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Phase 2 Report:

DOE Draft - Part 1

Interregional 

Transmission 

Development and 

Analysis for Three 

Stakeholder Selected 

Scenarios

DOE Award Project

DE-OE0000343

Draft – December 22, 2012
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TABLE OF CONTENTS

Acknowledgement .......................................................................................................................... 1

Page No.

Disclaimers ..................................................................................................................................... 1

Executive Summary.......................................................................Error! Bookmark not defined.

Condensed Report..........................................................................Error! Bookmark not defined.

Phase 1 ....................................................................................................................................... 8

Futures Development and Macroeconomic Modeling............................................................ 9

Selection of Three Scenarios for Phase 2 ............................................................................. 11

Phase 2 ...................................................................................................................................... 13

Reliability Analysis Results – Constraints............................................................................ 13

Reliability Analysis Results – Additional Transmission ...................................................... 16

Production Cost Results............................................................................................................ 18

Scenario Cost Results ............................................................................................................... 22

Sensitivity Analysis and Results............................................................................................... 24

Scenario 1 Sensitivity Results: Wind Curtailment................................................................ 24

Scenario 3 Sensitivity Results: Natural Gas Price and Load Increases................................ 25

Observations and Guidance ...................................................................................................... 26

Report: 

 1.0 Introduction and Background .......................................................................................... 1

1.1 DOE Funding Opportunity Announcement – Overview and Purpose............................. 1

1.2 Statement of Project Objectives....................................................................................... 2

1.3 Scope and Schedule of Work ........................................................................................... 2

1.4 Three Scenarios Analyzed in Phase 2 .............................................................................. 5

1.4.1 Scenario 1: Nationally-Implemented Federal Carbon Constraint with Increased 

Energy Efficiency/Demand Response .................................................................................... 5

1.4.2 Scenario 2: Regionally Implemented National Renewable Portfolio Standard........ 6

1.4.3 Scenario 3: Business as Usual................................................................................... 7

1.5 Phase 2 Work ................................................................................................................. 10

1.6 Unique Study Characteristics......................................................................................... 11
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List of Figures

Figure ES 1. Stakeholder Specified Infrastructure ........................................................................ 9

Figure ES 2. NEEM Regions (blue) and Super Regions (black)................................................. 10

Figure ES 3. Scenario 1 -- Constraints......................................................................................... 14

Figure ES 4. Scenario 2 – Constraints......................................................................................... 15

Figure ES 5. Scenario 3 -- Constraints......................................................................................... 15

Figure ES 6. Scenario 1 – New/Upgraded Transmission ............................................................ 16

Figure ES 7. Scenario 2 – New/Upgraded Transmission ............................................................ 17

Figure ES 8. Scenario 3 – New/Upgraded Transmission ............................................................ 18

Figure ES 9. EI Generation Capacity........................................................................................... 19

Figure ES 10. EI Energy .............................................................................................................. 19

Figure 1- 1. NEEM Regions (blue) and Super-Regions (black).................................................... 7

Figure 1- 2. SSI Transmission Additions....................................................................................... 8

Figure 1- 3. EI Generation Capacity.............................................................................................. 9

Figure 1- 4. EI Energy ................................................................................................................... 9

List of Tables

Table ES 1. Scenario Descriptions for Phase 2 Studies............................................................... 12

Table ES 2. Transmission Line Miles Added by Voltage Level ..Error! Bookmark not defined.

Table ES 3. Annual Production and CO2 Costs and Emissions.................................................. 21

Table ES 4. Quantified O&M and Capital Costs......................................................................... 23

Table ES 5. Sensitivity Results – Production Costs, Emissions and Wind Curtailment ............. 24

Table ES 6. Sensitivity Results –Production Costs, Emissions, Load and Gas Prices................ 25
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Acknowledgement

This material is based upon work supported by the Department of Energy, National Energy 

Technology Laboratory, under Award Number DE-OE0000343. 

Disclaimers

This report was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States Government nor any agency thereof, nor any of their 

employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The 

views and opinions of authors expressed herein do not necessarily state or reflect those of the 

United States Government or any agency thereof. 

The information and studies discussed in this report are intended to provide general information 

to policy-makers and stakeholders but are not a specific plan of action and are not intended to be 

used in any state electric facility approval or siting processes. The work of the Eastern 

Interconnection States Planning Council or the Stakeholder Steering Committee does not bind 

any state agency or Regulator in any state proceeding.
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Executive Summary

In mid-2009 the Department of Energy (DOE) issued a funding opportunity announcement DEFOA-0000068 “Resource Assessment and Interconnection-level Transmission Analysis and 

Planning,” directed towards the Eastern, Western, and Texas interconnections. PJM 

Interconnection, LLC (PJM) bid for and won the Topic A portion of this FOA for the Eastern 

Interconnection, award DE-OE0000343, supported by nine members1

The work of this funding opportunity was divided into two phases. Phase 1 began with the 

creation of a combined grid model for the Eastern Interconnection (the “roll-up” case) and the 

formation of a diverse Stakeholder Steering Committee (SSC) with interests in public policy 

“futures”. Work continued with macroeconomic and generation resource allocation studies of

eight futures chosen by the SSC, and the modification of the roll-up case into a Stakeholder 

Specified Infrastructure (SSI). Finally the SSC chose three future scenarios as the basis for

Phase 2 of the project:

of the Eastern 

Interconnection Planning Collaborative (EIPC). EIPC had been formed earlier in 2009 by 25 of 

the larger Planning Authorities in the Eastern Interconnection.

1. A Nationally Implemented Federal Carbon Constraint with Increased Energy 

Efficiency/Demand Response, (Scenario 1: Combined Policies)

2. A Regionally Implemented National Renewable Portfolio Standard (Scenario 2: National 

Renewable Portfolio Standard/Implemented Regionally), and

3. Business as Usual (Scenario 3: Business as Usual).

An interim report describing Phase 1 studies and results was released in December 2011

(http://www.eipconline.com/uploads/Phase_1_Report_Final_12-23-2011.pdf). 

Phase 2 included transmission studies and production cost analyses of the three future scenarios 

chosen by the stakeholders. This included developing transmission options, study of grid 

reliability and production costs, and estimating generation, transmission, and selected “other”

costs. A number of sensitivities were studied for the three scenarios. The sensitivities included 

four sensitivities to investigate the amount of wind curtailment in Scenario 1 which was 15% in 

the base run. They also included analyzing high loads and high gas prices in Scenario 3.

This Topic A work was carried out in close interaction with the Eastern Interconnection Topic B 

recipient of DOE-FOA-0000068, the National Association of Regulatory Utility Commissions 

(NARUC), and the state representative’s group formed through their award, the Eastern 

Interconnection States Planning Council (EISPC). EISPC members include regulatory 

representatives from the 39 states of the Eastern Interconnection, the District of Columbia, and 

the City of New Orleans. While the EISPC report on their work will be published separately, 

this report includes input from the EISPC. DOE is additionally supporting the InterconnectionLevel Transmission Planning Analysis through work at selected national laboratories on grid 

frequency response and on fault induced delayed voltage recovery.

 1 Study participants were: Entergy, ISO-NE, MAPPCOR, MISO, NYISO, PJM, Southern Company, TVA, 

American Transmission Company
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With the completion of the Phase 2 work by EIPC, the Eastern Interconnection Topic A work 

scope has now met the goals initially defined in the Statement of Project Objectives. One aspect 

highlighted in Phase 1 of the project but not studied in detail is the interrelationships of various 

energy related infrastructures. These interrelationships may need to be considered further to 

better understand how these relationships might impact the broad range of alternative futures. 

One example is the relationship between the natural gas supply and delivery infrastructure and 

the electric transmission system. This report contains the Phase 2 studies, results, and 

conclusions. As was done for Phase 1, a final version will be posted at 

http://www.eipconline.com/uploads. 

A number of valuable conclusions were drawn from the study. While the results were not

intended as a specific plan of action or for use in any state electric facility approval or siting 

processes, and did not include all mandatory NERC reliability planning requirements, they do 

provide general information to policy-makers and stakeholders and will serve as guidelines in 

future activities of EIPC as it focuses on its continuing scope. As the first interconnection-wide 

study of its kind, the work provided insights to EIPC members regarding how future studies may 

be performed and how future interconnections may develop.

Other benefits of the study included an interaction and development of experience between 

Planning Authority participants and state participants. The formation of the SSC, which 

represented a wide range of interests, presented challenges but both EIPC and SSC found 

substantial advantages resulting from the study, as well as identifying opportunities for 

improvement in the future. 

The EIPC is grateful to DOE and to all the above participants for their contributions. 
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Below are the three transmission options developed for each of the scenarios, followed by a 

summary of the costs estimated for each scenario.

