analysis of current and pending epa regulations...

Analysis of Current and Pending EPA Regulations on the U.S. Electric Sector

May 31, 2012

PRISM 2.0: Regional Energy and Economic Model Development and Initial ApplicationModel Development and Initial ApplicationDevelop a new energy-economy model of the U.S. with a special focus on the electric power sector:

U S Regional Economy Greenhouse Gas and Energy (US REGEN) modelU.S. Regional Economy, Greenhouse Gas, and Energy (US-REGEN) model (completed)

Develop appropriate sectoral data and detail in electric power production and in energy demand, taking into account regional differences in generating costs and resources, especially for renewables, carbon capture and storage, and land use

Perform detailed analysis:1st Phase – Current and Pending Environmental Controls (completed)2nd Phase – Clean Energy Standard proposals (Summer 2012)3 d Ph li i l i th I t f CO C t i t th3rd Phase – preliminary analysis on the Impact of CO2 Constraints on the

Electric Power Sector (Fall 2012)

Communicate results at on-site member briefings and via public reports and

2© 2012 Electric Power Research Institute, Inc. All rights reserved.

Communicate results at on site member briefings and via public reports and presentations

US-REGEN Model Description

Pacific General• Aggregate Economic

RepresentationPacific

Mountain‐N

NW‐Central

NENE‐Central‐C NY

General Equilibrium

Economy Model

Representation

• Energy Markets for Oil, Natural Gas, Coal, & Bioenergy

• Foreign Exchange

• Landuse (Ag and Forest)

California

NW Central

NE‐Central‐R

M‐Atlantic• Landuse (Ag and Forest)

Energy Demand (Electric & Non-

El t i )

• Energy Efficiency across Commercial, Industrial, &

Residential Sectors

• Transportation: Detailed model of

SW‐Central

S‐Atlantic

SE‐CentralMountain‐S

Electric) vehicle technologies and intermodal choices

Electric Sector• CO2 Mitigation Technologies

TexasFlorida

Electric Sector Module

• Environmental Controls: Air, Water, Land

• Transmission


Key Messages

• The confluence of multiple environmental control requirements requiring retrofits on existing coal fired powerrequirements requiring retrofits on existing coal-fired power plants has significant implications for asset management and generation planning decisions, and substantial effects on electricity generation costs

• Decisions about whether to retrofit or retire existing coal-fired power plants are complex with multiple uncertaintiesfired power plants are complex, with multiple uncertainties, interactions, and implications for electricity generators and the broader economy

• With phased compliance more time can facilitate testing and application of new and existing lower-cost technologies with significant savings, and with little change in overall


with significant savings, and with little change in overall emission reductions

Baseline Scenario

• Economic growth and energy supply and demand based on EIA’s Annual Energy Outlook 2011EIA s Annual Energy Outlook 2011

• Economic and electric power unit data based on 2009 and 2010 datasets, respectively, 2010 is the model’s base yearEl t i t li i d ti• Electric sector policies, and assumptions:– Include state RPS Programs– State (CA RGGI) or federal (CAA) GHG regulations notState (CA, RGGI) or federal (CAA) GHG regulations not

included– Include Cross-State Air Pollution Rule (CSAPR) by 2015

Aims to Reduce SO emissions by 73 percent and NOxAims to Reduce SO2 emissions by 73 percent and NOx emissions by 54 percent from 2005 levels. Final rule.

– New coal additions limited to units currently under t ti


construction

Reference (Environmental Controls) Scenario

• Starting from the Baseline Scenario, then addingEl t i S t P li i• Electric Sector Policies– Mercury and Air Toxics Standard (MATs) Rule by 2015,

more stringent SO2, and SO3 control by 2018)more stringent SO2, and SO3 control by 2018) (Dry/wet scrubbing with increased particulate control)

– Ozone and haze regulations by 2018 (Stringent NOx SC f )control with SCRs for all coal)

– SO2 NAAQS, haze regulations by 2018Clean Water Act (CWA) 316(b) Controls by 2018– Clean Water Act (CWA) 316(b) Controls by 2018 (closed-cycle cooling on facilities with intake flow > 125)

– Coal Combustion Residuals (CCRs) Controls by 2020


( ) y(RCRA Subtitle D “non-hazardous”)

Hundreds of GW of Existing Coal Units Facing Multiple Compliance Obligations by 2015Multiple Compliance Obligations by 2015

