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

Date: July 31, 2015 

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. 

Since much of the infrastructure required in the electric utility industry can take several years to build and lasts for decades, it is 

important to develop long-term plans. These plans typically cover 10 to 20 years and are mandated by state public utility 

commissions (PUCs). To develop these plans, utilities model demand over a specified time period and evaluate a suite of options 

for meeting that demand (e.g., demand side management programs, investment in transmission infrastructure or new capacity). 

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

that could impact the system. Additionally, IRPs account for existing environmental regulations and the potential for future 

regulations and, in many cases, provide plans for compliance. These plans are generally updated every two or three years per 

state law. States vary in the specificity of the content they require. Usually an overview of supply, demand and transmission are 

required, while some require a particular focus on certain areas such as demand-side initiatives. Some states provide guidelines 

for analysis. 

EPA conducted a review of current IRPs to inform the development of the new source performance standard for emissions of 

carbon dioxide for existing affected fossil fuel-fired electric utility generating units. An overview of the results is provided below. 

The EPA reviewed publicly available IRPs from a range of companies (e.g., varying in size, location, current fuel mix), and these 

plans are generally consistent with both EIA and EPA modeling projections. These IRPs indicate that companies are focused on 

demand-side management programs to lower future electricity demand and are mostly reliant on a mix of new natural gas-fired 

generation and renewable energy to meet increased load demand and to replace retired generation capacity. Notwithstanding 

the clear trend towards natural gas-fired generation and renewables, many of the IRPs highlight the value of fuel diversity and 

include options to diversify new generation capacity beyond natural gas and renewable energy. Several IRPs indicate that 

companies are considering new nuclear generation, including either traditional nuclear power plants or small modular reactors, 

and a smaller number are considering new coal-fired generation capacity with and without CCS technology. 
Summary of IRPs 

Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Tennessee Valley Authority (TVA) 

2011 (through 2030) 

Federal • Peak: 1.3% annual 

growth (evaluated 0-2%) 

• Energy 

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

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

EE

• EE/DSM/DR: 3,600 - 5,100 MW by 

2020 

RE 

• Renewables: 1,500 – 2,500 MW by 

2020 

Nuclear 

• Nuclear: 1,150 – 5,900 MW in 2013 

to 2029 

Other 

• Energy Storage: 850 MW in 2020 to 

2024 

• Coal: 0 – 900 MW by 2025 to 2029 

• NG: 900 – 9,300 MW in 2012 to 2029 

New with dramSigncapa4,70
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Dominion 2015- 2029 

Planning Period 

IOU • Peak: 1.4% annual 

growth 

• Energy 

Requirement: 1.3% annual growth 

7% increase in demand reductions from DSM programs between 2013 Plan to 2014 Plan. 583 MW total capacity reduction by 2029. 3% decrease in energy reductions for DSM programs between 2013 Plan and 2014 Plan. 3,063 GWh reduction in 2014 Plan. 

RE

• Renewables: 818 MW ( wind and 

solar) 

Nuclear 

• 1,453 MW by 2028 Other 

• NG: 3,132 MW (total capacity of two 

additional CCs) and 914 MW (total capacity of two additional banks of CTs) by 2029 (Base Plan) 

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Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Duke Energy Indiana 

2013 (plan through 2032) 

IOU • Summer Peak: 

0.9% annual growth 

• Winter Peak: -0.2% 

annual growth 

• Net Energy for 

Load: 0.6% 

• CAGR for Energy 

and Peak Load Demands: 0.95% from 2013-2033 

Base Case projections: • EE program load 

impact of 641.1 MW by 2032 

• DR program 

load impact of 586.7 MW by 2032 

EE

• EE/DR: 1,227.8 MW RE • Renewables (nameplate) 

o 600 MW added by 2027 o Additional 1,450 MW added in 

early 2030s due to increasing price of CO2. 

