From: Frey, Nathan J. <Nathan_J._Frey@omb.eop.gov>

Sent: Wednesday, July 29, 2015 1:59 PM

To: Vasu, Amy; Culligan, Kevin; Harvey, Reid

Subject: Summary of Interagency Comments Under EO 12866 and 13563 -- Supporting TSD's

for the Clean Power Plan

Salutation,

Attached please fins summaries of interagency comments under EO 12866 and 13563 on 4

Technical Support Documents associated with the Clean Power Plan draft final rule:

Thanks and please let me know if you have any questions.

Nathan

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## Summary	of	Interagency	Working	Com ments	on	Draft	Language	under

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

1 (page numbers refer to the clean version)

Technical Comments

Page 3. Reviewer suggests adding the following sentence to the end of the first paragraph under

Methodology: “We also assume that the coal assets that had not been fully depreciated by 2025 or 2030

are some of the most efficient and least expensive to operate because they are the youngest coal assets

with the most modern pollution controls. As a result, those assets would be some of the first coal assets

dispatched in each interconnection.”

Typographical Comments

Reviewer believes that the units for Table 1 are GWh and not TWh, as currently shown.

## Summary	of	Interagency	Working	Com ments	on	Draft	Language	under

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Chapter 2

Page 2

‐ 42: Reviewer recommends clarifying step 1 for calculating the consistency factor. Reviewer

thought that it would also be necessary to calculate the 20

‐ year average gross heat rate for each

capacity

‐ temperature bin. Reviewer recommend clarifying if this is the case and if not to include an

explanation.

Page 2

‐ 42: In step 4, reviewer recommends clarifying what is meant by “comparing” the lowest 1

‐ and

2

‐ year standard deviations and the 11

‐ year standard deviation. Is the consistency factor the difference

between the 1

‐ year standard deviation and the 11

‐ year standard deviation?

Page 2

‐ 43: Reviewer recommends clarifying in the preceding discussion why in step 4 EPA is calculating

the 11

‐ year generation

‐ weighted adjusted heat rate average, when EPA decide to replace the 11

‐ year

baseline from the proposal TSD with a 2012 baseline in this analysis.

Page 2

‐ 43: Reviewer recommends including an example for the procedures for calculating the

consistency factor similar to section 2.5.5.2 that gives an example for calculating the potential heat rate

improvement. Reviewer believes this could make the consistency factor easier to understand.

Chapter 2

– editorial comments

Page 2

‐ 27: Reviewer notes that there appear to be a number of places in the next that refer to average

gross heat rates that are missing the adjective “average.” See example below. Reviewer recommends

searching for the needed places to add “average” in this chapter.

“...the agency refined the approach and calculated 1

‐ and moving 2

‐ year average gross heat rates for

each of the 884 coal

‐ fired EGUS in the study...”

Page 2

‐ 45: Reviewer recommends clarifying in Table 2

‐ 9 that the consistency factors are percentages.

Chapter 3

Page 3

‐ 2: Reviewer recommends referring to "system operators" in place of the RTOs/ISOs because

there are some system footprints that are not part of an ISO or RTO.

" Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs)

System operators help coordinate economic dispatch over larger areas to help keep the

cost of meeting electricity demand as low as possible, subject to operational

constraints."

Page 3

‐ 4: Reviewer recommends revising this text to reflect the roles of the balancing authority and

reliability coordinator. They are not interchangeable entities, as some of the current text

suggests. Specifically, the Reliability Coordinator ensures that the generation

‐ demand balance is

maintained within its Reliability Coordinator Area, which, in turn, ensures that the Interconnection

frequency remains within acceptable limits. The Balancing Authority has the responsibility for

generation

‐ demand

‐ interchange balance in the Balancing Authority Area. The Reliability Coordinator

may direct a Balancing Authority within its Reliability Coordinator Area to take whatever action is

necessary to ensure that this balance does not adversely impact reliability. (NERC Functional Model)

## Summary	of	Interagency	Working	Com ments	on	Draft	Language	under

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Page 3

‐ 14: Reviewer recommends the following edit for clarity. “Therefore, in the first year of the state

plans (2022)

, NGCC generation is limited to a maximum of a 22 percent increase from 2012 levels in

each region.

