To: Docket ID EPA-HQ-OAR-2013-0495 

Date: October 23, 2013 Title: Review of Electric Utility Integrated Resource Plans Integrated Resource Plan Overview

Integrated resource plans (IRPs) are a tool that electric utilities use to plan operations and investments over long time horizons. Srequired in the electric utility industry can take several years to build and lasts for decades it is important to develop long-term pl

10 to 20 years and are mandated by public utility commissions (PUCs). In order to develop these plans utilities model demand ove

evaluate a suite of options for meeting that demand (e.g., demand side management programs, investment in transmission infras

Multiple scenarios are typically evaluated that look at variations in fuel prices, demand growth, carbon price and other factors tha

Additionally, IRPs account for existing environmental regulations and the potential for future regulations and, in many cases, provThese plans are generally updated every two or three years per state law. States vary in the specificity of the content they requirsupply, demand and transmission are required, while some require a particular focus on certain areas such as demand-side initiatguidelines for analysis. EPA conducted a review of current IRPs in order to inform the development of the proposed new source performance standard fo

for new affected fossil fuel-fired electric utility generating units. An overview of the results of this review is provided below. 
Summary of IRPs

Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Tennessee Valley Authority (TVA) 

2011(through 2030) 

• Peak: 1.3% 

annual growth (evaluated 0-2%) 

• Energy 

Requirement: 1% annual growth (evaluated 0-1.9%) 

EE and DSM/DRare significant in all cases (3,600MW5,100MW) 

• EE/DSM/DR: 3,600 

- 5,100MW by 2020 

• Renewables: 1,500 

– 2,500MW by 2020 

• NG: 900 – 

9,300MW in 2012 to 2029 

• Nuclear: 1,150 – 

5,900MW in 2013 to 2029 

• Energy Storage: 

850MW in 2020 to 2024 

• Coal: 0 – 900MW 

by 2025 to 2029 

New coal beginning in 2025 with CCS if there is dramatic load growth Significant existing coal capacity idled (2,400MW4,700MW) 

Fuel diversity is 1 of 4 metrics used to evaluate all portfolio results. 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Dominion 2012

(plan through 2027) 

• Peak: 1.8% 

annual growth 

• Energy 

Requirement: 1.9% annual growth 

Future annual increases in peak demand and energy requirement are reduced to 1.6% and 1.7% respectively. 

• DSM: 206-615MW 

by 2027 

• Renewables: 

36MW (onshore wind and solar) 

• NG: 3512MW • Nuclear: 2,828MW 

No new coal planned through 2027. Considered IGCC with CCS and SCPC with CCS, not coal without CCS 

“Preferred Plan” 3.53% more costly than cheapest plan in base case scenario (4.10% on average across all scenarios) due to desire to maintain fuel diversity and price stability. Notes nuclear and renewables included to maintain fuel diversity even though they were higher cost then relying solely on NG. 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Duke Energy Indiana 

2011 (plan through 2031) 

• Summer Peak: 

0.9% annual growth 

• Winter Peak: 

0.6% annual growth 

• Energy 

Requirement: 0.5% annual growth 

EE and DRprograms have increased significantly. Project total reduction in peak demand of 825MW by 2031 

• DR = 452.4MW 

• EE = 372.6MW 

• EE/DR: 825MW 

• Renewables 

(nameplate) 

o Wind: 1400 MW o Solar: 160 MW o Biomass: 71 MW 

• NG 

o CT: 810MW o CC: 650MW 

• Nuclear (maybe 

2025-2030 timeframe) 

Edwardsport IGCC began operations in 2013. No new coal planned through 2031. Notes the difficulty of getting new coal permitted. 

Notes “fuel diversity” important qualitative factor when evaluating scenarios. No data given. 

Black Hills Power 

2011 (plan through 2030) 

• Peak: 1.0% 

annual growth 

• Energy 

Requirement: 1.0% annual growth 

Projected reductions in demand from EE and DSM for 3 years. 

• Year 1: 

737kW 

• Year 2: 

1,107kW 

• Year 3: 

1,450kW 

• NG 

o CT: 36MW o CC: 55MW in 

2014 

• Coal: 100MW in 

2024 

• Market Purchases: 

25– 50MW annually 

Included 100MW of coal (2,627 $/kW in 2010 $s) in 2024 but noted the uncertainty due to potential carbon costs. Assumed CCS not viable in the IRP 20 year horizon. 