o Solar: 330 MW by 2026 o Biomass: 14 MW by 2027 o

Nuclear 

• 280 MW in 2031 

Other 

• NG 

o CT: 800 MW by 2025 o CC: 680 MW by 2030 o Wabash River 6 NG Conversion 

(318 MW) in 2016 

Capacity Sources in Reference Scenario: Coal – 59% Gas – 24% IGCC – 7% Renewable/EE/DR – 11% 

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Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Black Hills Power 

2011 (plan through 2030) 

IOU • 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 

Other

• NG 

o CT: 36 MW o CC: 55 MW in 2014 

• Coal: 100 MW in 2024 

• Market Purchases: 25 – 50 MW 

annually 

Inclu(2,6202uncpoteAssuthe 

Ameren MO 2014 

(plan through 2034) 

IOU Expect energy 

consumption to increase by 12% and peak demand to increase by 8% over 20 year timeframe. Retail Sales: 0.59% annual increase Retail Peak Demand: 0.40% annual increase 

Demand Side: Plans to spend $148 million from 2016-2018 to achieve 426 GWH of energy savings and 114 MW of peak demand savings. 

REAdding 400 MW of wind power, 45 MW of solar, 20 MW of hydroelectric and 5 MW of landfill gas Other 

• NG 

o CC: 600 MW by 2034 o Conversion of Units 1&2 at 

Meramec Energy Center to NG in 2016 

Additional CC and Nuclear options presented in contingency plan. 

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Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Delmarva Power & Light Company 

2014 (through 2024) 

IOU Total Peak Demand:

• 2015: 1,957 MW • 2020: 2,127 MW • 2024: 2,220 MW 

Total DSM Savings: 2015: 344 GWh 2020: 591 GWh 2024: 801 GWh 

REThe 2014 DE Solar Renewable Energy Credits (SREC) Procurement Program secured SRECs from 385 projects that represent 5.5 MW of solar facilities. 

No n

City of Pasadena Water and Power Department 

2012 (through 2030) 

Muni • Energy 

Requirement: 0.5% annual growth 

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

EE

• DR: 5 MW RE • Renewables (nameplate) 

o Wind: 3 MW o Solar: 19 MW o Biomass: 10 MW o Landfill Gas: 10 MW o Geothermal: 10 MW o Feed-in-Tariff: 10 MW 

Other 

• NG 

o CC: 67 MW 

No nExisconttheidisc
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Portland General Electric 

2013 (through 2033) 

IOU Annual average 

demand growth rate of 1.3%. Peak demand grows 1.0% in winter and 1.3% in summer Load growth averages 1.56% per year between 2014 and 2033. 

Additional 23 MW of Dispatchable Standby Generation (DSG) by 2017. 158 MW worth of demand-side actions by 2017. DR: additional 25 MW by 2017. Reference Case—Total Cumulative EE by 2032 is 361 MWa at the meter. All Deployable EE case—479 MWa by 2032. 

OtherNo major new resource actions are warranted in current IRP Action Plan horizon. Future IRP will identify actions to be taken in intermediate term. New resources under construction will provide approximately 462 MWa energy capability annually, as well as 784 MW of peaking capacity. These include Port Westward 2 flexible gas plant, Carty base load gas plant, and Tucannon River wind farm. 

No nBoause 

San Diego Gas and Electric (SDG&E) 

2014 (through 2023) 

IOU Must use CEC 

forecasts 

• 2014 Peak Load: 

4850 MW 

• 2024 Peak Load: 

5357 MW 

2015 EE: additional 60 MW 2015 DR: 90 MW 2024 EE: additional 567 MW 2024 DR: 95 MW 

OtherD.14-03-004 directs SDG&E to procure a minimum of 500 MW and up to 800 MW of new resources by 2022. 

No c
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Georgia Power 

2013 (through 2032) 

IOU • 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. 