Page 3

‐ 17 to 3

‐ 18: Reviewer recommends clarifying if the increase from 2005 to 2011 was used as an

input to IPM or how the increase in pipeline capacity was used.

“As a conservative assumption, the increase from the period 2005 to 2011 can be used

as an estimator of the potential increase in pipeline capacity between 2016 and 2030 in

the IPM projections for the BB2 BSER scenario where existing natural gas units were

required to operate at the BSER capacity factor.

Page 3

‐ 18: Reviewer recommends clarifying the following sentence to make it clear if the data indicates

if the pipeline capacity will be adequate with or without building additional pipelines. The text does not

make it clear if limited additions or no additions are needed.

“...the historical data indicate that pipeline capacity will be adequate to support the

potential increased utilization of natural gas power plants quantified for building block 2

in the BSER modeling.”

Page 3

‐ 20: Reviewer recommends clarifying if NGCC utilization would be lower than the 70 percent

capacity factor, because there was not enough fossil steam to replace at higher levels. If this is the case

reviewer recommends explaining that explicitly. See below for relevant text.

“...either to a 70 percent capacity factor on average, or to a lower utilization level if such

a level would deliver the same amount of fossil fuel

‐ fired generation projected from

existing sources in that interconnection in the base case.”

Chapter 3

– editorial comments

Page 3

‐ 8: Reviewer recommends changing the heading of the third column in Table 3

‐ 1 as follows.

“Percentage of Capacity of Total Existing NGCC Fleet”

Page 3

‐ 15: Reviewer recommends adding a reference to Table 3

‐ 5 to highlight it is included in the Goal

Computation TSD.

Page 3

‐ 16: Reviewer recommends checking the figure and table numbers and references. It appears

that in the text Figure 3

‐ 4 should be 3

‐ 3 and that Table 3

‐ 5 should be 3

‐ 6.

Chapter 4

Page 1: Reviewer recommends the following edits for accuracy and clarity, because step 4 calculates an

initial level for total RE not for each technology type.

3. “Use the data from steps 1 and 2 to produce annual generation change levels associated

with the historical average and historical maximum RE capacity changes for each

technology.”

4. “Establish an initial level of incremental RE generation from each technology that could

be expected by 2022 even in the absence of the rule, using the EPA’s IPM Base Case.”

Page 1 : Reviewer recommends inserting a footnote to define what EPA considers “utility

‐ scale solar

photovoltaic.” As the historical capacity deployment numbers are taken from SEIA/GTM, reviewer

recommends using their definition:

## Summary	of	Interagency	Working	Com ments	on	Draft	Language	under

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“In their Solar Market Insight reports, Greentech Media and SEIA define utility

‐ scale by offtake

arrangement rather than by project size: any project owned by or that sells electricity directly to a utility

(rather than consuming it on site) is considered a “utility

‐ scale” project. This definition includes even

relatively small projects (e.g., 100 kW) that sell electricity through a feed

‐ in tariff (“FIT”) or avoided cost

contract.”(See Bolinger, M.; Weaver, S.; "Utility Scale Solar 2013." Defining "Utility

‐ Scale," LBNL, Sept.

2014. Page 3. http://emp.lbl.gov/publications/utility

‐ scale

‐ solar

‐ 2013

‐ empirical

‐ analysis

‐ project

‐ cost

‐ performance

‐ and

‐ pricing

‐ trends)

Page 3: Reviewer recommends the following edits for accuracy and clarity, because step 3 is calculating

the change in annual generation not total annual generation.

“The change in generation totals

, expressed in MWhs, associated with the average and

maximum capacity changes...”

