Economic Impacts of Implementing a Regional SO2 Emissions Program in the

Grand Canyon Visibility Transport RegionVolume I

Prepared for:

Western Regional Air PartnershipMarket Trading Forum

Prepared by:

ICF Consulting

September 2000

2 Volume I

Outline

Study Goals

Overview of Study Approach

Analytic Framework

Assumptions and Data Sources

Results

3 Volume I

Study Objectives

An economic assessment of alternative milestone levels and policy implementation approaches

– Command and control methods

– Regional SO2 cap under the assumption that the backstop trading program has not been triggered

– Regional SO2 emissions cap with a backstop market trading program

Sector-by-sector analysis of all utility, industrial and other sectors

Description of the impact on the state, tribal and regional economy through 2018

4 Volume I

Changes in: • Capacity and output levels • SO2, CO2 and NOx

Emissions • Investment costs • Fuel consumption and

production• Wholesale power prices• SO2 Allowance Prices

Sources CharacteristicsDemand LevelsTechnology and Control Options/CharacteristicsMilestone Levels

Overview of Analytic Approach

ICF’s IPM

REMI

ICF’s IPM Changes in:•Employment •Output (GRP) •Disposable Income

5 Volume I

Overview of Analytic Approach

ICF’s Integrated Planning ModelTM -- a detailed model of the power and industrial boiler sectors, modified to include other sources -- was used to project the economic impacts of the alternative scenarios. This model captures the complex interactions between electricity, steam, fuel and environmental markets.

The energy and environmental market impacts -- in terms of energy price impacts, consumption levels, investments, permit values, among other factors -- were used to drive a regional economic model to assess the impacts on the regional, state and tribal economies.

6 Volume I

IPM Used in Many Similar Studies IPM has been used for 20 years for power market analyses and

forecasting, environmental policy and regulatory analyses and compliance planning.

IPM is used in support of EPA analyses of NOX, SO2, mercury, and CO2 emissions policies and power and industrial markets impacts. Used in support of the Clean Air Policy Initiative (CAPI), the OTAG process, analysis of the NAAQS, the SIP Call, the Section 126 analysis, and carbon policy analysis.

IPM was used for for FERC’s Order 2000.

IPM is used for industry clients in evaluating the impact of the SIP Call and other proposed regulations on the value of their existing and potential assets. Used for electric market assessments, forward price curves, and asset valuation.

7 Volume I

Integrated Planning ModelTM

8 Volume I

IPMTM Regional Map

ERCOT

DUKE

Downstate NY

MAPP

Southern

ILMO

PJM East

So. ECAR

NE

PO

OL

TVA

Flo

rida

SPP-N

SPP-W

WU

MS

COMED

ME

CS

Upstate

NY

PJM-W

LILCO

PJM SouthVIEP

CP&L

SCEGEn

terg

y

PACNWMontana

NWPP East

RMA

S-NM

N-NMArizona

NOCAL

SOCAL

New York City

9 Volume I

The Integrated Planning ModelTM

IPM is a detailed engineering-economic capacity expansion and production costing model for analyzing the electric power and industrial steam markets.

IPM is a multi-regional, dynamic linear programming model. It has explicit representation of interregional transmission linkages between 21 regional power markets.

IPM finds the least-cost solution to meeting electricity and steam demand subject to transmission, fuel, energy demand, reserve margin, and other system operating constraints, including simultaneous environmental requirements.

10 Volume I

GCVTC States in IPM Regions

Wyoming

Colorado

New Mexico

Oregon

California

Nevada

Idaho

Utah

ArizonaCNV

WSCP

WSCR

11 Volume I

Geographic Coverage

The EPA Winter 1998 Base Case implementation of IPM represents 21 regional electric power markets in the contiguous U.S.

IPM regions generally correspond to the regions and sub-regions defined by the North American Electricity Reliability Council (NERC).

12 Volume I

Geographic CoverageContinued

The nine GCVTC States (AZ, CA, CO, ID, NV, NM, OR, UT, WY) are contained in IPM regions WSCP, WSCR and CNV (NERC region WSCC).

For WRAP, IPM was modified slightly to account for Tribal Areas.

IPM reporting modified to track impacts for the nine states and tribal area.