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Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Idaho Power 

2013 (through 2032) 

IOU • Peak: 1.4% 

(55MW) annual growth (avg) 

• Energy 

Requirement: 1.1% annual growth (avg) 

Planned DR Capacity: 

• 150 MW by 

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

• 370 MW by 

2024-2032 

EE

• DR: 370 MW by 2032 Other • Transmission Line: 500 kV 300 miles 

to connect Boardman to Hemingway by 2018 

No cCoain a
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Duke Energy Carolinas 

2014 (through 2029) 

IOU • Energy 

Requirement: 1.5% annual growth (avg); 1.0% if EE programs counted 

• Peak: 1.4% annual 

growth (avg 

NCUC requires examination of DSM to meet peak and DSM/EE market potential studies. EE can be used to meet RPS. DEC Projected EE and DSM Energy and Capacity Savings: 2015 

• 664,000 

MWh energy 

• 1,173 MW 

capacity 

2029 

• 7,668,000 

MWh energy 

• 2,475 MW 

capacity 

RE• Renewables 

o Biomass/Hydro: 324 MW by 

2029 

o Solar: 1,670 MW by 2029 

o Wind: 150 MW by 2029 

• Total of ~1,248 MW (nameplate) 

additional renewables by 2021, and ~2,144 MW by 2029 

Nuclear 

Commercial operation of the first unit at the Lee Nuclear Station by 2024. Consider nuclear a viable option, especially regional nuclear (i.e., multiple owners).Other • NG 

o CT: consider 792 MW in 2028 

o CC: consider 866 MW in 2020 

o 770 MW NG CC plant available 

by 2017 

o Convert 170 MW Lee Steam Unit 

3 from coal to natural gas in 2015 

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cont
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Progress Energy Carolinas, Inc. 

2012 (through 2027) 

IOU (Merged with Duke) 

• 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

• EE&DSM: 613 MW 

Nuclear 

• Nuclear: 552 MW (regional partial 

ownership agreements) 

Other 

• NG 

o CT: 1,051 MW o CC: 3,119 MW 

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Indianapolis Power & Light Company 

2014 (through 2034 but also includes scenarios through 2024) 

IOU • Base Case with net 

DSM impacts: 

• 0.3% CAGR peak 

load growth 

• 3131 MW net 

internal demand by 2034 

Indiana General Assembly passed legislation eliminating previously established IURC target levels of EE DSM. Company will identify cost effective DSM strategy. 

EE

• EE: 379,204 kW savings by 2017 • DSM: 182,703 kW savings by 2017 

• Renewables: 300 MW wind and 100 

MW solar by 2024 

Other 

• NG 

o CC: 644-685 MW plant under 

construction 

Base Case expansion plan includes no additional generation extending out until 2031. 

No cPlancoaPlan
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Indiana Michigan Power Company 

2013 (through 2033) 

IOU • Energy 

Requirement: 0.2% annual growth (avg) 

• Summer Peak: 

0.3% annual growth (avg) 

• Winter Peak: 0.1% 

annual growth (avg) 

DR: 296 MW reduction in peak capacity requirements EE: 2,586 GWh reduction in energy requirements by 2033 Obligation to PJM of 296 MW Interruptible Demand Response by 2033. 

New capacity needed to replace retired coal capacity. EE 

• DR: 296 MW 

RE

• Renewables 

o Wind: 200 MW by end of 2014 

and 100 MW by 2026 

o Solar: 50 MW (nameplate) added 

each year beginning in 2020 

o Solar from customers: 10 MW 

(nameplate) in 2016, ~150 MW (nameplate) by 2033 

Nuclear Do not view new nuclear as financially practical. Coal and nuclear baseload options were not included in plan. 

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Indiana Municipal Power Agency 

2013 (through 2033) 

Muni • Energy 

Requirement: 1.0% annual growth 

• Peak: 1.0% annual 

growth 

High EE target 10% reduction in demand and energy requirements by 2020. Early indicators suggest this may not be realistic. Base EE plan targets 2.5% cumulative savings by 2020. 

New peaking and intermediate capacity needed to replace retiring capacity. RE 

• Renewables 

o Solar: 21 MW by 2020 

Other 

• NG 

o CT: 185 MW by 2016 o CC: 200 MW by 2023 

No cmod
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Northern Indiana Public Service Company 

2014 (through 2035) 

IOU • Energy 

Consumption : less than 0.5% annual growth over next 20 years 

• Peak: 3,208 MW in 

2014 to 3,574 MW by 2035 

Variety of DSM programs available. 2015 Projected Savings: 119,603 MWh DSM: 126.5 average peak reduction over planning horizon 

RE

• Included renewables in one model, 

but added no value to portfolio and led to increased cost. 