Figure ES-1. Scenario 1: Combined Policies – New/Upgraded Transmission

Figure ES-2. Scenario 2: NRPS/IR – New/Upgraded Transmission

Scenario 1 – New/Upgraded 

Transmission

Scenario 2 – New/Upgraded 

Transmission 
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Figure ES-3. Scenario 3: Business as Usual – New/Upgraded Transmission

Scenario 1, with its elimination of virtually all coal plants, inclusion of over 215 GW of wind in 

Nebraska, the MISO region and the SPP region, and use of 152 GW of Demand Response 

needed the largest transmission buildout to meet the policy objectives. Scenario 2 with a 

National Renewable Portfolio Standard that was implemented within regions needed a more 

moderate amount of transmission added and Scenario 3, Business as Usual, required the least 

amount of transmission added of the three scenarios.

Scenario 3 – New/Upgraded 

Transmission
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Below are the relative costs for the three scenarios. 

The cost estimates in the project are based on a variety of generalized assumptions and are only 

broadly indicative on a relative basis between the futures. The analysis did not include social 

benefits and costs that would arise from the different policies modeled. Also not included in the 

above are costs for:

1. Lower voltage transmission projects

2. SSI generation and transmission projects (common to all three scenarios)

3. Generation interconnection costs not included in the overlays, i.e., the generator step-up 

and the lead lines to the first breaker – the costs for the generator interconnection 

overlays are included

4. Generation deactivation/decommissioning

5. Capital costs for existing units

6. Transmission O&M.

Costs

Scenario 1: 

Combined 

Policy

Scenario 2: 

RPS 

Implemented 

Regionally

Scenario 3: 

Business 

as Usual

Production Costs - Fuel $ 40.8 $ 73.8 $ 85.1

Production Costs - Variable O&M $ 6.4 $ 15.5 $ 18.4

CO2 Costs $ 45.3 $ 0.1 $ 0.2

Policy Driven Energy Efficiency $ 8.9 $ 1.5 $ 1.5

CO2 Price Driven Energy Efficiency $ 10.0 $ - $ -

Demand Response O&M $ 0.6 $ 0.3 $ 0.3

Variable Resource Integration $ 2.9 $ 2.5 $ 1.0

Fixed O&M $ 34.7 $ 52.1 $ 48.1

Total O&M Costs $ 149.6 $ 145.9 $ 154.5

Total O&M Costs without CO2 $ 104.3 $ 145.7 $ 154.4

Costs Scenario 1 Scenario 2 Scenario 3

Transmission - Generation 

Interconnection $ 49.6 $ 54.3 $ 7.3

Transmission - Constraint Relief $ 48.4 $ 13.0 $ 7.9

Transmission - Voltage Support $ 0.5 $ 0.1 $ 0.2

Generation $ 868.1 $ 679.4 $ 242.3

Nuclear Uprates $ 4.9 $ 4.9 $ 4.9

Pollution Retrofit Costs $ 6.8 $ 20.2 $ 22.0

Distributed Generation $ - $ - $ -

Total Capital Costs $ 978.2 $ 771.9 $ 284.6

2030 O&M Costs - ($2010 Billions)

Overnight Capital Costs for Capital through 2030 ($2010 Billions)
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Condensed Report

The North American electrical power grid has developed into five separate systems: the Western, 

Texas, Eastern, Alaska, and Quebec Interconnections, which together serve more than 300 

million people through 200,000 miles of high-Voltage transmission lines. Of these five, the 

Eastern Interconnection in the United States covers the largest area, serves all or portions of 39 

states with 70% of the U.S. population, has the largest number of utility companies, and contains 

six of the eight North American Electric Reliability Corporation (NERC) regions. 

On June 15, 2009, the Department of Energy (DOE) released an FOA, “Resource Assessment 

and Interconnection-Level Transmission Analysis and Planning,” DE-FOA-0000068, funded by 

the American Recovery and Reinvestment Act of 2009 (ARRA). The FOA’s objective was to 

support development of grid capabilities in the three largest interconnections by preparing 

analyses of transmission requirements under a range of alternative futures and developing

interconnection-wide transmission expansion plans. PJM submitted a proposal, on behalf of 

EIPC, for the Eastern Interconnection Topic A portion of the FOA and it was accepted by DOE. 

The Eastern Interconnection Topic A work scope is comprised of twelve tasks, divided into two 

phases.

Phase 1 tasks, which were completed in 2011 and documented in the Phase 1 Report released in 

December 2011, included: 

7. Task 1: Initiate Project (Governance and Selection of Stakeholder Steering Committee 

[SSC]). 

8. Task 2: Integrate Regional Plans (Roll-up Report). 

9. Task 3: Production Cost Analysis for Roll-up Report (This task was later dropped as not 

necessary). 

10. Task 4: Macroeconomic Futures Definition. 

11. Task 5: Macroeconomic Analysis of Defined Futures. 

12. Task 6: Expansion Scenario Concurrence and Phase 1 Report. 

The Phase 1 Report is referenced throughout this report and can be found at 

http://www.eipconline.com/uploads/Phase_1_Report_Final_12-23-2011.pdf. 

This report outlines the process and results for Phase 2 of the project. Phase 2 tasks included: 

13. Task 7: Interregional Transmission Options Development. Identify the transmission 

needed to provide a reliable system for each of the three scenarios.

14. Task 8: Reliability Review. Further analyze the transmission options developed in 

Task 7 using additional NERC reliability tests.

15. Task 9: Production Cost Analysis of Scenarios. Analyze the cost of the energy that needs 

to be supplied in each scenario by running a security-constrained economic dispatch 

model.

16. Task 10: Generation and Transmission Cost Development. Develop estimates of the cost 

of the supply resources and transmission in each scenario. 

17. Task 11: Review of Results and Draft Report. Draft the final report.

18. Task 12: Phase II Report. Incorporate comments and finalize report for DOE approval.
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In Phase 1, an early requirement was the formation of a Stakeholder Steering Committee (SSC)

that would provide input and strategic guidance to EIPC through consensus decisions.

Phase 1

2 The SSC 

was comprised of 29 official members, ten representatives from the States, three representatives 

from each of six sectors and one representative from Canada. The six sectors were Transmission 

Owners and Developers; Generation Owners and Developers; Other Suppliers; Transmission 

Dependent Utilities and Public Power & Coops; End Users; and Non-Governmental 

Organizations.3

The first major task of Phase I was development of a combined grid model for the 

interconnection based on a roll-up of the Planning Authorities’ expansion plans for the year 

2020. The Planning Coordinators undertook a reliability analysis of the roll-up of the regional 

plans and found no significant reliability issues. Such a finding is noteworthy as it indicates the 

individual regional plans are not causing burdens that would manifest themselves as unsolved 

reliability violations elsewhere in the Eastern Interconnection. 

Phase 1 Results – Eastern Interconnection Roll-Up Plan and Stakeholder-Specified Infrastructure

This model served as the basis for the EISPC and the SSC to formulate a Stakeholder Specified 

Infrastructure (SSI) Model as the starting point for analyses extending to 2030. The SSI 

infrastructure shown below in Figure ES 1 depicts only the additional transmission lines that 

passed the SSI screening process. A map showing the full transmission topology included in the 

base model is included in Appendix 2. As Phase 2 began, some changes were made in the 

Stakeholder Specified Infrastructure due to updates in projects that moved forward or were set 

aside. A list of those changes can be found at 

http://www.eipconline.com/uploads/20120314_Revised_NewFaciltitiesIncluded_SSI_model.xlsx.

 2 The SSC developed a back-up voting structure in the event consensus could not be reached. 3 More information on the formation and composition can be found in Section 2 of the Phase 1 report.
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Figure ES 1. Stakeholder Specified Infrastructure

EIPC chose Charles River Associates’ (CRA) Multi-Region National (MRN) macroeconomic 

model and their NEEM model to develop information on resource development in eight futures,

with 72 sensitivities to be allocated amongst the eight futures, for a total of 80 model runs. The 

NEEM model used in Phase 1 selected different types of generation based on economics, 

generation characteristics, and numerous input assumptions

Futures Development and Macroeconomic Modeling

4

. It is a “pipe and bubble” model 

that placed new generation in various regions (“bubbles”) but could not automatically resize the 

transmission between regions (the “pipes”)5

Figure ES 2

. Thus, the Phase 1 modeling focused on economic 

generation additions/retirements within specific regions – using fixed transmission transfer 

capabilities. In the Phase 1 resource expansion model, a number of modeling runs relaxed the 

transmission constraints as a proxy for iterating between transmission expansion and resource 

expansion. The NEEM regions are shown in , below. The regions outlined in blue 

and red are the NEEM regions that were modeled in all three scenarios. The combinations of 

regions outline in black are the “Super Regions.” The Super Regions were used in the futures 

that called for regional implementation of policies; one of these futures was chosen as 

Scenario 2: RPS Implemented Regionally. 

