phase II Facilities with Operational Changes ( 2013)

Economic Measures Reduction Increase No Change N/ A </= 1% 1 3% > 3% </= 1% 1 3% > 3%

( 1) Change in Capacity Utilization 4 11 21 6 14 15 430

( 2) Change in Generation 7 24 37 5 7 23 398

( 3) Change in Revenues 56 13 41 108 247 28 8

( 4) Change in Variable Production Costs/ MWh 18 5 8 154 115 21 118 62 ( 5) Change in Fuel Costs 11 3 8 90 114 19 194 62 ( 6) Change in Pre Tax Income 51 62 164 45 141 36 2

a For all measures percentages used to assign facilities to impact categories have been rounded to the nearest 10th of a percent. b The change in capacity utilization is the difference between the capacity utilization percentages in the base case and postcompliance case. For all other measures, the change is expressed as the percentage change between the base case and postcompliance values.

Source: IPM analysis: Model runs for Section 316( b) NODA Base Case ( AEO electricity demand) and the waterbody/ capacity based option.

Table B8 4 indicates that the majority of Phase II facilities would not experience changes in capacity utilization or generation due to compliance with the waterbody/ capacity based option. Of facilities with post compliance changes in capacity utilization and/ or generation, the majority would experience reductions in these measures. Table B8 4 also indicates that the majority of Phase II facilities would experience increases in revenues, variable production costs per MWh, and fuel costs per MWh of between zero and three percent. Similarly, almost all Phase II facilities would experience a change in pre tax income, with a slight majority seeing a reduction in this measure.

B8 4 MARKET ANALYSIS FOR 2008 This section presents market level results for the waterbody/ capacity based option for model run year 2008. Unlike the market level analysis for 2013 described above, model run year 2008 includes facilities that experience a one time downtime due to the installation of Phase II compliance technologies. This analysis therefore presents potential short term effects that may occur during the five year period ( 2005 to 2009) represented by model run year 2008. However, it should be noted that not all facilities are in compliance by 2008. Therefore, potential effects of installation downtimes may be mitigated by the fact that some facilities will not incur compliance costs until after 2008.

Table B8 5 below presents the following market level impacts for 2008: ( 1) electricity price changes, including changes in energy prices and capacity prices; ( 2) generation changes; ( 3) revenue changes; ( 4) cost changes, including changes in fuel costs, variable O& M costs, fixed O& M costs, and capital costs; ( 5) changes in pre tax income, defined as revenues minus total costs; and ( 6) changes in variable production costs per MWh. For each measure, the table presents the results for the base case and the waterbody/ capacity based option, the absolute difference between the two cases, and the percentage difference. The table also repeats the percentage difference based on the market level analysis for 2013 presented in Table B8 2 above. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis B8 16 NODA Version   March 12, 2003 Table B8 5: Comparison of Market Level Impacts of the Waterbody/ Capacity Based Option ( 2008 and 2013)

Economic Measures Base Case ( 2008) WB/ C Based Option ( 2008) Difference ( 2008) % Change ( 2008) % Change ( 2013)

National Totals ( 1a) Energy Price ($ 2002/ MWh) n/ a n/ a n/ a n/ a n/ a ( 1b) Capacity Price ($ 2002/ KW) n/ a n/ a n/ a n/ a n/ a ( 2) Total Generation ( GWh) 4,243,558 4,243,985 427 0.0% 0.0%

( 3) Total Revenues ( Millions; $ 2002) $ 172,255 $ 173,591 $ 1,336 0.8% 1.0%

( 4) Costs ( Millions; $ 2002) $ 93,847 $ 95,111 $ 1,264 1.3% 1.9%

( 4a) Fuel Cost $ 51,909 $ 52,330 $ 421 0.8% 1.6%

( 4b) Variable O& M $ 8,091 $ 8,048 ($ 44)  0.5%  0.3%

( 4c) Fixed O& M $ 24,216 $ 24,767 $ 552 2.3% 3.2%

( 4d) Capital Cost $ 9,631 $ 9,965 $ 335 3.5% 2.0%

( 5) Pre Tax Income ( Millions; $ 2002) $ 78,409 $ 78,480 $ 72 0.1%  0.5%

( 6) Variable Production Costs ($ 2002/ MWh) $ 14.14 $ 14.23 $ 0.09 0.6% 1.2%

East Central Area Reliability Coordination Agreement ( ECAR)

( 1a) Energy Price ($ 2002/ MWh) $ 25.03 $ 25.36 $ 0.33 1.3% 0.8%

( 1b) Capacity Price ($ 2002/ KW) $ 80.14 $ 79.91 ($ 0.23)  0.3% 5.2%

( 2) Total Generation ( GWh) 665,167 663,991 ( 1,176)  0.2% 0.1%

( 3) Total Revenues ( Millions; $ 2002) $ 26,582 $ 26,691 $ 110 0.4% 1.2%

( 4) Costs ( Millions; $ 2002) $ 13,472 $ 13,515 $ 43 0.3% 1.1%

( 4a) Fuel Cost $ 6,921 $ 6,923 $ 1 0.0% 0.8%

( 4b) Variable O& M $ 1,613 $ 1,611 ($ 1)  0.1% 0.4%

( 4c) Fixed O& M $ 3,610 $ 3,691 $ 82 2.3% 2.6%

( 4d) Capital Cost $ 1,329 $ 1,290 ($ 39)  2.9% 0.1%

( 5) Pre Tax Income ( Millions; $ 2002) $ 13,109 $ 13,176 $ 67 0.5% 1.3%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.83 $ 12.85 $ 0.02 0.2% 0.5%

Electric Reliability Council of Texas ( ERCOT)