Other • Long term need includes one CCGT in 

2023 and one CCGT in 2035, 660 MW each. 

• Retiring 949 MW of coal by 2035. 

No cCoaevaopti
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

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

2014 (through 2034) 

IOU • Energy 

Requirement: --0.2% CAGR over planning period 

• Peak: -0.1% CAGR 

over planning period 

Savings target of 1% on eligible customer sales for 2015-2019. Incremental energy savings of 0.5% per year beginning in 2020. DSM energy efficiency programs available to all customer classes. 

No additional generation needed.In high load growth scenarios additional demand was met with CCGT and solar PV. Will reevaluate economic viability of solar generation in future IRPs 

No nplan
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Wabash Valley Power Association, Inc. 

2013 (through 2032) 

Coop • Energy 

Requirement: 0.7% annual growth (net of pass-throughs), or approximately 53 GWh/yr 

• Peak: 0.4% annual 

growth (including pass-throughs), reaching 1,926 MW by 2032 

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. Direct Load Control program (“PowerShift”) goal is 55 MW of controllable load by 2020. 

• First forecasts a need for additional 

capacity in 2017. Analysis does not add baseload or intermediate resources until 2027 when power purchase agreements expire. 

EE: • Specific capacity was not included 

but EE was referenced as a planned source. 

• DR: Additional 18 MW in 2014-2016 • 92 MW of planned additions by 

2032 in High Economic Growth scenario and Low Economic Growth scenario 

RE • Landfill: 4 MW gas power planned 

for purchase for 2014, as well as 3.2 MW gas-fired internal combustion engines in 2014 and 2016. 

• Solar: 20 KW purchase planned for 

2014 

• Wind: Plans to purchase 10 MW in 

2015. 

•Other• NG 

o Evaluated cost of CT and CC, but 

not included in short term plan. 

No c
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Great River Energy 

2014 (through 2029) 

Coop • Energy 

Requirement: 1.3% annual growth 

• Peak: 1.0% annual 

growth 

EE is a focus of the “preferred plan” but no specific capacities are given. EE contributes to 1.5% of total retail energy savings in each year of planning period. 

Addition of renewables needed in 2026 to meet the MN Renewable Energy Standard. No other capacity needed. RE 

o Wind: 600MW nameplate by 2029 o Hydro: 200 MW by 2020 o Exploring possibility of solar 

No cNo nis neperiPlan largby 2
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

AEP East 2011 IOU • Energy Sales: 

0.24% CAGR 

• Peak Load Growth: 

0.71% CAGR 

• 1,213 MW 

incremental peak demand reduction by 2014 

• Passive demand 

response (DR): 868 MW by 2020 

• Active DR: 600 

MW by 2020 

No new baseload capacity required within planning period. Assumes 540 MW Dresden CC facility comes on line in 2013. Also includes assumed performance of Donald C. Cook Nuclear Plant Extended Power Update (EPU) within 2014-2018 time period. Purchase power agreements for renewable energy—mostly wind. Natural gas-fired peaking and intermediate capacity added shortly after 2020 to meet future load obligations. 

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legisPlan potearoudue regurule
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

PacifiCorp 2013- 2022 IOU • Peak: 1.2% annual growth 

• 1.1% annual 

energy load growth 

• 1,593 MW of 

DSM EE Installed Capacity 

• 193 MW of DSM 

load control 

• System capacity deficit of 2,308 MW 

by 2022 

RE 

• Wind: 650 MW between 2024-

2025 

• Solar: 303 MW utility + 

distributed 

Other 

• 362 MW peaking gas installed 

capacity by 2032

• 2,813 MW CCTT by 2032

No cReti201
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Colorado Springs Utilities 

2012- 2031 Muni • Energy requirements: 

1.9% increase by 2031 

• System peak: 2.1% 

increase by 2031 

Analyzed various DSM scenarios High: 10% energy reduction by 2020 Medium: 6% energy reduction by 2020 Low: 4% energy reduction by 2020 DSM could decrease load requirement by 82 MW by 2030. 

