PJM Regional Transmission Expansion Plan

Transcription

1 PJM Regional Transmission Expansion Plan 2016 Book 1 PJM 2016 RTEP in Review Book 2 Inputs and Process Book 3 Studies and Results February 28, 2017

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3 Book 3: Preface Preface PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV Book 3, Studies and Results, is the third in a series of three books that comprise PJM s 2016 Regional Transmission Expansion Plan Report: Book 1: PJM 2016 RTEP in Review Book 2: 2016 Inputs and Process Book 3: Studies and Results Book 3 presents results from studies conducted throughout 2016: Recommendations and approvals associated with RTEP process window evaluation of baseline reliability and market efficiency proposals Immediate need system enhancements to address operational performance issues, generator deactivations and transmission owner criteria violations PJM Regional Transmission Expansion Plan 2016 Book 1 PJM 2016 RTEP in Review Book 2 Inputs and Process Book 3 Studies and Results February 28, /2017 Market Efficiency Analysis Interregional planning activities Book 3 also provides subregional summaries of RTEP projects approved by the PJM Board in PJM 2016 Regional Transmission Expansion Plan i

4 Book 3: Preface RTEP Process Description The online resources below provide additional description of RTEP process business rules and methodologies: The M-14 series of PJM Manuals contain the specific business rules that govern the entire RTEP Process. Specifically, Manual 14B describes the methodologies associated with conducting planning studies and developing solutions to solve planning criteria violations and market efficiency issues identified by them. PJM Manual 14B, Regional Planning Process can be found on PJM s website via the following link: media/documents/manuals/m14b.ashx. Schedule 6 of the PJM Operating Agreement codifies the overall provisions under which PJM implements its Regional Transmission Expansion Planning Protocol, more familiarly known (and used throughout this document) as the PJM RTEP process. The PJM Operating Agreement can be found on PJM s website via the following link: media/documents/merged-tariffs/oa.pdf. The PJM Open Access Transmission Tariff (OATT) codifies provisions for generating resource interconnection, merchant/customer funded transmission interconnection, long-term firm transmission service and other specific new service requests. The PJM OATT can be found via the following link: com/media/documents/merged-tariffs/oatt.pdf. The status of individual PJM Boardapproved baseline and network RTEP projects, as well as that of Transmission Owner supplemental projects, can be found on PJM s website: planning/rtep-upgrades-status.aspx. Stakeholder Forums The Planning Committee, established under the PJM Operating Agreement, has the responsibility to review and recommend system planning strategies and policies as well as planning and engineering designs for the PJM bulk power supply system to assure the continued ability of the member companies to operate reliably and economically in a competitive market environment. Additionally, the Planning Committee makes recommendations regarding generating capacity reserve requirement and demandside valuation factors. Committee meeting materials and other resources are accessible from PJM s website: committees-and-groups/committees/pc.aspx. Transmission Expansion Advisory Committee and subregional RTEP committees continue to provide forums for PJM staff and stakeholders to exchange ideas, discuss study input assumptions and review results. Stakeholders are encouraged to participate in these ongoing committee activities. TEAC resources are accessible from PJM s website: committees-and-groups/committees/teac.aspx. Each subregional RTEP committee provides a forum for stakeholders to discuss more local planning concerns. Interested stakeholders can access subregional RTEP committee planning process information from PJM s websites: PJM Mid-Atlantic Subregional RTEP Committee: PJM Western Subregional RTEP Committee: PJM Southern Subregional RTEP Committee: The Independent State Agencies Committee (ISAC) is a voluntary, stand-alone committee comprising representatives from regulatory and other agencies in state jurisdictions within the PJM footprint. Through the activities of the ISAC, states have an opportunity to provide input on the assumptions and scenarios that PJM incorporates in the scope of its RTEP studies. Additional information is available on PJM s website: pjm.com/committees-and-groups/isac.aspx. ii PJM 2016 Regional Transmission Expansion Plan

5 Book 3: Table of Contents Book 3: Table of Contents PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV Contents 1: RTEP Process Context : RTO Perspective Regional Scope RTEP Process Windows System Enhancement Drivers : NERC Reliability Criteria RTEP Perspective Bulk Electric System Facilities NERC Reliability Standard TPL : Artificial Island : Ongoing Analysis in : Immediate Need Projects : Generator Deactivation Requests RTEP Process Context Deactivation Requests Mid-Atlantic Subregion Western PJM Subregion : Baseline Analysis Driven Projects Immediate Need Operational Performance High Voltage Newark Airport Additional Source Need Load Deliverability Review iii

6 Book 3: Table of Contents 4: Market Efficiency Projects : 2016 Activity Three Additional Approved Projects Capacitors AP-South Congestion Relief Project 9A Loretto-Wilton Center 345 kv Line : 2016 RTEP Proposal Windows : 2016 RTEP Proposal Window No Window Process Proposals : 2016 RTEP Proposal Window No Window Process Proposals : 2016 RTEP Proposal Window No Window Process Proposals : 2016 RTEP Proposal Window No. 3 Addendum Window Process Proposals : 2016/2017 Market Efficiency Analysis : Window Scope RTEP Process Context Near-Term Simulations Long-Term Simulations Benefit-to-Cost Threshold Test : 2016 Input Parameter Overview : Study Results from 2016 Analysis Near-Term Simulation Results Acceleration Analysis Long-Term Simulation Results /17 RTEP Long-Term Proposal Window Market Efficiency Proposals iv

7 Book 3: Table of Contents 7: Transmission End-of-Life Assessments : Dominion FERC No. 715 Criteria Violations Immediate Need Three to Five Year Out Need Beyond Five Years : PSE&G FERC 715 Criteria Violations Metuchen-Edison-Trenton-Burlington Corridor Newark Switch : Interregional Coordination : Interregional Scope Adjoining Systems FERC Order No Compliance Filings : Interregional Activities PJM-MISO Joint Operating Agreement NYISO and ISO-NE Adjoining Systems South of PJM Eastern Interconnection Planning Collaborative : Planning Parameters : Reliability Pricing Model Recognizing Locational Constraints CETO and CETL Development Capacity Performance Reserve Requirements Parameters : Clean Power Plan Reliability Studies : Scenario Studies : Subregion Summaries : Mid-Atlantic PJM Summary RTEP Context Baseline Projects Network Projects Supplemental Projects v

8 Book 3: Table of Contents 11.1: Western PJM Summary RTEP Context Baseline Projects Network Projects Supplemental Projects : Southern PJM Summary RTEP Context Baseline Projects Network Projects Supplemental Projects Topical Index Glossary vi

9 Book 3: RTEP Process Context 1: RTEP Process Context PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 1 1.0: RTO Perspective Map 1.1: PJM Backbone Transmission System Regional Scope PJM a FERC-approved RTO coordinates the movement of wholesale electricity across a high voltage transmission system in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia as shown on Map 1.1. PJM s footprint encompasses major U.S. load centers from the Atlantic coast to Illinois s western border including the metropolitan areas in and around Baltimore, Chicago, Columbus, Cleveland, Dayton, Newark and northern New Jersey, Norfolk, Philadelphia, Pittsburgh, Richmond, Toledo and the District of Columbia. PJM s Regional Transmission Expansion Plan (RTEP) process identifies transmission system additions and improvements needed to serve more than 65 million people throughout 13 states and the District of Columbia. The PJM system includes key U.S. Eastern Interconnection transmission arteries, providing members access to PJM s regional power markets as well as those of adjoining systems. Collaborating with more than 990 members, PJM dispatches more than 176,560 MW of generation capacity over 82,540 miles of transmission lines. PJM 2016 Regional Transmission Expansion Plan 1

10 1 Book 3: RTEP Process Context PJM s RTEP process spans state boundaries shown in Map 1.1 in the broader context of the RTO functions shown in Figure 1.1. Doing so gives PJM the ability to identify one optimal, comprehensive set of solutions to resolve reliability criteria violations, operational performance issues and congestion constraints. Specific system enhancements are justified to meet local reliability requirements and deliver needed power to more distant load centers. Once the PJM Board approves recommended system enhancements new facilities and upgrades to existing ones they formally become part of PJM s overall RTEP. PJM Board approval obligates Designated Entities to implement those plans. PJM recommendations can also include removal of previously approved projects if expected system conditions have changed such that justification no longer exists RTEP Process Windows PJM instituted proposal solicitation windows as part of its RTEP process in January 2014, to address compliance with FERC Order No During each window PJM seeks transmission proposals to address one or more identified needs reliability, market efficiency, operational performance and public policy. RTEP windows provide opportunity for non-incumbent transmission developers to submit project proposals to PJM for consideration. The scope and timing of the issue to be addressed and likely type of solutions to be submitted dictate window duration. Once a window closes, PJM proceeds with specific company, analytical and constructability evaluations to assess proposals for possible recommendation to the PJM Board, as shown in Figure 1.2. If selected, designated developers Figure 1.1: RTEP Process RTO Perspective Stakeholders Transmission System Enhancements become responsible for project construction, ownership, operation, maintenance, and financing. The expected type of system enhancement and required in-service data dictates window duration: Long-Lead Projects: PJM will open a 120-day proposal window for projects with required inservice dates greater than five years out that address identified reliability criteria violations, economic constraints, RPM limitations and public policy requirements. Please note that the 120-day proposal window is a default. PJM may shorten or extend the window as needed. Public Policy PJM Regional Transmission Expansion Planning Process Board Approvals Planning Criteria Markets Operations Plan Implementation Short-Term Projects: PJM will open a 30- day proposal window for projects to address reliability driven upgrades with required in-service dates between three and five years out. Please note that the 30-day proposal window is a default. PJM may shorten or extend the window as needed. 2 PJM 2016 Regional Transmission Expansion Plan