13 Volume I

IPM

EnvironmentalCompliance

Technologiesand Costs

• Capacity Additions• Fuel Prices• Electric Prices• Asset Values• Emissions• Retrofit Decisions• Compliance Costs

• Steam Demand• Electric Demand• Gas Supply• Coal Supply

Environmental

RegulatoryScenario

Existing and New Electric, CHP and Boiler

Technologies

14 Volume I

IPM’s Internal Structure

IPM is a dynamic optimization framework with an objective function of minimizing the present value of total system cost over the study horizon subject to:

– Electricity & Steam Demand Constraints

– Reserve Margin Constraints

– Environmental Constraints

– Transmission Constraints

– Fuel Constraints

– Other Operational Constraints

Detailed information on fuels, resource options, and environmental compliance technologies.

15 Volume I

Sources: Electric Generator, Boilers, CHP, Process Sources

Electric Generators

Electric Generators

ElectricDemand

ElectricDemand

RepoweredCHP

RepoweredCHP BoilersBoilers

SteamDemand

SteamDemand

Existing CHPNew CHP

Process Sources

Process Sources

Allowance Market

Other Output

Other Output

16 Volume I

Sources Modeled Affected sources include generators, boilers and other

sources of SO2 over 100 TPY.

Generators, cogenerators, industrial boilers and other SO2 sources were modeled simultaneously.

Allows development of optimal long-term generating and boiler capacity expansion plans while meeting both steam and electricity demands.

Affected process emissions sources were added as producers of SO2 emissions and consumers of allowances under the cap and trade system.

Other sources -- emissions tracked and reduction options provided. Did not model output decisions of these sources.

17 Volume I

Electric Load Modeling

0

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12000 600 900300 1500 2100 24001800

Segment 1

Segment 2 Segment 3Segment 4

Segment 5

Segment 6Segment 7

Segment 8

Segment 9

Hours

Meg

awat

ts

18 Volume I

Electric Load and Dispatch Modeling

Electricity demand is modeled in the form of a load duration curve by season and segment.

Generating units are dispatched by segment.

IPM performs accurate plant dispatch based on seasonal load curves.

Power plants are dispatched based on cost, and capacity, de-rated for their forced and planned outages.

Pollution control cost is endogenously modeled.

19 Volume I

Environmental Capabilities

Multi-pollutant modeling capabilities (SO2, CO2, NOx, Hg, TSP)

Tonnage caps and rate limits

Emission policies:

– Trading only

– Trading and Banking

– Banking and Borrowing over multiple periods

– Command & Control

– Progressive Flow Control

– Input/Output based Allowance Allocation Schemes

– Renewable Portfolio Standards.

20 Volume I

Environmental Compliance Options

IPM can model a broad range of options to comply with the air emissions regulations, including:

– Install pollution control equipment (e.g., scrubber)

– Fuel switching (e.g., coal to gas)

– Co-firing

– Repowering of steam power plants to gas-fired combined cycle

– Repowering of industrial boilers to CHP system with fuel switching

– Changes in system dispatch

IPM evaluates economic early retirement of generating units.

21 Volume I

Coal Supply Regions

NDMEMW

MP

WP

WG

CGUC

USCU

CD

NR

CR

NSAZ

IA

MOKS

OK AN

AS

TX

LA

ASAL

TN

ILIN

KWKE

OH

PCPW

WN

WS

VA

WA

CS

Western NorthernGreat Plains Eastern Northern

Great Plains

Northwest

Rockies

CentralWest

Gulf

Mid-West

NorthernAppalachia

SouthernAppalachia

CentralAppalachia

Southwest

MD

22 Volume I

Fuel Market Capabilities

IPM has an endogenous fuel supply capability

Separate coal supply and demand regions connected by a transportation network

Natural gas fuel supply curves available

– Gas Transportation cost matrix

– Seasonal price adders for natural gas

Produces gas and coal price and consumption forecasts.

Allows an integrated assessment of the Impact of environmental regulations on fuel markets.

23 Volume I

Assumptions and Data Development

24 Volume I

Data Development Process

Starting point for assumptions was U.S. EPA’s Winter 1998 Base Case, documented in “Analyzing Electric Power Generation Under the CAAA”, Office of Air and Radiation, March 1998, the basis for EPA’s regulatory and policy analysis. Details of EPA assumptions can be found at www.epa.gov/capi.