( 1a) Energy Price ($ 2002/ MWh) $ 29.59 $ 31.08 $ 1.49 5.0% 1.7%

( 1b) Capacity Price ($ 2002/ KW) $ 48.19 $ 40.35 ($ 7.83)  16.3%  1.3%

( 2) Total Generation ( GWh) 341,915 342,502 587 0.2% 0.0%

( 3) Total Revenues ( Millions; $ 2002) $ 13,770 $ 13,702 ($ 68)  0.5% 1.0%

( 4) Costs ( Millions; $ 2002) $ 8,400 $ 8,450 $ 49 0.6% 1.4%

( 4a) Fuel Cost $ 5,540 $ 5,542 $ 2 0.0% 1.4%

( 4b) Variable O& M $ 677 $ 675 ($ 2)  0.3% 0.0%

( 4c) Fixed O& M $ 1,723 $ 1,743 $ 20 1.2% 1.9%

( 4d) Capital Cost $ 461 $ 490 $ 29 6.3% 1.8% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 5: Comparison of Market Level Impacts of the Waterbody/ Capacity Based Option ( 2008 and 2013)

Economic Measures Base Case ( 2008) WB/ C Based Option ( 2008) Difference ( 2008) % Change ( 2008) % Change ( 2013)

NODA Version   March 12, 2003 B8 17 ( 5) Pre Tax Income ( Millions; $ 2002) $ 5,370 $ 5,252 ($ 118)  2.2%  0.1%

( 6) Variable Production Costs ($ 2002/ MWh) $ 18.18 $ 18.15 ($ 0.03)  0.2% 1.2%

Florida Reliability Coordinating Council ( FRCC)

( 1a) Energy Price ($ 2002/ MWh) $ 30.75 $ 31.08 $ 0.33 1.1% 3.8%

( 1b) Capacity Price ($ 2002/ KW) $ 64.79 $ 63.37 ($ 1.42)  2.2%  6.3%

( 2) Total Generation ( GWh) 197,481 196,939 ( 542)  0.3% 0.0%

( 3) Total Revenues ( Millions; $ 2002) $ 9,399 $ 9,370 ($ 29)  0.3% 1.0%

( 4) Costs ( Millions; $ 2002) $ 5,868 $ 6,014 $ 147 2.5% 3.3%

( 4a) Fuel Cost $ 3,411 $ 3,451 $ 40 1.2% 1.9%

( 4b) Variable O& M $ 379 $ 378 ($ 1)  0.3% 0.3%

( 4c) Fixed O& M $ 1,210 $ 1,312 $ 102 8.5% 11.4%

( 4d) Capital Cost $ 868 $ 874 $ 6 0.7% 0.0%

( 5) Pre Tax Income ( Millions; $ 2002) $ 3,531 $ 3,356 ($ 176)  5.0%  5.4%

( 6) Variable Production Costs ($ 2002/ MWh) $ 19.19 $ 19.44 $ 0.25 1.3% 1.7%

Mid Atlantic Area Council ( MAAC)

( 1a) Energy Price ($ 2002/ MWh) $ 28.18 $ 28.17 $ 0.00 0.0% 1.4%

( 1b) Capacity Price ($ 2002/ KW) $ 74.94 $ 75.14 $ 0.20 0.3% 0.1%

( 2) Total Generation ( GWh) 289,502 288,953 ( 549)  0.2% 0.0%

( 3) Total Revenues ( Millions; $ 2002) $ 13,142 $ 13,132 ($ 10)  0.1% 0.9%

( 4) Costs ( Millions; $ 2002) $ 6,665 $ 6,827 $ 162 2.4% 4.1%

( 4a) Fuel Cost $ 3,166 $ 3,180 $ 14 0.4% 1.6%

( 4b) Variable O& M $ 594 $ 591 ($ 3)  0.6%  0.3%

( 4c) Fixed O& M $ 2,306 $ 2,448 $ 142 6.2% 11.5%

( 4d) Capital Cost $ 599 $ 608 $ 9 1.5% 0.6%

( 5) Pre Tax Income ( Millions; $ 2002) $ 6,478 $ 6,306 ($ 172)  2.7%  4.1%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.99 $ 13.05 $ 0.06 0.5% 1.3%

Mid America Interconnected Network ( MAIN)

( 1a) Energy Price ($ 2002/ MWh) $ 24.20 $ 24.57 $ 0.37 1.5% 1.6%

( 1b) Capacity Price ($ 2002/ KW) $ 78.33 $ 77.81 ($ 0.52)  0.7% 0.1%

( 2) Total Generation ( GWh) 294,504 294,233 ( 271)  0.1%  0.6%

( 3) Total Revenues ( Millions; $ 2002) $ 11,982 $ 12,032 $ 50 0.4% 0.7%

( 4) Costs ( Millions; $ 2002) $ 6,288 $ 6,304 $ 15 0.2% 0.2%

( 4a) Fuel Cost $ 3,130 $ 3,162 $ 31 1.0% 1.9%

( 4b) Variable O& M $ 604 $ 604 $ 0 0.0%  0.5% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 5: Comparison of Market Level Impacts of the Waterbody/ Capacity Based Option ( 2008 and 2013)

Economic Measures Base Case ( 2008) WB/ C Based Option ( 2008) Difference ( 2008) % Change ( 2008) % Change ( 2013)

B8 18 NODA Version   March 12, 2003 ( 4c) Fixed O& M $ 1,966 $ 1,942 ($ 24)  1.2%  4.1%

( 4d) Capital Cost $ 588 $ 596 $ 8 1.4% 2.2%

( 5) Pre Tax Income ( Millions; $ 2002) $ 5,694 $ 5,729 $ 35 0.6% 1.4%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.68 $ 12.80 $ 0.12 0.9% 2.2%

Mid Continent Area Power Pool ( MAPP)