11 Book 3: RTEP Process Context 1 Immediate-Need Reliability Projects: A reliability-based transmission enhancement or expansion with a required in-service date of three years or less. If PJM determines that insufficient time remains to develop and implement a short-term projects by way of a proposal window, PJM will work directly with the impacted Transmission Owner to develop and implement a solutions. If PJM determines that sufficient time remains, PJM will conduct a RTEP proposal window seeking solutions to address the immediate need project. PJM has the direction to dictate the length of the required proposal window based on the complexity of the issue. Figure 1.2: RTEP Proposal Window Process Window participants prepare and submit project packages Variable Proposal window ~30 to ~120 days PJM Company Evaluation PJM Constructability Evaluation PJM Analytical Evaluation Designated Entity Selection Project Selection PJM Recommendation to the PJM Board During each window, developers may submit solution proposals to solve posted violations, constraints, system conditions and public policy requirements. PJM may then also request any additional reports or information needed to evaluate a specific project proposal. Any deficiencies must be addressed within ten business days of PJM notification. PJM may also (i) shorten proposal windows should it be required to meet the needed in-service date of the proposed enhancements or expansions; or (ii) extend the windows as needed to accommodate updated information regarding system conditions. Submittals include both greenfield and upgrade proposals. A greenfield proposal is one that utilizes new right-of-way or creates a new substation, for example. An upgrade proposal is an enhancement or expansion to existing transmission system facilities. Upgrades can include new or replaced devices installed at existing substations and reconductoring or other modifications of existing transmission lines. Project(s) presented and reviewed at TEAC Window activity in 2016 proceeded along two avenues. First, PJM conducted five windows in 2016 that addressed both reliability criteria violations and market efficiency congestion. In parallel, PJM proceeded with finalizing the evaluation associated with several market efficiency projects from proposals submitted in the 2014/2015 long-term window. NOTE: PJM communicates RTEP window results to stakeholders via PJM Transmission Expansion Advisory Committee (TEAC) activities: pjm.com/committeesand-groups/committees/ teac.aspx. Stakeholders are also encouraged to follow discussion of additional window process changes based on lessons learned per PJM Planning Committee activities: committees-and-groups/committees/pc.aspx. PJM 2016 Regional Transmission Expansion Plan 3

12 1 Book 3: RTEP Process Context System Enhancement Drivers A 15-year long-term planning horizon allows PJM to consider the aggregate effects of many factors, shown in Figure 1.3. Initially, beginning with its inception in 1997, PJM s RTEP consisted mainly of system enhancements driven by load growth and generating resource interconnection requests. Today, PJM s RTEP process considers the interaction of many system enhancement drivers including those arising out of federal and state public policy. Figure 1.3: System Expansion Drivers Transmission Service Load Forecast, Demand Resources Public Policy Resilience Reliability Criteria Violations PJM s RTEP process encompasses a comprehensive assessment of system compliance with the thermal, reactive, stability and short-circuit NERC Standard TPL events P0 through P7 as described in 1.1. The relationship between a reliability criteria violation and transmission project location generally takes one of two forms. Reliability criteria violations in a given Transmission Owner zone may be driven by a local issue in that same zone. For example, local load growth may drive local transformer loadings and, thus, be the potential cause of future overloads. Also, reliability criteria violations in one or more Transmission Owner zones may be driven by some combination of regional factors including those potentially arising some distance away. Transmission projects that improve reliability can also improve economics and vice versa. PJM conducted four windows during 2016, seeking proposals to solve identified reliability criteria violations. Still other RTEP projects were required to address immediate need reliability issues. Operational Performance Aging Infrastructure Market Efficiency The RTEP process also examines market efficiency to identify transmission enhancements that relieve congested facilities, allowing lower cost power to flow to consumers. From a process perspective the goal is to accomplish one or more objectives: Determine which reliability projects, if any, have economic benefit if accelerated Identify new transmission projects that may realize economic benefit RTEP Development Reliability Criteria Interregional Coordination Market Efficiency Capacity Resources, RPM Identify economic benefits associated with modification to reliability-based enhancements already included in the RTEP that if modified would relieve one or more economic constraints. Such projects, originally identified to resolve reliability criteria violations, may be designed in a more robust manner to provide economic benefit as well. PJM identifies the economic benefit of proposed transmission projects by conducting 4 PJM 2016 Regional Transmission Expansion Plan

13 Book 3: RTEP Process Context 1 production cost analyses. Simulations show the extent to which congestion is mitigated by the project for given transmission topologies and generation dispatch. Benefit metrics compare future year simulation congestion results with and without proposed transmission enhancements. The set of metrics and methods used to determine economic benefit are described in Book 2 of this report, based on PJM Manual 14B, 2.6 and PJM Operating Agreement, Schedule 6, 1.5.7, accessible online: PJM Manual 14B, 2.6: com/~/media/documents/manuals/m14b.ashx PJM Operating Agreement, Schedule 6, 1.5.7: documents/merged-tariffs/oa.pdf Discussion of Market Efficiency analyses completed in 2016, can be found in 6.2. Operational Performance Under Schedule 6, 1.5 of the PJM Operating Agreement, PJM may also identify transmission enhancements to address system limitations encountered during real-time operations, often under recurring, similar system conditions. To that end, PJM planners meet with operations staff several times each year to assess the need for transmission enhancement plans that would address identified thermal, reactive, stability and other issues. This was the case, for example, for the past several years under light load conditions during which operators experienced high voltage alarms. Additional studies replicating operating conditions revealed that reactors were needed in certain areas of PJM to address the issue. Scenario Studies For the first ten years following the inception of the RTEP process in 1997, PJM generally found that the magnitude of uncertainty regarding future system conditions driving transmission need was mainly limited to that associated with load growth and generation interconnection requests. RTEP process tests could reasonably define the expected date of future reliability violations with minimal risk of fluctuation. That has changed in many respects in more recent years. A single set of summer peak load baseline and market assumptions are simply not sufficiently flexible to assess the full extent and degree to which system drivers impact transmission need. For example, scenario studies have permitted PJM to examine the need for light load and winter criteria in light of the operating condition drivers unique to each. Scenario studies also permit PJM to evaluate potential system conditions driven by factors outside its immediate sphere. Such studies provide valuable long-term expansion planning insights beyond those obtained from conventional baseline and market efficiency analyses. For example, PJM completed scenario studies in 2016, to assess the economic and reliability impacts of the U.S. Environmental Protection Agency s Clean Power Plan under 111(d) of the Clean Air Act, as described in 10. Interregional Studies PJM has engaged in successful, collaborative interregional studies for decades, many under the auspices of NERC. In recent years, PJM s interregional planning responsibilities have grown in parallel with the evolution of broader organized regional markets and interest at the state and federal level in favor of increased interregional coordination. As described in 8, under each interregional agreement, coordinated planning includes assessment of current operations to ensure that critical cross-border interface issues are identified and addressed before they impact system reliability or dilute effective market administration. Interregional reliability and economic efficiency issues span large parts of the U.S. and comprise a key part of broader public policy discussions. Previous planning cycle focus on large-scale integration of wind and other renewable resources has broadened to include transmission planning effects of the interface of gas and electric infrastructure and the impacts of planning to comply with environmental regulations. Interregional efforts have also begun to focus on smaller, incremental system enhancements along common seams. Doing so increases system efficiency by addressing congestion issues of common concern with transmission projects that can be implemented in the near term. PJM 2016 Regional Transmission Expansion Plan 5

14 1 Book 3: RTEP Process Context Considering Multiple Drivers PJM s RTEP process provides the flexibility to develop more efficient, cost-effective projects justified on the basis of multiple drivers resolving reliability violation solutions, promoting market efficiency by resolving economic constraints and advancing public policy requirements. Much of the multi-driver concept falls within the context of PJM s FERC-approved state agreement approach and how to incorporate the voluntary nature of a public policy driver component within this context. RTEP projects will likely continue to be driven primarily by reliability criteria violations. Others will continue to be approved based on market efficiency criteria. Some additional number of RTEP projects that provide a combination of benefits may suggest a greater scope than required to satisfy any one driver individually, and provide opportunities for economic efficiency. Future expansion of the multi-driver approach may also consider system needs driven by interconnection queue requests, aging infrastructure and grid resilience. Regardless, multi-driver projects present challenges in terms of timing, certainty, state buyin and cost allocation. Initial in-service dates must consider the onset of reliability criteria violations, the value of market efficiency benefits, the value of renewable energy delivery benefits, the uncertainty around planning process, load and resource assumptions, and project construction lead time. 6 PJM 2016 Regional Transmission Expansion Plan

