MEMORANDUM

To: Docket ID EPA-HQ-OAR-2013-0602

Date: May 7, 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.
Summary of IRPs

Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 coal beginning in 2025 

with CCS if there is 

dramatic load growth

Significant existing coal 

capacity idled (2,400 MW4,700 MW)

Fuel diversity is 1 

of 4 metrics used 

to evaluate all 

portfolio results. 

7 of 8 scenarios 

included 

carbon price of 

at least 

$17/ton up to 

$45/ton by 

2030.

Prices not 

given.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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)

No new coal planned 

through 2029.

Does not believe new coal 

generating facility could be 

built without CCS while still 

complying with regulations. 

Considered coal and CCS 

options in analysis, but not 

pursuing at this time. 

“Fuel Diversity 

Plan” reduces 

reliance on natural 

gas.

Solar: 559 MW by 

2029 

Onshore Wind: 247 

MW by 2022 

Offshore Wind: 12 

MW demonstration 

project by 2018 

Nuclear: 1,453 MW 

by 2028 

Also selects 1,566 

MW of CC capacity 

and 457 MW of CT 

capacity

 

Base case

assumes 

carbon tax 

efficiency 

requirement 

enacted by 

2020. No prices 

given Due to 

uncertainties, 

examined a 

scenario with 

no marginal 

cost of carbon 

emissions 

during the 

study period. 

Predict 

lower 

prices than 

in the 2013 

Plan. 

2014 Plan 

Base case:

Henry Hub 

Natural 

Gas-- $6.02 

$/MMbtu 

DOM Zone 

Delivered 

Natural 

Gas--$6.01 

$/MMbtu
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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%

Edwardsport IGCC began 

operations in 2013.

No new coal planned 

through 2031.

Sourcing low-sulfur coal on 

a short-term basis for low 

capacity factor coal 

stations. 

Coal retirements included 

in Recommended Plan.

Signed a 20-year 

power purchase 

agreement with 

the Benton County 

Wind Farm, 

resulting in 100 

MW of wind 

capacity for 20 

years.

Carbon Tax 

Assumptions—

Environmental 

Focus Scenario: 

$20/ton in 

2020, 

increasing to 

$75/ton by 

2033.

Low Regulation 

Scenario: 

$0/ton all 

years.

Reference 

Scenario:

$17/ton in 

2020, 

increasing to 

$50/ton by 

2033.

Reference 

Scenario 

Base 

Assumption 

of $5-

12/mmBtu
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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

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.

Carbon costs 

not included in 

base case. 

Sensitivity 

analysis used 

linear rise from 

15.74 $/ton 

(2015) to 54.06 

$/ton (2030).

Linear rise 

from 4.45 

$/MMBtu 

(Jan 2011) 

to 11.60 

$/MMBtu 

(Dec 2030).

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.

RE

Adding 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.

No new coal planned.

Evaluated over 20 coal and 

natural gas resource 

options. Eliminating coal 

without CCS from any 

future consideration.

Planning to retire one-third 

of coal-fired generating 

capacity. 

• 400 MW wind 

• 45 MW solar

• 28 MW 

hydroelectric

• 5 MW landfill 

gas

• 600 MW 

efficient NGfired CC

• Continue to rely 

on existing 

nuclear, 

preserve 

options for new 

nuclear 

generation

Need to meet 

requirements of 

Missouri’s RES.

Between 

$23/ton and 

$53/ton 

starting in 

2025.

Cost of 

compliance 

with CPP 

expected to be 

higher than 

$53/ton.

Use range 

of 4 - 6 

$/MMBtu 

over 20 

year 

planning 

horizon.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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

RE

The 2014 DE Solar Renewable Energy 

Credits (SREC) Procurement Program 

secured SRECs from 385 projects that 

represent 5.5 MW of solar facilities.