“ Table X

‐ X: Annual Generation Change Totals Associated with Average and Maximum

RE Capacity Changes”

Page 2: Reviewer recommends adding a footnote after the listing of onshore wind capacity factors: “the

simple average of the TRG capacity factors (41.8%) is very similar to the technical potential weighted

average of the TRG capacity factors (41.4%), as listed in the ATB.”

Page 3 : Reviewer recommends the following edit to clarify that the hydropower potential is added

exogenously using results from the NREL renewable energy economic potential study’s Primary Case 3,

and not directly from IPM results, as is indicated in the preamble.

“Initial incremental RE generation totals for utility

‐ scale solar PV, CSP, onshore wind, and geothermal

, and hydropower are taken from the EPA IPM Base Case. Hydropower was added exogenously based on

NREL’s Renewable Energy Economic Potential study, since incremental hydropower cannot be modeled

in IPM. ”

Page 6: Reviewer recommends updating the second table to include the average annual incremental

generation values for 2022

‐ 2023 and 2024

‐ 2030.

Page 6: Reviewer recommends indicating that there are two types of “incremental” generation shown in

the table “Annual Average Incremental Generation Values, Eastern Interconnection.” Columns two and

four are incremental to 2012 baseline and column 5 is incremental to 2021 generation from IPM.

Page 7 (Section 4.3): Reviewer recommends clarifying why EPA assumes that all the BB3 potential is not

needed to meet the goals instead of assuming it is BB2 since BB2 is applied after BB3 in the goal

computation methodology.

Page 7: Similar to page 3, recommend changing to “The scenario included a representation of utility

‐

scale solar PV, CSP, onshore wind, and geothermal

, and hydropower generation. Hydropower

generation was added exogenously.”

Page 8: Reviewer recommends the following edits for accuracy and clarity.

“...amount of building block 3 generation necessary in each interconnect for affected

EGUs to achieve the source category

‐ specific emission performance rates.

Table X

‐ X: National Building Block 3 Generation Necessary to Achieve Source

Category

‐ Specific Emission Performance Rates (MWh)”

## Summary	of	Interagency	Working	Com ments	on	Draft	Language	under

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Page 10: Reviewer recommends adding the following text “The EPA selected the NREL 2015 ATB mid

‐

case estimates based on the quality of its data and consistency with recent RE cost and performance

trends. The ATB capital cost estimates cover the same scope of power plant envelope (equipment,

installation, developer costs, etc.) as used for AEO inputs used in the proposal. The agency used the

draft 2015 ATB version, which was available at the time of the analysis.”

Page 11: Reviewer recommends explicitly indicating that the comparison of RE cost and performance is

between the proposal and the final rule, as the AEO 2013 is two years older than the NREL ATB data:

“In comparing the AEO2013 data set used in the proposal to the NREL ATB data set used in the final rule

two data sets

, the EPA found AEO2013 installation cost assumptions for onshore wind in 2014 are 30%

higher than the ATB mid

‐ case cost assumptions for the same year.”

Also recommend adding a footnote (see the following sentence) at the end of the above line:

“The AEO2015 contains updated capital costs for wind and solar PV which are also lower than the

AEO2013, reflecting the decrease in costs over the previous two years.”

Page 11

– Table X : Reviewer notes that there are no differences in capital costs for solar TRGs in the

ATB. Recommend removing “TRG 3” from the report row (also on page 12, Table X).

Page 11

– Table X: Reviewer notes that in Note 2, the referenced EIA report uses a ratio of 1.3:1 for DC

‐

to

‐ AC conversion, not 1.25:1 as indicated (also on page 12, Table X).

Page 12

– Table X: Reviewer recommends adding an additional note for the table: “While all sources are

reported as ‘2013’, there is a difference what each source defines as ‘year’. For example, the LBNL

report and the ATB represent the projects completed installation in 2013 while the AEO numbers are for

projects that were initiated in 2013. Therefore the LBNL averages reflect what costs were a few years

ago and may not be representative of current costs for projects initiated today.”