350

Reference Case Capacity Requiring Retrofits

250

300~2020

200

250

al Cap

acity 2015/

~2018 ~20182015

~2018

100

150

GW Coa

‐

50


SO2 NOx Hg 316(b) CCRs

Controlling Emissions from Power PlantsExample Costs – 400 MW, Bituminous Coalp ,

Chemical or b t SCR

Chemical or S b t SCR

$190M

sorbentInjection

Chemical Injection

SCR Catalysts

SorbentInjection

Chemical Injection

SCR Catalysts

$110MBaghouse

Structures

Combustion Control Fixed

Combustion Control

$10M

$110M

Coal Cleaning Chemical

Coal Cleaning Chemical Additives

Sorbentinjection

TOXICON

TOXICON IIAdditives

Additives

SorbentInjection

TOXECON

TOXECON IIWet Scrubbers

$310M$80M

$50M


$80M

Integrated Analysis of Retrofit Decision in Light of Full Set of Air (non-GHG), Water, Ash Policiesof Full Set of Air (non GHG), Water, Ash Policies

• Full Control policy defined as stringent control of SO2, NOx, Hg, entrainment (316b), and coal combustion residuals (CCRs) but e t a e t (3 6b), a d coa co bust o es dua s (CC s) butnot recent proposed CO2 performance standards.

• Assume asset owner make single retrofit-retire decision in 2015 based on full mix of requirements.based on full mix of requirements.

• Retrofit cost scenarios reflect broad cost and policy uncertainty:– Ref uses reference costs

Fl h l t l t i t ti t i t– Flex has lower costs, less stringent aquatic entrainment controls, less retrofit cost escalation, and additional time for compliance for SO2 and NOx to allow for newer control technology optionstechnology options

– High costs with less policy flexibility to choose low-cost technologies and higher retrofit cost escalation to meet stringent deadlines


stringent deadlines

Scenarios Represent Uncertainty Ranges in Costs for Technology, Policy, and Escalation

3 500

4,000High

R f

Costs for Technology, Policy, and Escalation

3,000

3,500

W)

Ref

Flex High (Current) scenario represents little technology flexibility, and real cost escalation driven by demand for retrofits

2,000

2,500

rol Cost ($/kW

Flex (Alternate) scenario represents availability of lower cost technologies and policy flexibility to apply them,

1,000

1,500

Contr p y y pp y ,

lower escalation in retrofit costs associated with extra time for MATS and Ozone compliance

0

500

0 50 100 150 200 250 300 350


0 50 100 150 200 250 300 350Cumulative Generation Capacity (GW)

Cost to Retrofit Entire Fleet Uncertain but Several $100 BillionsSeveral $100 Billions

• Chart show investment cost to retrofit entire existing fleet (sum Expenditures to Retrofit All Existing Coalretrofit entire existing fleet (sum of unit costs input to model)

• Existing coal316 GW

250

300

– 316 GW– 40% of electric supply– 1,100 generating units

150

200 Ash

316bBillion

s– Diverse size/age mix

• Age, size, and market impact retrofit/retire decisions

100

150Hg

NOx

SO2

$

• Many units poor candidates for environmental retrofits

• ~ 40 GW of coal retirements 0

50


40 GW of coal retirements announced to date

0Ref Flex High

Comparisons Show How Retrofits Will Cut EmissionsEmissions

15

Comparison of Emissions by Level of Retrofits ‐ High Scenario

11

12

13

14

c tons)

7

8

9

10

(million metric

SO2

4

5

6

7

al Emission

s (

NOx

0

1

2

3Tot


1990 History 2010 as Operated 2010 w PendingRetrofits

2010 w Full Control

U.S. Electric Generation in Baseline

6000

EE + Price Response

4000

5000Other Renewable

Wind

Hydro+

3000

TWh

Nuclear (New)

Nuclear (Existing)

2000

Gas

New Coal

Environmental Retrofit

0

1000Existing Coal

AEO 2011


2010 2015 2020 2025 2030 2035

U.S. Electric Generation in Controls (Ref)

6000

EE + Price Response

4000

5000Other Renewable

Wind

Hydro+

3000

TWh

Nuclear (New)

Nuclear (Existing)

2000

Gas

New Coal


0

1000Existing Coal

AEO 2011


2010 2015 2020 2025 2030 2035

Regional Generation in Controls (Ref)

Total Energy

for Load

Imports

Solar

Wind

Hydro+

N l (N )

