i | Page 

# 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 , 2012ii | Page 

# 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

................................ ................................ ......................... 11iii | Page 

# List of Figures

Figure ES 1. Stakeholder Specified Infrastructure

................................ ................................ ........ 9 Figure ES 2. NEEM Reg ions (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

................ 251 | Page 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 respo nsibility 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 se rvice 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 n ot 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 s tate electric facility approval or siting processes

. The work of the Eastern Interconnection States Planning Council or the Stakeholder Steering Committee does not bind any s tate agency or Regulator in any s tate proceeding.2 | Page Executive Summary
In mid

- 2009 the Department of Energy (DOE) issued a funding opportunity announcement DE

FOA

- 0000068 “Resource Assessment and Interconnection

- level Transmission Analysis and Planning , ” directed towards the Eastern, West ern, 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 members 1

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 Inter connection (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 Eff iciency/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 in terim 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 ch osen 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 i nteraction with the Eastern Interconnection Topic B recipient of D O E

- FOA

- 0000068, the National Association of Regulatory Utility Commissions (NARUC), and the state representative’s group formed through their award, the Eastern Interconnection States Planni ng 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 I nterconnection

L evel T ransmission P lanning A nalysis 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 Company3 | Page With the compl etion of the Phase 2 work by EIPC, the Eastern Interc onnection 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 interrelatio nships 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 natu ral gas supply and delivery infrastructure and the electric transmission system. T his 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. W hile the results we re not intended as a specific plan of action or for use in any s tate 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 stud y of its kind, the work provided insights to EIPC members regarding how future studies may be performe d and how future interconnection s may develop. Other benefits of the study included an interaction and development of experience between Planning Authorit y 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 improve ment in the future

. The EIPC is grateful to DOE and to all the above participants for their contributions

.4 | Page 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 Transmission5 | Page Figure ES

- 3. Scenario 3: Business as Usual

– New/Upgraded Transmission

Sce nario 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 Renewabl e 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 Transmission6 | Page 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 ben efits 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 co sts 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)7 | Page 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 E astern I nterconnection 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 a n FOA , “Resource Assessment and Interconnection

- Level Transmission Analysis and Planning,” DE

- FOA

- 0000068, funded by the Amer ican Recovery and Reinvestment Act of 2009 ( ARRA )

. The FOA’s objective was to support development of grid capabilities in the three largest interconnection s by preparing analyses of transmission requirements under a range of alternative futures and develo p ing 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 comprise d 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 S takeholder S teering C ommittee [SSC] )

. 8. Tas k 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 D efined F utures

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

. 14. Task 8: Reliability Review

. F urther analyz e the transmission options developed in T ask 7 using additional NERC reliability tests

. 15. Task 9: Production Cost Analysis of Scenarios

. A nalyz e t he 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

. D evelop estimates of the cost of the supply resources and transmission in ea ch scenario

. 17. Task 11: Review of Results and Draft Report

. D raft the final report. 18. Task 12: Phase II Report

. I ncorporat e comments and finaliz e report for DOE approval.8 | Page 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 develop ment of a combined grid model for the interconnection based on a roll

- up of the Planning Authorities ’ expansion plans for the year 2 020

. 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 woul d 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

. T he 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 o r 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.9 | Page F igure ES 1 . Stakeholder Specified Infrastructure

EIPC chose Charles River Associates’ (CRA) Multi

- Region National ( MRN ) macroeconomic model and the ir 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, gene ration 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 model ing 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 itera ting between transmission expansion and resource expansion

. The NEEM regions are shown in , below

. The regions outlined in blue and red are the NEEM regi ons 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 ele ctric 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 obs ervations. 5 A nother key assumption that impacted the Phase 2 work of the Planning Coordinators is that, within the NEEM “bubbles”, it wa s assumed that there wer e no transmission constraints. In Phase 2 , any transmission constraints that
occur red within t he bubbles were identified and transmission was developed to alleviate those constraints

