BPC Modeling Results: Projected Impact of Changing ...For those plants that burn HCl-compliant coal,...

July 2012

BPC Modeling Results:

Projected Impact of

Changing Conditions

on the Power Sector From the Staff of the Bipartisan Policy Center

BPC Modeling Results: Projected Impact of Changing Conditions on the Power Sector | 2

AUTHORS Jennifer Macedonia, Senior Advisor Colleen Kelly, Policy Analyst DISCLAIMER This report was prepared by the staff of the Bipartisan Policy Center

to promote a better understanding of the possible impacts of U.S.

Environmental Protection Agency regulation of the electric power

sector. The views expressed here do not necessarily reflect those of

the Bipartisan Policy Center’s Energy Project. ACKNOWLEDGEMENTS The Bipartisan Policy Center would like to express its thanks for the

strong support of its funders. In addition, we would like to thank

Chris MacCracken and the team at ICF International for their

modeling support and guidance on this project.


Electric Power Sector Current Landscape

The electric power sector in the United States is facing a changing market environment—

one that features low natural gas prices, rising coal prices, flattening electric demand, new

environmental regulations, expanding renewable power, uncertainty about future carbon

risk, and an aging coal fleet. This combination of factors continues to influence the relative

competitive positions of all forms of electricity generation, as evidenced by recent shifts in

dispatch resulting in a declining share of electricity generation from coal-fired generators, as

well as infrastructure decisions including announced coal plant retirements, planned gas-

fired and renewable capacity additions, and proposed retrofits.

To help understand the impacts of these changes, the Bipartisan Policy Center (BPC) has

continued its ongoing effort begun several years ago to model and to analyze the power

sector with ICF International’s Integrated Planning Model (IPM). This document is a follow-

up to the power-sector analysis presented in the June 2011 BPC staff paper, Environmental

Regulation and Electric System Reliability, specifically to the modeling results presented in

that report’s “Appendix B: BPC Modeling Using ICF’s Integrated Planning Model.” This paper

details the assumptions—including important updates on fuel price trends, electric demand

projections, and final air regulations—and results from BPC’s recent analysis.


Background on IPM Modeling

IPM is a multi-region model that endogenously determines capacity- and transmission-

expansion plans; unit dispatch and compliance decisions; and power, coal, and allowance

price forecasts—all based on power-market fundamentals. To use the model, it is necessary

to make a number of assumptions concerning key market parameters, including electricity

demand growth, fuel prices, cost and performance of new generating capacity, and cost and

performance of pollution controls and other options for complying with environmental

regulations. This document details the assumptions and regulatory compliance scenarios

included in the BPC analysis. With complex and differing financial, regulatory, and local

considerations influencing the investment decisions for specific generators, IPM is not

intended to accurately predict each unit level decision, but rather is designed to reflect

national trends and to incorporate the key drivers of investment and dispatch decisions.

Assumption for Analysis BPC based many of the assumptions for this analysis on information from the Energy

Information Administration’s Annual Energy Outlook (EIA AEO 2012 Early Release). In some

cases, BPC selected alternative assumptions to reflect recent market conditions.

Assumptions for electricity demand growth, cost and performance of new capacity, and

costs of regulatory compliance options were held constant across the scenarios analyzed.

Natural gas and coal prices varied by scenario based on the relative fuel demand from

scenario to scenario. The model is designed to include the relevant pollutant emission rates

for different fuel and unit types and to choose compliance options to meet the defined

emission limits assumed for each scenario based on the assumed cost and performance of

available pollutant-control technology options and/or fuel switching, as appropriate. Table 1

below summarizes the sources of key assumptions in the analysis. Table 2 summarizes our

detailed assumptions for select parameters.


Table 1: Sources of Key Input Assumptions

INPUT

PARAMETER

SOURCE OF

ASSUMPTION NOTES

Electric Demand Growth

EIA AEO 2012 Early Release (regional net energy for load)

BPC did not simulate demand response or additional electric demand sensitivities to represent further energy efficiency investment, appliance standards, etc.

Peak Demand Growth

EIA AEO 2012 Early Release and the same premium in peak overload assumption that EPA makes in the December 2011 MATS analysis

EPA’s peak growth rates are derived from AEO’s load growth and the assumed hourly load profiles in each region.