 4 The NEEM model considered the expansion of the electric resource system. It was not able to capture the 

infrastructure interrelationships between the electric system and other infrastructures like the natural gas supply and 

delivery system. This limitation is highlighted in the Phase 1 report Section 4.2.1.4 Electric-Gas Interdependencies. 

The Phase 1 report includes other significant conclusions and observations. 5 Another key assumption that impacted the Phase 2 work of the Planning Coordinators is that, within the NEEM 

“bubbles”, it was assumed that there were no transmission constraints. In Phase 2, any transmission constraints that 

occurred within the bubbles were identified and transmission was developed to alleviate those constraints.
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Figure ES 2. NEEM Regions (blue) and Super Regions (black)

The eight futures analyzed as part of Phase 1 were:

1. Business as Usual with EPA regulations proposed in 2011;

2. National Carbon Constraint – National Implementation – 42% reduction by 2030;

3. National Carbon Constraint – Regional Implementation – 42% reduction by 2030; 

4. Aggressive Energy Efficiency/Demand Response/Distributed Generation/Smart Grid –

20% load reductions by 2030;

5. National Renewable Portfolio Standard – National Implementation – 30% by 2030;

6. National Renewable Portfolio Standard – Regional Implementation – 30% by 2030;

7. Nuclear Resurgence – significant new nuclear facilities developed in EI;

8. Combined Federal Climate and Energy Policy – 42% reduction in CO2 by 2030, 30% 

Renewable Portfolio Standard (RPS), significant deployment of demand side 

measures; EI-wide implementation. 

To construct computer simulations for each of these futures and sensitivities, many assumptions 

and data inputs were developed by the SSC Modeling Work Group (MWG), for consideration by 

IESO
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the SSC. A detailed summary of the assumptions can be found at 

http://www.eipconline.com/uploads/MWG_Recommendations to the SSC March 28 29 Revised 

FINALdocx.pdf. In addition, more information is included in presentations to the SSC, which 

can be found at http://www.eipconline.com/SSC_Meetings.html.

In addition to the information from the NEEM model on additional needed transmission, the SSC 

requested cost estimates for energy efficiency, demand response and distributed generation, as 

well as costs associated with maintaining higher levels of reserve generation to integrate 

conventional generators and renewable generators. High-level estimates of these additional costs 

were developed by the SSC’s MWG in collaboration with Oak Ridge National Laboratory 

(ORNL). 

The SSC chose three scenarios, as shown in 

Selection of Three Scenarios for Phase 2

Table ES 1, for which the EIPC was to develop full 

interregional transmission expansion models in the second phase of the work. These scenarios

were considered by the SSC to be a diverse set of scenarios in terms of policy goals, levels of 

implementation, transmission build-outs, and total cost. Each of the three scenarios had 

specified peak demands and energy levels. They also had required additional annual average 

transfers between NEEM regions over and above the transfers that occurred in the base NEEM 

run that needed to be achieved by the Phase 2 transmission buildout. The peak demands, energy 

requirements and additional average transfers required are included in the descriptions below.

The levels of additional average transfers required were based upon the Phase 1 NEEM analysis. 

More detailed maps of where the additions were required in the EI are included in Appendix 1.
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Table ES 1. Scenario Descriptions for Phase 2 Studies

Scenario 1: Nationally Implemented Federal 

Carbon Constraint with Increased Energy 

Efficiency/Demand Response

• Peak Demand: 565,012 MW

• Total Energy: 2,979 TWh

• Additional Average Transfers Required

above SSI Model Limits:

37,000 MW

Reduce economy-wide carbon emissions by 

42% from 2005 levels in 2030 and 80% in 

2050, combined with meeting 30% of the 

nation’s electricity requirements from 

renewable resources by 2030 and significant 

deployment of energy efficiency measures, 

demand response, distributed generation, smart 

grid and other low-carbon technologies; 

achieved by utilizing an Eastern 

Interconnection-wide implementation strategy. 

The scenario has flat CO2 prices after 2030, 

more wind in the Midwest Independent System 

Operator (MISO) _W, and the MISO 

combined cycle plants and MISO eastern wind 

were dispersed throughout the MISO regions.

Scenario 2: Regionally Implemented National 

Renewable Portfolio Standard

• Peak Demand: 673,108 MW

• Total Energy: 3,621 TWh

• Additional Average Transfers Required

above SSI Model Limits:

3,000-4,000 MW

Meet 30% of the nation’s electricity 

requirements from renewable resources by 

2030; achieved by utilizing a regional 

implementation strategy. 

Scenario 3: Business as Usual

• Peak Demand: 690,492 MW

• Total Energy: 3,687 TWh

• Additional Average Transfers Required

above SSI Model Limits: 

0 MW

Continuation of forecasted load growth, 

existing RPS requirements, and Environmental 

Protection Agency (EPA) regulations as 

proposed and understood in the summer of 

2011. 

The results of the Topic A Phase 1 work are intended to provide information to stakeholders, 

including policy makers, on the combinations of generation (including type of resource and 

location) and transmission transfer increases needed between the NEEM regions to support those 

generation resources. It is important to note that any transmission expansions indicated from the 

macroeconomic studies do not provide a transmission plan, and the generic transmission 

infrastructure upgrades associated with the Phase 1 analysis were high level approximations only 

and do not represent likely project solutions; rather, such information was developed as 

information to assist the SSC in determining the three scenarios to be analyzed during the 

Phase 2 studies. The choice of transmission line types and voltages for expansion of the pipes 

was developed in the same way for all regions for the purpose of the study and does not 

necessarily reflect regionally the actual facilities that would be chosen as a result of a fully 

developed regional planning process. 
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In Phase 2, the EIPC performed N-1 reliability analysis on generation and transmission elements, 

reliability analysis on common tower outages and bus outages and used the results to develop 

more detailed transmission build-outs for the three selected scenarios. Phase 2 included 

performing production cost analysis on each of the three scenarios, using a model that provided a 

security constrained economic dispatch for all 8,760 hours of the year. It also included analyzing 

six sensitivities around them and developing capital cost estimates for the generation and 

transmission included in each of the scenarios. 

Phase 2

Even with this additional detail in Phase 2, the results are indicative only and not representative 

of actual project solutions, which will be determined in regional level transmission planning 

processes as future resource requirements become more certain. 

The EIPC Planning Authorities developed transmission options for the three chosen scenarios in 

collaboration with the Transmission Options Task Force (TOTF), a group designated by the 

SSC. The study year chosen for the analysis was 2030. The transmission planners identified 

five cases for the three scenarios. Scenarios 1: Combined Policies and 2: RPS Implemented 

Regionally required a shoulder case in addition to the traditional peak case because of their 

significant additions of wind generation in remote locations. Scenario 3: Business as Usual 

required only a peak case.

As part of the original project team EIPC chose CRA to perform the production cost modeling 

using the GE MAPS model. In contrast to the NEEM model used in Phase 1, GE MAPS is a 

detailed economic dispatch and production cost model that simulates the operation for the 

electric power system, taking into account transmission topology. Analysis of the three 

scenarios and six sensitivities was performed using the transmission expansion options 

developed in the reliability analysis. The GE MAPS model forecasted energy production costs, 

constraints limiting dispatch and interregional transactions, anticipated emissions, renewable 

energy production, and other pertinent factors. 

Below are three maps (

Reliability Analysis Results – Constraints

Figure ES 3, 

Figure ES 4, and Figure ES 5) showing the overload and voltage constraints identified by the 

Planning Authorities during the reliability analysis conducted for the entire EI for each of the 

three scenarios. These constraints occurred in the model after the generation interconnection 

projects were included in the model. Without the generation interconnection projects, the 

models would not have solved. 

The transmission options developed by the group are designed to reliably serve the load specified 

in each scenario and to meet the interchange between NEEM regions that was specified in the 

scenario. In Phase 1, the NEEM model assumed that each of the NEEM regions had enough 

internal capacity to allow power to move without constraint within each of the regions. In 

Phase 2, the Planning Authorities performed transmission reliability analysis to determine where 

constraints would arise within the regions as well as between the regions. For these analyses, all 

constraints 200 kV and above were addressed by the Planning Authorities. In selected cases, at a 
14 | Page

Planning Authority’s discretion, lower voltages were addressed if the issues were severely 

affecting the 200 kV and above system and/or the area did not have the necessary supporting 

200 kV and above infrastructure.

The results of this analysis comply with selected NERC reliability standards that are described in 

the report; however, because of the study’s long-term nature, it did not include all requirements 

for full compliance with all NERC standards. One example of a NERC standard that was not 

included was testing for transient stability for generators. This is a very detailed requirement that 

would not be addressed in a strategic analysis such as this.