• 35 MW deficit by 2030 

Scenario 1—Energy Vision 2020 

RE • Wind: 100 MW in 2013 • Biogas: 0.6 MW in 2013 • Biomass: 20 MW in 2024 • Hydro: 13.2 MW by 2026 • Geothermal: 10 MW in 2023 • Solar: 40 MW by 2031 

Scenario 2—Current Business 

RE • Wind: 50 MW in 2013 • Biogas: 0.6 MW in 2013 • Hydro: 10.2 by 2029 • Geothermal: 10 MW in 2018 Other 

• LM 6000 Gas CT: 39 MW in 2030• Nixon Plant Upgrade: 15 MW in 

2018

No cAdvwith inclu
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Arizona Public Service Company (APS) 

2014- 2029 IOU— subsidi

ary of Pinnacle West 

• Peak Load Growth: 

3% annual increase over planning period 

EE: 1,447 MWDR: 275 MW Distributed Energy: 261 MW (722 MW Nameplate capacity) 

About 6,600 MW of additional resources needed by 2029 RE Total: 425 MW Other NG Total: 4,205 MW 

No c

Tucson Electric Power (TEP) 

2014- 2028 IOU • Peak Demand: 1.0%-1.5% annual 

increase 

EE: reduce peak demand by 312 MW by 2028 DR: reduce peak demand by 50 MW by 2028 

RE• Total: 529 MW utility-scale 

nameplate capacity by 2028 (solar, wind, and biogas)

• Solar: 78 MW rooftop solar by 2015Other • CC: 413 MW in 2015 • Other NG: 820 MW from 2019-2026 

(550 MW CC and 270 MW peaking resources) 

• Transmission upgrades and 

improved storage technologies: 50 MW battery storage by 2028 

Plan capanext 
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

UNS Electric, Inc. 

2014- 2028 UniSou rce—

IOU 

• 2014 Reference 

Case projects peak demand staying relatively flat for planning period 

EE: reduce peak demand by 59 MW by 2028 DR: reduce peak demand by 14 MW by 2028 

RE• Total: 119 MW utility-scale 

nameplate capacity by 2028 (Solar and wind) 

• Solar: 56 MW distributed generation 

by 2028 

Other • CC: 138 MW in 2015 • CT: 111 MW by 2019 • 408 MW nameplate capacity in NG 

resources by 2028 

• Transmission upgrades and 

improved storage technologies: 1.85 MW battery storage by 2028 

No a

Arizona Electric Power Cooperative 

Coop • Total annual peak 

demand forecast of 62.5 MW through 2028 for Duncan Valley Electric Cooperative, Inc. (DVEC) and Graham County Electric Cooperative, Inc. (GCEC) 

• No demand growth expected 2014-

2021. No indication of new resource capacity in planning horizon. 
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Puget Sound Energy 

2013- 2033 IOU • Additional 12 MW of peak hour 

capacity by 2017. Grows to 100 MW by 2020. 

Demand-Side resources: 1,007 MW cumulative nameplate capacity by 2033 

Retiring up to 2,000 MW by 2020, creating a need for new resources. RE • Wind: 600 MW by 2033Other • Peakers (CT in MW): 2,212 by 2033 • Transmission renewals: 1,567 MW 

by 2033 

• Gas storage: 150 MDth/day 

EvalviabgendiffescencontColscycl

Seattle City Light 

2014- 2034 Muni • Demand growth: 0.5% annual 20-

year avg. 

Conservation Potential Assessment: 118.4 MW by 2023 and 250.6 MW by 2033 

Other• Hydro efficiencies expected to 

increase generating capability by ~40 MW by 2017 

No c
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Montana- Dakota Utilities 

2013- 2032 IOU • Summer Peak demand: 1.6% 

average annual growth rate (prior to DR programs) through 2032, but 2.4% increase annually through 2018 

• Energy 

Requirements: 2.0% annual increase through planning period, but 3.2% annual increase through 2018 

DR: 10 MW program by 2015 Will continue to promote the interruptible rates to reach 23 MW total. 