Page 13: Reviewer recommends inserting the following text: “It should also be noted that the NREL ATB

cost report was published in 2015, whereas the AEO costs were published in 2013

, and that the most

recent AEO 2015 includes significant cost reductions of wind and solar PV as compared to AEO 2013

(footnote: http://www.eia.gov/forecasts/aeo/ assumptions/pdf/table_8.2.pdf)

. Commenters noted that

the LBNL found that the AEO2013 assumptions were based on projects completed in 2012, and the

installed price data for those projects may reflect contract terms agreed to a number of years prior to

project completion.”

Page 14: Reviewer recommends including the full cost projection references for footnote 30:

“Greenpeace/EREC (2014). Energy [R]evolution: A Sustainable USA Energy Outlook.

http://www.greenpeace.org/usa/Global /usa/planet3/PDFs/Solutions/Energy

‐ Revolution

‐ 2014.pdf

(utility

‐ scale only)

International Energy Agency. (2013). World Energy Outlook 2013.

http://www.worldenergyoutlook.org/publications/weo

‐ 2013/. (New Policy & 450 Scenarios for utility

‐

scale & commercial

‐ scale)

Bloomberg New Energy Finance (2014). Q2 PV Market Outlook.

## Summary	of	Interagency	Working	Com ments	on	Draft	Language	under

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United States Energy Information Administration (EIA). (2014a). Annual Energy Outlook 2014 with

Projections to 2040. DOE/EIA

‐ 0383(2014). Washington, D.C.: U.S. Department of Energy Office of

Integrated and International Energy Analysis. http://www.eia.gov/foreca sts/aeo/pdf/0383(2014).pdf”

Page 15: Reviewer recommends editing and adding the following references to support the line. “These

figures, along with numerous studies looking at integration of VG RE resources, indicate that the current

configuration of the electric power system is already capable of integrating very high levels of renewable

variable generation for sustained periods of time”

References to include:

 Cochran, J., Denholm, P., Speer, B., and Miller, M. Grid Integration and the Carrying Capacity

of the U.S. Grid to Incorporate Variable Renewable Energy. NREL/TP

‐ 6A20

‐ 62607, 2015.

( http://www.nrel.gov/docs/fy15osti/62607.pdf )

 Hand, M.M.; Baldwin, S.; DeMeo, E.; Reilly, J.M.; Mai, T.; Arent, D.; Porro, G.; Meshek, M.;

Sandor, D. eds. 4 vols. (2012). Renewable Electricity Futures Study. NREL/TP

‐ 6A20

‐ 52409.

Golden, CO. ( http://www.nrel.gov/analysis/re_futures/ )

 Bloom, A., Townsend, A., Palchak, D., King, J., Ibanez, E., Barrows, C., Hummon, M., Draxl, C.,

(2015). Eastern Renewable Generation Integration Study. NREL/TP

‐ 6A20

‐ 64472. Golden,

CO. In press, http://www.nrel.gov/electricity/transmission/eastern_renewable.html

 Lew, D., Brinkman, G., Ibanez, E., Florita, A., Heaney, M., Hodge, B.

‐ M., Hummon, M., Stark,

G., King, J., Lefton, S.A., Kumar, N., Agan, D., Jordan, G., Venkataraman, S., (2013). The

Western Wind and Solar Integration Study Phase 2. NREL/TP

‐ 5500

‐ 55588. Golden, CO.

( http://www.nrel.gov/docs/fy13osti/55588.pdf )

 Miller, N.W., Shao, M., Pajic, S., D’Aquila, R., (2014). Western Wind and Solar Integration

Study Phase 3

– Frequency Response and Transient Stability. NREL/SR

‐ 5D00

‐ 62906. Golden,

CO. ( http://www.nrel.gov/docs/fy15osti/62906.pdf )

 PJM Renewable Integration Study. 2014. ( http://www.pjm.com/committees

‐ and

‐ groups/subcommittees/irs/pris.aspx )

Page 15

– Figure X

‐ X

– Reviewer recommends including full source for EIA capacity numbers, as it is not

clear where the numbers for 2015 are coming from.