Gas

New Coal

E i t l R t fit 1200

1600 EAST

for LoadGeothermal

Biomass

Nuclear (New)

Nuclear (Existing)


Existing Coal800

1200

TWh

16001600 MIDWESTWEST

0

400

2010 2015 2020 2025 2030 2035800

1200TW

h

800

1200

TWh

0

400

2010 2015 2020 2025 2030 20350

400

2010 2015 2020 2025 2030 2035

1200

1600

h

SOUTH

2010 2015 2020 2025 2030 20352010 2015 2020 2025 2030 2035

400

800

TWh


02010 2015 2020 2025 2030 2035

Coal Units May Cease to Operate Coal Due to Retirements as Well as Conversions to GasRetirements as Well as Conversions to Gas

• Economics to retire or convert to gas or biomass can be very closevery close

• Conversions can buy cheap capacity• Capacity value depends on regional capacity needs andCapacity value depends on regional capacity needs and

operating limitations of converted capacity• Cost of conversion to gas can vary widely with distance to

gas lines• Many economically viable gas conversions may prove

infeasible (e g siting access to gas)infeasible (e.g., siting, access to gas)• As consequence we group units that cease to operate as

coal into a Retire/Refuel category


Existing Coal Disposition in Controls (Ref)

300

350

250

300

city

200

ng Coa

l Cap

ac

Age Retire

Retire/Refuel

Env Retrofit

Takeaway 1: Policy has dramatic impact on coal. Retirements and conversions in range of ~50 GW

100

150

GW Existin Env Retrofit

Base

conversions in range of 50 GW likely, larger with conservative investment thresholds

Takeaway 2: Coal remains a critical f ti d i

50

source of generation and survivors have a lot of value worth preserving


02010 2015 2020 2025 2030 2035

Regional Coal Disposition in Controls (Ref)

Age Retire

Retire/Refuel


Base100

125 EAST

50

75

GW

125 MIDWEST125 WEST

0

25

2010 2015 2020 2025 2030 2035

SOUTH50

75

100GW

50

75

100

GW

75

100

125

W

SOUTH

0

25

50

2010 2015 2020 2025 2030 2035

0

25

2010 2015 2020 2025 2030 2035

25

50

GW2010 2015 2020 2025 2030 2035


02010 2015 2020 2025 2030 2035

New Capacity Additions Through 2025

300

200

250

150

200

GW

Solar

Wind

Hydro / Geo

Nuclear

100

Nuclear

NGCC

New Coal

50


0Baseline Ref Flex High

Broad Distribution of Pay-offs for Retrofits of Existing Coal (Ref)

350

Existing Coal (Ref)Continued operationin question (on bubble)

188 0

57

250

300

city

Retire/Refuel

> 15 year payback2

200

ing Co

al Cap

a > 15‐year payback

10 ‐ 15 year payback period

227100

150

GW Exist 5 ‐ 10 year payback period with

IRR in first 10 years < 15%

5 ‐ 10 year payback period withIRR in first 10 years > 15%

Retrofits

Strong economics

50

100 y %

<= 5 year payback period

Already in compliance

gsupporting retrofits


50

Potentially Large Fraction of Existing Coal Fleet May Retire or Refuel with Bio Energy or GasMay Retire or Refuel with Bio Energy or Gas

300

350

250

300

city

200

ng Coa

l Cap

ac

Age Retire

Retire/Refuel

>10yr payback

100

150

GW Existin

<10yr payback

Base

50

Disposition of existing coal capacity in 2020 by retrofit cost scenario


0Baseline Ref Flex High

Long-term History of Natural Gas Prices Shows High Level of VariabilityHigh Level of Variability

16Historical Monthly U.S. Natural Gas Prices (2011$)

12

14

Wellhead Price

Henry Hub Spot Price

8

10

MMBtu)

6

8

Price (2011$/

2

4

Gas P


0Jan‐1976 Jan‐1980 Jan‐1984 Jan‐1988 Jan‐1992 Jan‐1996 Jan‐2000 Jan‐2004 Jan‐2008 Jan‐2012

Sensitivity Analysis on Natural Gas Prices

$9

$10

$7

$8

+$2

$5

$6

er m

mbtu

+$2

+$1

Ref

‐$1

$3

$4$ pe ‐$2

AEO 2012

NYMEX (2009$)

$1

$2Note: Price paths are intended to show sensitivity of electric system over broad range. They are not intended to quantify gas price uncertainty.