Committed to:

• 88 MW Simple cycle CT at 

Heskett by 2015 

• Air Quality Control System at Big 

Stone plant by 2015 

Potential Resource Options: RE 

• Wind: 50 to 100 MW 

Other 

• 36.6 MW internal combustion 

engines by 2015 

• CC: 200 MW in 2020 

CoaanaoptiNo c

Xcel Energy Upper Midwest 

2016- 2030 IOU • Peak demand: 0.4% annual 

increase 

• Forecasted load: 

10,251 MW by 2030 

DR: additional 76 MW through 2030 DSM goal: 1.5% of retail sales 

No new capacity needs for the first five years of the plan. By 2030, 2,862 MW deficit. RE • Wind: 1,800 MW • Solar (utility-scale): 1,887 MW • Small-scale solar: 500 MW by 2030 Other 

• NG Peaking Resources: 1,750 

MW

ConUnitthe No a
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Southwestern Electric Power Company 

2016- 2035 IOU • Internal energy requirements: 

0.2% annual decrease through 2035 

• Summer peak 

demand: 0.2% annual decrease through 2035 

• Winter peak 

demand: 0.1% annual decrease through 2035 

• Demand decrease 

is due to expiring contracts—if these are omitted, demand is expected to increase by 0.7% (internal energy), 0.7% (summer peak demand), and 1.1% (winter peak demand), annually 

Reduce energy requirements by 1,121 GWh (5% of projected energy needs) by 2035 Reduce capacity requirements by 410 MW by 2035 

RE

• Wind: 1,700 MW • Solar (utility scale): 800 MW • Solar (distributed): 50 MW 

Other

• Retires 722 MW of older gas-steam 

units beginning in 2016 through 2030. 

• Adds 207 MW of natural gas peaking 

resources over the 20-year planning period 

MaiWelCreeaddenethe Dole

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Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Duke Energy Ohio 

2013- 2023 IOU • Net energy: 1.7% annual increase 

from 2013 (~21.5 million MWh) to 2023 (~25.5 million MWh) before EE, 0.4% increase after EE 

• Summary peak 

demand: 1.7% annual increase from 2013 (~4,250 MW) to 2023 (~4,500 MW) before EE, .5% increase after 

• Winter peak 

demand: 1.6% annual increase from 2013 (~3,500 MW) to 2023 (~3,750 MW) before EE, 0.8% after 

Cumulative savings of 3.5 million MWh through 2023. Reduced summer peak demand through Conservation Program Load Impacts (595 MW) and DSM impacts (138 MW) in 2023 (733 MW total). 

Few specifics on the fuel/plant types to meet new demand. Duke does employ a competitive bidding process to secure competitive retail supply in advance. EE Plans to meet Energy Efficiency obligations under existing law through conservation and demand-side management programs. 

AccecertgenFutumusNSPhav
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

PG&E 2015- 2024 IOU • Firm peak-hour August demand 

increases from 21,186 MW in 2015 to 21,724 MW in 2024 (CPUC-mandated scenario) 

• Firm peak-hour 

August demand decreases from 20,153 MW in 2015 to 18,091 MW in 2024 (PG&E alternative scenario) 

• Energy demand 

increase of 85,494 GWh in 2015 to 77,968 GWh in 2024 (CPUCmandated scenario) 

• Energy demand 

increase of 85,494 GWh in 2015 to 66,855 GWh in 2024 (PG&E alternative scenario) 

DR Program of 287 MW in 2024 of base interruptible power, 82 MW of AC Cycling residential power, and 1 MW of AC Cycling nonresidential power 