Natural Gas Prices

EIA AEO 2012 Early Release and ICF-derived curves

BPC used ICF-derived curves, which were created from plotting gas prices and consumption points from AEO 2011 scenarios and calibrating with AEO 2012 Early Release; AEO 2011 data were used for the curve shape and slope, because AEO 2012 Early Release didn’t include scenarios to represent the curve.

Coal Price & Production

ICF-derived coal supply curves

For HCl-compliant coal in the Powder River Basin, BPC adopted EPA’s coal supply curves to limit the production of these coal types as a response to policy drivers.

Air Pollution Control Costs

EPA (FGD, scrubber upgrades, LSD, DSI, SNCR, Fabric Filter, ACI); BPC (SCR)

For those plants that burn HCl-compliant coal, the capital costs of backup DSI were imposed without the operating costs.

Nuclear Power Licensing / Operation

BPC Nuclear units are assumed to receive one 20-year license extension and then retire (at age 60).

Production Tax Credit (PTC) Outlook

BPC

The full value of the PTC is assumed to retire this year, but half of the PTC value is assumed through 2015, before it completely disappears. The half value is intended to reflect some probability that the PTC will be renewed.

Abbreviations used:

MATS: Mercury and Air Toxics Standards HCl: Hydrogen Chloride; air pollutant FGD: Flue Gas Desulfurization; pollution control technology known as a scrubber

LSD: Lime Spray Dryer; pollution control technology known as a dry scrubber DSI: Dry Sorbent Injection, pollution control technology SNCR: Selective Non-Catalytic Reduction; pollution control technology

ACI: Activated Carbon Injection; pollution control technology SCR: Selective Catalytic Reduction; pollution control technology


Table 2: BPC Assumptions for the Cost and Performance of Air-

Pollution Controls

CAPACITY

(MW) WET FGD LSD DSI SCR SNCR

Capital Costs (2010$/kW)

300 596 510 57 450 20

500 516 441 40 400 15

700 469 419 31 350 N/A

Variable O&M (2010$/kW) 1.91 2.45 Bit. 8.46 Sub. & Lig. 3.83

1.29 1.02

Energy Penalty % 2.10% 1.33% 0.02% 0.50% 0.05%

Removal SO2 – 95% SO2 – 92% SO2 – 70% NOX – 85% NOX – 30%

First Year Allowed 2014 2014 2014 2014 2013

Source EPA EPA EPA BPC EPA

CAPACITY

(MW)

FABRIC

FILTER ACI

FGD

UPGRADE ESP UPGRADE

Capital Costs (2010$/kW)

300 168 Bit. – H 3.65; Bit. – L 2.72; Lig. 25.11; Sub. 3.86

101 55-100 500 152

700 142

Variable O&M (2010$/kW) 0.15

Bit. – H 0.41; Bit. – L 0.27; Lig. 0.50; Sub. 0.35

0 0

Energy Penalty % 0% 0% 0% 0%

Removal Hg – 90% Hg – 90% SO2 – 90% Hg – 99%

PM Compliance

First Year Allowed 2014 2013 2014 2014

Source EPA EPA EPA EPA

Abbreviations used (see also: list under Table 1):

MW: Megawatt kW: Kilowatt

O&M: operation and maintenance Bit: bituminous coal Sub: sub-bituminous coal

Lig: lignite coal SO2: sulfur dioxide

NOX: nitrogen oxides Hg: mercury


Description of Scenarios For this analysis, BPC defined two scenarios—a Base Case and a Policy Case—to examine

the impacts of the Environmental Protection Agency’s (EPA) proposed regulations on the

U.S. power sector. BPC had ICF analyze these cases using IPM based on the assumptions

described above. The cases are described below in more detail. BPC conducted similar

modeling analysis in spring 2011; two of the cases for the 2011 scenarios are also detailed

briefly below as they are included for comparison in some of the results figures.