15 Book 3: RTEP Process Context 1 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 1.1: NERC Reliability Criteria RTEP Perspective PJM s RTEP process rigorously applies NERC s Planning Standard TPL through the application of a wide range of reliability analyses including load and generation deliverability tests over a 15-year planning horizon. PJM documents all instances that did not meet applicable Reliability Standards and develops system reinforcements to ensure compliance. NERC penalties for violation of a standard can be as high as $1 million per violation per day. PJM addresses transmission expansion planning from a regional perspective, spanning Transmission Owner zonal boundaries and state boundaries to address the comprehensive impact of many system enhancement drivers, including NERC reliability criteria violations. The relationship between violation and solution generally takes one of two forms. Reliability criteria violations may occur more locally, in a given Transmission Owner zone, driven by an issue in that same zone. For example, local load growth or generator deactivations may drive higher power flow on a specific transformer and potentially cause an overload. Violations may also be driven by some combination of regional factors including those potentially arising some distance away. In such instances, PJM is able to pursue optimal regional solutions to solve such violations more economically and efficiently than if approached individually Bulk Electric System Facilities NERC s planning standards apply to all bulk electric system (BES) facilities, defined by Reliability First and the SERC Reliability Corporation to include all of the following power system elements: 1. Individual generation resources larger than 20 MVA or a generation plant with aggregate capacity greater than 75 MVA that is connected via step-up transformer(s) to facilities operated at voltages of 100 kv or higher 2. Lines operated at voltages of 100 kv or higher 3. Associated auxiliary and protection and control system equipment that could automatically trip a bulk electric system facility, independent of the protection and control equipment s voltage level (assuming correct operation of the equipment) The Reliability First definition of BES excludes the following: 1. Radial facilities connected to load serving facilities or individual generation resources smaller than 20 MVA or a generation plant with aggregate capacity less than 75 MVA where the failure of the radial facilities will not adversely affect the reliable steady-state operation of other facilities operated at voltages of 100 kv or higher 2. The balance of generating plant control and operation functions (other than protection systems that directly control the unit itself and its associated step-up transformer); these facilities would include relays and systems that automatically trip a unit for boiler, turbine, environmental and/or other plant restrictions 3. All other facilities operated at voltages below 100 kv Given this BES definition, PJM conducts reliability analyses to ensure system compliance with NERC Standard TPL If PJM identifies violations, it develops transmission expansion solutions to solve them, frequently as part of its RTEP window process NERC Reliability Standard TPL Under NERC Reliability Standard TPL-001-4, planning events in NERC parlance are categorized as P0 through P7 and defined in the context of system contingency. PJM studies each event as part of one or more RTEP process steady-state analyses as mapped in Table 1.1 and described in PJM Manual 14B, PJM Region Transmission Planning Process: com/~/media/documents/manuals/m14b.ashx. PJM 2016 Regional Transmission Expansion Plan 7

16 1 Book 3: RTEP Process Context P0 No Contingency P1 Single Contingency P2 Single Contingency (bus section) P3 Multiple Contingency P4 Multiple Contingency (fault plus stuck breaker) P5 Multiple Contingency (fault plus relay failure to operate) Table 1.1: Mapping RTEP Analysis to NERC Planning Events Steady-State Analysis Base Case N-0 No Contingency Analysis Base Case N-1 Single Contingency Analysis Base Case N-2 Multiple Contingency Analysis N-1-1 Analysis Generator Deliverability Common Mode Outage Procedure Load Deliverability Light Load Reliability Criteria NERC Standard TPL P0 P1 P2, P4, P5, P7 P3, P6 P0, P1 P2, P4, P5, P7 P0, P1 P1, P2, P4, P5, P7 P6 Multiple Contingency (two overlapping singles) P7 Multiple Contingency (common structure) Consistent with NERC definitions, if an event comprises an equipment fault such that the physical design of connections or breaker arrangements also takes additional facilities out of service, then they are taken out of service as well. For example, if a transformer is tapped off a line without a breaker, both the line and transformer are removed from service as a single contingency event. PJM N-0 analysis mapped to planning event P0 examines the bulk electric system as is with all facilities in service. PJM identifies facilities that have pre-contingency loadings which exceed applicable normal thermal ratings. Bus voltages are also identified that violate established limits specified in PJM Manual 3, Transmission Operations: documents/manuals/m03.ashx. Generator and load deliverability tests are also applied to event P0 per the methodologies described in Book 2, 4.2. Similarly, N-1 analysis mapped to planning event P1 requires that bulk electric system facilities be tested for the loss of a single generator, transmission line or transformer. Likewise, bus voltages that exceed limits specified by PJM Manual 3 are also identified. Generator and load deliverability tests are applied to event P1 here as well. PJM N-1-1 analysis mapped to planning events P3 and P6 examines the impact of two successive N-1 events with re-dispatch and system adjustment prior to the second event. Monitored facilities must remain within normal thermal and voltage limits after the first N-1 contingency and re-dispatch and within applicable emergency thermal ratings and voltage limits after the second as specified in PJM Manual 3. PJM s N-2 multiple contingency and common mode analyses evaluate planning events P2, P4, P5 and P7 to look at the loss of multiple facilities that share a common element or system protection arrangement. These include bus faults, breaker failures, double circuit tower line outages and stuck breaker events. N-2 analysis is conducted on the base case itself. Common mode analysis is conducted within the context of PJM s generator deliverability system test facility loading methodology, discussed in PJM Manual 14B, PJM Region Transmission Planning Process: pjm.com/~/media/documents/manuals/m14b.ashx. NERC Standard TPL includes extreme events as well. Also known as maximum credible disturbances, PJM studies system conditions following a number of extreme events, judged to be critical from an operational perspective for risk and consequences to the system. 8 PJM 2016 Regional Transmission Expansion Plan

17 Book 3: RTEP Process Context 1 Stability Requirements PJM Planning conducts stability studies to ensure that the planned system can withstand NERC criteria disturbances and maintain stable operation throughout PJM s planning horizon. NERC criteria disturbances are those required by the NERC planning criteria applicable to system normal, single element outage and commonmode multiple element outage conditions. A key aspect of NERC Reliability Standard TPL also calls for modeling the dynamic behavior of loads as part of stability analysis at peak load levels. Prior to TPL standard implementation, stability analyses were conducted on static load models that may not necessarily have captured the dynamic nature of real and reactive components of system loads and energy efficient loads, for example. From an analytical perspective, this requirement enhances analysis of fault induced delayed voltage recovery or changes in load characteristics like that of more energy efficient loads. NOTE: NERC s website contains a complete description of Standard TPL requirements: aspx?standardnumber=tpl-001-4&title=transmission System Planning Performance Requirements&jurisdiction=United States PJM 2016 Regional Transmission Expansion Plan 9

18 1 Book 3: RTEP Process Context 10 PJM 2016 Regional Transmission Expansion Plan

19 Book 3: Artificial Island 2: Artificial Island PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 2 2.0: Ongoing Analysis in 2016 PJM continued throughout 2016, to refine its analysis of the approved Artificial Island project, shown on Map 2.1, given cost estimates developed by PSE&G and technical information submitted after original PJM Board approval in July 2015: Map 2.1: Approved Artificial Island Project Protection system clearing times Artificial Island transformer modeling data based on installation of new generator step-up transformers Artificial Island dynamics models based on installation of new exciters on Salem and Hope Creek generator excitation systems Anticipated impedances for the proposed 500 / 230 kv transformer at the Artificial Island end of the Delaware River underwater cable PJM 2016 Regional Transmission Expansion Plan 11

20 2 Book 3: Artificial Island On August 3, 2016, the PJM Board decided to suspend the Artificial Island project and directed PJM staff to perform a comprehensive analysis to support a future course of action. Stakeholders were notified via communication from PJM CEO Andy Ott, the text of which follows: Dear Members and Stakeholders of PJM: PJM has been working with transmission owners and developers to resolve operational voltage and stability problems in the area known as Artificial Island in southern New Jersey. This is a very complex project, compounded by the unique design of the electrical system and geography of the area. It has become evident to all involved that the projected costs to resolve the problems at Artificial Island have increased significantly. PJM has been examining alternatives in an attempt to offset some of the increases. In addition, questions have arisen about whether the currently proposed solution would perform as intended without further expense. Because of these concerns, PJM has come to the conclusion that a pause in the project is necessary before any new financial obligations are incurred by the project developers. At this time, the PJM Board is suspending all elements of the Artificial Island project and directing PJM to perform a comprehensive analysis to support a future course of action. In light of the current uncertainties around the changing scope and configuration of the project, it is imperative that we understand the basis for any alternatives that may exist to manage the operational issues at Artificial Island. The Board has asked for the review to be completed by February 2017, at which time PJM will be in a position to decide how best to proceed. Background information and details leading to this decision are outlined in a letter from Steven Herling, PJM s Vice President of Planning, to the PJM membership and stakeholders. 12 PJM 2016 Regional Transmission Expansion Plan