( 1a) Energy Price ($ 2002/ MWh) $ 23.73 $ 23.77 $ 0.04 0.2% 1.8%

( 1b) Capacity Price ($ 2002/ KW) $ 77.83 $ 77.17 ($ 0.66)  0.9%  0.1%

( 2) Total Generation ( GWh) 186,975 187,698 723 0.4% 0.0%

( 3) Total Revenues ( Millions; $ 2002) $ 7,295 $ 7,300 $ 5 0.1% 1.2%

( 4) Costs ( Millions; $ 2002) $ 3,642 $ 3,683 $ 42 1.1% 0.7%

( 4a) Fuel Cost $ 1,877 $ 1,890 $ 13 0.7% 0.3%

( 4b) Variable O& M $ 376 $ 377 $ 1 0.3% 0.1%

( 4c) Fixed O& M $ 1,017 $ 1,035 $ 18 1.8% 1.7%

( 4d) Capital Cost $ 372 $ 381 $ 9 2.3% 0.7%

( 5) Pre Tax Income ( Millions; $ 2002) $ 3,653 $ 3,616 ($ 36)  1.0% 2.0%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.05 $ 12.08 $ 0.03 0.3% 0.3%

Northeast Power Coordinating Council ( NPCC)

( 1a) Energy Price ($ 2002/ MWh) $ 31.19 $ 31.20 $ 0.01 0.0% 1.1%

( 1b) Capacity Price ($ 2002/ KW) $ 70.60 $ 70.38 ($ 0.22)  0.3% 0.1%

( 2) Total Generation ( GWh) 291,319 291,301 ( 17) 0.0% 0.1%

( 3) Total Revenues ( Millions; $ 2002) $ 13,908 $ 13,896 ($ 13)  0.1% 0.9%

( 4) Costs ( Millions; $ 2002) $ 8,240 $ 8,317 $ 77 0.9% 2.8%

( 4a) Fuel Cost $ 4,875 $ 4,887 $ 12 0.2% 1.5%

( 4b) Variable O& M $ 393 $ 391 ($ 2)  0.5%  0.8%

( 4c) Fixed O& M $ 1,799 $ 1,857 $ 58 3.2% 8.5%

( 4d) Capital Cost $ 1,173 $ 1,182 $ 9 0.8% 1.2%

( 5) Pre Tax Income ( Millions; $ 2002) $ 5,669 $ 5,579 ($ 90)  1.6%  3.3%

( 6) Variable Production Costs ($ 2002/ MWh) $ 18.08 $ 18.12 $ 0.04 0.2% 1.2%

Southeastern Electric Reliability Council ( SERC)

( 1a) Energy Price ($ 2002/ MWh) $ 26.49 $ 26.56 $ 0.07 0.3% 1.4%

( 1b) Capacity Price ($ 2002/ KW) $ 69.71 $ 69.43 ($ 0.27)  0.4%  0.2%

( 2) Total Generation ( GWh) 978,448 980,504 2,055 0.2% 0.2%

( 3) Total Revenues ( Millions; $ 2002) $ 39,685 $ 39,811 $ 126 0.3% 1.1%

( 4) Costs ( Millions; $ 2002) $ 21,171 $ 21,493 $ 322 1.5% 1.6% § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis Table B8 5: Comparison of Market Level Impacts of the Waterbody/ Capacity Based Option ( 2008 and 2013)

Economic Measures Base Case ( 2008) WB/ C Based Option ( 2008) Difference ( 2008) % Change ( 2008) % Change ( 2013)

NODA Version   March 12, 2003 B8 19 ( 4a) Fuel Cost $ 11,457 $ 11,521 $ 64 0.6% 1.3%

( 4b) Variable O& M $ 1,834 $ 1,831 ($ 3)  0.2% 0.5%

( 4c) Fixed O& M $ 5,302 $ 5,475 $ 173 3.3% 3.3%

( 4d) Capital Cost $ 2,578 $ 2,665 $ 88 3.4% 0.8%

( 5) Pre Tax Income ( Millions; $ 2002) $ 18,514 $ 18,318 ($ 196)  1.1% 0.2%

( 6) Variable Production Costs ($ 2002/ MWh) $ 13.58 $ 13.62 $ 0.03 0.2% 1.0%

Southwest Power Pool ( SPP)

( 1a) Energy Price ($ 2002/ MWh) $ 25.94 $ 25.84 ($ 0.10)  0.4% 1.5%

( 1b) Capacity Price ($ 2002/ KW) $ 67.00 $ 68.19 $ 1.19 1.8%  0.1%

( 2) Total Generation ( GWh) 225,563 225,164 ( 400)  0.2% 0.0%

( 3) Total Revenues ( Millions; $ 2002) $ 9,236 $ 9,264 $ 27 0.3% 1.0%

( 4) Costs ( Millions; $ 2002) $ 4,531 $ 4,535 $ 4 0.1% 0.8%

( 4a) Fuel Cost $ 2,909 $ 2,905 ($ 3)  0.1% 0.7%

( 4b) Variable O& M $ 426 $ 426 $ 0 0.1% 0.2%

( 4c) Fixed O& M $ 1,051 $ 1,063 $ 11 1.1% 1.4%

( 4d) Capital Cost $ 146 $ 141 ($ 4)  2.9% 1.4%

( 5) Pre Tax Income ( Millions; $ 2002) $ 4,705 $ 4,728 $ 23 0.5% 1.2%

( 6) Variable Production Costs ($ 2002/ MWh) $ 14.78 $ 14.80 $ 0.01 0.1% 0.6%

Western Systems Coordinating Council ( WSCC)