Table 3: Overview of Modeling Scenarios

MODELING SCENARIO DESCRIPTION

Base Case All existing regulations as of summer 2011 without CSAPR and MATS

Policy Case All existing regulations as of summer 2011 with CSAPR and MATS

Former BAU Case All existing regulations as of winter 2011 with CAIR and without MATS and CSAPR

Former Policy Case All existing regulations as of winter 2011 with proposed rules—MATS, Transport Rule, cooling water intake rule, and

coal ash regulation

BPC BASE CASE

The BPC Base Case represents a business-as-usual (BAU) projection in the absence of two

recently finalized EPA air regulations: the Mercury and Air Toxics Standards (MATS) for

power plants and the Cross-State Air Pollution Rule (CSAPR). This Base Case incorporates

other existing finalized federal and state regulations as of summer 2011, including state

mercury, SO2, and NOX requirements, as well as state renewable portfolio standards. It

assumes regional cap-and-trade programs for SO2 and NOX in the eastern United States, as

stated under Phases I and II of the Clean Air Interstate Rule (CAIR). Pollution control and

retirement decisions reflected in completed New Source Review consent decrees, settlement

agreements, and “firm”1 public retirement announcements as of fall 2011 are also included

in the BPC Base Case.

BPC POLICY CASE

This case builds on the BPC Base Case and adds the recently finalized EPA air rules MATS

and CSAPR. This BPC Policy Case does not include proposed regulations for cooling water

and coal ash, the proposed New Source Performance Standard for greenhouse gases, or

more stringent requirements for SO2 and NOX beyond CSAPR that might be required in the

future to meet National Ambient Air Quality Standards and/or future Regional Haze


requirements. BPC incorporated the following assumptions regarding the final air

regulations:

Mercury and Air Toxics Standards (MATS): IPM models emissions from various fuels and

unit types and allows the model to choose the most economic compliance strategy based

on the cost and performance assumptions of pollution retrofits and fuel changes

available for specific unit types to comply with emission limits under the MATS rule. As

mentioned above, this case primarily relies on EPA assumptions from the MATS final

rulemaking for control-equipment costs and performance. For compliance timing, this

Policy Case assumes that when chosen as a viable and economic compliance option,

installations of ACI, DSI, as well as ESP upgrades will be completed by January 2015. To

simulate use of the one-year MATS compliance-deadline waiver authorized by permitting

authorities, BPC assumed that all wet and dry scrubber and baghouse/fabric filter

installations required for compliance would be completed by January 2016. In addition,

units that were economically projected to retire rather than incur compliance costs were

assumed to get a one-year compliance waiver that would allow operation without MATS

compliance through the end of 2015 for units that retire by January 2016. To simulate

potential reliability constraints, retirements were limited to 15 gigawatts (GW) in 2014

and then determined on an economic basis thereafter. This BPC Policy Case assumes a

limited supply of sub-bituminous coal with low chlorine content that allows compliance

with the MATS HCl limit without any additional pollution controls. For units burning this

“HCl-compliant coal,” we assigned a capital cost for the installation of “backup” DSI, but

did not include an operating/sorbent cost for DSI.

Cross-State Air Pollution Rule (CSAPR): This BPC Policy Case, developed without

knowledge of the court’s final decision, assumes that the court’s stay on the regulation

delays Phase I CSAPR compliance until 2013 and that Phase II and the assurance

provisions begin in 2014. In this exercise, interstate trading is limited to regional

markets (i.e., Group 1 vs. Group 2 SO2; annual vs. ozone season NOX). Before 2013, the

Policy Case includes the same CAIR assumptions as the Base Case.

BPC FORMER BAU AND POLICY CASES

The BPC Former BAU Case was presented in the June 2011 BPC staff paper Environmental

Regulation and Electric System Reliability and represents our business-as-usual (BAU)

projection as of spring 2011. This case includes existing federal and state regulations as of

January 2011, including state mercury, SO2, and NOX requirements, as well as renewable

portfolio standards. The case assumes regional cap-and-trade programs for SO2 and NOX in

the eastern United States, as stated under CAIR Phases I and II. The case does not include

any federal mercury-reduction or carbon dioxide requirements for the power sector.

The BPC Former Policy Case was also presented in the June 2011 staff paper and includes

BPC assumptions as of spring 2011 for the requirements under EPA’s then-proposed suite of

new regulations, including the proposed MATS, proposed transport rule (which was


subsequently finalized as CSAPR), the proposed cooling water intake rule §316 (b), and an

assumed non-hazardous coal ash regulation.

Select Results of BPC Analysis The following charts present select results for the BPC cases described in the previous

section and, in some cases, also include the 2011 BPC scenarios for comparison. Unless

otherwise specified, the results are presented for the continental United States and do not

include Hawaii and Alaska.