No new coal planned. In the first year, 

Delmarva is 

required to procure 

13% of its supply 

requirements from 

renewable 

resources, 

including at least 

1% from solar. By 

2024, the 

percentage 

increases to 24% 

for all qualifying 

resources and at 

least 3.25% from 

solar.

DE subject to a 

RPS.

No prices 

given.

No prices 

given.

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 new coal planned.

Existing coal delivery 

contract (largest source in 

their portfolio) will be 

discontinued (108 MW).

More renewables 

can help mitigate 

risks associated 

with higher 

NG and CO2

compliance 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.

Evaluated a 

33% and 40% 

RPS.

CO2 Price 

scenarios 

included both 

state and 

federal 

regulatory 

scenarios. Price 

range of 15-50 

$/tonne.

Reference 

case: 15 

$/tonne in 

2013 rising to 

30 $/tonne in 

2030.

Evaluated 4 

trends. 

Trends 

include 

prices 4-12 

$/MMBtu

Reference 

case: 5 

$/MMBtu 

in 2013 

rising to 8 

$/MMBtu 

in 2030.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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.

Other

No 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 new coal planned.

Boardman Plant ends the 

use of coal by 2020.

Need to maintain 

compliance with 

Oregon RPS

Model existing 

regulations in 

CA and Alberta, 

Canada.

2013: $9.10 

per short ton

2020: $14.55 

per short ton

Model a CO2 

tax of 

$16/short ton 

in 2023, 

escalating at 

8%/yr on all 

WECC thermal 

plants. 

Reference 

case real 

levelized 

price in 

2013 $ is 

$4.76/MM

Btu

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

Other

D.14-03-004 directs SDG&E to procure a 

minimum of 500 MW and up to 800 MW 

of new resources by 2022.

No coal considered. CA has “preferred 

loading order”

• cost-effective EE 

and DR

• renewable 

resources to 

meet RPS

• cost-effective 

CHP

• other resources

Subject to 

AB32 which 

includes a 

carbon trading 

scheme. No 

prices given.

No prices 

given.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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.

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.

Base case 

assumed no 

carbon price.

Sensitivities of 

10 $/tonne 

(beginning 

2017), and 20 

$/tonne 

(beginning 

2020). 

Escalation 

rates redacted.

Prices 

redacted.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 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.

3 Scenarios:

• No cost

• 14.64 $/ton 

in 2018 

escalating

at 3% 

annually

• 35 $/ton in 

2018 

escalating 

at 9% 

annually

Board of 

Directors 

guidelines 

reduce avg.

CO2 emissions 

intensity from 

2010 through 

2013 to 10-

15% below 

2005 level of

1,194 lbs/MWh

RPS in Oregon 

of 10% by 

2025; no RPS in 

Idaho.

Use EIA 

AEO 2012 

forecasts 

(9-17 

$/MMBtu 

by 2032, 

nominal 

$s).
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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

No new coal construction 

planned. Noted EPA rules 

for new coal.

Will soon be closing last 

coal facility without 

advanced emission 

controls.

Considered SCPC and IPCC 

with CCS but determined 

no cost-effective CO2

controls for fossil plants.

Nuclear included in 

portfolio in order 

to maintain fuel 

diversity.

Need to comply 

with NC REPS. 

Developed a 

separate 

carbon neutral 

plan.

Must make 

Cliffside Unit 6 

carbon neutral 

by 2018 for air 

permit.

Reference 

case:

• $17/ton in 

2020

• $36/ton 

2029

High case:

• $20/ton in 

2020

• $50/ton 

2029

Gas has 

traditionall

y been 

used for 

peaking 

generation, 

but has 

begun to 

play a more 

important 

role due to 

pricing and 

addition of 

significant 

CC 

generation.

Sensitivity 

of +- 15% 

was 

performed:

Short-term 

pricing: 

based on 

market 

observation

s.

Long-term 

pricing: 

based on 

Company’s 

fundament

al fuel price 

projections.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

Progress 

Energy 

Carolinas, 

Inc.