( 1a) Energy Price ($ 2002/ MWh) $ 29.23 $ 29.10 ($ 0.12)  0.4% 1.4%

( 1b) Capacity Price ($ 2002/ KW) $ 30.03 $ 37.90 $ 7.87 26.2%  0.1%

( 2) Total Generation ( GWh) 772,683 772,700 17 0.0%  0.1%

( 3) Total Revenues ( Millions; $ 2002) $ 27,255 $ 28,393 $ 1,137 4.2% 1.0%

( 4) Costs ( Millions; $ 2002) $ 15,569 $ 15,973 $ 403 2.6% 2.6%

( 4a) Fuel Cost $ 8,623 $ 8,870 $ 247 2.9% 3.5%

( 4b) Variable O& M $ 1,196 $ 1,164 ($ 32)  2.7%  2.5%

( 4c) Fixed O& M $ 4,232 $ 4,201 ($ 31)  0.7%  0.7%

( 4d) Capital Cost $ 1,518 $ 1,738 $ 220 14.5% 7.4%

( 5) Pre Tax Income ( Millions; $ 2002) $ 11,686 $ 12,420 $ 734 6.3%  1.7%

( 6) Variable Production Costs ($ 2002/ MWh) $ 12.71 $ 12.99 $ 0.28 2.2% 2.9%

Source: IPM analysis: Model runs for Section 316( b) NODA Base Case ( AEO electricity demand) and the waterbody/ capacity based option.

Summary of Market Results at the National Level. The results presented in Table B8 5 show that under the waterbody/ capacity based option economic impacts due to downtimes associated with the installation of compliance technologies would not be substantially different from impacts observed in 2013 ( which represents the post compliance § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis B8 20 NODA Version   March 12, 2003 scenario in which no facilities experience downtimes). Total cost increases would be lower in 2008 than 2013, reflecting the fact that some facilities would not yet be in compliance with this option. Similarly, increases in fuel costs in 2008 would be half of those in 2013, leading to lower increases in variable production costs per MWh.

Summary of Market Results at the Regional Level. The results for 2008 in most regions are similar to results for 2013. Results for 2008 reflect installation downtimes for some facilities, while 2013 results do not. On the other hand, some of the facilities do not come into compliance until after 2008. Therefore, their compliance costs would not be reflected in the 2008 results but are reflected in the 2013 results. Overall, the impact of installation downtimes ( reflected in the 2008 results) appears to be similar to the impact of compliance costs incurred after 2008 ( reflected in the 2013 results). The following discussion highlights differences in the analysis results between 2013 and 2008: < Two regions, ECAR and ERCOT, would experience higher increases in energy prices in 2008 than in 2013. All other regions would experience lower impacts on energy prices in 2008 compared to 2013. < Three regions ( MAAC, SPP, and WSCC) would experience increases in capacity prices in 2008, compared to four regions ( ECAR, MAAC, MAIN, and NPCC) in 2013. The increase in WSCC would be 26.2 percent; the increases in the other two regions would be less than 2.0 percent. < Five regions ( ECAR, FRCC, MAAC, MAIN, and SPP) would experience reductions in generation in 2008. However, these reductions are all less than 0.3 percent and within 0.5 percent of the changes observed in 2013. < Revenues in 2008 would decrease in four regions ( ERCOT, FRCC, MAAC, and NPCC) but these reductions are 0.5 percent or less in all cases. In 2013, none of the 10 NERC regions would experience revenue reductions. < Total costs in 2008 are higher in MAPP compared to 2013. In all other regions, 2008 cost increases are equal to those observed in 2013 or less. < Six regions ( ERCOT, FRCC, MACC, MAPP, NPCC, and SERC) would experience reductions in pre tax income in 2008. The largest reduction, 5.0 percent, would be in FRCC, compared to a 5.4 percent reduction in 2013. The reductions in all other regions in 2008 would be less than 3.0 percent. < Increases in variable production costs would be lower or the same in 2008 compared to 2013 in all 10 NERC regions.

B8 5 UNCERTAINTIES AND LIMITATIONS The uncertainties described in section B3 5 of Chapter B3: Electricity Market Model Analysis also apply to the analyses presented in this chapter. § 316( b) Phase II EBA, Part B: Costs and Economic Impacts B8: Alternative Options  Electricity Market Model Analysis NODA Version   March 12, 2003 B8 21 REFERENCES U. S. Department of Energy ( U. S. DOE). 1999a. Form EIA 860A ( 1999). Annual Electric Generator Report   Utility.

U. S. Department of Energy ( U. S. DOE). 1999b. Form EIA 860B ( 1999). Annual Electric Generator Report   Nonutility.

U. S. Environmental Protection Agency ( U. S. EPA). 2002. Documentation of EPA Modeling Applications ( V. 2.1) Using the Integrated Planning Model. EPA 430/ R 02 004. March 2002.


[Federal Register Volume 78, Number 237 (Tuesday, December 10, 2013)]
[Notices]
[Pages 74151-74154]
[FR Doc No: 2013-29393]

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DEPARTMENT OF HEALTH AND HUMAN SERVICES

Food and Drug Administration

[Docket No. FDA-2013-D-1478]

Agency Information Collection Activities; Proposed Collection;
Comment Request; Providing Waiver-Related Materials in Accordance With
Draft Guidance for Industry on Providing Postmarket Periodic Safety
Reports in the International Conference on Harmonisation E2C(R2) Format

AGENCY: Food and Drug Administration, HHS.

ACTION: Notice.