Figure ES 3. Scenario 1 -- Constraints
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Figure ES 4. Scenario 2 – Constraints

Figure ES 5. Scenario 3 -- Constraints
16 | Page

Scenario 1 was the most challenging from a transmission planning perspective because of the 

large amount of additional transfers that needed to occur in the scenario, particularly from 

MISO-West to PJM and from Southwest Power Pool to PJM. In Scenario 2, the bulk of the 

constraints occur in the MISO and SPP regions due to the amount of wind being sited in those 

areas. Some constraints also occur in the southeast states. Scenario 3 has scattered constraints in 

Canada and a number of states. In all three scenarios it was assumed that new natural gas plants 

would be placed at the site of deactivated coal plants, reducing the need for transmission; the 

locations and capacities of natural gas pipelines were not taken into account.

The constraints identified were eliminated with the addition of transmission elements. These 

elements range from transformers to high voltage direct current HVDC MW and extra high 

voltage alternating current (AC) transmission lines that are hundreds of miles long. 

Reliability Analysis Results – Additional Transmission

Below are maps (Figure ES 6, Error! Reference source not found., and Figure ES 7) of the 

transmission fixes that were identified by the Planning Authorities for each of the three 

scenarios. 

Figure ES 6. Scenario 1 – New/Upgraded Transmission

In solving the significant constraints that occurred in the model for Scenario 1, the Planning 

Authorities found that building a larger AC system was not sufficient. New 500 kV HVDC lines 

were added until the most significant constraints were solved. Six 500 kV HVDC lines, each 

capable of carrying 3,500 MW, were needed to reliably achieve the required transfers. In 

addition, there were still significant amounts of 765 kV, 500 kV and 345 kV AC lines that were 
17 | Page

needed to maintain reliability. The maps above show new and reconductored/upgraded facilities 

added to the system for Scenario 1. Over 4,300 miles of existing transmission lines, ranging 

from 115 kV to 345 kV, needed to be reconductored or upgraded. 

In Scenario 1, the required additional average transfers specified by the SSC in Phase 1 were 

37,000 MW

Error! Reference source not found.. Scenario 2 – New/Upgraded Transmission

For Scenario 2, the largest amount of transmission added is from Illinois going east to Ohio and 

Pennsylvania. This 765 kV transmission was developed to move renewable wind power from 

the western to the eastern side of PJM – Rest of Region NEEM region. Other additions involved 

wind collector systems and some additional transmission in other areas. In addition to the new 

lines, over 2,600 miles of lines needed to be reconductored or upgraded. Both the new and 

reconductored/upgraded lines are depicted in Error! Reference source not found.. 
18 | Page

Figure ES 7. Scenario 3 – New/Upgraded Transmission

Scenario 3, because it had no required additional transfers above the limits in the SSI model 

between NEEM regions and new generation was placed first on brownfield sites where 

generation had been deactivated in the model, required very few transmission upgrades to 

support the new generation interconnections. An additional 765 kV line was needed in 

Virginia/West Virginia and 345 kV lines were needed in a few regions. In addition to the new 

lines, over 2,500 miles of existing transmission lines needed to be reconductored or upgraded. 

Both the new lines and the reconductored/upgraded lines are depicted in Figure ES 7.

A comparison of the additional transmission transfers between Phase 1 results and Phase 2 

results shows the additional transmission provided approximately the levels of transfer 

anticipated by the NEEM model. 

The following figures (

Production Cost Results

Figure ES 8 and Figure ES 9) show the installed capacity and total energy 

for each of the three scenarios from the GE MAPS base runs.
19 | Page

Figure ES 8. EI Generation Capacity

Figure ES 9. EI Energy
20 | Page

For Scenario 1: Combined Policy, the largest amount of installed capacity in the Eastern 

Interconnection is wind capacity, followed by combined cycle and demand response. Together, 

these three generation types comprise 64% of the total capacity in the Eastern Interconnection. 

While wind, combined cycle and demand response make up the largest amount of installed 

capacity, the largest amount of generation comes from nuclear power plants, combined cycle and 

wind. Together, they produce 87% of the energy needed for the Eastern Interconnection.6

For Scenario 2: RPS Implemented Regionally, the largest amount of installed capacity in the 

Eastern Interconnection is wind capacity, followed by peakers and coal. Together, these three 

generation types comprise 57% of the total capacity in the Eastern Interconnection. While wind, 

peakers and coal make up the largest amount of installed capacity, the largest amount of 

generation comes from coal plants, nuclear and wind. Together, they produce 70% of the energy 

needed for the Eastern Interconnection. Scenario 2 has a more diverse supply-fuel mix in its 

portfolio than Scenario 1, both in terms of capacity and energy.

For Scenario 3: Business as Usual, the largest amount of installed capacity in the Eastern 

Interconnection is coal, followed by combined cycle and peakers. Together, these three 

generation types comprise 64% of the total capacity in the Eastern Interconnection. While wind, 

peakers and coal make up the largest amount of installed capacity, the largest amount of 

generation comes from coal plants, nuclear and combined cycle. Together, they produce 85% of 

the energy needed for the Eastern Interconnection. 

For Scenario 3, the energy produced by the top three generation types is roughly equal to 

Scenario 1 with coal replacing wind in Scenario 3. Combined cycle and nuclear energy show up 

in the top three energy sources in both Scenarios 1 and 3, producing 50% and 47% of total 

energy, respectively.

Table ES 3 shows the production costs, CO2 emissions costs and emissions levels for each of the 

three scenarios. 

Production Costs and Emissions Results

 6 Total energy on pp. 8 & 17 may not match totals due to interchange and netting hydro.
21 | Page

Table ES 2. Annual Costs, Emissions, Demand and Energy

CO2, SOx and NOx emissions in Scenario 1 are significantly lower than in Scenarios 2 and 3, 

due to the policies that are being modeled. Production costs (fuel and variable O&M) are also 

significantly lower than in Scenarios 2 and 3. In this scenario, EI-wide CO2 costs are explicitly 

modeled based on an underlying CO2 price determined in the Phase I NEEM runs and the 

quantity of emissions from fossil-fueled resources. Those costs are shown in the “Total w/ CO2” 

entry in the table above. The peak demand and energy for Scenario 1 are lower than for 

Scenarios 2 and 3 because of the aggressive energy efficiency/demand response assumptions 

made in Scenario 1. 

Emissions in Scenario 2 are significantly higher than in Scenario 1, resulting from a generation 

portfolio that is more dependent on fossil fuel generation. Production costs are also significantly 

higher than Scenario 1 also due more reliance on fossil-fuel generation. EI-wide CO2 costs were 

assumed at current levels, i.e., only those costs incurred in Regional Greenhouse Gas Initiative 

(RGGI) states in Scenario 2. Thus the CO2 costs shown in the summary above are small.

Emissions in Scenario 3 are the highest of the three scenarios, with no additional environmental 

policies assumed other than implementation of the EPA regulations as they were proposed in 

2011. There are significant CO2 emissions but as with Scenario 2 cost were was assumed by the 

SSC at existing levels for RGGI states. The very low costs in Scenario 3 resulted from these 

assumptions. Overall production costs for Scenario 3 are the highest of the three scenarios, 

roughly $56 billion/year higher than Scenario 1, and $14 billion/year higher than Scenario 2.

In Phase 1, the EIPC and SSC agreed upon an expansion of the transmission inter-regional 

capacity of 37 GW in Future 8 Sensitivity 7, which became Scenario 1 in Phase 2. During the 

Build-out task in Phase 2, both AC and DC lines were added to the grid in order to meet 

reliability constraints during one peak hour and off-peak hour of 2030, while approximating the 

Production Cost Results – Transfers

Scenario 1 Base - 

Combined Policies

Scenario 2 Base - 

RPS Implemented 

Regionally

Scenario 3 Base - 

Business as Usual

Annual Production Costs ($M)

 Fuel 40,802 73,789 85,057

 Variable O&M 6,430 15,502 18,411

 Total Production Costs ($M) 47,231 89,291 103,469

 CO2 Costs ($M) 45,340 126 154

 Total w/CO2 92,571 89,416 103,622

Emissions (short tons)

 SO2 (000) 93 873 1,122

 NOx (000) 21 1,300 1,771

 CO2 (millions) 358 1,391 1,792

Peak Demand (MW) 565,012 673,108 690,492

Energy (TWh) 2,979 3,621 3,687
22 | Page

power generation and loads from Phase 1. The transmission system for the BAU case was 

similarly built-out for the peak hour in 2030.

These transmissions systems were then modeled in GE MAPS for all 8760 hours. The results 

from MAPS show greater tieline flows between the regions in both scenarios than were in Phase 

1. Peak inter-regional flows are higher by a combined total of 117 GW; average flows over the 

8760 hours are higher by 58 GW.