Exposure to fuel price volatility was factored into generation mix choices but no quantitative measurements given. 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Ameren MO 2012

(plan through 2032) 

Evaluate 0.5% and 1.0% annual growth. No new generation needed until 2026. 

Scaling back DSM from 2011 projections. 

• Wind coupled with 

CT: 

o Wind: 800 MW 

(nameplate) 

o CT: 346 MW o Total planning 

capacity: 465 MW 

• NG 

o CT: 692MW o CC: 600MW 

• SMR: 480MW 

No new coal planned. 

Specifically identifies SMR as hedge against NG price volatility. 

Delmarva Power & Light Company 

2012(through 2022) 

• Peak: 1.6% 

annual growth 

• Energy 

Requirement: 0.3% annual growth 

Reduce overall demand by 603MW by 2022. 

No new resources needed. May consider 300 MW NGCC unit. 

No new coal planned. 

N/A, no new resources planned 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

City of Pasadena Water and Power Department 

2012 (through 2030) 

• Energy 

Requirement: 0.5% annual growth 

EE goals included in baseline scenario: energy requirement 14.8% lower in 2030 with EE than without EE. 

• DR: 5MW 

• Renewables 

(nameplate) 

o Wind: 3MW o Solar: 19MW o Biomass: 10MW o Landfill Gas: 

10MW 

o Geothermal: 

10MW 

o Feed-in-Tariff: 

10MW 

• NG 

o CC: 67MW 

No new coal planned. Existing coal delivery contract (largest source in their portfolio) will be discontinued (108MW). 

More renewables can help mitigate risks associated with higher NG and CO2compliance costs. Diverse set of renewables preferred. Portfolios were evaluated based on the difference between the high and low LCOE outcomes across a range of market drivers including fuel costs. 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Portland General Electric 

2012(through 2016) 

50 MW/yr growthenergy demand 

• Energy 

Requirement: 2.0% annual growth 

Assume EE offsets half of the load growth expected through 2016 (an additional ~25MW per year). Contracted for minimum of 25 MW of DR by 2016. 

• DR: 25MW by 2016• Renewables: 

100MW (Oregon RPS compliant reournces) 

• NG 

o CC: 300-500MW 

in 2016 

o CT: 100-200MW 

No new coal planned. Boardman Plant ends the use of coal by 2020. 

San Diego Gas and Electric (SDG&E) 

2012 (through 2021) 

Must use CEC forecasts 

• Peak: 1.28% 

annual growth 

• Energy 

Requirement: 1.31% annual growth 

Significant reductions due to EE/DR/DSM/CHP by 2021 

• Peak 

Reduction: 27.49% 

• Energy 

Requirement Reduction: 22.62% 

In need of peaking capacity due to large amount of renewables being added to system 

• EE/DR/DSM/CHP: 

664MW 

• Other Generation 

(e.g., storage or CC): 1742MW 

• Renewables 

o Biomass: 54MW 

o Geothermal: 

19MW 

o Hydro: 3MW o Solar: 102MW 

o Wind: 27MW 

No coal considered. 

CA has “preferred loading order” • cost-effective 

EE and DR 

• renewable 

resources to meet RPS 

• cost-effective 

CHP 

• other 

resources 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Georgia Power 

2013 (through 2032) 

• Energy 

Requirement: 1.2% annual growth (avg) 

DSM:2011 - achieved 130.4 GWh energy savings 2012 - achieved 215 GWh of energy savings Planned DSM program 2014 savings projections: 

• Demand: 

~64MW 

• Energy: 

~290GWh 

Sources recommended after feasibility review (capacity mix redacted): 

• NG 

o CT o CC o CC with CCS 

• Nuclear • Coal with CCS 

Currently have 1,007MW of nuclear under construction to be completed by 2018.

Only include coal with CCS in generation mix feasibility review. Working on IGCC with CCS demonstration plant (Kemper County). Applied to decertify 2,093MW of coal. Switching coal to NG at Yates Units 6 -7 and Gaston Units 1-4. Switching coal to biomass at Mitchell Unit 3. 