Page 17: Reviewer recommends clarifying how load growth was met in the IPM model run described on

the top of page 17. If every incremental MWh of qualifying RE the model deployed required one MWh

of affected EGU generation to be reduced, was load growth only meet by new NGCC? Or did existing

NGCC, new nuclear, or non

‐ qualifying RE also play a role?

Page 17: Reviewer recommends adding the following paragraph after “The EPA believes the 2022

‐ 2030

average cost of $37/ton to be reasonable.”:

“These costs may be exaggerated due to the constraints built into IPM. IPM does not allow more

than 20% of generation in any of its 64 subregions in the U.S. to come from either solar or wind

energy, and does not allow more than 30% of generation to come from a combination of solar and

wind energy. This is a conservative assumption, as evidenced by the fact that several subregions

already exceed 20% wind generation, for instance. This constraint is included to ensure variable

renewable energy generation does not reach levels at which integration costs could begin to rise,

## Summary	of	Interagency	Working	Com ments	on	Draft	Language	under

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

but to the extent that it underestimates the ability of grid operators to integrate cheaply higher

levels of variable renewable energy, it will increase the costs of building the minimum levels of

renewable generation required by Building Block 3.”

Page 18: Reviewer also recommends including the references recommended for page 15 after the

following line: “Virtually all recent studies of achievable penetration level of RE in the power grid are

above 20 percent, for the simple reason that 20 percent has been shown to be feasible

– as indicated by

the current RE levels discussed above

– and studies are directed at assessing the impact of higher

levels.“

Page 18

– Table X

‐ X : Reviewer recommends indicating whether or not these numbers represent all RE

or only BSER eligible technologies.

Page 19

– Table X

‐ X : Recommend indicating if these capacity additions are all RE technologies or only

BSER technologies.

Page 19

– Table X

‐ X : Recommend including other independent third party projections of RE deployment

to show reasonableness of BB3 deployment. Assuming this is all RE and not just BSER technologies, the

BNEF New Energy Outlook also provides projections through 2030:

Scenario Through 2025 Through 2030

EPA Base Case 48 62

EPA Building Block 3 121 233

IHS Energy

‐ Low 64 87

IHS Energy

‐ Mid 126 192

IHS Energy

‐ High 222 352

BNEF

– New Energy Outlook

(BSER Only) 55 74

BNEF

– New Energy Outlook

(All RE including distributed PV) 133 258

Chapter 4

‐ Editorial Comments

Page 1: “ Establish an initial level of incremental RE generation from each technology that could be

expected by 2022 even in the absence of the rule, using the EPA’s IPM Base Case.”

Page 6: Reviewer recommends adding in missing average data in the final blank column of “Annual

Average Incremental Generation Values, Eastern Interconnection.”

Page 10: Reviewer recommends changing “80 TWh” to be “80,000 GWh” to be consistent with earlier

numbers presented in GWh.

Page 10: Edit title of figure: “ Building Block 3 Generation Levels Necessary to Achieve Goal Rates and

Alternative NREL Values, in 2030”

## Summary	of	Interagency	Working	Com ments	on	Draft	Language	under

EO12866/13563	Interagency	Review.		Subject	to	Further	Policy	Re view.

Page 14: Reviewer notes that footnotes 28, 29, and 30 are the same and could be combined into one

footnote.

Page 15: “The current grid can reliably integrate much higher levels of variable RE generation over short

time intervals of an hour or a day.”

Page 18

– Footnote 38: “ HIS IHS Energy, North American Renewables Outlook: The rise of solar and the

uncertainty of policy, 2 June 2015; UBS Securities LLC, US Solar & Alternative Energy, Sizing Up the US

Solar Market.”

Page 19 : “...the total incremental to 2012 renewable capacity additions were 95 GW in 2030”

Page 19

– footnote 41 : Replace “Stateholder” with “Stakeholder”

Chapter 5/7

Page 5: Reviewer recommends the following edit. “However, the EPA does not believe that it can serve

as the best system of emission reduction as a broadly applicable GHG mitigation program at this time .”