The build-out (from Phase 2 used in MAPS) ended up requiring more transmission capacity 

(than shown in Phase 1 by NEEM) to meet reliability constraints, and MAPS used that capacity 

to the maximum extent possible..

The three scenarios were intentionally chosen by the Stakeholder Steering Committee to 

represent “bookend” scenarios; scenarios that were very different in the amount of transmission 

that would be needed to support them. Below is a table showing the quantified costs for each of 

the three scenarios. Costs are represented in two ways, annual costs for the year 2030 and 

“overnight” capital costs for all transmission and generation installed through 2030. For 

summary purposes, mid-level costs are presented. All costs are represented in $2010 Billions.

Scenario Cost Results

The production costs shown are for a single year – 2030. Production costs occur each year, and 

will vary each year depending on the supply mix and demand; in Phase 2 of the EIPC process, 

only a single year’s production costs (2030) were computed. The capital costs presented below 

are “overnight” capital costs. As the name implies, “overnight” capital costs represent the capital 

cost of a project if it could be built overnight - they do not include the interest costs of funds used 

during construction.
23 | Page

Table ES 3. Quantified O&M and Capital Costs

The analysis did not include social benefits and costs that would arise from the different policies 

modeled. Also not included in the above are costs for:

1. Lower voltage transmission projects

2. SSI generation and transmission projects (common to all three scenarios)

3. Generation interconnection costs not included in the overlays, i.e., the generator step-up 

and the lead lines to the first breaker – the costs for the generator interconnection 

overlays are included

4. Generation deactivation/decommissioning

5. Capital costs for existing units

6. Transmission O&M.

Costs

Scenario 1: 

Combined 

Policy

Scenario 2: 

RPS 

Implemented 

Regionally

Scenario 3: 

Business 

as Usual

Production Costs - Fuel $ 40.8 $ 73.8 $ 85.1

Production Costs - Variable O&M $ 6.4 $ 15.5 $ 18.4

CO2 Costs $ 45.3 $ 0.1 $ 0.2

Policy Driven Energy Efficiency $ 8.9 $ 1.5 $ 1.5

CO2 Price Driven Energy Efficiency $ 10.0 $ - $ -

Demand Response $ 0.6 $ 0.3 $ 0.3

Variable Resource Integration $ 2.9 $ 2.5 $ 1.0

Thermal Contingency $ 3.8 $ 5.0 $ 6.2

Fixed O&M $ 34.7 $ 52.1 $ 48.1

Total O&M Costs $ 153.4 $ 150.9 $ 160.7

Costs Scenario 1 Scenario 2 Scenario 3

Transmission - Generation 

Interconnection $ 49.6 $ 54.3 $ 7.3

Transmission - Constraint Relief $ 48.4 $ 13.0 $ 7.9

Transmission - Voltage Support $ 0.5 $ 0.1 $ 0.2

Generation $ 868.1 $ 679.4 $ 242.3

Nuclear Uprates $ 4.9 $ 4.9 $ 4.9

Pollution Retrofit Costs $ 6.8 $ 20.2 $ 22.0

Distributed Generation $ - $ - $ -

Total Capital Costs $ 978.2 $ 771.9 $ 284.6

2030 O&M Costs - ($2010 Billions)

Overnight Capital Costs for Capital through 2030 ($2010 Billions)
24 | Page

Six stakeholder-specified sensitivity analyses were performed using the GE MAPS model. A 

significant concern of many stakeholders was the level of wind curtailment (15% over the EI and 

rising as high as 25%-40% in some regions) in Scenario 1: Combined Policies. The sensitivities 

performed are described below. The first four sensitivities listed were intended to address the 

wind curtailment issue. 

Sensitivity Analysis and Results

1. Scenario 1: Combined Policy – Loads were increased by 5%.

2. Scenario 1: Combined Policy – Increased flexibility and availability of spinning reserves.

3. Scenario 1: Combined Policy, Flowgate Relief – Increase flowgate capacity on top 25 

binding flowgates by 50%. These flowgates involved seven transmission elements. 

These changes were applied to the High Spin sensitivity case rather than to the Base S1 

model. 

4. Scenario 1: Combined Policy, Reduced Wind – Reduce the wind build-out in the highly 

constrained wind regions. Reduction amount was based on how much wind reduction 

occurred in the top four curtailed regions in the base run and totaled 35 GW. 

5. Scenario 3: Business as Usual, High Gas Prices – Gas prices were increased by 25% 

across all seasons.

6. Scenario 3: Business as Usual, Higher Loads – Loads were increased by 5% across all 

regions and time periods.

The following table summarizes the results of the four sensitivities designed to investigate the 

wind curtailment issue. 

Scenario 1 Sensitivity Results: Wind Curtailment 

Table ES 4. Sensitivity Results – Production Costs, Emissions and Wind Curtailment

Base High Load

High Spin 

Availability

 +Flowgate 

Relief

Reduced 

Wind

Annual Production Costs ($M)

 Fuel 40,802 45,805 39,552 39385 42630

 Variable O&M 6,430 6,932 6,457 6443 6536

 Total Production Costs ($M) 47,231 52,737 46,010 45828 49165

 CO2 Costs ($M) 45,340 52,360 43,153 42825 47586

 Total w/CO2 92,571 105,097 89,163 88654 96751

 % Increase - 14% -4% -4% 5%

Emissions (short tons)

 SO2 (000) 93 113 92 92 99

 NOx (000) 21 25 21 21 23

 CO2 (millions) 358 413 340 338 375

 % Increase in CO2 - 15% 5% 6% 5%

Wind Curtailment

 Wind Curtailment (TWh) 131 119 120 110 64

 Percentage Curtailed 0.15 0.14 0.14 0.13 0.09

 % Change in Curtailment - -10% -9% -16% -51%

Scenario 1 - Combined Policies
25 | Page

In the High Load sensitivity production costs increased by 14% and CO2 emissions by 15%. 

Wind curtailment was reduced from 131 TWhs to 119 TWhs, or approximately 10%.

The High Spin Availability sensitivity reduced production costs by 4% and CO2 emissions by 

5%. Wind curtailment was reduced from 131 TWhs to 120 TWhs or approximately 9%. 

The Flowgate Relief sensitivity decreased the production costs and CO2 emissions slightly from 

the High Spin Availability results. It does, however, decrease the wind curtailment from 120 

TWhs in the High Spin Availability to 110 TWhs, reducing the overall wind curtailment by 16%

when compared to the Base Case.

The Reduced Wind sensitivity increases both production costs and CO2 emissions by 5% and 

reduces the wind curtailment to 64 TWhs. If compared on an absolute value basis to the wind 

curtailment in the S1 Base, this represents a 51% reduction. Comparing on a percentage basis, 

because of the reduced wind potential in the sensitivity, still shows a wind curtailment reduction 

of approximately 43%. 

The relative sizes of the impacts from Flowgate Relief and Reduced Wind, cannot be compared, 

however, because the relative changes that were made are very dissimilar. Although the 

Flowgate Relief sensitivity increased flows by 50% on the affected elements, only seven

transmission elements in three regions were adjusted. In the Reduced Wind case, wind 

generation in four of the largest wind producing regions in the EI were reduced significantly.

The final two sensitivities involved increasing load and gas prices in S3. Increasing gas prices 

by 25% in all seasons reduced the use of combined cycle plants and increased the use of coal. 

This resulted in production costs increasing by 10% overall and emissions increasing from 2%-

12%, depending on the emission type. Increasing load by 5% increased the use of combined 

cycle plants and, to a lesser extent, combustion turbines and coal. This resulted in increased 

production costs of 9% overall, and increased emissions in the 5-6% range.

Scenario 3 Sensitivity Results: Natural Gas Price and Load Increases

Table ES 5. Sensitivity Results –Production Costs, Emissions, Load and Gas Prices

S3 Base S3 Hi Gas S3 Hi Load S3 Hi Gas S3 Hi Load

Fuel $ 85,057 $ 94,326 $ 93,317 11% 10%

Variable O&M $ 18,411 $ 19,072 $ 19,407 4% 5%

Total $ 103,469 $ 113,398 $ 112,724 10% 9%

CO2 $ 154 $ 150 $ 178 -3% 16%

Total w/ CO2 $ 103,623 $ 113,548 $ 112,902 10% 9%

S3 Base S3 Hi Gas S3 Hi Load S3 Hi Gas S3 Hi Load

NOx (000) 1,122 1,171 1,184 4% 6%

SO2 (000) 1,771 1,988 1,880 12% 6%

CO2 (millions) 1,792 1,833 1,889 2% 5%

Production Costs ($2010 Millions) Change from the Base (%)

Emissions (short tons) Change from the Base (%)
26 | Page

Following the completion of Phase 1 of the project, some initial observations were drawn by 

stakeholders as follows: 

Observations and Guidance

• This project represents a unique dialogue with many different stakeholder groups on 

public policy and interconnection-wide transmission analyses to increase understanding 

of alternative policy futures and the generation and transmission that might be needed to 

support them. It does not require one size fits all projects or solutions, nor does it make 

any conclusions regarding market driven versus vertically integrated utility models. It 

does, however, show potential ways to accommodate differing stakeholder-chosen policy 

futures. The EIPC analysis will continue to be a valuable contributor to both the utility 

and the regulatory functions in their efforts to efficiently advance the electricity industry. 