Emissions characteristics, controls, and stock were updated by ICF to reflect most recent available information (CEMs data, Form 479, and WRAP/MTF data)

Other key assumptions developed by MTF participants

– Emissions baseline for non-utility, non-boiler sources (“Other” sources) based on IAS

– Control Options for BART-eligible sources

– Control technology options and characteristics

25 Volume I

Key Assumptions

Electricity and Steam Demand

Bart-eligible sources, controls and characteristics

Technology Control Options and Characteristics for trading scenarios

Fuel Prices

26 Volume I

Electric Demand Assumptions

Electricity demand growth of 1.85 % per year for 2000-2009 and 1.4 % per year for 2009 - 2030 based on WRAP directive.

WSCCNational CNV WSCR WSCP

Net Energy For LoadActual 1998 (GWh) 3,418,380 267,704 167,534 189,5191999-2008 Annual Average Growth Rate (%) 1.85 1.53 2.22 1.042009-2030 Annual Average Growth Rate (%) 1.40 1.40 1.40 1.40Peak Demand (MW) 46,055 26,780 30,802

NERC ES&D 1999

27 Volume I

WSCC

Steam Demand Growth Rates2

(% ) National CNV WSCR WSCP2001 - 2005 2.60 2.94 2.70 2.942006 - 2010 2.14 2.43 2.28 2.432011 onwards 1.47 1.57 1.63 1.57

1 EPA’s Industrial, Commercial and Institutional (ICI) Boiler Database

2 DRI-McGraw Hill Industrial Production Forecast published in GRI’s 1997 Baseline Report

Steam Demand

1995 National Steam Demand1 2,766 TBtu.

Steam demand based on DRI forecasts.

28 Volume I

Control Equipment Cost and Performance Options

Scenario Utility Boilers Other SourcesCommand & Control Repower to CC Repower to Cogen

Repower to IGCCLime Spray Dryer - Scrubber Lime Spray Dryer - ScrubberPartial Bypass - Incremental SO2 removal

Partial Bypass - Incremental SO2 removal

Trading Repower to CC Repower to Cogen Install ControlsRepower to IGCCLime Spray Dryer - Scrubber Lime Spray Dryer - ScrubberPartial Bypass - Incremental SO2 removal

Partial Bypass - Incremental SO2 removal

Dry Sodium Injection - Scrubber

Dry Sodium Injection - Scrubber

Retire

29 Volume I

Bart-Eligible Sources

Identified by MTF participants. Include 85 sources in the nine state region

Required to install controls in the command and control scenario beginning in 2013

– Sources with current controls of less than 70% efficiency are required to install control that achieve 85% efficiency

– Sources with current controls of between 70% and 80% efficiency are required to increase control efficiency to 85%

– Sources with current controls above 80% require no further abatement activity

30 Volume I

Control Equipment Cost and Performance - Command & Control

Control options for the utility sector include lime spray dryers and incremental SO2 removal technology based on partial bypass option.

Costs for the dry scrubber was based on actual experience at Cherokee and Valmont units. Costs were adjusted to reflect unit size.

Boilers were given the same options, adjusted to reflect size impacts.

Cost and performance data for incremental SO2

removal technology were taken from the Craig report.

31 Volume I

Control Equipment Cost and Performance - Policy Trading

Scenarios Additional controls were made available to affected

sources in the policy trading scenarios.

Dry sodium injection (DSI) scrubbers achieving a 50% reduction was made available to utilities under the trading policy scenarios.

Costs for the DSI scrubber was based on actual experience at Arapahoe and Cherokee units. Boilers were given the same options, adjusted to reflect size impacts.

32 Volume I

Control Costs for Utilities

*Reference Size is 352 MW

TechnologyCapital Cost (1997$/kW)

Fixed Cost (1997$/kW-yr)

Variable Cost (mills/kWh)

% Removal

Incremental SO2 Removal 16.01 0.31 0.06 85%Lime Spray Dryer (LSD)* 94.45 5.31 0.52 85%Dry Sodium Injection (DSI) 8.17 1.53 1.01 50%Retrofit to Cogen (Coal to Gas) 355 19.5 1.10 -Repower Coal to IGCC 1,566 25.44 2.42 100%Repower Coal to CC 279 19.5 1.10 -Repower Oil/Gas to CC 279 19.5 1.10 -

33 Volume I

Control Equipment - Policy Trading Scenarios (Continued)

Utilities were given the option to retire.