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SUMMARY: The Food and Drug Administration (FDA) is announcing an
opportunity for public comment on the proposed collection of certain
information by the Agency. Under the Paperwork Reduction Act of 1995
(the PRA), Federal Agencies are required to publish notice in the
Federal Register concerning each proposed collection of information and
to allow 60 days for public comment in response to the notice. This
notice solicits comments on the information collection associated with
the submission of periodic safety reports as described in the guidance
entitled ``Periodic Benefit-Risk Evaluation Report (PBRER) (E2C(R2)).''
The guidance was prepared under the auspices of the International
Conference on Harmonisation (ICH) of Technical Requirements for
Registration of Pharmaceuticals for Human Use, and describes the
format, content, and timing of a PBRER for an approved drug or
biologic. This notice also solicits comments on the information
collection associated with the submission of waiver-related materials
as described in the draft guidance entitled ``Providing Postmarket
Periodic Safety Reports in the ICH E2C(R2) Format.'' The draft guidance
is intended to inform applicants of the conditions under which FDA will
exercise its waiver authority to permit applicants to submit an ICH
E2C(R2) PBRER in place of the ICH E2C(R1) Periodic Safety Update Report
(PSUR), U.S. periodic adverse drug experience report (PADER), or U.S.
periodic adverse experience report (PAER), to satisfy the periodic
safety reporting requirements in FDA regulations.

DATES: Submit either electronic or written comments on the collection
of information by February 10, 2014.

ADDRESSES: Submit electronic comments on the collection of information
to http://www.regulations.gov. Submit written comments on the
collection of information to the Division of Dockets Management (HFA-
305), Food and Drug Administration, 5630 Fishers Lane., Rm. 1061,
Rockville, MD 20852. All comments should be identified with the docket
number found in brackets in the heading of this document.

FOR FURTHER INFORMATION CONTACT: FDA PRA Staff, Office of Operations,
Food and Drug Administration,1350 Piccard Dr.,PI50-400B, Rockville, MD
20850<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Under the PRA (44 U.S.C. 3501-3520), Federal
Agencies must obtain approval from the Office of Management and Budget
(OMB) for each collection of information they conduct or sponsor.
``Collection of information'' is defined in 44 U.S.C. 3502(3) and 5 CFR
1320.3(c) and includes Agency requests or requirements that members of
the public submit reports, keep records, or provide information to a
third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A))
requires Federal Agencies to provide a 60-day notice in the Federal
Register concerning each proposed collection of information before
submitting the collection to OMB for approval. To comply with this
requirement, FDA is publishing notice of the proposed collection of
information set forth in this document.
    With respect to the following collection of information, FDA
invites comments on these topics: (1) Whether the proposed collection
of information is necessary for the proper performance of FDA's
functions, including whether the information will have practical
utility; (2) the accuracy of FDA's estimate of the burden of the
proposed collection of information, including the validity of the
methodology and assumptions used; (3) ways to enhance the quality,
utility, and clarity of the information to be collected; and (4) ways
to minimize the burden of the collection of information on respondents,
including through the use of automated collection techniques, when
appropriate, and other forms of information technology.

Reporting in Accordance With International Conference on
Harmonisation--Periodic Benefit-Risk Evaluation Report (E2C(R2))
Guidance

I. Background

    ICH was organized to provide an opportunity for tripartite
harmonization initiatives to be developed with input from both
regulatory and industry representatives. ICH is concerned with
harmonization of technical requirements for the registration of
pharmaceutical products among three regions: The European Union, Japan,
and the United States. In January 2012, the ICH Steering Committee
agreed that the ``E2C(R2) Periodic Benefit-Risk Evaluation Report''
draft guidance (the draft PBRER guidance) should be made available for
public comment. The PBRER is intended to provide a common standard for
periodic reporting on approved drugs or biologics among the ICH
regions. The harmonized PBRER is intended to promote a consistent
approach to periodic postmarket safety reporting among the ICH regions
and to enhance efficiency by reducing the number of reports generated
for submission to the regulatory authorities.
    The draft PBRER guidance revises an earlier version of this
guidance issued in 1997 with an addendum issued in 2004. In the Federal
Register of April 11, 2012 (77 FR 21782), FDA announced the
availability of the draft PBRER guidance for public comment. FDA
presented the comments received as part of the considerations by the
E2C(R2) Expert Working Group for revisions of the guidance. A final
version of the guidance was subsequently endorsed by the ICH on
November 15, 2012, and published as the ICH harmonized tripartite
guideline ``Periodic Benefit-Risk Evaluation Report (PBRER) E2C(R2)''
(the PBRER guidance), available at http://www.ich.org/products/guidelines/efficacy/article/efficacy-guidelines.html. FDA anticipates
issuing final guidance on this topic that is consistent with the final
ICH document, published November 2012, and thus is seeking PRA approval
for information collections consistent with that document.
    The April 11, 2012, Federal Register notice stated that the draft
PBRER guidance includes information collection provisions that are
subject to review by OMB under the PRA, and that before publication of
the final guidance document, FDA intends to solicit public comment and
obtain OMB approval for any information collections recommended in the
guidance that are

new or that would represent material modifications to previously
approved collections of information found in FDA regulations. This
Federal Register notice begins the process of requesting public comment
and obtaining OMB approval for collections of information associated
with reporting in accordance with the PBRER guidance.

II. Voluntary Preparation of Periodic Safety Reports in Conformance
With the ICH E2C(R2) PBRER Guidance, in Lieu of PADERs/PAERs Required
Under 21 CFR 314.80(c)(2) and 600.80(c)(2)