2012 

(through 

2027)

IOU 

(Merge

d 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

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.

Base case:

• $26/ton in 

2017

• $80/ton 

2031

Low case:

• $20/ton in 

2017

• $45/ton 

2031

High case:

• $70/ton in 

2017

• $170/ton 

2031

Prices 

redacted.

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 coal planned.

Planning to retire some 

coal units by end of 

Planning Period.

Exposure to fuel 

price volatility was 

factored into 

generation mix 

choices but no 

quantitative 

measurements 

given.

Base Case : 

$0/ton

Analyzed 

Environmental 

Scenario with 

carbon tax 

beginning in 

2020, but 

assumptions 

not listed.

Acknowled

ges that 

natural gas 

prices are a 

key driver 

in 

modeling. 

Does not 

list specific 

price 

assumption

s. 
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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. 

No coal planned in any 

modeled scenario—new 

coal seen as 

environmentally and 

economically impractical

Plan to retire 982 MW of 

coal.

Exposure to fuel 

price volatility was 

factored into 

generation mix 

choices but no 

quantitative 

measurements 

given.

Expects that utilityscale solar 

resources will 

become 

economically 

justifiable by 2020.

Project carbon 

tax to take 

effect in 2022.

$15-$20/metric 

ton assumed 

over long-term 

analysis period. 

Use EIA’s 

2013 

Annual 

Energy 

Outlook 

forecasts.

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 coal planned in any 

modeled scenario.

Exposure to fuel 

price volatility was 

factored into 

generation mix 

choices but no 

quantitative 

measurements 

given.

Include a 

model scenario 

with CO2 cap 

and trade 

beginning in 

2021.

Include a 

model scenario 

with a modest 

carbon tax 

implemented 

in 2030. 

Assumed max 

$25/metric ton 

in 2032.

Use EIA 

2012 

reference 

case, which 

projects NG 

price 

increase on 

4.5% per 

year.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 coal planned.

Coal and CCS were 

evaluated as resource 

options. 

Exposure to fuel 

price volatility was 

factored into 

generation mix 

choices but no 

quantitative 

measurements 

given.

No price on 

carbon prior to 

2020.

Assumed 

$20/ton by 

2025 with Slow 

Economic 

Improvement, 

and $20/ton by 

2020 in 

Aggressive 

Environmental 

scenario. 

Assumed 

$4.54/MM

Btu @ 5% 

in Slow 

Economic 

Improveme

nt scenario. 

Assumed 

$5.85/MM

Btu @4.9% 

in 

Aggressive 

Environme

ntal 

Scenario.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 new generation 

planned.

No new generation 

planned in near 

future. 

Not making a 

decision about 

retirement date for 

FB Culley 2 at this 

time. 

Models consider 

potential 

Renewable 

Portfolio Standard.

Analysis 

considers price 

for carbon 

beginning in 

2020.

High scenario 

assumed 

$15.5/ton, low 

scenario 

assumed 

$10.3/ton.

Base Case 

(2014 $s):

$4.65/MM

Btu in 

2015.

$7.35/MM

Btu in 2034

The natural 

gas price 

forecast is 

an average 

of U.S. 

Energy 

Informatio

n 

Administrat

ion

(EIA) 

Annual 

Energy 

Outlook 

(AEO) 2014 

Reference 

case, Wood 

Mackenzie 

long term

forecast, 

and Black & 

Veatch’s 

natural gas 

forecast.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 coal planned. Exposure to fuel 

price volatility was 

factored into 

generation mix 

choices but no 

quantitative 

measurements 

given.

Potential 

future 

legislation is 

factored into 

analysis

beginning in 

2023. Price 

assumptions 

based on ACES 

long-term 

forecast. 

High Price: 

$10/MMBt

u

Low Price: 

$1/MMBtu
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 coal planned.

No non-renewable capacity 

is needed in the planning 

period.