Non boilers, non utility control cost and performance were extracted from IAS.

Control cost for smelters and refineries were updated based on data provided by EPA.

Repowering options for utilities and boilers were taken from “Analyzing Electric Power Generation Under the CAAA”, Office of Air and Radiation, March 1998.

34 Volume I

Control Costs for Other Sources

Industry TypeAverage Total Cost

(1990$/ton)Total Emissions (Thousand Tons)

Average Reduction (%)

Sulfuric Acid Plants 1,868 21.09 96%Sulfur Recovery Plants 1,971 6.00 99%Industrial Petroleum Process Fuel Use 2,902 1.11 90%Inorganic Chemical Manufacture 3,106 7.60 90%Process Heaters (Oil and Gas Production industry) 3,358 1.48 90%Industrial Natural Gas Production 4,790 41.89 92%Refineries 8,120Smelters 9,149 85.95

35 Volume I

Control Costs for Other Sources

Control costs for smelters and refineries costs were based on industry review of current information and reflect current level of controls. Cost estimate was based on data provided by EPA. Cost estimates was based on EPA estimates.*

* “Regulatory Impact Analysis for the Particulate Matter and Ozone National Ambient Air Quality Standards and Proposed Regional Haze Rule.” Appendix B, “Summary of Control Measures in the PM, Regional Haze, and Ozone Partial Attainment Analyses.”

36 Volume I

New Capacity Performance and Unit Costs for Fossil and Nuclear Technologies (1997$)

Conventional Pulverized Coal

Coal (IGCC)Advanced Combined-

CycleGas

TurbineNuclear

Size (MW) 400 380 400 80 1,3002000 - 2004 Vintage Heat Rate (Btu/kWh) 9,419 8,470 6,773 11,075 Capital ($/kW) 1,377 2,136 617 379 Fixed O&M ($/kW/yr) 33.59 25.44 19.50 1.74 Variable O&M ($/MWh) 2.74 2.02 1.10 1.002005 - 2009 Vintage Heat Rate (Btu/kWh) 9,253 8,470 6,562 11,075 10,400 Capital ($/kW) 1,377 2,136 431 379 2,865 Fixed O&M ($/kW/yr) 33.59 25.44 19.50 1.74 56.30 Variable O&M ($/MWh) 2.74 2.02 1.10 1.00 0.412010 and After Vintage Heat Rate (Btu/kWh) 9,087 8,470 6,350 11,075 10,400 Capital ($/kW) 1,377 2,136 367 379 2,865 Fixed O&M ($/kW/yr) 33.59 25.44 19.50 1.74 56.30 Variable O&M ($/MWh) 2.74 2.02 1.10 1.00 0.41

Regional Cost Multiplier for WSCC = 0.92

37 Volume I

Performance and Unit Costs of New Co-generation Technologies (1997 $)

Small CT-HRSG Gas-Fired

Large CT-HRSG Gas-Fired

Size (MW) 10 1202000-2004 Vintage Heat Rate (Btu/kWh) 10,526 9,970 Capital ($/kW) 778 620 Fixed O&M ($/kW/yr) 23.4 19.5 Variable O&M ($/MWh) 1.41 1.12005-2009 Vintage Heat Rate (Btu/kWh) 10,526 9,665 Capital ($/kW) 778 496 Fixed O&M ($/kW/yr) 23.4 19.5 Variable O&M ($/MWh) 1.41 1.12010 and After Vintage Heat Rate (Btu/kWh) 10,526 9,355 Capital ($/kW) 778 444 Fixed O&M ($/kW/yr) 23.4 19.5 Variable O&M ($/MWh) 1.41 1.1

Regional Cost Multiplier for WSCC = 0.92

38 Volume I

Fuel Prices - Gas

Delivered Natural Gas Prices (1997 $/MMBtu)