    FDA currently has OMB approval for the required submission of
PADERs for drugs subject to a new drug application (NDA) or an
abbreviated new drug application (ANDA) (Sec.  314.80(c)(2) (21 CFR
314.80(c)(2)); OMB control number 0910-0230), and for the required
submission of PAERs for drugs subject to a biologics license
application (BLA) (Sec.  600.80(c)(2) (21 CFR 600.80(c)(2)); OMB
control number 0910-0308). Such reports include, for the reporting
interval, reports of serious, expected adverse experiences and all non-
serious adverse experiences and an index of these reports, a narrative
summary and analysis of adverse experiences, an analysis of the 15-day
Alert reports submitted during the reporting interval, and a history of
actions taken because of adverse experiences. Applicants must submit
each PADER/PAER to FDA quarterly for the first 3 years after the
product is approved by FDA and annually thereafter. As described in the
supporting documentation under OMB control numbers 0910-0230 and 0910-
0308, FDA currently has OMB approval for approximately 60 hours for the
preparation and submission of each PADER under Sec.  314.80(c)(2) and
28 hours for the preparation and submission of each PAER under Sec.
600.80(c)(2).
    There is considerable overlap in the information required under
Sec. Sec.  314.80(c)(2) and 600.80(c)(2) and the information requested
in a periodic safety report using the ICH E2C(R2) PBRER format. As a
result, and as discussed further in this document, FDA, in the Federal
Register of April 8, 2013 (78 FR 20926), announced the availability of
a draft guidance to indicate its willingness to accept postmarket
periodic safety reports using the ICH PBRER format in lieu of the
specific reports described in FDA regulations. (As described further in
this document, the April 2013 draft guidance also addresses waiver-
related information that should be submitted to FDA by companies who
wish to exercise this alternative reporting.)
    Companies who submit periodic reports on the same drug to multiple
regulators, including not only the United States, but, also the
European Union, Japan, and regulators in other countries who have
elected to adopt the ICH standards, may find it in their interest to
prepare a single PBRER, rather than preparing multiple types of reports
for multiple regulators. Companies who choose to submit a PBRER to FDA
would include some information beyond that required by FDA regulations,
including worldwide marketing approval status; estimated exposure and
use patterns; information from clinical trials, non-interventional
studies, non-clinical data, and literature; benefit evaluation, and
benefit-risk analysis for approved indications, and should use a
particular format described in that guidance.
    FDA is not proposing to require submission of the PBRER; applicants
subject to periodic safety reporting requirements under FDA regulations
could choose to continue to submit the reports as specified in those
regulations, and would be permitted to alternate between submission of
reports in the PBRER format and submission of reports as specified in
FDA regulations with an approved waiver. Based on FDA's experience with
submission of periodic safety reports under previous ICH periodic
reporting guidance, FDA believes that applicants would elect to submit
the PBRER to FDA only in cases where they are also submitting that
report to other regulatory authorities, some of which have underlying
legal requirements that closely parallel the elements of the PBRER. For
this reason, FDA believes that the additional burden associated with
preparation of a PBRER in lieu of existing PADERs/PAERs is not
attributable to the proposed collection of information by FDA, but
rather is a ``usual and customary'' expenditure of time, effort, and
financial resources that would be ``incurred by persons in the normal
course of their activities,'' and thus is excluded from the calculation
of burden under the PRA (5 CFR 1320.5(b)(2).) Cf. 5 CFR 1320.5(b)(3)
(permitting exclusion from Federal burden of burden incurred in
complying with an information collection that is also conducted by a
State or local government if the State or local requirement would be
imposed even in the absence of a Federal requirement).
    We therefore believe that the existing estimate of burden for
submission of periodic safety reports, approved under OMB control
numbers 0910-0230 and 0910-0308, would be unchanged by this proposed
collection, which would permit, but not require, the substitution of a
PBRER for the periodic safety report otherwise required. We request
comment on the assumption that all PBRERs submitted to FDA would be
prepared in any event to submit to other jurisdictions, or
alternatively, on the number of PBRERs that applicants will choose to
prepare solely for submission to FDA, and the estimated burden for
submitting such a report.

III. Materials Related to Waivers Permitting Submission of a PBRER To
Satisfy the Periodic Safety Reporting Requirements in Sec. Sec.
314.80(c)(2) and 600.80(c)(2)

    Because FDA regulations in Sec. Sec.  314.80(c)(2) and 600.80(c)(2)
include specific requirements for periodic safety reports, in order for
an applicant to submit an alternative report, such as the PBRER, for a
given product, FDA must grant a waiver. Existing regulations permit
applicants to request waivers of any postmarketing safety reporting
requirement, and the information collections associated with such
waiver requests generally are approved under existing control numbers.
(See Sec.  314.90(a), waivers for drugs subject to NDAs and ANDAs
(approved under OMB control number 0910-0001); and Sec.  600.90(a),
waivers for products subject to BLAs (approved under OMB control number
0910-0308).)
    In the Federal Register of April 8, 2013, FDA announced the
availability of a draft guidance entitled ``Providing Postmarket
Periodic Safety Reports in the ICH E2C(R2) Format,'' which indicates
that FDA will be prepared to grant waivers to enable submission of the
PBRER in the United States in place of a PADER required under Sec.
314.80(c)(2) or in place of a PAER required under Sec.  600.80(c)(2).
The draft guidance both explains conditions under which applicants that
have previously received waivers to submit reporting information in the
format of the previous ICH guidance would be permitted to apply those
existing waivers to the submission of PBRERs, and also advises how
applicants that have not previously obtained a waiver may submit waiver
requests that would be granted for the submission of PBRERs. This
Federal Register notice solicits comment on certain information
collections proposed in the April 8, 2013, draft guidance that are
related to waivers specifically to enable the submission of PBRERs, and
that are not already addressed under approved control numbers covering
waiver submissions and periodic safety reports generally.
    FDA has previously granted waiver requests, submitted under
Sec. Sec.  314.90(a)