• Although previous experience of the participants has been in transmission planning 

exercises that are generally more limited in geographic scope and involving fewer 

participants than the analyses conducted by EIPC, the Topic A project work involving a 

larger team over the full Eastern Interconnection proceeded well. 

• The interaction between Planning Authorities and state participants also developed a 

communication capability that will serve the nation well in the future. 

• It is expected that the participants will use the experience for continuing and enhancing 

future coordination efforts and that all of these efforts will help guide the U.S. in 

considering and establishing potential national goals for energy. 

Phase 2 continued the open and productive dialogue between the EIPC, states and stakeholders. 

Because of the nature of the work in Phase 2, the discussions were focused on traditional 

transmission planning and production cost analysis and were somewhat more technical in nature. 

General Observations from Phase 2 include:

• The goal of the DOE’s Funding Opportunity Announcement, “to prepare analyses of 

transmission requirements under a broad range of alternative futures...” has been met. 

The project is not intended to supplant existing regional planning processes. 

• The project was very helpful in understanding the complexity of interconnection-wide 

transmission planning. 

• The futures developed represent significantly different policy drivers and the project has 

provided a great deal of information on these three scenarios. 

• The results of Phase 2 serve as indicative transmission build-outs that present options that 

could be considered as part of a more traditional planning process that involves analyzing 

more model years, considering all NERC mandatory compliance criteria and evaluating 

the economic benefits of specific transmission projects or groups of projects as resource 

plans become more certain.

• Transmission reinforcements presented in this report are not an absolute indication of the 

required transmission reinforcements since the scope of this project was limited to 

evaluate specified alternatives and considered only higher voltage level additions and 
27 | Page

constraints and did not consider all mandatory NERC planning requirements. In addition, 

necessary simplifying assumptions used for this analysis regarding the choices of how 

transmission facilities are configured, the impact of fuel supply variations on resource 

availability, and other factors would be taken into account in the final determination of 

required transmission reinforcements.

• Much more detailed analysis, iteration and optimization than was possible in the project 

would be needed to develop actual detailed transmission plans. 

In the last quarter of 2012, The Keystone Center, the facilitator of the EIPC stakeholder process,

conducted a number of interviews with various members of the stakeholder process and EIPC 

planning authorities to gather input about whether these goals were met. 

Stakeholders found the overall process to be extremely worthwhile and they are pleased to have 

participated. Stakeholders across the board agreed that the EIPC process had great value and 

elements of EIPC should continue in the future. Stakeholders in general developed more trust of 

the PAs’ process and over time relied more heavily on their input and judgment. Stakeholders

particularly saw value in:

• The openness, inclusiveness and transparency of the process

• The opportunity to learn more about transmission planning and have input into the 

process

• The structure and balance of the SSC

• The independence of the Chair, Vice-Chair and facilitators

• The willingness and ability of the chairs to develop straw proposals when the group 

faced difficult or contentious issues

• The relationships and understanding that developed over time

• The working groups’ ability to delve into the details and make recommendations to the 

SSC

• The access to data and information on the web site

• The DOE requirement to come to consensus; at first, stakeholders were concerned 

about this requirement but believed it ultimately led to a better understanding of others’ 

positions and more creative ideas to achieve consensus.

Stakeholders also identified the following challenges/opportunities:

• Understanding the transmission planning process and the models used

• The inability to iterate the analysis more frequently; i.e., to review the results from a 

smaller set of analysis before determining next steps 

• More time was needed to consider the results of the analyses and the voluminous data 

generated

• The stakeholder balance designed into the SSC structure did not always materialize in 

the process.

In addition to process Observations and Guidance, there were also Observations and Guidance 

on the analytical process undertaken. These are listed below:
28 | Page

• The transmission option analysis presented here represents a single snapshot in time for 

each of three very different scenarios. It focuses on a snapshot of a specific year – 2030. 

Traditional transmission planning analyzes interim years typically utilizing models for 

one, five, and ten years out rather than “jumping” out twenty years. The results of this 

transmission analysis might be very different if it were done in a more incremental 

fashion. Future studies may wish to look at smaller time intervals – e.g., 5, 10 and 15 

years.

• The interrelationships of various energy related infrastructures may need to be considered 

further to better understand how these relationships might impact the broad range of 

alternative futures. One example is the relationship between the natural gas supply and 

delivery infrastructure and the electric transmission system highlighted in Phase 1 of the 

project.

• There are many ways to implement a given policy initiative and different forms of 

implementation may require different generation and transmission. 

• The cost estimates in the project are based on a variety of generalized assumptions and 

are only broadly indicative on a relative basis between the futures. A number of 

potentially significant costs were not included. 

• Future interconnection-wide studies may wish to consider a more iterative process, 

allowing for opportunities to review the analysis results before making decisions on the 

next part of the analysis.

• Many planning authorities are already doing transmission expansion planning that 

considers economic criteria in addition to reliability criteria. Future interconnection-wide 

transmission planning exercises should consider doing so as well.

At the final SSC meeting of the project, the Chairs proposed and the SSC accepted, with 

revisions, a document outlining their observations and guidance for the use of the report. This 

memo is included in its entirety in Section 6.0 - Observations and Guidance of this report. 
1 | Page

Report

1.0 Introduction and Background

The Eastern Interconnection Planning Collaborative (EIPC) received funding from the U.S. 

Department of Energy (DOE) in 2010 to initiate a broad-based, transparent collaborative process 

to involve interested stakeholders in the development of policy futures for transmission analysis. 

This report describes the work performed in Phase 2 of the project and forms a companion 

document to the report published in December 2011 that encompasses Phase 1 of this analysis. 

Regional, multi-regional, and interconnection-wide studies and planning provide the potential for 

improvements in reliability and significant economic benefits for ratepayers when compared to 

the alternative approach of planning only on a local basis. They also provide the potential for the 

following: 

• Increased opportunities for states and federal agencies to work cooperatively on planning, 

siting, and constructing new (or upgraded) infrastructure to better ensure that necessary 

infrastructure is constructed in a timely manner. 

• Expanded opportunities to work with Planning Coordinators and other stakeholders on 

routine planning matters apart from contested proceedings. 

Throughout the Eastern Interconnection, Planning Coordinators (formerly called Planning 

Authorities) manage their individual local and regional planning processes. The EIPC was 

initiated by a coalition of regional Planning Coordinators and represents a first-of-its-kind effort 

to involve Planning Coordinators throughout the Eastern Interconnection to model the impact of 

various policy options determined to be of interest by state, provincial and federal policy makers, 

and other stakeholders on the entire Eastern Interconnection. The work of the EIPC builds upon, 

rather than replaces, the current local and regional transmission planning processes implemented 

by the Planning Coordinators and associated regional stakeholder groups within the Eastern 

Interconnection. 

1.1 DOE Funding Opportunity Announcement – Overview and Purpose 

In June 2009, DOE issued a Funding Opportunity Announcement (FOA), DE-FOA-0000068, 

which provided funding to prepare analysis of transmission requirements under a broad range of 

alternative futures. The DOE FOA covered two specific topics. Topic A was to fund 

Interconnection-level analysis and planning work while Topic B was to fund cooperation among 

States on electric resource planning and priorities. DOE anticipated issuing three awards under 

each Topic, corresponding to the three geographic areas served by the three major 

interconnections (Eastern, Western, and Texas). 

In August 2009, the Planning Coordinators in the Eastern Interconnection reached agreement 

through a formal contract on the formation of the EIPC. The group developed a proposal 

submitted by PJM Interconnection, LLC (PJM) in August 2009, on behalf of the EIPC to 

perform the Topic A work under the DOE FOA. All 26 EIPC members support the work 

prescribed for Topic A. Eight of the 26 members are designated as Principal Investigators, who 

bear additional responsibilities with respect to project execution, management and reporting, 
2 | Page

along with American Transmission Co., which is a sub-recipient. PJM serves as the lead 

Principal Investigator for the project. 