Page 6: Reviewer recommends the following edit, because there is no evidence CCS would affect the

reliability of the supply of electricity. The “at this time” language is used elsewhere in the document and

should be used here and on page 5 as well.

“An emission standard for existing units based on CCS (or even partial CCS) would most certainly have an

even more significant effect on nationwide electricity prices and could affect the reliability of the supply

of electricity

. Therefore, as stated earlier, the EPA did not find that the cost to implement partial CCS at

existing source emission standards to be reasonable, which further supports the determination that CCS

is not an appropriate component of the best system of emission reduction for CO 2 emissions from

existing fossil fuel

‐ fired EGUs at this time

.

## Summary	of	Interagency	Working	Com ments	on	Draft	Language	under

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New Source Complements Technical Support Document

(Page numbers refer to the page numbers in Word, since document did not have page numbers.)

(Title page is Page 1.)

General Comment

Page 2 & 8 : Reviewer recommends not using the NSPS emission rate of 1,030 lbs/MWh to convert state

‐

level incremental generation to emissions, because the average emission intensity of the current NGCC

is approximately 900 lbs/MWh and new NGCC units have significantly lower emission rates. Therefore,

using the NSPS emission rate produces a new source complement that does not effectively address

leakage.

Technical Comment

Page 2 : Reviewer recommends defining “net energy for load.” From EIA’s website

‐ Net energy for

load: Net generation of main generating units that are system

‐ owned or system

‐ operated, plus energy

receipts minus energy deliveries.

Page 4: Reviewer recommends that EPA clarify the sentence below. If the capacity factor is not

representing the total annual output, how is EPA accounting for the rest of the output. “This capacity

factor does not represent expected total annual output, but instead represents the portion of total

annual output that will deduct from the incremental generation needed to support demand growth.”

Page 5: Reviewer notes that numbers in Figure 6 that represent the BB3 potential that is not needed for

the mass state goals seem to differ slightly between the Goal Computation and GHG Mitigation TSD

versions that we have.

Editorial Comments

Reviewer recommends relabeling all “Figures” to “Tables”

Reviewer recommends including the units of GWh in the title of “Figure 3”

Footnote 3: “scaler” should be replaced with “scalar”

Reviewer recommends replacing “*” and “x” with multiplication symbol “×” in equations.

## Summary	of	Interagency	Working	Com ments	on	Draft	Language	under

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Page 3. Reviewer notes that it is worth double checking whether there should be a plus sign instead of

minus sign in front of 12,626. If not, would suggest re

‐ wording (Plus New Capacity Change).

Page 5. Reviewer notes it is unclear why renewable additions seem to be the same under the CPP as

under the base case.

Page 5. Reviewer recommends the following revision: the largest decrease are in new NGCC (7,808

MW) and CT (3,131 MW)

Page 5. (4 lines up from the bottom of the page) Reviewer recommends changing “might that” to “that”

Page 5. "Although there can be local grid reliability issues in replacing some of the retiring units shown

in Table 1 above and in Table A4, these can be managed within the normal reliability planning and

management time frames provided by the flexible resource options and time frames in the rule."

Reviewer suggests revising this sentence to say that local reliability issues "... are expected to be

manageable within the normal reliability planning processes and ...", as these reliability management

cannot be guaranteed.

Page 7. (2 nd full paragraph, 4 lines from the bottom of the paragraph) Reviewer recommends revisiting

wording: “firm impacts on reliability”

Page 8. (in the only full paragraph on the page a little more than halfway through the paragraph)

Reviewer recommends changing “net decrease new” to “net decrease”.

Page 9. Reviewer recommends clarifying in the text that the reason there are more retirements in the

mass scenario than the rat e scenario is because the mass scenario was only modeled without trading.

Appendix B. Reviewer recommends indicating whether results from later years (e.g., 2025) are

cumulative (i.e., include those from 2020) or additive (i.e., numbers from 2020 are added to 2025) to get

actual portfolio totals at the end of the 2020 and 2025 periods.