21 Book 3: Artificial Island 2 PJM pursued comprehensive analysis on a number of fronts, the scope of which is summarized here. Protection & Control PSE&G notified PJM in April 2016, that key relay clearing times had changed. Fault clearing time for a bus fault with stuck breaker delayed clearing scenario was now longer than that for a line fault with stuck breaker delayed clearing. Having confirmed that it was indeed longer, PJM proceeded to determine if existing limiting contingencies assumed in the existing Artificial Island Operating Guide (AIOG) have been valid since first published and implemented. Artificial Island Operating Guide The Artificial Island Operating Guide addresses a wide variety of operating scenarios based on key 500 kv transmission line outages, Artificial Island unit status (the number of units online), and Power System Stabilizer status. The guide provides unit-specific MVAR outputs to maintain system stability under both normal and maintenance conditions. The Artificial Island Project was approved on the basis of addressing operational performance issues by eliminating or significantly reducing AIOG complexity. Transient Stability Assessment Tool Impact on Artificial Island Operating Guide Implemented in June 2013, PJM s Transient Stability Assessment (TSA) tool provides system operators with real-time feedback, including recommended operating strategies to prevent generator instability. This offers more precise stability mitigation in real-time than that provided by the AIOG. TSA availability minimizes AIOG need in real-time operations or for outage planning, provided that a minimum voltage schedule is maintained. TSA tool availability was taken into consideration as part of the comprehensive analysis of the Artificial Island Project. Operational Data In light of existing AIOG complexity, PJM researched Salem and Hope Creek bus voltage, MW, MVAR and power factor data over a four and one-half year period. That period included various local transmission outages under which observed operational data showed that Artificial Island voltages remained above p.u. The lowest observed voltage during an outage was kv or p.u. with the Hope Creek 3-4 circuit breaker open. The voltage schedule to be included in a revised Artificial Island operating guide will be determined in collaboration with PJM operations and PSE&G. PJM 2016 Regional Transmission Expansion Plan 13

22 2 Book 3: Artificial Island New Freedom Static Var Compensation Based on the operational voltage data assessment described above, PJM conducted additional sensitivity testing with and without the New Freedom Static Var Compensation (SVC) to assess unit stability under critical maintenance outages and critical faults, assuming a voltage schedule of p.u. Units were stable for all faults under all critical maintenance outages. PJM s preliminary recommendation under consideration is to remove the New Freedom SVC from the project scope and utilize a voltage schedule at Artificial Island. Optical Ground Wire The approved Artificial Island project included high speed relaying utilizing optical ground wire (OPGW) communication technology to be added to the protection systems of eight critical 500 kv circuits. However, the revised relay clearing times communicated by PSE&G have shifted critical fault and critical contingency assumptions. Subsequent PJM studies have focused on system stability to determine if the addition of fiber optic technology offered any additional clearing time margin, translating into additional stability margin. Table 2.1: AI Cost Estimate Comparison, March 2016 vs. July 2015 LS Power 5A 230 kv Submarine Line Costs as of July 2015 Costs as of March 2016* Cost Containment $146 $146 Salem Expansion $61 - $74 $152 Optical Ground Wire $25 $39 SVC Cost Estimate $31 - $38 $81 Project Total $263 - $283 $418 * Incorporates cost estimates from PSE&G; excludes PSE&G risk and contingency cost components Next Steps As PJM s Board-directed comprehensive analysis has proceeded, discussion of preliminary results with stakeholders raised several questions and considerations requiring additional time for further evaluation and response. PJM now expects to discuss revised project recommendations at a special TEAC meeting in March 2017, followed by a presentation and report to the PJM Board in April Cost and Constructability Table 2.1 compares cost estimates as of March 2016 with PJM s original July 2015 cost estimates. PJM, PSE&G and LS Power have held multiple meetings to take a more granular look at cost components. PJM, PSE&G and LS Power also explored alternative 230 kv line attachment configurations at both Salem and Hope Creek to reduce the constructability risk associated specifically with line termination at Artificial Island. 14 PJM 2016 Regional Transmission Expansion Plan

23 Book 3: Immediate Need Projects 3: Immediate Need Projects PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 3 3.0: Generator Deactivation Requests RTEP Process Context Given the short-term nature of generator deactivation notifications, and the nature of the system reinforcements required, RTEP baseline reinforcements are typically tagged as immediate need; no RTEP windows are required. In some instances, reliability criteria violations caused by unit deactivation have been solved by RTEP enhancements already approved by the PJM Board. Others have been solved in whole or in part by supplemental projects proposed by the native Transmission Owner. Generator deactivations alter power flows that can cause transmission line overloads and, given reductions in system reactive support from those generators, can undermine voltage support. Generation owners are required to notify PJM of their intent to deactivate generation per Article V of the PJM Tariff. Per FERC order, PJM cannot compel unit owners to remain in service. Unlike time lines associated with requests for interconnection, deactivation may take effect upon 90 days notice. After a deactivation request is received, PJM conducts reliability studies to identify RTEP baseline system reinforcements needed to resolve all identified reliability criteria violations, as shown in Figure 3.1. The 90 days gives PJM time to identify reliability criteria Figure 3.1: Generator Deactivation Process Generator provides PJM with a notice of their intent to deactivate With 75 days PJM provides an updated estimate of when the required transmission upgrades will be completed Within 30 days of the deactivation notification PJM notifies the generation owner if deactivating the unit will adversely effect reliability violations, transmission needed to resolve them and to pursue reliability-must-run (RMR) agreements with generation owners, if needed. Over the past several years, potential reliability issues related to generator deactivations have been forestalled through a combination of short leadtime baseline RTEP transmission enhancements, operating procedures to address conditions which cannot be resolved by new transmission before the requested deactivation date and, in some limited instances, RMR agreements. These agreements with the generator owner keep units online beyond announced retirement dates until transmission enhancements can be placed in-service. Within 90 days PJM posts a report on the web Within 60 days the generation owners notifies PJM if they will operate beyond their intended deactivation date Reliability-Must-Run Units If transmission improvements are completed prior to a unit s intended deactivation date, reliability issues can be avoided. However, if improvements are not in place prior to deactivation, and if reasonable operating procedures cannot be implemented, then PJM can pursue a RMR agreement with the generator owner. Doing so can keep a unit online beyond its announced retirement date until transmission improvements are completed. Under the PJM OATT, costs incurred to compensate RMR generator owners are recovered through an additional transmission charge allocated to TO zonal load that bears the financial responsibility for the required transmission PJM 2016 Regional Transmission Expansion Plan 15

24 3 Book 3: Immediate Need Projects improvements. Regardless, a generation owner is not under any obligation to pursue the RMR agreement and may retire the unit at any time. PJM cannot compel a generator to remain in service. Age and Public Policy Drivers Generation owners weigh investments and operational costs against anticipated revenues from PJM markets and existing power purchase agreements to determine the economic viability of a facility. Those generators considered at-risk face the real possibility of deactivation given the economic impacts of increasing operating costs associated with unit age many more than 40 years old and regulatory requirements such as those that address environmental policy. Units must compete with other resources offered into each PJM Reliability Pricing Model (RPM) capacity auction including more efficient plants, renewable energy resources, demand response programs, and energy efficiency programs. PJM continues to monitor federal public policy for its potential impact on deactivation activity Deactivation Requests PJM continued to receive deactivation notifications throughout 2016, totaling 2,273 MW, up from 1,626 MW in 2015, but still below 4,291 MW in 2014, 7,745 MW in 2013 and 14,444 MW in By contrast, PJM received and studied deactivation requests for nearly 11,000 MW during the eight years ending November 1, Table 3.1 and Map 3.1 show the deactivation requests received between January 1, 2016 and December 31, Generator owners have requested deactivation of these units between June 2016 and October PJM Table 3.1: PJM Generator Deactivation Notifications: 1/1/2016 through 12/31/2016 Unit Capacity Trans Zone Age (Years) Actual Deactivation Date Warren County Landfill Generator 1.5 JCPL 10 3/1/2016 6/1/2016 6/1/2016 Actual Hopewell James River Cogeneration 92.0 DOM 28 4/26/2016 5/31/2017 5/31/2017 Projected Sammis ATSI 57 7/22/2016 5/31/2020 5/31/2020 Projected Sammis ATSI 56 7/22/2016 5/31/2020 5/31/2020 Projected Sammis ATSI 55 7/22/2016 5/31/2020 5/31/2020 Projected Sammis ATSI 53 7/22/2016 5/31/2020 5/31/2020 Projected Bay Shore ATSI 61 7/22/ /1/ /1/2020 Projected Harrisburg 4 CT 14.0 PPL 49 8/9/ /17/ /17/2016 Actual Columbia Dam Hydro (Columbia NJ) 0.5 JCPL 0 8/19/ /18/ /3/2016 Actual Rolling Hills Landfill Generator 0.0 ME 10 9/12/ /7/ /7/2016 Actual Hudson PSE&G 47 10/5/2016 6/1/2017 6/1/2017 Projected Mercer PSE&G 55 10/5/2016 6/1/2017 6/1/2017 Projected Mercer PSE&G 55 10/5/2016 6/1/2017 6/1/2017 Projected Roanoke Valley DOM 22 12/1/2016 3/1/2017 3/1/2017 Projected Roanoke Valley DOM 21 12/1/2016 3/1/2017 3/1/2017 Projected Worcester County Landfill 0.0 DPL 8 12/5/2016 3/5/ /23/2016 Actual Will County ComEd 52 6/3/2016 5/31/2020 5/31/2020 Projected maintains a list of formally submitted deactivation requests, accessible via the following link: generation-deactivation.aspx. Deactivation reliability studies comprise thermal and voltage analysis including generator deliverability, common mode outage, N-1-1 analysis and load deliverability tests. System expansion solutions may include upgrades to existing facilities, scope expansion for current baseline projects already in the RTEP or construction of new transmission facilities. Request Submittal Date Requested Deactivation Date 16 PJM 2016 Regional Transmission Expansion Plan