Exposure to fuel price volatility was factored into generation mix choices but no quantitative measurements given. 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Idaho Power 2013

(through 2032) 

• Peak: 1.4% 

(55MW) annual growth (avg) 

• Energy 

Requirement: 1.1% annual growth (avg) 

Planned DRCapacity: 

• 150MW by 

2016-2017 (needed prior to completion of transmission line) 

• 370MW by 

2024-2032 

• DR: 370MW by 

2032 

• Transmission Line: 

500kV 300 miles to connect Boardman to Hemingway by 2018 

No coal planned. Coal/CCS were not added in any sensitivity analysis. 

Exposure to fuel price volatility was factored into generation mix choices but no quantitative measurements given. 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Duke Energy Carolinas 

2012(through 2032) 

• Energy 

Requirement: 1.5% annual growth (avg) 

• Peak: 1.7% 

annual growth (avg); 1.9% if EE programs not counted 

Need capacity beginning 2016 (410MWs). 

NCUC requires examination of DSM to meet peak and DSM/EE market potential studies. EE can be used to meet RPS. By 2032 the programs will reduce demand by: 

• EE: 1320MW 

• DSM: 

1206MW (includes 135MW of grid modernization) 

Consider nuclear a viable option, especially regional nuclear (i.e., multiple owners). 

• EE: 1320MW 

• DSM: 1206MW 

(includes 135MW of grid modernization) 

• NG 

o CT: 1750MW 

o CC: 2270MW 

• Nuclear: 2,345MW 

(either 1 plant full ownership or multiple plants partial ownership); mostly 2017-2028 

• Renewables 

o Biomass: 

173MW 

o Solar: 1004MW 

o Wind: 457MW 

No coal considered without CCS. Noted EPA rules for new coal. Considered SCPC and IPCC with CCS but determined no cost-effective CO2 controls for fossil plants. Projects major advancement in CCS over next 20 yrs. Doing R&D on NG with CCS. 

Nuclear included in portfolio in order to maintain fuel diversity. 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Progress Energy Carolinas, Inc. 

2012 (through 2027) 

• Retail 

Demand: 1.2% annual growth; 1.6% if DSM programs not counted 

NCUC requires examination of DSM to meet peak and DSM/EE market potential studies. EE can be used to meet RPS. 

• EE&DSM: 613MW 

• NG 

o CT: 1051MW o CC: 3119MW 

• Nuclear: 552MW 

(regional partial ownership agreements) 

No coal planned. Modeled NGCC costs (capital and O&M) lower than PC costs across all capacity factors. 

Exposure to fuel price volatility was factored into generation mix choices but no quantitative measurements given. 

Indianapolis Power & Light Company 

2011 (through 2031 but focus through 2021) 

• Energy 

requirement before any DSM are expected to grow at 1.34% annually over the next three years, and 1.09% over the next 10 years. 

IURC Rules require by 2021: EE: 337 MW DSM: 119 MW 

• EE: 337MW 

• DSM: 119MW 

(includes DR) 

• NG 

o CC: 600MW 

No coal planned. Identified NGCC as the least-cost supply resource over wind, coal, and nuclear over a range of future horizons. 

Exposure to fuel price volatility was factored into generation mix choices but no quantitative measurements given. 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Indiana Michigan Power Company 

2011 (through 2031) 

• Energy 

Requirement: 0.3% annual growth (avg) 

• Peak: 0.4% 

annual growth (avg) 

Plan to have 423MW of DR/EE to meet state mandates by 2031. Plan to have 258MW of contracted interruptible demand. 

New capacity needed to replace retired coal capacity. 

• DR/EE: 423MW 

• Contracted 

Interruptible: 258MW 

• NG 

o CC: 562MW 

• Renewables 

o Wind: 500MW 

nameplate 

Do not view new nuclear as viable in the AEP System-East Zone from 2012-2031. 

No coal planned in any modeled scenario. Plan to retire 985MW of coal. 

Exposure to fuel price volatility was factored into generation mix choices but no quantitative measurements given. 