Source: EIA’s Annual Energy Outlook 1999

Region 2000 2005 2010 2020CNV 3.22 4.11 4.17 4.19WSCP 2.84 3.21 3.25 3.39WSCR 2.89 3.64 3.73 3.97National 2.64 2.95 3.09 3.25

39 Volume I

Fuel Prices - Coal

Delivered Coal prices (1997$/MMBtu)

Region 2000 2005 2010 2020CNV 0.91 1.01 0.92 0.78WSCP 0.94 0.84 0.78 0.66WSCR 0.93 0.83 0.75 0.65National 1.12 1.01 0.94 0.81

Source: Forecast based on WRAP Baseline Scenario. Cost Curve based on “Analyzing Electric Power Generation Under the CAAA”, Office of Air and Radiation, March 1998.

40 Volume I

Scenarios Evaluated

Baseline scenario assumes existing environmental regulations (Title I and Title IV NOX, Title IV SO2, and the SIP Call regulations)

“Command and control” scenario

– Bart-eligible sources retrofit with BART

– IPM captures impacts on operation in the system.

Market Trading Program

– Emissions limit (and interim milestones) imposed on all affected emissions sources with full trading among all sources; new units subject to the cap

– Emissions control options include the control technologies supplied in the model, fuel switching to lower sulfur content fuels, or reducing output

– Model determines the optimal mix of control, dispatch changes (including changes in

imports/exports), fuel switching, new unit construction, existing unit retirements to meet the cap in a least-cost way (on a national level)

41 Volume I

Results

42 Volume I

Baseline Results

43 Volume I

Baseline Results

-

100

200

300

400

500

600

700

800

1999 2001 2006 2013 2018

Other Sources Smelters (excl. boilers) Industrial Boilers

Combined Heat and Power Utility Generators

44 Volume I

Baseline Results

Baseline emissions estimates are reported only for affected sources.

Emissions from industrial boilers and cogenerators are flat since they operate at fixed capacity factors.

Emissions from smelters and other sources are assumed to remain flat over time based on 1998 levels provided by WRAP.

45 Volume I

Baseline Emissions (Thousand Tons of SO2)

Source 1999 2001 2006 2013 2018Utility Generators 425 415 381 374 375Industrial Boilers 40 40 40 40 40Combined Heat and Power 14 14 14 14 14Smelters (excl. boilers) 86 86 86 86 86Other Sources 133 133 133 133 133Total Nine State Region 698 688 653 647 648

46 Volume I

Trends in Baseline Emissions

Baseline emissions total 648 in 2018 for utility, cogenerators, boilers and other sources, declining by 50 tons (or about 12 percent) relative to 1999 levels.

Existing SO2 sources operate at maximum availability, thus reductions in the utility sector are due primarily to the addition of controls to existing units with all fully operational by 2006.

Small decline in 2013 emissions is due to planned retirement and small shifts in fuel quality in response to tightening national SO2 markets. 7 GW of low -efficiency existing oil/gas steams units are retired early, and 9 GW are repowered.

47 Volume I

Projected Trend in Emission from Electric Utility Generators

300

350

400

450

1999 2001 2006 2013 2018

Year

MT

on

s

Reductions from Denver Front Range Plants fully operational

Actual CEMS Data

Controls at Mohave units operational Coal plants operate at

maximum availability. Repowering of old Oil/gas unit begins

Scheduled retirement of some coal units

New coal units come on line

48 Volume I

Trends in Emissions from Electric Generating Units (Continued)

New generation and capacity demand is serviced predominantly by new combined cycle units.

New coal plants, new gas cogenerators and new combustion turbines also come into the mix by 2018.

Average out-of-stack SO2 emission rate for new builds in 2018 is at 0.01 lbs/mmbtu.

Emissions from cogenerators and boilers are flat because all new additions are gas-fired.

Emissions from other sources are flat by assumption.

49 Volume I

Baseline Out-of-Stack Average Emission Rate for Electric Utilities

Mohave installs controls

Denver Front Range units are controlled

New Coal units come into mix

50 Volume I

New Capacity and Generation in Baseline by 2018

2.3 GW

16.9 GW

4.9 GW

51 Volume I

Baseline Results(Continued)

This effort was initiated prior to the Inventory Reconciliation effort. As a result, the findings of the later study are not reflected in the economic analysis.