25 Book 3: Immediate Need Projects 3 Map 3.1: PJM Generator Deactivation Notifications: 1/1/2016 through 12/31/2016 PJM 2016 Regional Transmission Expansion Plan 17

26 3 Book 3: Immediate Need Projects Mid-Atlantic Subregion Generator deactivation studies conducted during 2016 identified reliability criteria violations in PJM s Mid-Atlantic Subregion requiring system reinforcements. While PJM evaluated all the deactivation notifications received in 2016, as listed earlier in Table 3.1, system reinforcements were identified in 2016 for the Mercer 1 and 2 deactivation in the Northern New Jersey area of PJM s Mid-Atlantic Subregion. Accordingly, PJM identified the two baseline reliability projects shown in Table 3.2 and Map 3.2 (including those under $5 million). Map 3.2: Mid-Atlantic 2016 RTEP Baseline Projects Driven by Generator Deactivations Table 3.2: Mid-Atlantic 2016 RTEP Baseline Projects Driven by Generator Deactivations Baseline ID b2774 Upgrade Reconductor the Emilie-Falls 138 kv line and replace station cable and relay Trans Zone Violation Deactivated Unit(s) PECO Overload of Emilie-Falls 138 kv Mercer 1-2 b2775 Reconductor the Falls-U.S. Steel 138 kv line PECO Overload of Falls-U.S. Steel 138 kv line Mercer PJM 2016 Regional Transmission Expansion Plan

27 Book 3: Immediate Need Projects Western PJM Subregion Generator deactivation studies conducted during 2016 identified reliability criteria violations in PJM s Western Subregion requiring system reinforcements. While PJM evaluated all the deactivation notifications received in 2016, as listed earlier in Table 3.1, system reinforcements were identified in 2016 for the Will County 4 deactivation in the ComEd transmission zone of the PJM Western Subregion. Accordingly, the PJM Board approved the two baseline reliability projects shown in Table 3.3 and Map 3.3 (including those under $5 million). Map 3.3: Western 2016 RTEP Baseline Projects Driven by Generator Deactivations Table 3.3: Western 2016 RTEP Baseline Projects Driven by Generator Deactivations Baseline ID b b Upgrade Cut-in of line Tazewell-Kendall 345 kv line into Dresden Raise towers to remove the sag limitations on 345 kv line 8012 Pontiac-Loretto Trans Zone ComEd Violation Overload of Dresden 345/138 kv transformer No. 83 Deactivated Unit(s) Will County 4 ComEd Overload of Pontiac-Loretto 345 kv line Will County 4 PJM 2016 Regional Transmission Expansion Plan 19

28 3 Book 3: Immediate Need Projects 20 PJM 2016 Regional Transmission Expansion Plan

29 Book 3: Immediate Need Projects 3 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 3.1: Baseline Analysis Driven Projects Immediate Need Immediate Need system enhancements can also be driven by operational performance; NERC TPL short circuit and stability criteria violations; and, local Transmission Owner criteria violations. Analyses in 2016 identified the need for 48 such projects as listed in Table 3.4 and shown on Map 3.4. PJM 2016 Regional Transmission Expansion Plan 21

30 3 Book 3: Immediate Need Projects Table 3.4: Immediate Need Projects Map Id RTEP Upgrade Id Description Driver b2186 Replace poles at Earleys 230 kv; replace two spans of conductor on Earleys-Roanoke Valley 230 kv line; add new battery enclosure. Baseline Deliverability b2269 Upgrade relays at Mountain 230 kv substation. Baseline Deliverability b2458 b2746 b2751 b2753 b2779 b2824 b2699 b2747 Reconductor Carolina Jackson 115 kv line Rebuild Ridge Road-Kerr Dam 115 kv; rebuild Ridge Road-Chase City 115 kv line; install 25 MVAR capacitor at Ridge Road Rebuild/resag portion of Hays Road-SW kv line Upgrades: George Washington 138 kv substation; Dilles Bottom substation; Burger-Cloverdale No kv line; Burger-Longview 138 kv line; Moundsville substation; Construct new Campbell Road 138 kv station on Grabill-South Hicksville 138 kv line; Reconstruct Butler-N.Hicksville and Auburn-Butler 69 kv circuits as 138 kv; construct new Wilmington 345/138 kv substation; loop-in new circuits from Auburn, Rob Park and Dunton Lake 138 kv substations Expand Lackawanna 500 kv substation to add third bay with three circuit breakers Powerton 345 kv substation upgrade Upgrade Gordonsville 115 kv substation equipment Baseline Deliverability Baseline Deliverability Baseline Deliverability Baseline Deliverability Baseline Deliverability Baseline Deliverability Operational Performance Operational Performance Transmission Owner Required In-Service Date Dominion 5/31/2017 UGI 12/31/2016 Dominion 5/1/2016 Dominion 6/1/2018 RMU 6/1/2016 AEP 1/1/2019 AEP 6/1/2016 PPL 1/31/2019 ComEd 6/1/2018 Dominion 6/1/ b1696 Replace breakers at Idylwood 230 kv substation Short Circuit Dominion 6/1/ b2720 Replace breakers at Loudoun 500 kv substation Short Circuit Dominion 6/1/ b2723 Replace breakers at Mickleton 69 kv substation; Short Circuit AEC 6/1/ b2725 Replace breaker at Murray 138 kv substation Short Circuit ATSI 4/16/ b2727 Replace breakers at South Canton 138 kv substation Short Circuit AEP 6/1/ b b2739 Replace breakers a Warren 115 kv substation Short Circuit PENELEC 6/1/ b2740, b2741 Breaker work at Hooversville 115 kv substation Short Circuit PENELEC 6/1/ b2742 Replace the Hoytdale 138 kv 83-B-26 and 83-B-30 breakers with 63 ka breakers Short Circuit ATSI 6/1/ b2756 Install 2 percent reactors at Martins Creek 230 kv Short Circuit PPL 6/1/ b2817 Replace breaker at Delaware 138 kv substation Short Circuit AEP 6/1/ b2818 Replace breaker at West Huntington 138 kv substation Short Circuit AEP 6/1/ b2819 Replace breaker at Madison 138 kv substation Short Circuit AEP 6/1/ b2820 Replace Sterling 138 kv breaker G with a 40 ka breaker Short Circuit AEP 6/1/ b2821 Replace breakers at Morse 138 kv substation Short Circuit AEP 6/1/ b2822 Replace breakers at Clinton 138 kv substation Short Circuit AEP 6/1/ PJM 2016 Regional Transmission Expansion Plan