.10 | Page Figure ES 2 . NEEM Regions (blue) and Super Regions (black)
T he eight futures analyzed as part of Phase 1 were :
1. Business a s 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. Nat ional Renewable Portfolio Sta ndard

– 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 CO 2 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 IESO11 | Page 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.eipco nline.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 maintain ing 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 o f 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

. The se scenarios
were considered by the SSC to be a diverse set of scenari os in terms of policy goals, levels of implementation, transmission build

- out s, 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

. M ore detailed maps of where the additions were required in the EI are included in Appendix 1

.12 | Page 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: 2,9 79 TWh

**•** Additional Average Transfers Required above SSI Model Limits : 37,000 MW Reduce economy

- w ide 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 CO 2 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: 3,6 87 TWh

**•** Additional Average Transfers Required above SSI Model Limits : 0 MW Continuation of forecasted load growth, existing RPS requirement s, and E nvironmental Protection Agency (E PA ) 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 regio ns 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 voltage s 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

.13 | Page 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 detaile d 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

E ven with th is additional detail in Phase 2, the results are indicative only and not representa tive 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 fo r the electric power system , taking into account transmission topology

. A nalysis of the three scenarios and six sensitivities was performed using the transmission expansion option s 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 Ana lysis 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 generati on 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 P hase 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 2 0 0 kV and above were addressed by the Planning Authorities. In selected cases, at a14 | Page Planning Authority’s discretion, lower v oltages were addressed if the issues were severely affecting the 2 0 0 kV and above system and/or the area did not have the necessary supporting 2 0 0 kV and above infrastructure.

T he 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 s tandards

. 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

-- Constraints15 | Page Figure ES 4 . Scenario 2

– Constraints

Figure ES 5 . Scenario 3

-- Constraints16 | 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, t he bulk of the constraints occur in the MISO and SPP regions due to the amount of wind being site d 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 co al 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 transmi ssion 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 Transmissi on 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 were17 | Page needed to maintain reliability

. The maps a bove 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 averag e 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 additio ns 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 in terconnections

. 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 Energy20 | 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 6 4 % 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 th e 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 7 0 % of the energy needed for the Eastern Interconnection. Scenario 2 has a more diverse supply

- fue l 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 o f 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 c oal 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 product ion costs, CO 2 emissions costs and emissions levels for each of the three scenarios

. P roduction 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 de termined 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 t he 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

. T hus 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 si gnificant 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 Futur e 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 3,68722 | 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 be tween 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 transmiss ion 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 represen t “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 f or 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. P roduction 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” capit al costs

. As the name implies, “overnight” capital costs represent the capital cost of a project if it could b e 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 n ot 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 leve l of wind curtailment (15% over the EI and rising as high as 25 %

- 40% in some regions ) in Scenario 1: Combined Polic ies

. T he sensitivities performed are described below

. The first four sensitivities listed were intended to address the wind curtailment iss ue

. 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 , Reduce d W ind

– Reduce the wind build

- out in the highly constraine d 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 G as P rices

– Gas prices were increased by 25% across all seasons. 6. Sce nario 3: Business as Usual , Higher Lo ads

– Loads were increased by 5% across all regions and time periods.

The following table summariz es 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 Policies25 | Page In the High Load s ensitivity production costs incr eased by 14% and CO 2 emissions by 15%

. W ind curtailment was reduced from 131 TWhs to 119 TWhs, or approximately 10%. The High Spin Availability sensitivity reduced production costs by 4% and CO 2 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 CO 2 emissions slightly from the H igh S pin Availability results

. It does, however, decrease the wind curtailment from 120 TWhs in the High Spin Availabil ity 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 CO 2 emissions by 5% and reduces the wind curtailment to 64 TWhs

. If compared on an absolute valu e 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%

. T he 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 t he 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 producti on 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 pr oduction 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% Change from the Base (%) Production Costs ($2010 Millions)

Change from the Base (%) Emissions (short tons)26 | Page Following the completion of Phase 1 of the pr oject, some initial observations were drawn by stakeholders as follows: Observations and Guidance

**•** This project represents a unique dialog ue 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 o ne 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 analy sis 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 E astern I nterconnection proceeded well

.