Plan to depreciate two 

largest coal fired stations 

by 2028.

Exposure to fuel 

price volatility was 

factored into 

generation mix 

choices but no 

quantitative 

measurements 

given.

Up to 2019 

(Environmental 

Cost): $0.43-

$4.46/ton for 

power 

generated 

within MN. $0 

for outside 

MN.

After 2019 

(Regulatory 

Cost): 

$9-$34/ton 

regardless of 

location.

Prices were 

projected 

by blending 

broker 

quotes with 

Wood 

Mackenzie 

price 

forecast. 

Prices not 

given.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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.

No new coal planned.

Plan includes development 

and phase-in of CCS at the 

APCo Mountaineer Plant 

and at a unit of the OPCo 

Garvin Station by 2020. CCS 

development driven in part 

by future CO2 emission 

legislation/regulation.

Plan also considers the 

potential retirement of 

around 6,000 MW of coal, 

due in part to future EPA 

regulation (HAP and CCR 

rulemaking).

Prospect of future 

GHG and CO2 

emission 

legislation/regulati

on has prompted 

around 2,000 MW 

of renewable 

resource additions 

by end of 2014.

Assumes 1,100 

MW nameplate 

capacity of 

renewables, mostly 

wind. Consistent 

with state 

requirements in 

region, including 

Ohio Substitute 

S.B. 221.

150 MW dedicated 

biomass generation 

by 2018

CO2 pricing 

assumptions 

developed 

after U.S. 

House passage

of the 

WaxmanMarkey bill.

Analysis 

assumes 

legislation will 

be effective by 

2014.

No natural 

gas prices 

listed
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 coal planned.

Retiring 502 MW of coal in 

2015.

Variations of RPSs 

included in 

scenarios.

Various 

scenarios 

analyzed, both 

carbon tax and 

cap-and-trade.

Tax: $13.52-

$74.99/short 

ton over 

planning 

period

Cap-and-trade: 

$47/47-

$132.25/short 

ton over 

planning 

period

PacifiCorp 

relies upon 

a number 

of

expert 

third-party 

proprietary 

data and 

forecasting 

services to 

establish a 

range of 

gas price

scenarios.

Prices not 

given.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 coal planned.

Advanced pulverized coal 

with and without CCS 

included in evaluation.

CO RES requires 

that energy from 

qualifying 

renewable energy 

resources must be 

at least six percent 

for the years 2015 

through 2019 and 

10 percent for year 

2020 and 

thereafter. Must

come from 

qualifying 

renewable energy 

resources, which 

include solar, wind, 

geothermal, 

biomass, existing 

hydroelectric 

generation with a 

nameplate rating 

of 30 megawatts or 

less, and new 

hydroelectric 

generation with a 

nameplate rating 

of 10 megawatts or 

less.

Low Price 

Point: $3/ton

Medium and 

High Points: 

Based on 

European 

Union carbon 

markets. Range 

from $25-

$50/ton

$4.29/mmB

tu in 2012

$10.49/mm

Btu in 2031

High and 

low 

scenarios 

used plus 

and minus 

40% of this 

range.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

Arizona 

Public 

Service 

Company 

(APS)

2014-

2029

IOU—

subsidi

ary of 

Pinnacl

e West

• Peak Load Growth: 

3% annual increase 

over planning 

period

EE: 1,447 MW

DR: 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 coal growth planned Highly flexible 

natural gas 

resources will be 

favored over 

traditional 

baseload sources 

due to low prices, 

increased cost of 

environmental 

regulation, and 

increased selfdispatching solar 

generation.

Assumed 

carbon 

allowances 

beginning in 

2021, based on 

trading price of 

CO2 allowances 

in CA in 

September 

2013. After 

2021, prices 

escalate at rate 

of inflation.

High Scenario: 

$15/ton in 

2019, 

increasing 7.5% 

annually

Price 

assumption

s derived 

from 

analysis of 

forward 

market 

price curve 

at end of 

3rd quarter 

2013. 