However, 2018 aggregate baseline emissions from the two studies are very close, within 8,000 tons or less than 1 percent.

The differences arise due to the mix of new builds and fuel input.

52 Volume I

Command & Control Scenario Results

53 Volume I

Command and Control Results:Emissions From BART-Eligible

Sources

54 Volume I

Command & Control Scenario - Results

Total emission reductions from BART-eligible sources in 2018 totals 139 thousand tons. The majority of those reductions come from the utility sector.

Emissions prior to 2013 do not change from baseline levels.

The emission impacts (and cost impacts) in 2013 reflect full implementation due to the year mapping approach used in IPM -- 2013 represents multiple year through 2017. Actual year 2013 costs would be lower under the phased in implementation.

55 Volume I

Command & Control Scenario - Results

In addition to reductions from control, in 2013 a small premium for lower sulfur coal induces some Colorado units to switch to higher sulfur coal.

In 2018 the demand for lower sulfur coal from new coal units pushes coal prices back to baseline equilibrium, inducing the Colorado units back to baseline coal.

56 Volume I

Emission Reductions by Source for Command & Control Scenario

2013 2018Electric Utility ICI Boilers Total Electric Utility ICI Boilers Total

BASE 273 7 281 272 7 279 Command & Control 144 1 145 139 1 140 Reduction 129 6 136 132 6 139 WRAP - Reductions 138 13 151

57 Volume I

Command & Control ScenarioIncremental Costs

0

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250

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97

$

GCVTC National

58 Volume I

Command and Control ScenarioSummary of Results

In 2018, annualized costs of the command and control policy to the nine state region is about $209 million dollars, including incremental capital (for generating equipment and controls), FOM, VOM and fuel costs.

At the national level, costs impacts of the policy are lower by about $75 million in 2018. This is because the nation benefits as Title IV reductions are lowered as a result of the reductions that occur in the nine state region.

59 Volume I

Command and Control ScenarioSummary of Results

Increased capital investments required by the Command and Control policy are the major source of increased costs, accounting for over half of the cost impacts.

The emissions impacts (and costs impacts) in 2013 reflect full implementation due to the year mapping approach used in IPM -- 2013 represents multiple years through 2017. Actual year 2013 costs would be lower.

60 Volume I

24

36

41

108

Variable O&M Fixed O&M Fuel Capital

Command & Control ScenarioIncremental Costs

61 Volume I

Incremental Cost in Command & Control Scenario (Continued)

Cost impacts under command and control are capital intensive since the affected sources are required to install controls and do not seek cheaper alternates.

Controls in the GCVTC give rise to cost savings in the rest of the country due to relaxing of the Title IV SO2 emissions reductions required in the rest of the nation.

In addition, prices in the NOx SIP CALL decline and cost savings accrue to the rest of the nation.

62 Volume I

Results of Trading Scenarios

63 Volume I

Trading Cases – Milestones

Emission reductions range from 15 percent to 30 percent across the scenarios.

The EPA scenario is most comparable to the command and control scenarios in terms of total resulting emissions. The minority and MTF scenarios yield lower reductions than the command & control scenario.

2018 Milestones (thousand tons)Base Case Minority Report MTF EPA Environmental

Baseline Emissions 648 648 648 648 648Command & Control Reductions -95 -155 -177 -220Tribal Allocation 20 20 20 20Uncertainty 15 15 15 0Total 588 528 506 448

Reductions from Base Case 60 120 142 200

64 Volume I

Trading Cases Milestones

Milestones for the Trading cases were based on the Baseline Scenarios Emissions, independent estimates of BART reductions, a tribal allocation and the uncertainty adjustment.

Emissions limits equivalent to the milestones were placed on all sources. Trading was allowed among all sources.

65 Volume I

Trading Scenarios – 2018 Emissions Reductions from

Baseline

-180

-160

-140

-120

-100

-80

-60

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-20

0

Th

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Utility Generators Industrial Boilers Cogenerators Other Sources

66 Volume I

Trading Scenarios: Emissions Reductions

Emissions reductions and their distribution across the sectors under the alternative cases are shown above.

In all cases, the utility sector bears the largest share of reduction requirements.

Under the most stringent scenario, an increasing share of reductions come from industrial boilers installing scrubbers and boilers converting to CHP operation.