$02010 2015 2020 2025 2030 2035

Generation with low gas prices

6000 ‐$2 Gas Price Path EE + Price Response

h bl

4000

5000 Other Renewable

Wind

Hydro+

3000

TWh

Hydro+

Nuclear (New)

Nuclear (Existing)

2000

Nuclear (Existing)

Gas


0

1000

2010 2015 2020 2025 2030 2035

Existing Coal

AEO 2011


2010 2015 2020 2025 2030 2035

Gas Price Scenarios Show Critical Role of Gas Price Expectations for How Much Coal SurvivesPrice Expectations for How Much Coal Survives

300

350

250

300

ity

200

ng Coa

l Cap

aci

Age Retire

Retire/Refuel

E R fi

100

150

GW Existin Env Retrofit

Base

50

Disposition of existing coal capacity in 2020 by gas price scenario


0‐$2 ‐$1 Ref +$1 +$2

Natural Gas Price is the Dominant Uncertainty

Uncertainty level is very high• Price range over last decade shows over 5 to 1 ratio• Price range over last decade shows over 5 to 1 ratio• Are NYMEX futures and AEO 2012 projections going to

continue to decline?Dramatic consequences• Average power prices show ~$6/MWh swing for each $1

change in gas priceschange in gas prices• Low price paths have particularly large impact on retrofit vs.

retire/refuel decisionsImplications for decisions• Flexible compliance strategies with lower fixed costs

(despite higher operating costs) reduce risk or regrets


(despite higher operating costs) reduce risk or regrets

100’s of Billions of Dollars in Possible Electric Sector Expenditures

180

200

High

Ref

Sector Expenditures

T k 3 l t f i t

140

160

2009$)

Ref

Flex

Takeaway 3: a lot of money is at stake, but much less in technology flexibility scenario

(note: these values are undiscounted

100

120

pend

iture (B 2 (

total expenditures by time period)

60

80

Chan

ge in

Ex

Expenditures include: retrofits, new capacity, fuel, and O&M costs

20

40


02011‐15 2016‐2020 2021‐2025 2026‐2030 2031‐2035

Retrofit Investment is Only Part of Policy Expenditure Costs (Ref)

150

$)Expenditure Costs (Ref)

Takeaway 4: Retrofit investment is just the down payment incremental

123 121

100

125

ture (B

2009$ just the down payment, incremental

fuel plus replacement generation expenditures exceed total retrofit investment

75

35 Expen

dit

Note: values are total undiscounted expenditures over 2010-2035 time period.

4950

e in 2010‐20

22

0

25

Chan

ge


0Retrofit Fuel+VOM Investment FOM

GDP Impacts Show Magnitude of Costs and Opportunity in Flexibility

300

Opportunity in Flexibility

Takeaway 3 (reinforced): making flexible and technology

200

250

B 2009$)

making flexible and technology scenario happen worth $100 billion

150

200

0‐2035

(PV B

100

DP Loss 2010

0

50

GD


0Ref Flex High

Note That Total GDP Impacts ~25% Greater Than Increased Cost to Electric SectorThan Increased Cost to Electric Sector

300

GDP Loss Electric Sector Cost

200

250

2009$)

150

200

2035

(PV B 2

100

Costs 2010

‐2

0

50


0Ref Flex High

U.S. Average Power Producers’ Gas Price

$7

$8

$6

$7

$4

$5

er m

mbtu Baseline

Ref

Fl

$2

$3

$ pe Flex

High

$1

$2


$02010 2015 2020 2025 2030 2035

U.S. Average Retail Electricity Price

$90

$100

$70

$80

($/M

Wh)

$50

$60

ectricity Price

Baseline

Ref

Fl

$30

$40

rage Retail Ele Flex

High

$10

$20Ave


$02010 2015 2020 2025 2030 2035

U.S. Average Retail Electricity Price - Percent Change from BaselineChange from Baseline

8%

9%

ine

6%

7%

nge from

Basel

4%

5%

6%

‐Percent Cha

n

Ref

Flex

3%

4%

lectricity Price

High

1%

2%

Avg Retail E


0%2010 2015 2020 2025 2030 2035

U.S. Electric Sector CO2 Emissions2.5

2

1.5

on to

nnes History

Baseline

Flex

1Billi Ref

High

0.5


01990 1995 2000 2005 2010 2015 2020 2025 2030 2035

U.S. Electric Sector SO2 Emissions

14

16Takeaway 5: Emissions have declined steadily since 1990. Incremental reductions compared to historic levels relatively small.