and 600.90(a), that allow applicants to prepare and submit reports
using the PSUR format described in the 1997 and 2004 ICH E2C guidance.
In accordance with the recommendations of the April 8, 2013, draft
guidance, if an applicant already has a PSUR waiver in place for a
given approved application, FDA will consider the existing PSUR waiver
to allow the applicant to submit a PBRER instead of a PSUR because the
PBRER replaces the PSUR for postmarketing periodic safety reporting for
that application. The applicant would not need to submit a new waiver
request unless the applicant wishes to use a different data lock point
or change the frequency of reporting.
    If an applicant submits a PBRER in place of the PSUR and uses a
different data lock point, the applicant should submit overlapping
reports or submit a one-time PADER/PAER in order to cover the gap in
reporting intervals. The applicant should request a waiver to change
the data lock point and this waiver request should include a
description of the measures taken to ensure that there are no resulting
gaps in reporting with the change.
    If an applicant submits a PBRER in place of the PSUR and uses a
different reporting frequency for the PBRER than was used for the PSUR,
the applicant must request a waiver. This waiver request should
describe the measures taken to ensure that the periodicity requirements
under Sec. Sec.  314.80(c)(2)(i) and 600.80(c)(2)(i) are being met. If
an applicant requests to submit a PBRER less frequently than is
permitted under the applicant's PSUR waiver, the continued validity of
the waiver will be conditioned on the submission of a PADER/PAER as
needed to fulfill the reporting frequency requirement under FDA
regulations. The draft guidance also states that if an applicant is on
a quarterly reporting schedule but wishes to submit a PBRER every 6
months without submitting a quarterly PADER/PAER in the intervening
quarters, the applicant may request a waiver of the quarterly reporting
requirement.
    FDA expects approximately 189 waiver requests to include the
additional information and notifications described previously in this
document for using a different data lock point and/or for using a
different reporting frequency when submitting a PBRER. FDA expects
approximately 55 applicants to make these submissions, and we estimate
that the time for submitting the additional information and
notifications described previously would be on average approximately 1
hour for each waiver request.
    If an applicant does not have a PSUR waiver in place for an
approved application, the applicant may submit a waiver request under
Sec.  314.90(a) or Sec.  600.90(a) to submit a PBRER instead of the
PADER/PAER. The applicant should submit a request to FDA for each
approved application for which a waiver is requested, and a single
waiver request letter can include multiple applications. Waiver
requests should be submitted to each of the application(s) in the
request, and may be submitted electronically or by mail as described in
the April 8, 2013, draft guidance. Each PBRER waiver request should
include the following information:
    (1) The product name(s) and application number(s);
    (2) A brief description of the justification for the request;
    (3) The U.S. approval date for the product(s) and current reporting
interval used;
    (4) The reporting interval of the last PADER/PAER submitted for the
product(s);
    (5) The data lock point that will be used for each PBRER. If a data
lock point other than one aligned to the U.S. approval date is
proposed, the applicant should describe how he/she will ensure that
there are no gaps in reporting intervals (e.g., by submitting
overlapping reports; submitting a one-time PADER/PAER to cover the gap
period; or, if the gap is less than 2 months, extending the reporting
interval of the final PADER/PAER to close the gap).
    (6) The frequency for submitting the PBRER, as described in section
IV.C of the April 8, 2013, draft guidance.
    (7) The email address and telephone number for the individual who
can provide additional information regarding the waiver request.
    As explained earlier, existing regulations at Sec. Sec.  314.90(a)
or 600.90(a) permit applicants to request waivers of any postmarketing
safety reporting requirement, and the information collections
associated with such waiver requests generally are approved under OMB
control numbers 0910-0001and 0910-0308. FDA believes that the
information submitted under numbers 1-4 and number 7 in the list in the
previous paragraph is information that is typical of any waiver request
regarding postmarketing safety reporting and is accounted for in the
existing approved collections of information for waiver requests and
reports. Concerning numbers 5 and 6, FDA expects approximately 67
waiver requests to include the additional information for using a
different data lock point and/or for using a different reporting
frequency when submitting a PBRER. FDA expects approximately 29
applicants to make these submissions, and we estimate that the time for
submitting the additional information described in the previous
paragraph would be on average approximately 2 hours for each waiver
request.
    FDA estimates the additional burden of this collection of
information as follows:

                                     Table 1--Estimated Reporting Burden \1\
----------------------------------------------------------------------------------------------------------------
  Additional information and/or
    notifications for using a        Number of       Number of     Total annual       Average
different data lock point and/or    respondents    responses per     responses      burden per      Total hours
 a different reporting frequency                    respondent                       response
----------------------------------------------------------------------------------------------------------------
Applicants that have a PSUR                   55             3.4             187               1             187
 waiver for an approved
 application....................
Applicants that do not have a                 29             2.3              67               2             134
 PSUR waiver for an approved
 application....................
                                 -------------------------------------------------------------------------------
    Total.......................  ..............  ..............  ..............  ..............             321
----------------------------------------------------------------------------------------------------------------
\1\ There are no capital costs or operating and maintenance costs associated with this collection of
  information.

    Dated: December 3, 2013.
Leslie Kux,
Assistant Commissioner for Policy.
[FR Doc. 2013-29393 Filed 12-9-13; 8:45 am]
BILLING CODE 4160-01-P


[Federal Register Volume 80, Number 182 (Monday, September 21, 2015)]
[Notices]
[Pages 56974-56975]
[FR Doc No: 2015-23611]

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

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

Combined Notice of Filings #1

    Take notice that the Commission received the following electric
corporate filings:

    Docket Numbers: EC15-206-000.
    Applicants: South Central MCN, LLC.
    Description: Application of South Central MCN LLC for Authorization
under Section 203 to Acquire Transmission Facilities and Request for
Expedited Consideration, Shortened Comment Period and Certain Waivers.
    Filed Date: 9/14/15.
    Accession Number: 20150914-5257.
    Comments Due: 5 p.m. ET 10/5/15.