Figure 1: Projected Fate of Current Fleet by 20162

Figure 1 reflects the projected status of the current fleet of U.S. electric-generating units as

of the year 2016 under BPC’s Policy Case with MATS and CSAPR. (New capacity additions

are not included in Figure 1.) A total of 56 GW of coal-fired generating capacity is expected

to retire by 2016, with 40 GW retiring under BAU market conditions and an additional 16

GW retiring as a result of MATS and CSAPR compliance requirements. For the Base Case,

the key drivers of coal plant retirements include flattening electric demand, low natural gas

prices, and higher coal prices. These model inputs have experienced significant changes

since the last round of BPC analysis in 2011.

Remaining Coal (264 GW)

Natural Gas/Oil Retired in Base Case (30 GW)

Remaining Natural Gas/Oil

(427 GW)

Nuclear (105 GW)

Other (168 GW)

Remaining Coal

Natural Gas/Oil Retired in Base Case

Remaining Natural Gas/Oil

Nuclear

Other (Renewables, Hydro)

Coal Retired in Base Case (40 GW)

Coal Retired by Air Rules (16 GW)

Retiring coal (56 GW = 5% of total fleet)


Figure 2: Electric Demand Annual Forecasts 2009 – 20353

A key input that has changed since BPC’s 2011 analysis is the forecast for electric demand.

As seen in Figure 2, electric demand projections from EIA AEO 2012 reflect a flattening of

demand growth. The AEO 2012 demand forecast is lower than in recent years, which has a

significant impact on power-sector projections. Even though there are some regions of the

country expecting growth in electricity demand, the national trend reflects a slowing of the

historical growth rate for electricity demand due to a slow economic recovery in the short

term, as well as deployment of energy efficiency measures throughout the economy. The

absence of growing demand for electricity, combined with the excess capacity in the existing

fleet, is expected to depress the need for new generating capacity, even as significant

amounts of existing generation retire.

Figure 3: Projected Natural Gas Prices at Henry Hub4,5

3500

4000

4500

5000

5500

6000

Bil

lio

n k

Wh

AEO 2012 AEO 2011 AEO 2010 AEO 2009 AEO 2008 AEO 2007

4.00

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

8.50

9.00

$ /

MM

BT

U

Base Case Policy Case Former BAU Former Policy Case


Another key assumption that was updated since the 2011 analysis is the reference case of

natural gas prices, which we based on recently derived gas supply curves that were

calibrated with natural gas price projections in AEO 2012 Early Release. Figure 3 shows

projected natural gas prices at Henry Hub—used for the current analysis—compared with

results from the previous 2011 BPC analysis. In the current BPC Base Case, the natural gas

price is assumed to be near $4/mmBtu in 2013 and to climb over time to around

$6.25/mmBtu in 2030. As a result of the model simulating the impacts of increased demand

for natural gas under the BPC Policy Case, natural gas prices rise above the Base Case

prices from 2013 and beyond, but nonetheless remain below the Former BAU case natural

gas price. In 2030, the Policy Case natural gas price is projected to be around

$6.25/mmBtu, compared with around $8.00/mmBtu projected in the 2011 BPC analysis.

Figure 4: National Minemouth Coal Prices

While natural gas price projections have decreased recently, the coal price projections have

increased over the last few years. This BPC analysis incorporates updated coal price

projections (blue line in Figure 4). Figure 4 compares current coal price projections with the

assumptions from last year’s BPC analysis (in dashed lines). Throughout the entire period,

the BPC Base and Policy Case coal prices were higher than the former BPC BAU and Policy

Cases. The spike in the 2016 national average coal price in the BPC Policy Case is due to the

projected premium for low-chlorine-content sub-bituminous western coal (HCl-compliant

coal); this premium is projected based on the assumption, consistent with EPA’s analysis

supporting the MATS Final Rule, that such HCl-compliant coal allows compliance with the

MATS HCl limit without additional pollution controls.

1.50

1.60

1.70

1.80

1.90

2.00

2.10

$ /

MM

BT

U

Base Case Policy Case Former BAU Case Former Policy Case


Figure 5: Cumulative Coal Retirements

In comparison with the 2011 BPC modeling scenarios, the Base Case coal retirements have

more than doubled (from 14 GW in the previous analysis to 40 GW today), while the

incremental retirements from the EPA rules is roughly the same (15–18 GW in the previous

case and 16 GW today). (See Figure 5.)