R d ti b l B li 2010 2035

12

14 Reductions below Baseline over 2010-2035

Flex (61%)Ref (63%)High (64%)

8

10

ion tonn

es History

Baseline

Flex

g ( )

4

6

Milli

Ref

High

2

4


01990 1995 2000 2005 2010 2015 2020 2025 2030 2035

U.S. Electric Sector NOx Emissions

7

8Takeaway 5: Emissions have declined steadily since 1990. Incremental reductions compared to historic levels relatively small.

R d ti b l B li 2010 2035

6

7 Reductions below Baseline over 2010-2035

Flex (38%)Ref (40%)High (40%)

4

5

ion tonn

es History

Baseline

Flex

g ( )

2

3

Milli

Ref

High

1

2


01990 1995 2000 2005 2010 2015 2020 2025 2030 2035

Concluding Observations

• Economic cost of full control policy is $175B to $275B (PV 2010-2035)2035)

• Cost range driven by ability to deploy low-cost technologies, which may require policy flexibility and extra time to assess

• Cost impacts greatest in high-coal regions

• Compliance decisions dependent on gas price expectations

• 50 to 100+ GW of coal may retire or convert fuels

• Most of existing coal continues to play key role

• SO2/NOx emissions drop to less than 30% of 2010 levels

• If emission reductions phased in over an extra two years the


relative impact on cumulative emissions is modest

Contact InformationBryan HanneganVice President, Environment and RenewablesElectric Power Research Institute(650) 855 2459(650) [email protected]

Energy and Environmental Analysis Groupgy y p

Tom Wilson Victor NiemeyerSenior Program Manager Technical Executive (650) 855-7928 650-855-2262( )[email protected] [email protected]

Geoffrey Blanford Francisco de la ChesnayeProgram Manager Program Managerg g g g(650) 855-2126 (202) [email protected] [email protected]


Together…Shaping the Future of Electricity

Supplemental Material:Details & Assumptions for the Environmental Controls Cases


Overarching Analysis Framework

• Single near-term decision (by 2015) to retrofit or retire coal units• Decision informed by full set of ongoing policy and regulatory processes• Analysis focuses on pollutant control technologies as inputs to the US-REGEN

model and not necessarily on the various regulations (e.g., MATS, 316B, RCRA). • Need to recognize complexities and that the reality faced by sector is not clear cut:

– Uncertainties resolved over time, not all at once,– Control decisions staggered over time as well– Control technologies interact across emission targets, that is, control of SO2 and

NOx also affects Hg control costs• Important objective is to develop a range of costs and technologies between Flex• Important objective is to develop a range of costs and technologies between Flex

and High cases to reflect uncertainty:– Flex has lower costs, less stringent aquatic entrainment controls, less retrofit

cost escalation, and additional time for compliance for SO2 and NOx to allow for newer control technology options; assumes technologies still need to gy p ; gdemonstrate their optimal performance.

– Ref uses reference costs.– High costs with less policy flexibility to choose low-cost technologies and higher

retrofit cost escalation to meet stringent deadlines.


g

US-REGEN Input Assumptions for SO2 Control TechnologiesTechnologiesScenario Ref Flex HighSO2 Control Required 2015 2017 2015SO2 Threshold 0 15 0 15 0 15 lb/MMBtuSO2 Threshold 0.15 0.15 0.15 lb/MMBtuFGD needed for all units? no no yesCost to upgrade SO2 150 100 200 $/kWEquation source IECCost IECCost IECCostTechnology required

E. Bit FGD+WWT LSD FGD+WWTSub Bit LSD DSI + FGD+WWT

Li SD FGD DSI FGD WWT

• Expenditure ranges also include ranges for retrofit difficulty and market/timing

Lig SD‐FGD DSI + FGD+WWTRetrofit Expend for All Coal 75 24 102 $ billions

market/timing• Lime Spray Drying (LSD) available for bit coal in Flex scenario• FGD + WWT = wet flue gas desulfurization• Dry sorbent injection (DSI)


y so be t ject o ( S )• Spray dryer – FGD = (SD-FGD)

US-REGEN Input Assumptions for NOx Control TechnologiesTechnologiesScenario Ref Flex HighNOx Control Required 2018 2020 2018NOx Threshold 0 10 0 10 0 10 lb/MMBtuNOx Threshold 0.10 0.10 0.10 lb/MMBtuSCR Required yes yes yesCost to upgrade NOx 100 50 150 $/kWEquation source IECCost IECCost IECCostqTechnology required