Indiana Municipal Power Agency 

2011 (through 2031) 

• Energy 

Requirement: 0.97% annual growth (High: 1.15%, Low: 0.63%) 

• Peak: 0.90% 

annual growth (High: 1.21%, Low: 0.70%) 

Target tosupply 40% of energy forecast with energy efficiency measures, renewable resources and no/low carbon resources by 2020. EE: 200MW by 2031 

New peaking and intermediate capacity needed to replace retiring capacity. 

• EE: 200MW 

• NG 

o CT: 150MW 

• Renewables 

o Wind: 200MW 

nameplate 

Exploring substituting wind with other renewables. 

No coal planned in any modeled scenario. 

Exposure to fuel price volatility was factored into generation mix choices but no quantitative measurements given. 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Northern Indiana Public Service Company 

2011 (through 2032) 

• Energy 

Requirement: 0.6% annual growth 

• Peak: 0.6% 

annual growth 

Focus is on interruptible capacity. 

• DSM: 50MW 

(interruptible capacity) 

• NG 

o CC: 898MW 

(2023 and 2029) 

No coal planned. The most preferred resources in modeled scenarios were NG CC and CT. 

Exposure to fuel price volatility was factored into generation mix choices but no quantitative measurements given. 

Vectren Corporation: Southern Indiana Gas and Electric Company (Vectren South) 

2011 (through 2031) 

• Energy 

Requirement: -0.17% annual growth 

• Peak: 0.21% 

annual growth 

Statewide electric savings goals for utilities:  0.3% of average sales in 2010 and ramping up to 2% per year in 2019. Incremental energy savings of 0.5% per year beginning in 2020. 

No additional generation needed. In high load growth scenarios additional demand was met with NGCC. 

No new generation planned. 

No new generation planned. 
Utility Year Future Demand Energy Efficiency New Resources to 

Meet Demand 

Future Coal and CCS 

Fuel Diversity Choices 

Wabash Valley Power Association, Inc. 

2011 (through 2030) 

• Energy 

Requirement: 0.7% annual growth (including PassThroughs) 

• Peak: 0.6% 

annual growth (including PassThroughs) 

Do not serve any retail customers directly. Customers served by the Association’s members. Have EE and DR committees that recommend EE and DR programs to members. 

• EE: specific 

capacity was not included but EE was referenced as a planned source. 

• NG 

o CT: 150MW 

(2022) 

o CC: 200MW in 

2018 and 600MW in 2027 

• Renewables: 

specific capacity was not included but renewables were referenced as a planned source. 

No coal planned. Identified NGCC as the least-cost supply resource over coal fired units for baseload capacity. 

Exposure to fuel price volatility was factored into generation mix choices but no quantitative measurements given. 

Great River’s Energy 

2011 (through 2027) 

• Energy 

Requirement: 1.7% annual growth 

• Peak: 1.6% 

annual growth 

EE is a focus of the “preferred plan” but no specific capacities are given. 

Addition ofrenewables needed in 2024 to meet the MN Renewable Energy Standard. No other capacity needed. • Renewables 

o Wind: 600MW 

nameplate by 2026 

No coal planned. No nonrenewable capacity is needed in the planning period. 

Exposure to fuel price volatility was factored into generation mix choices but no quantitative measurements given. 
IRP Titles and Links

Utility Document Title Web Link to IRPTennessee Valley Authority (TVA) 

Integrated Resource Plan: TVA’s Environmental & Energy Future, March 2011 

http://www.tva.gov/environment/reports/irp/pdf/Final_IR

Dominion Dominion North Carolina Power's and 

Dominion Virginia Power's Report of Its Integrated Resource Plan, August 2012 

https://www.dom.com/about/pdf/irp/irp-083112.pdf

Duke Energy Indiana The Duke Energy Indiana 2011 

Integrated Resource Plan, November 2011 

http://www.duke-energy.com/pdfs/2011_Indiana_IRP_Pla

Black Hills Power 2011-2030 Integrated Resource Plan For

Black Hills Power, 2011 

http://psc.state.wy.us/pscdocs/dwnload/BHP%20EFP%20I011-2030%20IRP.pdf 

Ameren MO Integrated Resource Plan Update, Spring 

2012 

http://www.ameren.com/sites/aue/Environment/RenewanualUpdate.pdf 

Delmarva Power & Light Company 

Delmarva Power & Light Company 2012 Integrated Resource Plan, December 2012 

www.delmarva.com/_res/documents/2012IntegratedReso

City of Pasadena Water and Power Department 

Integrated Resource Plan Update, February 2012 

http://cityofpasadena.net/waterandpower/IRP/

Portland General Electric 

2012 Integrated Resource Plan Update, November 2012 

http://www.portlandgeneral.com/our_company/energy_ss/irp_nov2012.pdf 

San Diego Gas and Electric (SDG&E) 