Figure 6: Cumulative Projected Capacity Additions6

Figure 6 shows cumulative U.S. capacity additions by type in both the BPC Base and Policy

Cases. In both cases, the build mix is dominated by renewable capacity (i.e., wind, biomass,

and other renewables) in the short term, as states work to meet Renewable Portfolio

Standards. Natural gas–fired plants are not built in substantial numbers until 2025, largely

0.00

10.00

20.00

30.00

40.00

50.00

60.00

Gig

aw

att

s

Base Case Policy Case Former BAU Case Former Policy Case

Current projection: 16 GW retires due to air rules

Last year's BPC projection: policy retires 15-18 GW

0

20

40

60

80

100

120

140

Base Case

Policy Case

Base Case

Policy Case

Base Case

Policy Case

Base Case

Policy Case

2016 2020 2025 2030

Gig

aw

att

s

Other NG/Oil Nuclear Biomass


because of the surplus of gas-fired capacity that was built out in the 1990s. Visibly absent is

new coal capacity; through 2030, no new coal generation is projected to be built in either

case except for the units that began construction prior to this analysis, which are not

included in this chart. Although the Policy Case does not include the EPA’s proposed New

Source Performance Standard for greenhouse gases—which would essentially require any

new coal capacity to include carbon capture and sequestration—these results would not be

impacted by such a requirement, because of the lack of new coal builds.

Figure 7: Generation Mix for Base and Policy Cases 2012 – 2035

Coal generation has seen a decline in recent years that is expected to continue. However,

even with the movement toward natural gas and renewables and a projected retirement of

56 GW of coal capacity in the coming years, coal is projected to remain the largest

generation source in both the Base Case and Policy Case through 2035 (as shown in Figure

7). In fact, the differences in generation fuel mix between the two cases are somewhat

modest. Generation from coal in the Policy Case is 3 percent lower in 2020 and 6 percent

lower in 2030 relative to the Base Case, as compliance costs further impact the competitive

position of coal generators. Increased gas-fired generation makes up for the majority of that

decline. In the BPC Policy Case, generation from gas is 5 percent higher in 2020 and 9

percent higher in 2030, compared with the BPC Base Case. Potential future environmental

requirements that are not included in this Policy Case, such as stricter NOX and/or

particulate limits, GHG limits for existing sources, coal ash handling, and cooling water

requirements have the potential to further influence the future generation mix.

0

1000

2000

3000

4000

5000

6000

Th

ou

san

d G

Wh

Base Case

Coal Natural Gas/Oil Nuclear Hydro Renewables Other

0

1000

2000

3000

4000

5000

6000

Th

ou

san

d G

Wh

Policy Case


Figure 8: Coal Capacity and Percent Difference in Coal Generation

Figure 9: 2012 Generation from Retiring and Non-Retiring Coal-

fired Units

Figure 8 highlights the changes in coal-fired generating capacity (i.e., nameplate capacity of

all remaining coal-fired electric generating units), as well as the amount of electricity

projected to be generated from coal-fired facilities. As coal-fired generators retire, coal-

generating capacity falls through 2016 and then remains constant. In response to the

competitive advantage of gas-fired generation in the short term, the percent change in coal

generation follows a similar downward trajectory through 2016. However, by 2020, the

amount of electricity generated from coal-fired facilities is projected to increase above

current levels and continue to grow well beyond today’s historically low level to reach 2007

– 2008 levels around 2025.

-10%

-5%

0%

5%

10%

15%

20%

0

50

100

150

200

250

300

350

% D

iffe

ren

ce

(B

ase Y

ear =

20

12

)

Co

al C

ap

acit

y (

GW

)

Coal Capacity Coal Generation % Diff

-

500,000

1,000,000

1,500,000

2,000,000

Base Case Policy Case

20

12

Gen

erati

on

(G

Wh

)

Operate Post-2016 Retire by 2016


Figure 9 offers an explanation for these trends, which on the surface may seem to be

contradictory. The coal plants that are retiring contribute only a small percentage (see the

red portion in Figure 9) to the total amount of electricity produced from coal-fired

generators in 2012. As shown in Figure 10, the units projected to retire tend to be older,

smaller, and less efficient on average than the rest of the fleet and tend to operate much

less frequently than baseload coal capacity: 74 percent of the projected retiring coal is at

least 40 years old, 50 percent are 200-megawatt capacity or less, and 55 percent have heat

rates of at least 11,000 mmBtu. (Higher heat rates indicate lower efficiency.) More details

about the age, size, and heat rate of units in the fleet can be found in the appendix.