**•** The interaction between Plan ning Authorities and state participants also developed a communication capability that will serve the nation well in the future

.

**•** It is expect ed that the participants will use the experience for continuing and enhancing future coordination efforts and tha t 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 interconnectio n

- 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

- out s 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 projec ts 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 specifie d alternatives and considered only higher voltage level additions and27 | 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 transmissio n 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 optimiz ation 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 agre ed that th e EIPC process had great value and elements of EIPC should continue in the future

. S takeholders in general developed more trust of the PAs’ process and over time relied more heavily on their input and judgment

. Stakeholders particularly saw val ue 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 recommendatio ns 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. S takeholders also identified the following challenges /opportunities:

**•** Understanding the transmission planning process and the models used

**•** The i nability 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 thr ee 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 ne ed 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 h ighlighted 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 generali zed 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 opportu nities 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 interc onnection

- 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 repo rt

. This memo is included in its entirety in Section 6.0

- Observations and Guidance of th is 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 i nterconnection

- wide studies and planning provide the potential for improvements in reliability and significant e conomic 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, sit ing, and constructi ng 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 fr om 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 Coor dinators 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 build s upon, rather than replace s , 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 u nder 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

- reci pient

. PJM serves as the lead Principal Investigator for the project

. The Eastern Interconnection Topic A cooperat ive agreement awarded to PJM, DE

- OE0000343, is titled the Eastern Interconnection Planning Collaborative (EIPC)

. EIPC chose to retain Whit eley 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 D OE’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 Comm issioners (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 Easte rn 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 c reated, 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 Obje ctives 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 expansion s 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, an d 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 th e 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 c riteria

.

**•** 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 require d 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 Per form 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 resourc e 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 comm ents 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 Plannin g 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 pl anned under Task 3 in Phase 1 of the project

. The Eastern Interconnection Topic B project leader , EISPC, also had a n SOPO including objectives, scope and task s

. 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

- lev el 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 w ill 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 u pdating 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
as sumptions 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

– Prepar e White Papers

.

**•** Task 6

– Reach consensus on the Recipient’s positions on the future scenarios for macroeconomic analysis to be conducted by Eas tern 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 Topi c 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, wel l 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 stud y was a national carbon constraint and demand reduction scenario, driven by a nationally implemented CO 2 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 CO 2 revenues

. The scenario includes a CO 2 price that escalates annually to achieve a 42% reduction in CO 2 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, mu ch of the reduction in demand is due to adjustments in demand from the higher energy prices driven by the CO 2 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
e nergy 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 build

out an off

- peak case was needed as part of the reliability analysis

. Th e demand used in modeling the transmission system in the off

- peak case was 351,750 MW

.6 | Page 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 o f 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 transfer s over the limits in the SSI model that were identified in the NEEM analysis for Scenario 1 were approximately 37,00 0 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 Po rtfolio 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 ener gy 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 off

peak 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 al ign 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 pe rmitted to expand

.7 | Page 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 Hydr o 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 IESO8 | Page resource expansion process, this generation (and other retiring oil/gas steam generation) was replaced with natural gas combi ned 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 B usiness as U sual 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, differe nt 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 th ree 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 Infrastructure9 | Page Figure 1

- 3 . EI Generation Capacity

Figure 1

- 4 . EI Energy10 | Page 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 transfer s needed to support the futures

. This effort involved stakeholders in direct and detailed conversat ions 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 engin eering

- 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 th ey 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 syste m (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 pro duction 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

- MAPS 7

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 ava ilable to stakeholders before the sensitivity analyses needed to be decided on

.

The production cost base model runs for each Sce nario 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: Combine d 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 De mand 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.11 | Page 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 start ing 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 differe nces 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 comp lexity 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 r esource 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 fu ture.