E. Bit SCR SCR SCR

Sub Bit SCR SCR SCR

• SCRs required in all scenarios to meet 0.10 lb/MMBtu (or better)

Lig SCR SCR SCR

Retrofit Expend for All Coal 88 70 102 $ billions

• Expenditure range reflects retrofit difficulty and market/timing factors


US-REGEN Input Assumptions for Hg Control TechnologiesTechnologiesScenario Ref Flex HighHg Control Required 2015 2017 2015Cost for FGD+SCR 15 10 25 $/kWCost for FGD SCR 15 10 25 $/kWEquation source IECCost IECCost IECCostTechnology required

E. Bit w FF or ESP ACI ACI ACIACI ACI ACISub Bit w FF or ESP ACI ACI ACI

Lig w FF or ESP ACI ACI ACI

E. Bit w other FF + ACI Toxecon FF + ACI

Sub Bit w other FF + ACI Toxecon FF + ACISub Bit w other FF + ACI Toxecon FF + ACI

Lig w other FF + ACI Toxecon FF + ACI


L t fl t b fit f t i t NO d SO t l• Low costs reflect co-benefits of stringent NOx and SO2 controls (FGD+SCR), final HAPS rules on particulate control

• Activated Carbon Injection (ACI)


• ToxeconTM = EPRI integrated mercury removal processes

US-REGEN Input Assumptions for 316(b) ControlsControlsScenario Ref Flex High316(b) Cooling Required 2018 2018 2018Flow Threshold 125 125 125 MGDFlow Threshold 125 125 125 MGDFactor for < threshold 10% 10% 10%CCC for O/E/TR & S.Rivers Only No Yes No


EPA proposed ruling March 2011:• Cooling towers not Best Available Technology on existing plants

p

Cooling towers not Best Available Technology on existing plants• Plants must retrofit improved impingement protection, larger plants

must also retrofit improved entrainment protectionAssume plants larger than 125 MGD threshold install cooling towers• Assume plants larger than 125 MGD threshold install cooling towers at an investment cost of ~$300/gpm (with plant-specific estimates where available)F Fl S i l t tid l i d ll


• For Flex Scenario assume only ocean, estuary, tidal river, and small river plants will require closed cycle cooling

US-REGEN Input Assumptions for CCR Controls

Scenario Ref Flex HighCCR Control Required 2020 2020 2020qRCRA Subtitle Sub D Sub D Sub D


• EPRI comprehensive survey in 2010 (Veritas Consulting)

• Veritas initially provided equations to Prism 2 for RCRA C costs

• Result is site-by-site quantification of fixed and O&M costs for complying with

• Veritas then undertook adjustment for Subtitle Dj• Dropped RCRA administrative costs, O&M for disposal• Kept some wet to dry conversion costs


Comparison of Input Retrofit Costs

Overnight Retrofit Investment Costs (billions) to retrofit entire existing coal fleet (sum of unit costs input to model; data for slide 11)

Cases Ref High FlexDifference

High to Flex % of ChangeShare due to

escalationSO2 $75 $102 $24 $78 56% 46%NOx 88 102 70 33 23% 84%NOx 88 102 70 33 23% 84%Hg 7 9 5 4 3% 22%316b 37 37 13 25 18% 0%Ash 33 33 33 0 0%Ash 33 33 33 0 0%Total $240 $284 $144 $140 100%

Final model results are lower given that not all coal units are retrofit.

A l i f ll t t t l t h l i i t t th US REGEN d l d t il thAnalysis focuses on pollutant control technologies as inputs to the US-REGEN model and not necessarily on the various regulations (e.g., MATS, 316B, RCRA).

For example, the difference between the SO2 retrofits (High minus Flex) was $78B, that was 56% of the difference in total retrofit costs. Of the $78B difference, 46% of that was due to higher escalation for the High case. What isn’t escalation can be attributed to different control costs. From this, it is roughly estimated that half the total impact is for savings from

SO f f f f


lower cost SO2 control technologies, and half of which is for lower escalation. The remaining half is about is roughly split between lower NOx and 316b control costs. Hg control’s share is low due to the co-benefits for SO2 and NOx control.

Together Shaping the Future of ElectricityTogether…Shaping the Future of Electricity


analysis of current and pending epa regulations...

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