Slightly 

more than 

$7/mmBTU 

delivered 

by 2029

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 2015

Other

• 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 to reduce coal 

capacity by 492 MW over 

next five years

Looking to 

minimize water 

usage and negative 

environmental 

impacts while 

meeting Arizona’s 

RES.

RES requires 4.5% 

of 2014 load 

requirement and 

15% of 2025 load 

requirement is met 

with renewable 

resources.

$17.23/metric 

ton beginning 

in 2023.

Increasing 6% 

annually.

WoodMackenzie 

forecast.

$4.47/MM

Btu in 

2014.

$7.36/MM

Btu in 

2028.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 additional coal planned. RES requires 4.5% 

of 2014 load 

requirement and 

15% of 2025 load 

requirement is met 

with renewable 

resources.

$17.23/metric 

ton beginning 

in 2023.

Increasing 6% 

annually.

WoodMackenzie 

forecast.

$4.47/MM

Btu in 

2014.

$7.36/MM

Btu in 

2028.

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.

Assume energy 

portfolio that 

complies with 

Arizona RES and 

energy efficiency 

standards
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 2033

Other

• Peakers (CT in MW): 2,212 by 2033

• Transmission renewals: 1,567 MW 

by 2033

• Gas storage: 150 MDth/day

Evaluated economic 

viability of Colstrip 

generating station under 

different regulation 

scenarios. Planning to 

continue operation of 

Colstrip for this planning 

cycle.

Need to comply 

with Washington 

state law (RCW 

19.285) and RPS

PSE has acquired 

enough eligible 

renewable 

resources and RECs 

to meet the

requirements of 

the law through 

2022.

To account for 

uncertainty, 

analysis 

includes range 

from $0 to 

$179/ton.

Gas price 

forecasts 

are a 

combinatio

n of 

forward 

marks in

the near 

term and 

Wood 

Mackenzie 

forecasts 

for the 

longer 

term.

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 coal planned. Modeled potential 

climate change 

impacts, especially 

the effect of glacial 

melt on 

hydropower. Taken 

into account in 

planning.

Includes forecasted 

electric vehicle 

demand.

Do not include 

prices. 

Assuming state 

regulation 

begins before 

federal 

regulation.

$6.50/MM

Btu by 

2031
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

MontanaDakota 

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

Coal-fired generation was 

analyzed as a resource 

option.

No coal planned. 

Considered 

economic, societal, 

and customer 

issues

Mentions 

commitment to 

reducing air 

emissions

Mentions ongoing 

CCS research

Modeled 

carbon tax of 

$30 and $50 

per ton

Base case:

$3.51/MBT

U in 2013 

and 

$4.33/MBT

U in 2017. 

3% annual 

escalation 

thereafter. 

High case is 

$3 more 

and low 

case is $1 

less. 

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

Continuing to run Sherco 

Units 1 and 2 throughout 

the planning period

No additional coal planned

Until 2020, focus is 

to meet the Solar 

Energy Standard 

and accomplish a 

30% carbon 

reduction. 

Exposure to fuel 

price volatility was 

factored into 

generation mix 

choices but no 

quantitative 

measurements 

given.

$21.50/ton in 

2019, 

increasing with 

inflation. 

Also analyzed 

societal value 

of CO2 as an 

externality. 

Prices not 

included
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

Southweste

rn 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

Maintains solid-fuel units at 

Welsh Units 1 & 3, Flint 

Creek and Pirkey, in 

addition to its share of 

energy and capacity from 

the non-SWEPCO operated 

Dolet Hills unit

Retires Welsh Unit 2 (coal 

fired plant) in 2016

Reduced reliance 

on solid fuel-based 

(from 46% to 31%) 

and gas-steam 

(from 25% to 13%) 

capacity as part of 

its portfolio

of resources.