CPUC ScenarioRE Portion of contracted renewable energy increases from 2,728 MW (17,791 GWh) in 2015 to 3,544 MW (14,656 GWh) in 2024 (other portion of RE was redacted in this version). Generic renewable energy increases from 0 MW (0 GWh) in 2015, increasing to 1,304 MW (8,691 GWh) in 2024. Other Energy storage resources increase from 0 MW (0 GWh) in 2015 to 403 MW (124 GWh) in 2024. PG&E ScenarioRE Portion of contracted renewable energy increases from 2,728 MW (17,791 GWh) in 2015 to 3,183 MW (14,656 GWh) in 2024 (other portion of RE was redacted in this version). Generic renewable energy increases from 0 MW (0 GWh) in 2015, increasing to 114 MW (1,532 GWh) in 2024. Other Energy storage resources increase from 0 MW (0 GWh) in 2015 to 403 MW (124 GWh) in 2024. 

Fossprojcon(althgenwas repo
Utility Year Utility 

Ownership Type 

Future Demand Energy Efficiency New Resources to Meet Demand Futu

Northwest Power and Conservation Council 

2010- 2030 Region al 

Advisory Council 

• Electricity load: 

1.4% annual growth (~335 MW per year) 

• Summer peak: 

1.7% annual growth 

• Winter peak: 1% 

annual growth 

Stringent enough energy efficiency and conservation could meet 85% of load growth for duration of planning period. Energy efficiency is NWPCC’s first priority resource. Council target is 1,200 average MW by 2014, and 5,900 average MW by 2030. 

EECouncil target is 1,200 average MW by 2014, and 5,900 average MW by 2030. RE 

• Resources developed in 

response to state RPS mandates will account for 1,450 MW of energy on average (4,500 MW installed capacity) 

 Options modeled include: 

• 4,800 MW of wind by 2030 • 424 MW geothermal by 2030 • 830 MW biomass by 2030 

Other 

• Mention that additional natural 

gas generation will likely be necessary 

• Considered 4,400 MW nuclear 

by 2030 

No nSomconThe utiliCCS 
Utility Document Title Web Link to IRP

Tennessee Valley Authority (TVA) Integrated Resource Plan 2015 Draft Report http://www.tva.com/environment/repDominion Dominion North Carolina Power's and Dominion 

Virginia Power's Report of Its Integrated Resource Plan, August 2014 

https://www.dom.com/library/domco

Duke Energy Indiana The Duke Energy Indiana 2013 Integrated Resource 

Plan, November 2013 

http://www.in.gov/iurc/files/2013_Duhttp://www.in.gov/iurc/files/2013_Du

Black Hills Power 2011-2030 Integrated Resource Plan For Black Hills 

Power, 2011 

http://psc.state.wy.us/pscdocs/dwnloa

Ameren MO Integrated Resource Plan Update, October 2014 https://www.ameren.com/missouri/enDelmarva Power & Light Company 

Delmarva Power & Light Company 2014 Integrated Resource Plan, December 2014 

https://www.delmarva.com/uploaded

City of Pasadena Water and Power Department 

Integrated Resource Plan Update, February 2012 http://ww2.cityofpasadena.net/water

Portland General Electric 2013 Integrated Resource Plan Update https://www.portlandgeneral.com/ouSan Diego Gas and Electric (SDG&E) 

San Diego Gas and Electric Company Draft 2014 Long- Term Procurement Plan, 2014 https://www.sdge.com/sites/default/f

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/Do

Idaho Power 2013 Integrated Resource Plan, June 2013 https://www.idahopower.com/AboutUDuke Energy Carolinas Duke Energy Carolinas’ 2014 Integrated Resource Plan, 

September 2014 

http://starw1.ncuc.net/NCUC/ViewFile

Progress Energy Carolinas, Inc. Progress Energy Carolinas, Inc.’s Integrated Resource 

Plan, November 2012 

http://www.energy.sc.gov/files/view/P

Indianapolis Power & Light Company 

Indianapolis Power & Light Company2014 Integrated Resource Plan 

http://www.in.gov/iurc/files/IPL_2014

Indiana Michigan Power Company 

Indiana Michigan Power Company Integrated Resource Planning Report, November 2013 

http://www.in.gov/iurc/files/2013_Ind

Indiana Municipal Power Agency Indiana Municipal Power Agency 2013 Integrated 

Resource Plan, November 2013 

http://www.in.gov/iurc/files/2013_Ind

Northern Indiana Public Service Company 

NIPSCO 2014 Integrated Resource Plan, November 2014 

http://www.in.gov/iurc/files/NIPSCO_
Vectren Corporation: Southern 

Indiana Gas and Electric Company (Vectren South) 

Vectren 2014 Integrated Resource Plan, November 2014 

http://www.in.gov/iurc/files/SIGECO-V

Wabash Valley Power Association, Inc. 