The Eastern Interconnection Topic A cooperative agreement awarded to PJM, DE-OE0000343, 

is titled the Eastern Interconnection Planning Collaborative (EIPC). EIPC chose to retain 

Whiteley BPS Planning Ventures, LLC, to support project management; The Keystone Center 

(Keystone) to support stakeholder process facilitation; and Charles River Associates (CRA) to 

support macroeconomic analysis and production cost studies. 

In response to DOE’s FOA, the 39 States in the Eastern Interconnection, along with the District 

of Columbia and the City of New Orleans, came together to form the Eastern Interconnection 

States Planning Council (EISPC). The National Association of Regulatory Utility 

Commissioners (NARUC) applied to DOE, on behalf of EISPC, for funding under the FOA’s 

Topic B for the Eastern Interconnection. 

The Eastern Interconnection Topic B cooperative agreement was awarded to NARUC. 

NARUC’s project, DE-OE0000316, is titled the Eastern Interconnection States Planning Council 

(EISPC). Similar application and award negotiations occurred for both Eastern Interconnection 

awards. The Eastern Interconnection Topic A and B recipients made a special effort to 

coordinate their work. 

Once created, EISPC and the Stakeholder Steering Committee (SSC) each created their own 

internal organizational structures, as well as By-Laws governing meetings, communications, 

governance and collaborative decision-making processes. 

1.2 Statement of Project Objectives 

PJM’s and NARUC’s awards each incorporate a Statement of Project Objectives (SOPO). Each 

applicant to the FOA submitted a draft SOPO that, following selection, was revised during award 

negotiations. The SOPO provides project objectives, tasking, and required deliverables. The 

negotiated SOPOs are included in Appendices 1 and 2 of EIPC’s Phase 1 interim report. 

Two objectives were stated in the EIPC SOPO: 

7. Establish processes for aggregating the modeling and regional transmission expansion 

plans of the entire Eastern Interconnection and perform interregional analyses to identify 

potential conflicts and opportunities between regions. This interconnection-wide analysis

would serve as a reference case for modeling various alternative grid expansions based 

on the scenarios developed by stakeholders. 

8. Perform scenario analysis as guided by broad stakeholder input and the consensus 

recommendations of a stakeholder committee formed under the proposal. The analysis 

would serve to aid federal, state, and provincial regulators, as well as other policy makers 

and stakeholders in assessing interregional options and policy decisions. 

1.3 Scope and Schedule of Work 

The scope of work proposed by the EIPC in the SOPO was divided into 13 tasks within two 

phases. Phase 1 included the following tasks: 
3 | Page

• Task 0 – Project Management and Planning 

• Task 1 – Initiate Project 

• Task 2 – Integrate Regional Plans 

• Task 3 – Production Cost Analysis of Regional Plans 

• Task 4 – Macroeconomic Futures Definition 

• Task 5 – Macroeconomic Analysis 

• Task 6 – Expansion Scenario Concurrence 

Phase 2 of the project proposed developing and analyzing transmission expansion options for the 

three scenarios selected by the SSC in Task 6 at the end of Phase 1. For each of the three 

scenarios selected, the work in Phase 2 includes the following tasks: 

• Task 7 – Interregional Transmission Options Development 

o Modify powerflow models built in Task 2 to create interregional transmission 

expansion models for each scenario.

o Develop and test transmission options that will provide reliable delivery of the 

power transfers specified by the NEEM model and create a reliable transmission 

system within and between each NEEM region in accordance with selected (but 

not all) NERC reliability criteria. 

• Task 8 – Reliability Review 

o Perform reliability analysis consistent with NERC reliability criteria regarding 

bus outages, common tower outages and combination generation/transmission 

element outages on each scenario. 

o Develop flowgates required in Task 9 for performing production cost analysis.

• Task 9 – Production Cost Analysis of Interregional Expansion Options 

o Develop the necessary inputs for the production cost model (GE-MAPS) 

consistent with scenario assumptions used in the NEEM model.

o Perform economic analysis using production cost modeling for each scenario. 

• Task 10 – Generation and Transmission Cost Estimates 

o Perform high-level cost estimates for transmission expansion options for each 

scenario. 

o Develop costs associated with resource additions and retirements for each 

scenario. 

• Task 11 – Review of Results 

o Produce a draft report on the Phase 2 effort. 

o Present the results of the analysis, respond to questions, and solicit input from 

stakeholders. 
4 | Page

o Provide SSC consensus-based comments on the draft report. 

• Task 12 – Phase 2 Report 

o Review the input received from the SSC and address it in the final report. 

There have been two core changes to the SOPO initiated by the SSC and supported by DOE. 

The first was to replace the Planning Authorities’ Roll-up Model with a new Stakeholder 

Specified Infrastructure (SSI) model to serve as the starting point for all of the remaining DOE 

project work. The second change to the SOPO related to eliminating the production costing 

work that was planned under Task 3 in Phase 1 of the project. 

The Eastern Interconnection Topic B project leader, EISPC, also had an SOPO including 

objectives, scope and tasks. 

Per the SOPO, the objective of EISPC is to provide for cooperation among states on electric

resource planning and priorities. NARUC will facilitate dialogue and collaboration among the 

states in the Eastern Interconnection and thus enable them to develop more consistent and 

coordinated input and guidance for the regional and interconnection-level analyses and planning 

that will be done under the Topic A award for the Eastern Interconnection. 

EISPC’s scope includes the following: 

• Identify Eastern Energy Zones of particular interest for low- or no-carbon electricity 

generation. The Recipient will allow for regional diversity and determine how the 

identification of Eastern Energy Zones could best serve the collective interests of the 

affected states. 

• Conduct studies on key issues related to reliable integration of variable renewables into 

the Eastern Interconnection and any other studies needed to better enable member state 

participation in regional and interconnection-wide analyses and planning. 

• Develop other inputs as needed to go into the interconnection-level analyses prepared 

under the Eastern Interconnection Topic A work. 

• Provide insight into the economic and environmental implications of the alternative 

electricity supply futures and their associated transmission requirements developed for 

the Eastern Interconnection under Topic A. 

• Demonstrate (and develop if necessary), a process for reaching decisions and consensus 

appropriate for an interconnection-wide entity representing all of the states and provinces 

in the Eastern Interconnection so as to participate in the development and updating of the 

long-term interconnection-level plan under Topic A. 

EISPC’s eight tasks are as follows: 

• Task 1 – Organizational development and project management. 

• Task 2 – Reach consensus decisions on the Recipient’s position on modeling inputs and 

assumptions via expansion of transmission planning knowledge base.
5 | Page

• Task 3 – Assemble data for analysis of Eastern Interconnection Topic A Roll-up 

Integration Case and reach consensus on feedback and input into the Eastern 

Interconnection Topic A. 

• Task 4 – Conduct studies to facilitate further refinement of the modeling inputs and 

future scenarios. 

• Task 5 – Prepare White Papers. 

• Task 6 – Reach consensus on the Recipient’s positions on the future scenarios for 

macroeconomic analysis to be conducted by Eastern Interconnection Topic A Recipient. 

• Task 7 – Reach consensus on the Recipient’s positions on the transmission build-out

scenarios to be conducted by the Eastern Interconnection Topic A Recipient. 

• Task 8 – Participate in Eastern Interconnection Topic A activities. 

The DOE FOA specified that the project work is to be completed by June 30, 2013. Phase 1 of 

the project was completed in December 2011. The current schedule, issued in mid-2011, calls 

for the completion of Phase 2 in December 2012, well ahead of the original June 2013 deadline 

set in the DOE FOA. 

1.4 Three Scenarios Analyzed in Phase 2

1.4.1 Scenario 1: Nationally-Implemented Federal Carbon Constraint with Increased Energy 

Efficiency/Demand Response 

The first scenario selected for Phase 2 study was a national carbon constraint and demand 

reduction scenario, driven by a nationally implemented CO2 price, as well as significant 

penetration of energy efficiency (EE) and demand response (DR). Costs of EE and DR are 

assumed to be partially offset by the CO2 revenues. 

The scenario includes a CO2 price that escalates annually to achieve a 42% reduction in CO2

emissions from 2005 levels throughout the economy by 2030, but then becomes flat after 2030. 

The scenario also includes very aggressive EE/DR assumptions; however, much of the reduction 

in demand is due to adjustments in demand from the higher energy prices driven by the CO2

price signals. The combined effect of the aggressive EE/DR and the carbon price results in a 

19% reduction from 2011 Eastern Interconnection-wide demand by 2030 and greater than 30% 

of energy delivered with renewable resources. The peak demand in the Eastern Interconnection 

used in this scenario was 565,012 MW, resulting from the assumption in Phase 1 that aggressive 

energy efficiency and other forms of demand response would reduce the actual demand from 

2011 levels by 1% per year. In addition, for Scenario 1, because of the significant wind buildout an off-peak case was needed as part of the reliability analysis. The demand used in modeling 

the transmission system in the off-peak case was 351,750 MW.
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This first scenario results in the most expansive transmission build-out of the three scenarios, 

and, based on the clustering analysis conducted as part of Phase 1, is anticipated to be robust 

enough to accommodate the transmission needs under a number of the futures analyzed in 

Phase 1:

• Future 5: National Renewable Portfolio Standard – National Implementation, 

• Future 2:National Carbon Constraint – National Implementation, and 

• Future 4: Aggressive Energy Efficiency, Demand Resources and Distributed Generation. 