Combined cycle 

natural gas 

increases from 12% 

to 13% of capacity 

mix.

Increased reliance 

on demand-side 

(from 1% to 6%) 

and renewable 

resource capacity 

(from 6.9% to 

37%), thereby

enhancing resource 

supply technology 

and resource 

supply fuel 

diversity.

Generation from 

coal decreases 

(81% to 49%), 

while renewables 

increase (7.7% to 

38.6%).

Base pricing 

scenario of 

$15/tCO2

beginning in 

2022, 

increasing to 

$17/mt in 2030

2 lower 

probability 

scenarios:

$15/mt in 2020

rising to 

$25/mt in 

2030, applying 

only to coal, 

not gas

$25/mt in 

2020, rising to 

$40/mt in 

2030, applying 

to all fossil 

generation

Base: 

$5.5/mmbt

u in 2015, 

rising to 

$8.5/mmbt

u in 2030

Highest 

scenario: 

$5.9/mmbt

u in 2016, 

rising to 

$9.8 in 

2030

Lowest 

scenario: 

$5.1/mmbt

u in 2015, 

rising to 

$7.5/mmbt

u in 2030

All prices in 

nominal 

dollars
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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.

Accelerated retirement of 

certain coal-fired 

generation is possible. 

Future coal and IGCC Units 

must employ CCS to meet 

NSPS. New gas will not 

have to use CCS.

Current renewable 

energy strategy is 

through short-term 

REC purchases, 

though Duke 

realizes efforts may 

be required in 

order to ensure 

compliance with 

the 12.5% 

renewable 

requirement under 

Ohio’s Alternative 

Energy Portfolio 

Standard (which 

also has a carveout for solar). 

Does not 

include carbon 

pricing

Annual 

growth rate 

from 2013 

to 2023 of 

2.9% 

annually, in 

nominal 

terms.
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

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 Scenario

RE

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 Scenario

RE

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.

Fossil resource capacity 

projected to remain 

constant through 2024 

(although projected 

generation information 

was redacted in the 

report).

California loading 

order preferences: 

Cost-effective EE 

and DR are 

preferred to meet 

California’s 

growing energy 

needs, followed by 

cost-effective 

renewable and DG 

resources, and 

finally clean and 

efficient fossilfueled generation.

Information on 

compliance 

with AB32 is 

redacted in the 

report. The 

report does say 

that “PG&E will 

only use 

approved GHG 

products that 

hedge GHG 

price risk that 

would be 

subject to GHG 

limits.”

Projections 

of natural 

gas 

consumptio

n and 

possibly 

prices have 

been 

redacted in 

this version 

of the 

procureme

nt plan. 
Utility Year Utility 

Ownership 

Type

Future Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel Diversity 

Choices

Carbon Price 

Assumptions

Natural Gas 

Price 

Projection

Northwest 

Power and 

Conservatio

n Council

2010-

2030

Region

al 

Advisor

y 

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.

EE

Council 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 new coal planned. 

Some new coal options 

considered in analysis.

The Council suggests that 

utilities and states support 

CCS development.

By 2030, the shares 

of loads that must 

be met from 

renewable 

technologies are: 

15% in MT, 25% in 

OR, and 15% (by 

2020) in WA.

Planning 

scenarios 

modeled from 

$0 to $100 per 

ton, with $47 

per ton by 

2030

High case 

wellhead 

price: $9 by 

2025 and 

$10 by 

2030

Low case: 

$4 to $5 

per million 

Btu
Utility Document Title Web Link to IRP

Tennessee Valley Authority (TVA) Integrated Resource Plan 2015 Draft Report http://www.tva.com/environment/reports/irp/pdf/TVA-Draft-Integrated-Resource-Plan.pdf

Dominion Dominion North Carolina Power's and Dominion 

Virginia Power's Report of Its Integrated Resource Plan, 

August 2014

https://www.dom.com/library/domcom/pdfs/corporate/integrated-resource-planning/nc-irp-2014.pdf

