### ***EO 12866_Review

- Draft

– Do Not Cite, Quote or Release During Review ***
To: Docket ID EPA

- HQ

- OAR

- 2013

-0495 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 i nfrastructure required in the electric utility industry can take several years to build and lasts for decades, it is important to d evelop 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 dem and (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 eve ry two or three years per state law. States vary in t he 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 s uch as demand

- side initiatives. Some states provide guidelines for analysis. EPA cond ucted a review of current IRPs to infor m the development of the new source performance standard for emi ssions of carbon dioxide for existing affected fossil fuel

-fired electric utility generating units. An overview of the results is provided below.Summa ry of IRPs **Utility Year**  **Utility Owner** **** **ship 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 (3,6 00 MW

5,1 00 MW) **EE**

 EE/DSM/DR: 3,6 00

- 5,1 00 MW by 2020 **RE**
 R enewables : 1,500
– 2,500 MW by 2020 **Nuclear**
 N uclear : 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 co al capacity idled ( 2,400 MW

4,700 MW) Fuel diversity is 1 of 4 metrics used to evaluate all portfolio results. 7 of 8 scenarios

include d c arbon price of at least $17/ton up to $45/ton by 2030

. Prices not

given.**Utility Year**  **Utility Owner** **** **ship 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 Pla n) 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 ca se

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 Owner** **** **ship 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 CO 2 . 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 Owner** **** **ship 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, 2 0 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 NG

fired 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 Owner** **** **ship 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 M W
 2020: 2,127 M W
 2024: 2,220 M W Total DSM Savings: 2015: 344 G Wh 2020: 591 G Wh 2024: 801 G Wh **RE**

The 2014 DE Solar Renewable Energy Credits ( SREC ) Procurement Program secured SRECs from 3 85 projects that represent 5.5 M W 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 CO 2 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 d rivers including fuel costs. Evaluated a

33% and 40% RPS. CO 2 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 Owner** **** **ship 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 Owner** **** **ship 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). Escalatio n rates redacted. Prices

redacted.**Utility Year**  **Utility Owner** **** **ship 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. CO 2 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 Owner** **** **ship 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: 1,6 70 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 M W 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 CO 2 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 Owner** **** **ship 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 wit h 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. Plannin g 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 Owner** **** **ship 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 utility

scale 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**
 Re newables 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 CO 2 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 Owner** **** **ship 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 Owner** **** **ship 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 Cor poration : 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 Portfoli o 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 Owner** **** **ship 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 p ass -t hroughs) , or approximately 53 GWh/yr
 Peak: 0.4% annual growth (including pass -t hroughs) , reaching 1,926 MW by 2032 Do not serve any

retail customers directly. Customers served by the Association’s memb ers. 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 d oes not add baseload or intermediate resources until 2027 when power purchase agreements expire. **EE** :  S pecific 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 scena rio 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. P otential

future legislation is factored into analysis beginning in 2023. Price assumptions based on ACES long

-term forecast. Hi gh Price:

$10/MMBt u Low Price: $1/MMBtu**Utility Year**  **Utility Owner** **** **ship 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 volatil ity 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 Owner** **** **ship 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) wit hin 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 CO 2 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 CO 2 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 CO 2 pricing

assumptions developed after U.S. House passage of the Waxman

Markey bill. Analysis assumes legislation will be effective by 2014. No natural

gas prices listed**Utility Year**  **Utility Owner** **** **ship 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 ra nge of gas price scenarios. Prices not given.**Utility Year**  **Utility Owner** **** **ship 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 m egawatts 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 Owner** **** **ship 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 self

dispatching solar generation. Assumed

carbon allowances beginning in 2021, based on trading price of CO 2 allowances in CA in September 2013. After 2021, prices escalate at rate of inflation. Hi gh Scenario: $15/ton in 2019, increasing 7.5% annually Price

assumption s derived from analysis of forward market price curve at end of 3 rd 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
 Oth er 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 neg ative 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. Wood

Mackenzie forecast. $4.47/MM Btu in 2014. $7.36/MM Btu in 2028.**Utility Year**  **Utility Owner** **** **ship 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. Wood

Macken zie 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 Owner** **** **ship 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 ve hicle demand. Do not include

prices. Assuming state regulation begins before federal regulation. $6.50/MM

Btu by 2031**Utility Year**  **Utility Owner** **** **ship Type**  **Future Demand Energy Efficiency**  **New Resources to Meet Demand Future Coal and CCS**  **Fuel Diversity Choices**  **Carbon Price**

**Assumptions Natural Gas** 

**Price Projection**  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 Coal

-fired generation was analyzed as a reso urce 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

M W 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 generat ion mix choices but no quantitative measurements given. $21.50/ton in

2019, increasing with inflation. Also analyzed societal value of CO 2 as an externality. Prices not

included**Utility Year**  **Utility Owner** **** **ship 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/tCO 2 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 Owner** **** **ship 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 IGC C 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 u nder Ohio’s Alternative Energy Portfolio Standard (which also has a carve

out for solar). Does not

include carbon pricing Annual

growth rate from 2013 to 2023 of 2.9% annually, in nominal terms.**Utility Year**  **Utility Owner** **** **ship 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 (CPUC

ma ndated 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 non

residential power **CP UC 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 gro wing energy needs, followed by cost
-effective renewable and DG resources, and finally clean and efficient fossil

fueled generation. Information on

compliance with AB32 is redacted in the report. The report does say that “PG&E will only use approved GHG pro ducts 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 Owner** **** **ship 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 like ly 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**U tility**  **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 Long

Term Procurement Plan, 2014 https://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 Plan t 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 Repo rt, November 2013 http://www.in.gov/iurc/files/2013_Indiana_Michigan_Power_Co_

-_IRP_Report.pdf Indiana Municipal Power Agency Ind iana Municipal Power Agency 2013 Integra ted 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 Integra ted Resource Plan, November 2014 http://www.in.gov/iurc/files/NIPSCO_2014_IRP.pdfVectren Corporation: Southern Indiana Gas and Electric Company (Vectren South) Vectren 2014 Integra ted Resource Plan, November 2014 http://www.in.gov/iurc/files/SIGECO

-Vectren_2014_IRP_Report.pdf

Wabash Valley Power Association, Inc. Wabash Val ley Power Association, Inc. 2013 Integra ted Resource Plan, November 2013 http://www.in.gov/iurc/files/2013_Wabash_Valley_Power_Association_

-_IRP_Report.p df

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/pac ificorp/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

Tucs on 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

- and

transmiss ion/generation/arizona

- electric

- power- cooperative/ Unable to find IRP, but presentation on IRP is available here: http://www.azcc.gov/D ivisions/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) S eattle City Light Integrated Resource Plan 2014 Update and Progress Report http://www.seattle.gov/light/news/issues/irp/docs/SeattleCityL ight2014_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=0Xcel 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 A EP

- East Integrated Resource Plan http://www.psc.ky.gov/PSCSCF/2011%20 cases/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.pdfAbbreviations 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 avera ge number of megawatt

- hours over a given yearMWh

– Megawatt hours NCUC
– North Carolina Utility Commission NG
– Natural gas RPS
– Renewable portfolio standards