San Diego Gas and Electric Company 2012 Long-Term Procurement Plan, 2012 

http://www.cpuc.ca.gov/NR/rdonlyres/6072C3B5-755A-4E947DE06FE8FC/0/SDGE2010LTPP1AB57BundledProcureme

Georgia Power Georgia Power Company’s 2013 

Integrated Resource Plan and Application for Decertification of Plant Branch Units 3 and 4, Plant McManus Units 1 and 2, Plant Kraft Units 1-4, Plant Yates Units 1-5, Plant Boulevard Units 2 and 3, and Plant Bowen Unit 6, 2013 

http://www.psc.state.ga.us/factsv2/Document.aspx?docu

Idaho Power 2013 Integrated Resource Plan, June 

2013 

http://www.idahopower.com/AboutUs/PlanningForFuture

Duke Energy Carolinas Duke Energy Carolinas’ 2012 Integrated 

Resource Plan and 2012 REPS Compliance Plan, September 2012 

http://ncuc.commerce.state.nc.us/cgi- bin/webview/senddoc.pgm?dispfmt=&itype=Q&authorizatparm3=000139578 
Progress Energy 

Carolinas, Inc. 

Progress Energy Carolinas, Inc.’s Integrated Resource Plan, September 2012 

http://ncuc.commerce.state.nc.us/cgi- bin/webview/senddoc.pgm?dispfmt=&itype=Q&authorizat&parm3=000139578 

Indianapolis Power & Light Company 

Indianapolis Power & Light Company2011 Integrated Resource Plan 

http://www.in.gov/iurc/files/IPL_2011_IRP_12-12-11.pdf

Indiana Michigan Power Company 

Indiana Michigan Power Company Integrated Resource Planning Report, November 2011 

http://www.in.gov/iurc/files/IRP_2011_Indiana_Michigan_

Indiana Municipal Power Agency 

Indiana Municipal Power Agency 2011 Integrated Resource Plan, November 2011 

http://www.in.gov/iurc/files/IRP_2011_Indiana_Municipa

Northern Indiana Public Service Company 

NIPSCO 2011 Integrated Resource Plan, November 2011 

http://www.in.gov/iurc/files/NIPSCO_IRP_Revised-Redacte

Vectren Corporation: Southern Indiana Gas and Electric Company (Vectren South) 

Vectren 2011 Integrated Resource Plan, November 2011 

http://www.in.gov/iurc/files/IRP_2011_Vectren.pdf

Wabash Valley PowerAssociation, Inc. 

Wabash Valley Power Association, Inc. 2011 Integrated Resource Plan, November 2011 

http://www.in.gov/iurc/files/IRP_2011_Wabash_Valley_Po

Great River’s Energy Great River Energy

Resource Plan 2013-2027, November 2012 

http://www.greatriverenergy.com/makingelectricity/resou
Abbreviations

AEO – Annual Energy Outlook AEP – American Electric Power CC – Combined cycle CCS – Carbon capture and sequestration CHP – Combined heat and power CT – Combustion turbine DR – Demand response DSM – Demand side management EE – Energy efficiency EIA – Energy Information Administration EPA – Environmental Protection Agency IGCC – Integrated gasification combined cycle IRP – Integrated resource plan IURC – Indiana Utility Regulatory Commission kV – Kilovolts kW – Kilowatt kWh – Kilowatt hours LCOE – Levelized cost of electricity MMBtu – Million British thermal units MW – Megawatts 
MWh – Megawatt hours 

NCUC – North Carolina Utility Commission NG – Natural gas RPS – Renewable portfolio standards SMR – Small modular reactor