67 Volume I

Policy Case Results - Emissions in 2018

Emission reductions are primarily borne by the electric utility sector.

Some reductions from ICI boilers, CHP sector and other sectors in the more stringent trading sectors.

68 Volume I

Approximate EmissionsAbatement Cost In 2018

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 50 100 150 200 250

Thousand Tons Removed

1997

$/to

n R

emov

ed

69 Volume I

Compliance Cost

The abatement cost curve shown above is an approximation of the marginal compliance cost at different reduction levels in 2018 based on a static analysis of compliance options for 2018. It is shown for illustrative purposes only.

Marginal abatement cost drives the overall cost of the policies.

Utility scrubbers and some sulfuric acid plants have relatively low compliance costs shown at the left side of the curve.

New combined cycles and CHP options dominate the middle to right portion of the curve.

70 Volume I

Trading Cases – Capacity Changes and Retrofits in

2018Minority MTF EPA Environmental

-2

0

2

4

6

8

10

12

GW

Combined Cycles Turbines Scrubbers

Repowering Retirements Cogenerators

71 Volume I

Trading Cases – Changes in Fossil Generating

Capacity in 2018

(3.0)

(2.5)

(2.0)

(1.5)

(1.0)

(0.5)

-

0.5

1.0

1.5

2.0

GW

Coal

Gas

72 Volume I

-25.0

-20.0

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-10.0

-5.0

0.0

5.0

10.0

15.0

20.0

Th

ou

san

d G

Wh

Trading Cases – Changes in Fossil Fuel Generation

in 2018

73 Volume I

Trading Cases: Compliance Strategy

Scrubbers are the predominant control technology across all the trading scenarios.

New coal generating units becomes less competitive relative to other new builds as a result of the cost of SO2 emissions.

Changes in coal capacity and generation are due to a decline in new coal builds, and a small decline in coal capacity factor.

Reductions in new coal builds creates a need for new base load generating capacity, causing combined cycle builds to increase.

Increased combined cycle builds reduces the demand for generation from new repowered units and cogenerators.

Existing oil/gas steam increase operation to service the small decline in generation from existing coal units.

74 Volume I

Trading Cases –Incremental Cost for GCVTC States

in 2013

-80

-60

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-20

0

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60

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ion

199

7 $

Variable O&M Fixed O&M Fuel Capital

75 Volume I

Trading Cases: Discussion of Results for 2013

In 2013, emission sources anticipate trading policy in 2018 and make adjustments.

Capital investment in peaking units are postponed in anticipation of the need for efficient new base load generation capacity.

Savings in capital investment are offset by increased fuel cost due to the need for generation from less efficient existing oil/gas steam units.

76 Volume I

Trading Cases –Incremental Cost for GCVTC States

in 2018

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-100

0

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500

Mil

lio

n 1

99

7 $

Variable O&M Fixed O&M Fuel Capital

77 Volume I

Trading Cases: Results in 2018

Unlike in command & control scenarios, compliance strategy relies more heavily on fuel adjustment and some capital investment.

Capital investment shifts away to more efficient cleaner generating units capable of servicing base load capacity.

New coal units become less attractive as a result of the cost of emissions.

78 Volume I

Trading Cases – Incremental Cost by Sector

in the GCVTC States in 2018

(Million 1997 $)Utilities Boilers Cogenerators Other Sources Total

Minority 54 2 1 4 61 MTF 114 1 1 7 123 EPA 140 1 1 7 149 Environmental 155 -17 126 10 274

79 Volume I

Policy Case Results - Cost Impacts by Sector in 2018

Except for the environmental scenario, utilities undertake most of the abatement activities and share the largest part of the cost.

Cogenerators bear 45% of the cost in the environmental scenario due to the reductions from ICI boilers that repower to cogenerators.

Control cost from other sources increase under the environmental scenario, but are stable over the MTF and EPA scenarios.

80 Volume I

Conclusions

Compliance costs under a command and control approach are estimated to be $50 - $100 million higher than under a trading system with identical reductions.

Control of existing capacity, most notably scrubbers on utility boilers, is the predominant control strategy in the trading scenario.

Utility sector provides the lowest costs reductions, boilers and other sources provide more expensive reductions.