31 Book 3: Immediate Need Projects 3 Table 3.4: Immediate Need Projects (Continued) Map Id 26 RTEP Upgrade Id Description Driver b2754 Install optical ground wire between Gilbert and Springfield 230 kv substations; Morris Park and Northwood 230 kv substation; upgrade relay equipment at Gilbert, Morris Park and Martins Creek 230 kv substations Transmission Owner Required In-Service Date Stability PPL, JCPL, ME 6/1/ b2731 Convert Sunnyside-East Sparta-Malvern 23 kv sub-transmission network to 69 kv. TO Criteria Violation AEP 8/1/ b2748 Install two 28 MVAR capacitors at Tiffany 115 kv substation TO Criteria Violation PENELEC 6/2/ b2749 Replace relay equipment at West Boyertown 69 kv station on the West Boyertown-North Boyertown 69 kv line TO Criteria Violation ME 6/1/ b2750. Retire Betsy Layne 138/69/43 kv substation; replace with greenfield Stanville station nearby; relocate capacitor bank TO Criteria Violation AEP 12/1/ b2757 Install a +/-125 MVAr Statcom at Colington 230 kv substation TO Criteria Violation Dominion 6/1/ b2758 Rebuild Dooms-Valley 500 kv line TO Criteria Violation Dominion 6/1/ b2759 Rebuild Mt. Storm-Valley 500 kv line TO Criteria Violation Dominion 6/1/ b2785 Install a 13.7 MVAR cap bank at Three Links 69 kv substation TO Criteria Violation EKPC 12/1/ b2802 Rebuild Chase City-Boydton Plank Road Tap TO Criteria Violation Dominion 6/30/ b2803 Reconductor Bethlehem-Leretto 46 kv line and replace terminal equipment at Summit 46 kv substation TO Criteria Violation PENELEC 6/1/ b2804 Install new relaying and replace bus conductor at Huntingdon 46 kv substation TO Criteria Violation PENELEC 6/1/ b2805 Install new relaying and replace conductor at Hollidaysburg 46 kv substation TO Criteria Violation PENELEC 6/1/ b2806 Install new relaying and replace metering at the Raystown 46 kv substation TO Criteria Violation PENELEC 6/1/ b2807 Replace relay equipment at Eldorado 46 kv substation TO Criteria Violation PENELEC 6/1/ b2808 Adjust the JBC overcurrent relay trip setting at Raystown 46 kv, and replace relay and 4/0 CU bus conductor at Huntingdon 46 kv substations, on the Raystown-Huntingdon 46 kv circuit TO Criteria Violation PENELEC 6/1/ b2809 Install a bypass switch at Mount Pleasant 34.5 kv substation TO Criteria Violation JCPL 6/1/ b2810 Install second 230/69 kv transformer at Cedar Grove; construct new Cedar Grove-Great Notch 69 kv line TO Criteria Violation PSE&G 6/1/ b2811 Construct new Locust Street-Delair 69 kv line TO Criteria Violation PSE&G 6/1/ b2812 Construct new River Road-Tonnelle Avenue 69 kv line TO Criteria Violation PSE&G 6/1/ b2813 Expand Lycoming 69 kv substation to double-bus-double-breaker arrangement TO Criteria Violation PPL 6/1/ b2814 Install third 230/69 kv 224 MVA transformer and terminal equipment at Lyons 69 kv substation TO Criteria Violation ME 6/1/ b2815 Construct new Pinewood 115 kv switching station TO Criteria Violation Dominion 6/1/2017 PJM 2016 Regional Transmission Expansion Plan 23

32 3 Book 3: Immediate Need Projects Map 3.4: Immediate Need Projects 24 PJM 2016 Regional Transmission Expansion Plan

33 Book 3: Immediate Need Projects Operational Performance High Voltage PJM system operators continue to encounter location-specific real-time high voltage alarms across the RTO during low load conditions, often during fall and spring months. These alarms identify substation voltages that have reached levels exceeding limits set by PJM and Transmission Owners to protect electrical equipment and preserve reliable system operation. PJM s generation dispatch stack during low load periods differs markedly than under peak load conditions. Many generating units do not or cannot cycle onand-off daily and can aggravate voltage levels under low load conditions. Once able to help in such situations, growing levels of large-coal-fired unit deactivation has meant the loss of their aggregate capability to absorb excess system reactive power. These factors, coupled with the capacitive effect of more lightly loaded transmission lines, increase bus voltages even further. When forecasted system conditions are such that high voltages may occur, PJM operations staff study possible actions to control them. Such actions can include switching out capacitors, switching on shunt reactors, changing transformer tap positions and other actions up to and including opening transmission lines. The need for system operators to take such measures is an indication that a more fundamental issue needs to be addressed as part of RTEP process analysis. Table 3.5: Northern New Jersey High Voltage Issues 138 kv Substations 230 kv Substations 345 kv Substations Doremus Place 138 kv 49 th Street R 230 kv Newark Airport 345 kv Fair Lawn 138 kv 49 th Street Y 230 kv Bayonne 345 kv Federal Square 138 kv Essex 230 kv Bayway 345 kv Foundry Street 138 kv Hoboken 230 kv Bergen 345 kv Newark 138 kv Homestead 230 kv Linden 345 kv Kearny 230 kv Marion 345 kv Madison 230 kv North Avenue 345 kv Newport 230 kv NJT Meadows 230 kv Penhorn 230 kv South Water Front 230 kv PSE&G Zone PJM system operators have recently observed high substation voltages across the eastern part of PJM s Mid-Atlantic Subregion, specifically within PSE&G. Given that the Bergen-Linden Corridor project in Northern PSE&G is under construction and scheduled to be completed by June 2018, PJM conducted additional near-term analysis using operational data to determine if high voltage violations would still exist once the project is fully energized. Those studies did identify several facilities ranging from 138 kv to 345 kv with high voltage issues as shown in Table 3.5 and on Map 3.5. These events are observed during light load periods when the transmission system experiences increased line charging arising from recent RTEP system enhancements coupled with loss of dynamic MVAR control from recent generation deactivations. The 1,500 MVARs of reactors and SVCs approved in prior years are improving voltage NOTE: A shunt reactor is an inductive device at a substation bus that can be switched into service to absorb reactive power, lowering the voltage at that location. PJM 2016 Regional Transmission Expansion Plan 25

34 3 Book 3: Immediate Need Projects Map 3.5: Northern New Jersey High Voltage Issues 26 PJM 2016 Regional Transmission Expansion Plan

35 Book 3: Immediate Need Projects 3 profiles. However, planning studies have shown that additional reactive devices to absorb reactive power will be required. PJM will recommend to the PJM Board that 600 MVAR of new shunt reactors in northern PSE&G as shown on Map 3.6: Map 3.6: Northern New Jersey Reactor Locations 100 MVAR at Kearny 230 kv An additional 100 MVAR at Hudson 230 kv (200 MVAR total) 200 MVAR at Bayway 345 kv 200 MVAR at Linden 345 kv Given the long procurement time for these devices, project work will commence as soon as possible to meet required in-service dates Newark Airport Additional Source Need The Newark International Airport is currently served by two 138 kv circuits and several 26 kv circuits. As part of the planned Bergen-Linden Corridor project, the two 138 kv circuits that currently serve Newark Airport will be converted to 345 kv. Over the next several years significant renovation and expansion projects will be completed at the airport. A new terminal A and associated infrastructure is planned for 2018 with additional load totaling approximately 30 MVA, increasing the total airport load to over 70 MVA. In addition, the Port Authority has plans to expand mass transit systems around the airport such that the total load in the area is expected to exceed 80 MVA by Under the existing planned configuration Newark Airport load will be primarily served from two new 345 kv underground cable circuits that are part of the Bergen-Linden Corridor project. In addition, several existing 26 kv circuits were intended to be used for back up. However, a portion of the property that the substation associated with the 26 kv circuits is located on is owned by the airport and will be needed by the Newark Airport to accommodate the new terminal. Based on PSE&G s filed FERC Form 715 planning criteria, load of more than 20 MVA cannot be dropped for more than 24 hours following the loss of two underground transmission lines. If one of the 345 kv cables planned to feed the airport is out on maintenance or the result of a fault and a second cable trips, the 26 kv circuits that were intended to provide backup power will not be able to serve the entire load at the airport following the expansion project. Considering all of these factors, a third transmission source to the airport is needed. PJM 2016 Regional Transmission Expansion Plan 27

36 3 Book 3: Immediate Need Projects Approved Project The recommended project to address the TO criteria violation is to introduce a third 345 kv source, from North Avenue substation to the Newark Airport as shown on Map 3.7. The new line is intended to be constructed at the same time portions of the Bergen-Linden Corridor project are being built to take advantage of project design and construction synergies and reduce overall cost. The expected cost of the project is $43 million and is required to be in-service by June 1, The PJM Board approved this project in October Map 3.7: North Avenue-Newark Airport 345 kv Line Load Deliverability Review PJM revisited the 2015 RTEP Load Deliverability analyses during 2016 to determine any changes to locational deliverability area CETO and CETL values caused by system topology changes identified during the 2015 RTEP cycle. The objective is to provide stakeholders as sense of system margin before another CETL might be encountered after the ones solved by approved projects identified during a given RTEP cycle. To do so, PJM conducted studies to identify limiting facilities identified for locational deliverability areas with less than 150 percent margin. Those conducted in 2016, incorporated updated 2019 Summer Peak RTEP base case study assumptions: 2016 PJM Load Forecast Report PJM Board approved projects and TO supplemental projects Generation Model deactivation and interconnection project changes Transmission service 28 PJM 2016 Regional Transmission Expansion Plan