Wabash Valley Power Association, Inc. 2013 Integrated Resource Plan, November 2013 

http://www.in.gov/iurc/files/2013_Wa

Great River Energy Great River Energy

Resource Plan 2015-2029, October 2014 

http://www.greatriverenergy.com/ma

PacifiCorp 2013 Integrated Resource Plan Volumes 1 and 2 http://www.pacificorp.com/content/d

p-2013IRP_Vol1-Main_4-30-13.pdfhttp://www.pacificorp.com/content/dp-2013IRP_Vol2-Appendices_4-30-13.pgeneral website: http://www.pacificor

Colorado Springs Utilities 2012 Electric Integrated Resource Plan https://www.csu.org/CSUDocuments/Arizona Public Service Company (APS) 

APS 2014 Integrated Resource Plan http://www.azenergyfuture.com/getm

ec96b2498e02/2014_IntegratedResou

Tucson Electric Power (TEP) Tucson Electric Power 2014 Integrated Resource Plan https://www.tep.com/doc/planning/2UNS Electric, Inc. UniSource Electric 2014 Integrated Resource Plan https://www.tep.com/doc/planning/2Arizona Electric Power Cooperative 

Arizona Electric Power Cooperative, Inc. IntegratedResource Plan Presentation to the Arizona Corporation Commission 2014 

General website, need to keep looking transmission/generation/arizona-electUnable to find IRP, but presentation on http://www.azcc.gov/Divisions/Utilitie

Puget Sound Energy (2013) 2013 Integrated Resource Plan, chapters and 

appendices 

http://pse.com/aboutpse/EnergySupphttp://pse.com/aboutpse/EnergySupp

Seattle City Light (2014) Seattle City Light Integrated Resource Plan 2014 

Update and Progress Report 

http://www.seattle.gov/light/news/iss

Montana-Dakota Utilities (2013) Montana-Dakota Utilities Co.

2013 Integrated Resource Plan, Volumes I-IV 

http://www.montana-dakota.com/dochttp://www.montana-dakota.com/dochttp://www.montana-dakota.com/dochttp://www.montana-dakota.com/doc

Xcel Energy Upper Midwest (2016) 

Upper Midwest Resource Plan 2016-2030 http://www.xcelenergy.com/staticfiles
AEP East 2010 AEP-East Integrated Resource Plan http://www.psc.ky.gov/PSCSCF/2011%

00401/Kentucky%20Power%20Respon3%20%20AEP%20East%202010%20IRP

SouthwesternElectric Power Company (SWEPCO) 

Draft Integrated Resource Plan (2015) https://www.swepco.com/global/utilit

O_LA_IRP_Filed_Feb_6.pdf

Duke Energy Ohio Duke Energy Ohio 2013 Resource Plan https://www.duke-energy.com/pdfs/2PG&E PG&E Proposed 2014 Bundled Procurement Plan 

Proceeding 

https://pgera.azurewebsites.net/Regu

Northwest Power and Conservation Council 

Sixth Northwest Conservation and Electric Power Plan https://www.nwcouncil.org/media/62
Abbreviations 

AEO – Annual Energy Outlook 

AEP – American Electric Power 

CAGR – Compound Annual Growth Rate 

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 energy 

MMBtu – Million British thermal units 

MW – Megawatts 

MWa – Average megawatts, or the average number of megawatt-hours over a given year 

MWh – Megawatt hours 

NCUC – North Carolina Utility Commission 

NG – Natural gas 

RPS – Renewable portfolio standards