Duke Energy Indiana The Duke Energy Indiana 2013 Integrated Resource 

Plan, November 2013

http://www.in.gov/iurc/files/2013_Duke_Energy_Indiana_-_IRP_Report_Volume_I.pdf

http://www.in.gov/iurc/files/2013_Duke_Energy_Indiana_-_IRP_Volume_II.pdf

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

Power, 2011

http://psc.state.wy.us/pscdocs/dwnload/BHP%20EFP%20IRP%20&CLFP%20IRP/BHP%202011-2030%20IRP.pdf

Ameren MO Integrated Resource Plan Update, October 2014 https://www.ameren.com/missouri/environment/renewables/ameren-missouri-irp

Delmarva Power & Light 

Company

Delmarva Power & Light Company 2014 Integrated 

Resource Plan, December 2014

https://www.delmarva.com/uploadedFiles/wwwdelmarvacom/DE%20IRP%20PUBLIC%20VERSION%20%20120114.pdf

City of Pasadena Water and 

Power Department

Integrated Resource Plan Update, February 2012 http://ww2.cityofpasadena.net/waterandpower/irp/2012IRPUpdate.pdf

Portland General Electric 2013 Integrated Resource Plan Update https://www.portlandgeneral.com/our_company/energy_strategy/resource_planning/irp.aspx

San Diego Gas and Electric 

(SDG&E)

San Diego Gas and Electric Company Draft 2014 LongTerm Procurement Plan, 2014https://www.sdge.com/sites/default/files/regulatory/PUBLIC-SDGE-Bundled-Plan.pdf

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?documentNumber=145981

Idaho Power 2013 Integrated Resource Plan, June 2013 https://www.idahopower.com/AboutUs/PlanningForFuture/irp/2013/default.cfm

Duke Energy Carolinas Duke Energy Carolinas’ 2014 Integrated Resource Plan, 

September 2014

http://starw1.ncuc.net/NCUC/ViewFile.aspx?Id=c3c5cbb5-51f2-423a-9dfc-a43ec559d307

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

Plan, November 2012

http://www.energy.sc.gov/files/view/ProgressEnergyResource%20Plan2012.pdf

Indianapolis Power & Light 

Company

Indianapolis Power & Light Company

2014 Integrated Resource Plan

http://www.in.gov/iurc/files/IPL_2014_IRP_Report.pdf

Indiana Michigan Power 

Company

Indiana Michigan Power Company Integrated Resource 

Planning Report, November 2013

http://www.in.gov/iurc/files/2013_Indiana_Michigan_Power_Co_-_IRP_Report.pdf

Indiana Municipal Power Agency Indiana Municipal Power Agency 2013 Integrated 

Resource Plan, November 2013

http://www.in.gov/iurc/files/2013_Indiana_Municipal_Power_Agency_(IMPA)_-_IRP_Report.pdf

Northern Indiana Public Service 

Company

NIPSCO 2014 Integrated Resource Plan, November 

2014

http://www.in.gov/iurc/files/NIPSCO_2014_IRP.pdf
Vectren Corporation: Southern 

Indiana Gas and Electric 

Company (Vectren South)

Vectren 2014 Integrated Resource Plan, November 

2014

http://www.in.gov/iurc/files/SIGECO-Vectren_2014_IRP_Report.pdf

Wabash Valley Power 

Association, Inc.