37 Book 3: Immediate Need Projects 3 The results of the 2016 analysis are shown in Table 3.6 reflects the limiting facilities identified for LDAs with a CETL to CETO margin less than 150 percent. Although studies revealed two LDAs with margins less than 150 percent, none qualified as reliability criteria violations given that their CETL values were still greater than respective CETOs. NOTE: Capacity Emergency Transfer Objective (CETO) is the emergency import capability, expressed in megawatts, required of a PJM LDA to remain within a loss of load expectation of one event in 25 years when the area is experiencing a localized capacity emergency Capacity Emergency Transfer Limit (CETL) is part of load deliverability analysis to determine the maximum capability of the transmission system to deliver power to an LDA experiencing a localized capacity emergency CETO and CETL are described in Book 2, Table 3.6: 2016 CETO and CETL Review per 2015 RTEP Projects Area MW CETO MW CETL Margin (%) Limiting Facility Violation Type AE 520 >780 >150 None AEP 740 >1,110 >150 None APS 2,680 >4,020 >150 None ATSI 4,490 >6,735 >150 None BGE 4,060 >6,090 >150 None CLEV 3,390 >5,085 >150 None ComEd 610 >915 >150 None DAYTON 1,290 >1,935 >150 None DLCO 1,630 >2,445 >150 None DPL 960 >1,440 >150 None DPL SOUTH 1,230 >1,845 >150 None DEO&K 3,540 5, Tanner-Miami Fort 345 kv for loss of Terminal-East Bend 345 kv Thermal EKPC 750 >1,125 >150 None EMAAC 1,580 >2,370 >150 None JCPL 2,670 >4,005 >150 None MAAC -6,930 >3,465 >150 None Met-Ed 1,220 >1,830 >150 None PECO 2,780 >4,170 >150 None PENELEC 140 >210 >150 None PEPCO 2,870 >4,305 >150 None PJM WEST 2,050 >3,075 >150 None PLGRP -170 >85 >150 None PSE&G 5,590 7, Roseland-Williams Pipeline 230 kv for loss of Roseland-Cedar Grove 230 kv Thermal PSE&G North 2,280 >3,420 >150 None SWMAAC 3,920 >5,880 >150 None VAP -2,360 >1,180 >150 None WMAAC -8,310 >4,155 >150 None PJM 2016 Regional Transmission Expansion Plan 29

38 3 Book 3: Immediate Need Projects 30 PJM 2016 Regional Transmission Expansion Plan

39 Book 3: Market Efficiency Projects 4: Market Efficiency Projects PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 4 4.0: 2016 Activity Three Additional Approved Projects During the first half of 2016, PJM continued to evaluate two groups of projects solicited through the 2014/15 RTEP Long-Term RTEP Proposal Window. The first group included projects submitted to address congestion associated with PJM IROL (Interconnected Reliability Operating Limit) interfaces. The second group included projects that addressed increased capacity costs from restricted Capacity Emergency Transfer Limits (CETL) encountered in PJM s Reliability Pricing Model (RPM) auctions for the ComEd Locational Deliverability Area (LDA). Based on that evaluation, PJM recommended three additional market efficiency projects in addition to the eleven approved in The projects address both energy market and capacity market congestion and have an estimated cost of $ million. The projects are expected to mitigate at least $922 million in energy market congestion over the next 15 years, and provide RPM capacity load payment savings totaling $118 million. Window Process PJM opened the 2014/15 RTEP Long-Term Proposal Window between October 30, 2014 and February 27, The window solicited technical solution alternatives to certain reliability criteria violations as well as alleviate market efficiency congestion drivers, as described in Book 3, 5.2 of the 2015 PJM RTEP report, available on PJM s website via the following link: reports/2015-rtep/2015-rtep-book-3.ashx. PJM s RTEP Market Efficiency study process and the benefit-to-cost ratio methodology are described in 2 of PJM Manual 14B, PJM RTEP, available on PJM s website via the following link: media/documents/manuals/m14b.ashx. The base case assumptions for the 2014/2015 RTEP Market Efficiency Cycle are described in 8.4 of the 2014 PJM RTEP Input Assumptions, available on PJM s website via the following link: documents/reports/rtep-plan-documents/2014- input-assumptions-white-paper.ashx. Additional sensitivity analysis in 2015 and 2016 incorporated updated assumptions for natural gas price, load forecast, significant generation, and transmission topology changes. The analysis tested submitted proposals to ensure they would still satisfy the benefit-to-cost threshold under the most up-to-date assumptions available to PJM, described in Book 3, 5.1 of the 2015 PJM RTEP report, available on PJM s website via the following link: reports/2015-rtep/2015-rtep-book-3.ashx. PJM recommended the projects associated with PJM IROL reactive interfaces to reduce congestion on the AP-South or AEP-Dominion reactive interfaces. PJM reactive interface limits are thermal megawatt values that correlate to power flows beyond which voltage reliability criteria violations may occur as established by AC voltage analysis. PJM initially evaluated each project in the context of original 2014 base case conditions. Six of the 41 project proposals to address the reactive interface congestion provided the most benefit and were evaluated further as part of sensitivity studies conducted in 2015 and These sensitivities focused on load forecast and natural gas price variation. PJM 2016 Regional Transmission Expansion Plan 31

40 4 Book 3: Market Efficiency Projects Capacitors Several projects proposed area reactive support with capacitor installations at various locations. Further study revealed that combining new reactive sources at various locations with other projects could create a hybrid project with a high benefit-to-cost ratio. Capacitors help support voltage under heavy crosssystem power transfers. However, the addition of too many capacitors in a local area can potentially create high voltage operational concerns. Cognizant of high voltage operational performance concerns, a cross-functional internal PJM team evaluated the impact of the proposed capacitors to determine an optimal capacitor configuration that provides significant market congestion relief, increased reliability, and additional operational flexibility. Map 4.1: AP Congestion Relief: Optimal Capacitor Locations Approved Optimal Capacitors Solution The solution (PJM designation b2729) was approved by the PJM Board in February The solution consists of 150 MVAR, 300 MVAR, and two 175 MVAR new shunt capacitor installations at the existing Brambleton, Ashburn, Shelhorn and Liberty substations. These system additions, shown on Map 4.1, have been designated to Dominion, the incumbent transmission owner. The project is expected to cost $8.98 million and be in service by June 1, Overall, the project is estimated to mitigate market congestion totaling approximately $300 million over a 15-year period. 32 PJM 2016 Regional Transmission Expansion Plan

41 Book 3: Market Efficiency Projects AP-South Congestion Relief Project 9A PJM s recommended AP-South congestion relief solution included both a reactive component capacitors just discussed as well as a nonreactive component, discussed here. Following the February 2016 PJM Board meeting, PJM continued to assess the non-reactive transmission solution components from among the 41 original proposals to address AP-South interface congestion. Over the course of 18 months, PJM conducted a series of market efficiency studies and reliability analyses that ultimately identified four proposals for more detailed consideration. Additional sensitivity studies would reveal that of the four, Project 9A provided the greatest congestion benefits and highest benefit-to-cost ratio. Project 9A includes a western component Rice-Ringgold 230 kv line and an eastern component Furnace Run-Conastone-Northwest 230 kv line as shown on Map 4.2, providing additional paths from the area 500 kv system to load on transmission at lower voltage levels. PJM notes that it the combination of both components provides the greatest benefits. A project comprised only of Project 9A western components would have increased congestion in eastern PJM. Overall, the project comprises ten components including new facilities, tapping existing facilities and reconductoring certain existing lines. The project was approved by the PJM Board in August 2016, with an estimated cost of $ million and a required in-service date by June 1, Expected 15- year congestion and load payment savings are $622 million and $269 million, respectively. Map 4.2: AP-South Congestion Relief: Non-Reactive Solution Proposals PJM 2016 Regional Transmission Expansion Plan 33

42 4 Book 3: Market Efficiency Projects Extensive Analysis Reaching a recommendation for AP-South required a number of steps over an 18-month period, culminating in the selection of 9A in the second quarter of 2016 as shown in the Figure 4.1 timeline. An initial set of sensitivity analyses focusing on natural gas price, load forecast and reactive reduced the number of competitive proposals under consideration from 41 to 11. Additional sensitivity analyses further reduced the eleven projects to four based on required benefit-to-cost threshold and degree of congestion relief provided. Those final four projects, located on the border between Pennsylvania and Maryland, are shown on Map 4.2. Project 9A as proposed by Transource Energy, LLC provided the greatest benefits. The project encompasses both a western and an eastern set of transmission facilities the combination of which provides significant benefits. The project provides additional paths from the area 500 kv system to load on transmission at lower voltage levels. A project comprised only of Project 9A western components would have increased congestion in eastern PJM given the change in power flow patterns that just those western components alone would have caused. Figure 4.1: Market Efficiency Timeline for AP-South Analysis Number of Projects Proposals review, base runs with 2014 assumptions Runs with 2015 updated assumptions Scenario runs with potential October, 2015 approved upgrades Scenario runs with change in gas, load and reactive limits Combination projects New base runs with 2016 updated assumptions Final four combination projects passed B/C test Final project recommendation for Project 9A Project 9A consistently showed greatest benefits finalist projects passed B/C test under all scenarios with approved February 2016 projects 21 projects passed updated 2015 assumptions Work led to capacitor projects approved in February May- Jun. Aug. Sep. Nov Jan.- Present Analysis of project combinations Although Project 9A itself provided the greatest congestion benefits and highest benefit-to -cost ratio, PJM performed additional sensitivity studies to assess different combinations of several similar proposals along the Pennsylvania- Maryland border, shown earlier on Map 4.2: 1. Project 9A, as proposed 2. Projects 18H+9A East 3. Projects 19B+9A East 4. Projects 19D+9A East NOTE: Figure 4.1: B/C = 1.25 benefit-to-cost threshold 34 PJM 2016 Regional Transmission Expansion Plan