Figure 10: Demographics of Coal Units Projected to Retire by

20167

Figure 11: Nationwide Emissions of Various Pollutants in 2016

15%

13%

17% 34%

16%

5% Size of Retiring Coal

500+

300-500

200-300

100-200

50-100

Less than 50

3% 5%

11%

36%

32%

13%

Heat Rate of Retiring Coal

14,000+

13,000-14,000

12,000-13,000

11,000-12,000

10,000-11,000

Less than 10,000

8%

40%

26%

16%

10%

Age of Retiring Coal

60+

50-60

40-50

30-40

Less than 30

Retiring plants tend to be older, smaller, and less

efficient:

74% are at least 40 years old

50% are 200 MW capacity or less

55% are at least 11,000 mmBtu heat rate

0

1

2

3

4

Base Case

Policy Case

Mil

lio

n T

on

s

Sulfur Dioxide

0

5

10

15

20

25

30

Base Case

Policy Case

To

ns

Mercury

0

500

1000

1500

2000

2500

Base Case

Policy Case

Mil

lio

n M

etr

ic T

on

s

Carbon Dioxide

0.0

0.5

1.0

1.5

2.0

Base Case

Policy Case

Mil

lio

n T

on

s

Nitrogen Oxides


Table 4: 1995 vs. 2016 Emissions by Pollutant8,9

POLLUTANT UNITS 1995 LEVELS 2016 BASE

CASE LEVELS

2016 POLICY

CASE LEVELS

SO2 Million Tons 12.1 3.8 1.8

NOx Million Tons 6.4 1.5 1.4

CO2 Million Metric Tons 1960 2009 1938

Mercury Tons 59.010 27.0 6.1

In addition to impacting the generation fuel mix, the impact of the Policy Case is seen in the

estimates of nationwide emission levels in Figure 11. The largest differences from CSAPR

and MATS are seen in the levels of SO2 and mercury; the Base Case levels are more than

two times the Policy Case levels for SO2 in 2016 and more than four times for mercury.

Looking at Table 4, substantial progress has also been made in reducing NOX from earlier

levels. Moving forward, there is potential for further reductions both within and outside the

power sector.

Figure 12: Compliance with SO2 and HCl Requirements (CSAPR

and MATS)11 for Non-Retiring Units

Of the pollution controls expected for compliance with the various limits in CSAPR and

MATS, a wet scrubber (flue gas desulfurization) is the most expensive technology. Contrary

to the final EPA regulations and available control-technology options, some previous

analyses have assumed that all plants will require wet scrubbers to comply with these

regulations, which has inflated the projected costs and resulting coal plant retirements in

their assessments.12 Instead, BPC analysis allows the model to choose the most economic

compliance strategy from the cost and performance data specified in the final rulemakings,

which include additional lower-cost technologies and fuel-switching options.

Existing Scrubbers Add wet scrubber

Add dry scrubber

Add DSI

Compliant coal


Figure 12 shows that almost 70 percent of the coal capacity projected to remain in

operation through 2016 already has scrubbers in place, although some require upgrades. To

comply with the SO2 requirements of CSAPR and the HCl limit in MATS, 13 percent of the

coal capacity forecasted to remain in operation is projected to add control technology (6

percent to add DSI, 4 percent to add a dry scrubber, and 3 percent to add a wet scrubber).

In addition, almost 20 percent (49 GW) of the remaining coal-fired fleet is projected to

comply by burning compliant coal13 (primarily Powder River Basin/western sub-bituminous

coal with low enough chlorine and sulfur contents to meet the HCl and SO2 emission

requirements without add-on controls). The units projected to burn such compliant coal are

units that have previously burned sub-bituminous coal, either in total or as part of a blend

(see Figure 18 in the Appendix). Because these units are not projected to install a scrubber

or operate DSI, their compliance costs are substantially less than most analyses assume

and many are projected to avoid retirement and remain competitive.