Wabash Valley Power Association, Inc. 2013 Integrated 

Resource Plan, November 2013

http://www.in.gov/iurc/files/2013_Wabash_Valley_Power_Association_-_IRP_Report.pdf

Great River Energy Great River Energy

Resource Plan

2015-2029, October 2014

http://www.greatriverenergy.com/makingelectricity/resourceplan/2014_irp.pdf

PacifiCorp 2013 Integrated Resource Plan Volumes 1 and 2 http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/PacifiCor

p-2013IRP_Vol1-Main_4-30-13.pdf

http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/PacifiCor

p-2013IRP_Vol2-Appendices_4-30-13.pdf

general website: http://www.pacificorp.com/es/irp.html

Colorado Springs Utilities 2012 Electric Integrated Resource Plan https://www.csu.org/CSUDocuments/eirp.pdf

Arizona Public Service Company 

(APS)

APS 2014 Integrated Resource Plan http://www.azenergyfuture.com/getmedia/c9c2a022-dae4-4d1b-a433-

ec96b2498e02/2014_IntegratedResourcePlan.pdf/?ext=.pdf

Tucson Electric Power (TEP) Tucson Electric Power 2014 Integrated Resource Plan https://www.tep.com/doc/planning/2014-TEP-IRP.pdf

UNS Electric, Inc. UniSource Electric 2014 Integrated Resource Plan https://www.tep.com/doc/planning/2014-UES-IRP.pdf

Arizona Electric Power 

Cooperative

Arizona Electric Power Cooperative, Inc. Integrated 

Resource Plan Presentation to the Arizona Corporation 

Commission 2014

General website, need to keep looking for IRP: http://www.azgt.coop/electricity-generation-andtransmission/generation/arizona-electric-power-cooperative/

Unable to find IRP, but presentation on IRP is available here: 

http://www.azcc.gov/Divisions/Utilities/Electric/IRP2012/2014/AEPCO%20IRP%20Presentation%2009.11.14.pptx

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

appendices

http://pse.com/aboutpse/EnergySupply/Documents/IRP_2013_Chapters.pdf

http://pse.com/aboutpse/EnergySupply/Documents/IRP_2013_Appendices.pdf

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

Update and Progress Report

http://www.seattle.gov/light/news/issues/irp/docs/SeattleCityLight2014_IRPUpdateandProgressReport.pdf

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

2013 Integrated Resource Plan, Volumes I-IV

http://www.montana-dakota.com/docs/default-source/2013-irp/2013-mdu-irp-report---volume-i.pdf?sfvrsn=0

http://www.montana-dakota.com/docs/default-source/2013-irp/2013-mdu-irp-report---volume-ii.pdf?sfvrsn=0

http://www.montana-dakota.com/docs/default-source/2013-irp/2013-mdu-irp-report---volume-iii.pdf?sfvrsn=0

http://www.montana-dakota.com/docs/default-source/2013-irp/2013-mdu-irp-report---volume-iv.pdf?sfvrsn=0

Xcel Energy Upper Midwest 

(2016)

Upper Midwest Resource Plan 2016-2030 http://www.xcelenergy.com/staticfiles/xe/Regulatory/Regulatory%20PDFs/03-Preferred-Plan.pdf
AEP East 2010 AEP-East Integrated Resource Plan http://www.psc.ky.gov/PSCSCF/2011%20cases/2011-

00401/Kentucky%20Power%20Responses%20to%20042312%20Order/Sierra%20Club/012712/Sierra%201-

3%20%20AEP%20East%202010%20IRP.pdf

Southwestern

Electric Power Company 

(SWEPCO)

Draft Integrated Resource Plan (2015) https://www.swepco.com/global/utilities/lib/docs/info/projects/SWEPCOIntegratedResourcePlan/2015_DRAFT_SWEPC

O_LA_IRP_Filed_Feb_6.pdf

Duke Energy Ohio Duke Energy Ohio 2013 Resource Plan https://www.duke-energy.com/pdfs/2013-Ohio-IRP-FINAL.pdf

PG&E PG&E Proposed 2014 Bundled Procurement Plan 

Proceeding

https://pgera.azurewebsites.net/Regulation/ValidateDocAccess?docID=313992

Northwest Power and 

Conservation Council

Sixth Northwest Conservation and Electric Power Plan https://www.nwcouncil.org/media/6284/SixthPowerPlan.pdf
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