The required additional transfers over the limits in the SSI model that were identified in the 

NEEM analysis for Scenario 1 were approximately 37,000 MW. 

1.4.2 Scenario 2: Regionally Implemented National Renewable Portfolio Standard

The main defining characteristic of this scenario is the deployment of significant amounts of 

local renewable energy. Scenario 2: Regionally Implemented National Renewable Portfolio 

Standard requires that 30% of each region’s load in 2030 be met with renewable resources within 

that region to the extent possible. The scenario assumes that a load serving entity has the option 

to meet the requirement by purchasing renewable energy credits from other entities. The 

definition of qualified renewable facilities includes wind, solar, geothermal, biomass, landfill 

gas, fuel cells using renewable fuels, marine hydrokinetic, and hydropower. This future results 

in moderate transmission expansion and investment with additional transfers of 3,100 MW. The 

peak demand for the Eastern Interconnection in this scenario was 673,108 MW, while the offpeak demand utilized was 421,692 MW. 

The greater diversity in supply mix, including with coal, gas, wind, nuclear, hydropower, 

offshore wind and other renewable technologies generation, was an important reason why the 

SSC selected this scenario. Additionally, stakeholders supported the selection of Scenario 2

because, in combination with the other two scenarios chosen, it provides information about a 

wide range of policy drivers. Moreover, in light of current economic and political 

circumstances, the SSC agreed that the enactment of higher RPS requirements is more likely 

than additional state-by-state carbon regulations.

This scenario was modeled using seven super regions, designed to enable regions to meet the 

RPS goals using regional resources first. Super regions are made up of multiple NEEM regions 

and align in most cases with the regional Planning Coordinator boundaries. The objective of this 

scenario was to have each “Super Region” supply its own renewable resources. To implement 

this regional approach, transfer limits between super regions were not permitted to expand. 
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Figure 1-1 is a depiction of the NEEM regions that make up each super-region. 

Figure 1- 1. NEEM Regions (blue) and Super-Regions (black)

In addition, the Eastern Interconnection interfaces with Hydro Quebec, WECC and ERCOT are 

represented using export/import border assumptions, as is the Maritimes portion of the Eastern 

Interconnection. 

1.4.3 Scenario 3: Business as Usual

The Business as Usual scenario is characterized by continuation of current federal, state, and/or 

regional energy or related environmental policies and programs without enactment of new 

policies. Proposed EPA regulations from summer 2011, including the Transport Rule, Utility 

MACT Rule, Utility NSPS Rule, Coal Combustion Residuals Rule, and Cooling Water Intake 

Structures Rule, are assumed to be implemented. Policies and/or regulations with an 

expiration/sunset date were renewed on a case-by case basis. The assumptions regarding EPA 

regulations led to the retirement of roughly 82 GW of coal capacity (by 2020 – see Phase I, 

F1S17 (BAU) Stakeholder Report Build Summary); based on the results of the Phase I economic 

IESO
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resource expansion process, this generation (and other retiring oil/gas steam generation) was 

replaced with natural gas combined cycle and combustion turbines, nuclear generation, and wind 

generation to collectively meet capacity reserve requirements and the state RPS requirements. 

Fuel prices remain stable and there are no major technological advances. The peak demand for 

the Eastern Interconnection in this scenario is 690,942 MW. 

In this scenario, the SSC decided not to expand NEEM transfer limits beyond the projects that 

were specified as part of the SSI. Below is a map of the transmission additions that were 

accepted as part of the SSI. 

Figure 1- 2. SSI Transmission Additions

The Business as Usual scenario had a significant number of generation deactivations and new 

builds. The Planning Authorities expected this to cause the need for some transmission 

development within the NEEM regions to ensure continued system reliability. Given the load 

levels in this scenario, the Transmission Options Task Force decided that many of the 

deactivated generation units would be replaced with new, different types of generation at the 

same location, as this was more efficient from a transmission development perspective. 

Figures 1-3 and 1-4 depict the resultant generation capacity and energy based on stakeholder 

specified assumptions utilized in the all three scenarios.

Transmission Voltage

100-161

230-287

345

500

735+

DC Line

Proposed Transmission

230-287

345

500

735+

DC Line

Substation

Transmission Constraint

Transformer Constraint

Stakeholder Specified Infrastructure
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Figure 1- 3. EI Generation Capacity

Figure 1- 4. EI Energy
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Phase 1 of the project focused on developing the stakeholder processes, developing and 

specifying inputs for eight different futures and an additional seventy-two sensitivities, and 

identifying the generation resources (location, type and amount) and additional transfers needed 

to support the futures. This effort involved stakeholders in direct and detailed conversations 

developing the futures and sensitivities and the many inputs needed for analysis. Stakeholders 

were also directly involved in reviewing results and choosing the final three scenarios.

1.5 Phase 2 Work 

Phase 2 Tasks 7 and 8 of the project were more engineering-focused with the transmission 

planning engineers of the Planning Authorities building models for the three scenarios and 

testing those models against specific NERC reliability criteria. Because some of the data and 

information shared in the process was deemed Critical Energy Infrastructure Information (CEII), 

precautions were necessary to ensure that those stakeholders receiving that information were 

authorized to receive CEII and a process was set up for stakeholders to receive CEII clearance if 

they needed it. In addition, the EIPC requested that members of the Transmission Options Task 

Force be technically qualified to participate in the transmission planning discussions.

The Planning Authorities used the models to identify overloads on the system (line trying to 

carry more power than it is designed to carry) or Voltage issues (Voltage either too high or too 

low). Then, they identified possible transmission fixes for the contingencies and tested those 

transmission options in the models to ensure the transmission system would operate reliably.

The Planning Authorities also developed the flow gates needed for Task 9, Production Cost 

Analysis, and the high-level transmission cost estimates needed for Task 10.

Task 9 of Phase 2 involves developing production cost estimates of each of the three base 

scenarios and an additional six sensitivities. The work was performed by Charles River 

Associates using the GE-MAPS7

The Modeling Work Group (MWG) was reconvened to develop the inputs needed for the 

production cost modeling and to recommend sensitivities to the SSC. The guiding premise of the 

group was that inputs would remain the same as the inputs that were developed for the NEEM 

model. Where more specificity was needed, the inputs would be consistent with the NEEM 

assumptions and outputs.

model. In a change from the approach in Phase 1, the base 

scenario results were made available to stakeholders before the sensitivity analyses needed to be 

decided on. 

The production cost base model runs for each Scenario were performed and presented to the 

Stakeholder Steering Committee. In addition, six sensitivities were available to provide more 

insight into the model results. There was stakeholder concern about the level of wind curtailment 

in Scenario 1: Combined Policies and ultimately four of the six sensitivity runs were used to 

understand this issue better. The other two sensitivities were applied to Scenario 3: Business as 

Usual and involved changes in load and natural gas prices. In addition, high use of Demand 

Response and high Locational Marginal Prices in the southeast were explored with the 

sensitivities. 

 7 The model used is the [spell out full name} and is licensed by the General Electric Company.
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1.6 Unique Study Characteristics 

This is a first of its kind effort for the Eastern Interconnection. As such, it has a number of 

unique study characteristics that are not found in local or regional planning processes. A number 

of these characteristics are laid out below. 

• Complexity and differences among the regions should be accommodated. 

• SSC provided modifications to the roll-up as a starting point for resource analyses. 

• SSC negotiated input assumptions need to be placed into context. 

• Stakeholder consensus process worked well and needed decisions were made. 

• Process has led to a better understanding of regional similarities and differences and to 

the degree of complexity involved in an analysis of such a broad and diverse region. 

• Process has provided all participants with a great deal of information that should be 

useful if similar studies are done in the future. 

• Because of the complexity of factors involved in this type of study, there was never any 

intent to optimize or “co-optimize” every input to the model. There was also no intent to 

co-optimize the mix of transmission and generation in a particular scenario. Due to time 

and resource constraints, such co-optimization was not possible.

• The transmission planning analysis that was completed is an “indicative” result; it 

provides a relative indication of the amount and type of transmission that would be 

needed under each scenario.

• The transmission planning analysis is a strategic snapshot in time, utilizing year 2030. 

Traditional transmission planning is much more incremental and an analysis would 

typically be done for five and ten years out rather than twenty years out into the future.