Figure 13: Regional Pollution Control Status by 2016

Figure 13 shows the projected status and pollution control complement of the remaining

coal fleet in 2016, broken out by areas of the country. The local conditions, environmental

requirements, and extent of pollution controls vary by state and region. Most of the units in

the West and Northwest are well controlled for SO2/acid gases with a scrubber or DSI but

lack post-combustion NOX controls. The amount of post-combustion NOX control (i.e., SCR

and SNCR) increases as you move east across the country, reflecting the fact that many of

these eastern areas have a regional ozone problem that has led to control requirements.

The central region has the largest percentage of capacity without advanced post-combustion

controls and is where much of the lower-emitting (for SO2 and HCl) compliant western coal

is burned.


Appendix: Additional Figures

Figure 14: Coal Retirements by Age and Size

Figure 15: Coal Retirements by Age and Heat Rate

-

200

400

600

800

1,000

1,200

1,400

- 10 20 30 40 50 60 70 80

Size

(MW

)

Age in 2016 (Years)

Coal Retirements by Age and Size

Operates Post-2016

Retires in Policy Case

Retires in Reference Case

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

16,000

- 10 20 30 40 50 60 70 80

Hea

t Rat

e (B

tu/K

Wh)

Age in 2016 (Years)

Coal Retirements by Age and Heat Rate

Operates Post-2016

Retires in Policy Case

Retires in Reference Case


Figure 16: Status of SO2 and NOX Pollution Controls after

Implementation of CSAPR and MATS14

Figure 17: Regional Breakout of Projected Coal Plant Retirements

(GW)

56%

0%

44%

SO2 Controls in 2012

Wet Scrubbers

Dry Scrubbers

No add-on SO2 Controls 70%

4%

6%

20%

SO2 Controls by 2016: Policy Case

Wet Scrubbers

Dry Scrubbers

DSI

No add-on SO2 Controls

17%

4%

78%

NOx Controls in 2012

SCR

SNCR

No post-combustion NOx Controls

19%

4%

77%

NOx Controls by 2016: Policy Case

SCR

SNCR

No post-combustion NOx Controls


Figure 18: Impact of Policy on Coal Switching: Coal Consumption

by GW

-

50

100

150

200

250

300

350

2012 2017

Gig

aw

att

s

Lignite

Blended

HCl Compliant Sub-Bit

Sub-Bit

Bituminous


Endnotes

1 For this analysis, “firm” planned retirements are defined as units that were (1) subject to agreement with EPA,

(2) tied to construction of new capacity that is underway, and (3) already in the process of closing as of fall 2011. Firm coal retirements using that criterion totaled roughly 14 GW over the period 2011 to 2020. The firm units did not include more recent announcements made specifically in response to MATS, low natural gas prices, and electric demand—which may coincide with IPM projected economic retirements.

2 New capacity additions not included.

3 Energy Information Administration. Annual Energy Outlook. Available at: http://www.eia.gov/forecasts/aeo/.

4 The 2011 BAU and Policy Cases are in 2006 dollars, while the 2012 BAU and Policy Cases are in 2010 dollars.

5 IPM does not model every year that is illustrated in the figures; the model includes 2012 – 2017, 2020, 2025,

2030, and 2035. Data for the other years in the charts throughout the paper was extrapolated.

6 This chart does not include firm builds. Firm builds are units that are currently under construction or units that are sufficiently far along in the permitting and financing processes.

7 The percentages are computed as percent of megawatts.

8 Energy Information Administration. U.S. Carbon Dioxide Emissions from Electric Power Sector Energy

Consumption, 1990-2009.

9 Environmental Protection Agency. National Emissions Inventory Air Pollutant Emissions Trends Data.

10 1990 levels listed in lieu of 1995 figure. Environmental Protection Agency. Mercury and Air Toxics Standards (MATS): Cleaner Power Plants. Available at: http://www.epa.gov/mats/powerplants.html#limits.

11 Analysis based on BPC Spring 2012 Policy Case; Particulate control upgrades/retrofits may also be required.

12 For example, in their May 2012 analyses, the Electric Power Research Institute assumed scrubber installations in

its “Reference (Environmental Controls) Scenario,” and North American Electric Reliability Corporation assumed wet scrubbers for all units in its analyses.

13 This is projected to result in a premium for such compliant coal, which is reflected as a spike in the national

mine-mouth coal price in Figure 4.

14 SO2 controls charts include just coal plants; NOx controls charts include both coal and natural gas plants. The

percentages are computed as percent of megawatts.

http://www.eia.gov/forecasts/aeo/

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