    Docket Numbers: EC15-207-000.
    Applicants: Eel River Power LLC.
    Description: Application for Authorization Under Section 203 of the
Federal Power Act and Request for Waivers, Expedited Action,
Confidential Treatment and Shortened Comment Period of Eel River Power
LLC.
    Filed Date: 9/14/15.
    Accession Number: 20150914-5297.
    Comments Due: 5 p.m. ET 10/5/15.

    Take notice that the Commission received the following electric
rate filings:

    Docket Numbers: ER10-2819-004; ER14-413-002; ER14-1390-003; ER10-
2358-005; ER14-1397-003; ER10-3131-005; ER10-2431-005; ER15-2255-001.
    Applicants: ALLETE, Inc., Lake Benton Power Partners LLC, Storm
Lake Power Partners I LLC, Storm Lake Power Partners II, LLC,
Chanarambie Power Partners, LLC, Armenia Mountain Wind, LLC, Condon
Wind Power, LLC, ALLETE Clean Energy, Inc.
    Description: Errata to July 23, 2015 Notice of Non-Material Change
in Status of ALLETE, Inc., et al.
    Filed Date: 9/14/15.
    Accession Number: 20150914-5268.
    Comments Due: 5 p.m. ET 10/5/15.

    Docket Numbers: ER15-192-001.
    Applicants: Arizona Public Service Company.
    Description: Tariff Amendment: Service Agreement Nos. 338 and 339--
APS Response Deficiency Letter to be effective 12/31/9998.
    Filed Date: 9/14/15.
    Accession Number: 20150914-5254.

    Comments Due: 5 p.m. ET 10/5/15.

    Docket Numbers: ER15-2255-000.
    Applicants: Armenia Mountain Wind, LLC.
    Description: Amendment to July 23, 2015 Armenia Mountain Wind, LLC
tariff filing.
    Filed Date: 9/14/15.
    Accession Number: 20150914-5260.
    Comments Due: 5 p.m. ET 10/5/15.

    Docket Numbers: ER15-2255-001; ER10-2819-004; ER14-413-002; ER14-
1397-003; ER14-1390-003; ER10-3131-005; ER10-2431-005; ER10-2358-005.
    Applicants: ALLETE, Inc., Lake Benton Power Partners LLC, Storm
Lake Power Partners I LLC, Storm Lake Power Partners II, LLC,
Chanarambie Power Partners, LLC, Armenia Mountain Wind, LLC, Condon
Wind Power, LLC, ALLETE Clean Energy, Inc.
    Description: Errata to July 23, 2015 Notice of Non-Material Change
in Status of ALLETE, Inc., et. al.
    Filed Date: 9/14/15.
    Accession Number: 20150914-5268.
    Comments Due: 5 p.m. ET 10/5/15.

    Docket Numbers: ER15-2651-000.
    Applicants: PJM Interconnection, L.L.C., American Transmission
Systems, Incorporated.
    Description: Sec.  205(d) Rate Filing: ATSI submits Service
Agreement No. 4245 (TIA) to be effective 12/7/2015.
    Filed Date: 9/14/15.
    Accession Number: 20150914-5219.
    Comments Due: 5 p.m. ET 10/5/15.

    Docket Numbers: ER15-2652-000.
    Applicants: Southwest Power Pool, Inc.
    Description: Sec.  205(d) Rate Filing: 2252R4 Cottonwood Wind
Project GIA to be effective 9/3/2015.
    Filed Date: 9/15/15.
    Accession Number: 20150915-5027.
    Comments Due: 5 p.m. ET 10/6/15.

    Docket Numbers: ER15-2653-000.
    Applicants: Campbell County Wind Farm, LLC.
    Description: Baseline eTariff Filing: Filing of Market-Based Rate
Tariff to be effective 11/14/2015.
    Filed Date: 9/15/15.
    Accession Number: 20150915-5044.
    Comments Due: 5 p.m. ET 10/6/15.

    Take notice that the Commission received the following PURPA
210(m)(3) filings:

    Docket Numbers: QM15-3-000.
    Applicants: Arkansas Electric Cooperative Corporation.
    Description: Amendment to April 15, 2015 Application of Arkansas
Electric Cooperative Corporation on Behalf of Itself and Its Members to
Terminate Mandatory PURPA Purchase Obligation in the Midcontinent ISO,
Inc.
    In addition, Response to July 14, 2015 Deficiency Letter of
Arkansas Electric Cooperative Corporation.
    Filed Date: 9/14/15.
    Accession Number: 20150914-5282; 20150914-5288.
    Comments Due: 5 p.m. ET 10/13/15.

    Docket Numbers: QM15-4-000.
    Applicants: Arkansas Electric Cooperative Corporation.
    Description: Amendment to April 15, 2015 Application of Arkansas
Electric Cooperative Corporation on Behalf of Itself and Its Members to
Terminate Mandatory PURPA Purchase Obligation in the Southwest Power
Pool, Inc.
    In addition, Response to July 14, 2015 Deficiency Letter of
Arkansas Electric Cooperative Corporation.
    Filed Date: 9/14/15.
    Accession Number: 20150914-5291; 20150914-5292.
    Comments Due: 5 p.m. ET 10/13/15.

    The filings are accessible in the Commission's eLibrary system by
clicking on the links or querying the docket number.
    Any person desiring to intervene or protest in any of the above
proceedings must file in accordance with Rules 211 and 214 of the
Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00
p.m. Eastern time on the specified comment date. Protests may be
considered, but intervention is necessary to become a party to the
proceeding.
    eFiling is encouraged. More detailed information relating to filing
requirements, interventions, protests, service, and qualifying
facilities filings can be found at: http://www.ferc.gov/docs-filing/efiling/filing-req.pdf. For other information, call<PHONE_NUMBER>
(toll free). For TTY, call<PHONE_NUMBER>.

    Dated: September 15, 2015.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2015-23611 Filed 9-18-15; 8:45 am]
 BILLING CODE 6717-01-P