43 Book 3: Market Efficiency Projects 4 Based on feedback from PJM stakeholders and in an effort to develop the most robust solution, PJM conducted additional sensitivity analysis comparing Project 9A with three proposal combinations with one another and under sensitivity variations in load forecast, fuel prices, and generator assumptions: 1. Baseline Case 2015 market efficiency baseline case Figure 4.2: Project Benefit/Cost Ratios Per Project Benefit/Cost Ratio A 18H+9A East 19B+9A East 19D+9A East 2. -$2 Gas forecasted baseline natural gas price was reduced by $2/MMBtu $1 Gas forecasted baseline natural gas price was reduced by $1/MMBtu 4. +$1 Gas forecasted baseline natural gas price was increased by $1/MMBtu Base Line Case B/C Threshold -$2 Gas - $1 Gas + $1 Gas - 2% Load + 2% Load Generator Sensitivity Figure 4.3: AP-South Congestion Benefits Per Project Millions ($) A 18H+9A East 19B+9A East 19D+9A East Base Line Case -$2 Gas - $1 Gas + $1 Gas - 2% Load + 2% Load Generator Sensitivity PJM 2016 Regional Transmission Expansion Plan 35

44 4 Book 3: Market Efficiency Projects Percent Load forecasted load was reduced by 2 percent Percent Load forecasted load was increased by 2 percent 7. Generator Sensitivity (Gen Sens) a scenario in which Dickerson and Chalk Point units do not retire These scenarios were evaluated in terms of the following project economic benefits, as successive figures show: Figure 4.4: PJM Total Congestion Benefits Millions ($) A 18H+9A East 19B+9A East 19D+9A East 1. Project Benefit-to-Cost Ratio, shown in Figure AP-South Congestion Benefit, shown in Figure Base Line Case -$2 Gas - $1 Gas + $1 Gas - 2% Load + 2% Load Generator Sensitivity 3. PJM Total Congestion Benefits, shown in Figure Load Payment Benefits, shown in Figure PJM Production Cost Benefits, shown in Figure 4.6 Figure 4.5: Load Payment Benefits Millions ($) A 18H+9A East 19B+9A East 19D+9A East 0 Base Line Case -$2 Gas - $1 Gas + $1 Gas - 2% Load + 2% Load Generator Sensitivity 36 PJM 2016 Regional Transmission Expansion Plan

45 Book 3: Market Efficiency Projects 4 The study results shown in those figures demonstrated that Project 9A consistently provided the most benefits across the scenarios studied. PJM also conducted additional economic analysis in which Project 9A was added to the base case followed by each of the three other projects in combination with it. Those results indicated that none of the three subsequently passed the benefit-to-cost 1.25 threshold test. Constructability and Cost Analysis The PJM Operating Agreement 1.5.7(g) requires PJM to develop an independent cost estimate for Market Efficiency projects with costs in excess of $50 million. PJM engaged an independent consultant who verified the proposed costs schedule duration, and risks for Project 9A and others, as described in the PJM 2014/2015 Long-Term Proposal Window Independent Cost Review White Paper available online: groups/committees/teac/ / long-term-proposal-windowindependent-cost-review-white-paper.ashx. Figure 4.6: PJM Production Cost Benefits Millions ($) Base Line Case 9A 18H+9A East 19B+9A East 19D+9A East -$2 Gas - $1 Gas + $1 Gas - 2% Load + 2% Load Generator Sensitivity PJM 2016 Regional Transmission Expansion Plan 37

46 4 Book 3: Market Efficiency Projects Approved AP-South Solution Project 9A, shown on Map 4.3, was approved by the PJM Board in August 2016 and includes the following components, designated to Transource and incumbent transmission owner as noted: Map 4.3: AP-South Congestion Relief: Non-Reactive Approved Solution The West Line: approximately 27 miles of new double-circuit 230 kv alternating current overhead transmission line configured in a sixwired arrangement between the existing Ringgold Substation to a new Rice Substation that will tie into the existing Conemaugh-Hunterstown 500 kv line, assigned to Transource. The Ringgold Substation will be expanded to accommodate the new 230 kv circuits with one new 230 kv breaker, assigned to APS. The new Rice Substation will include two 900 MVA, 500/230 kv transformers, two 245 kv breakers in a single bus double breaker configuration and four 500 kv breakers in a ring bus configuration, assigned to Transource. The East Line: approximately 14.5 miles of new double-circuit 230 kv alternating current overhead transmission line configured in a six-wired arrangement between the existing Conastone Substation to a new Furnace Run Substation that taps the existing Three Mile Island-Peach Bottom 500 kv line, assigned to Transource. The new Furnace Run Substation will include two 900 MVA, 500/230 kv transformers, two 245 kv breakers in a double breaker single bus configuration, and four 500 kv breakers in a ring bus configuration, assigned to Transource. The Conastone Substation will be expanded to accommodate the new double circuit 230 kv lines and two new 230 kv breakers, assigned to BGE. Reconductor the Conastone to Northwest Double Circuit 230 kv line, assigned to BGE. Replace the Ringgold No. 3 and No. 4 transformers with 230/138 kv autotransformers, assigned to APS. Reconfigure the Ringgold Bus, assigned to APS. Reconductor the Ringgold-Catoctin 138 kv line, assigned to APS. The project is estimated to cost $ million with a required in-service by June 1, The expected 15-year congestion and load payment savings are $622 million and $269 million, respectively. 38 PJM 2016 Regional Transmission Expansion Plan

47 Book 3: Market Efficiency Projects Loretto-Wilton Center 345 kv Line PJM received nine proposals as part of the 2014/2015 Long-Term Market Efficiency Proposal Window, to address congestion on the ComEd Loretto-Wilton Center 345 kv line shown on Map 4.4. Cost estimates ranged from $11.5 million to $290 million. The 2018/2019 Reliability Pricing Model Base Residual Auction in August 2015 had revealed that the Loretto-Wilton Center line constrained capacity delivery into the ComEd locational deliverability area. As a result, the nine proposals originally submitted to address energy market congestion could also provide Reliability Pricing Model capacity market benefit. PJM determined that by increasing the capability of the limiting element the Lorretto-Wilton Center line itself the ComEd zone and other locational deliverability areas would have the ability to supply capacity at lower overall cost. PJM recommended Project 10D to eliminate sag limitations on the line and to replace conductor at Wilton Center substation. The PJM Board approved the project in February 2016, at an estimated $11.5 million cost, with a required June 1, 2019, in-service date. The project will provide an annual estimated $118 million in capacity payment benefits when the ComEd locational deliverability area is limiting. Given that this project comprises upgrades to existing equipment, it was designated to the incumbent transmission owner, ComEd. Map 4.4: Loretto-Wilton Center 345 kv Market Efficiency Proposals PJM 2016 Regional Transmission Expansion Plan 39

48 4 Book 3: Market Efficiency Projects Capacity Market Benefit PJM calculated the capacity benefits associated with the proposed projects using the methodologies specified in Schedule 6 of the PJM Operating Agreement. PJM s annual capacity benefit calculation for regional facilities is weighted 50 percent to change in total system capacity cost and 50 percent to change in net load capacity payments for zones with a decrease in net load capacity payments as a result of the proposed project. PJM s annual capacity benefit calculation for lower voltage facilities is weighted 100 percent to zones with a decrease in net load capacity payments as a result of the proposed project. Change in net load capacity payment comprises the change in gross capacity payment offset by the change in capacity transfer rights. PJM assessed each proposal s impact on the ComEd Capacity Emergency Transfer Limit (CETL). This revealed that by increasing Lorretto- Wilton Center line capability, the ComEd zone and other locational deliverability areas would have the ability to supply capacity at a lower overall cost. PJM simulated the RPM process for multiple study years with the updated CETL values and measured each project s capacity benefits over a 15-year period. Evaluation of the nine proposals revealed that Project 10D provided the highest total benefit-to-cost ratio. Board Approval Project 10D (PJM designation b2728) comprises elimination of existing sag limitations on the Loretto-Wilton Center 345 kv line itself, shown on Map 4.5, and an upgrade to station conductor at Wilton Center. Conventional planning analysis of the project did not identify any reliability criteria violations. PJM recommended Map 4.5: RPM Recommended Project Loretto-Wilton Center 345 kv Project 10D to the PJM Board who approved it in February 2016, at an estimated $11.5 million cost, with a required June 1, 2019 inservice date. The project will provide an annual estimated $118 million in capacity payment benefits when the ComEd locational deliverability area is limiting. Given that this project constitutes upgrade to existing facilities, it was designated to the incumbent Transmission Owner, ComEd. 40 PJM 2016 Regional Transmission Expansion Plan

49 Book 3: 2016 RTEP Proposal Windows 5: 2016 RTEP Proposal Windows PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 5 5.0: 2016 RTEP Proposal Window No Window Process PJM conducted 2016 RTEP Proposal Window No. 1 from February 16, 2016 to March 17, 2016, to solicit solutions to address two 2015 generator deliverability analysis reliability criteria violations associated with the Chesterfield-Messer Road 230 kv line and the Carson-Rodgers Road 500 kv lines, shown in Table 5.1 and Map 5.1. However, 2015 Window No. 1 solution proposals to address these reliability criteria violations were put on hold in light of a queued generator interconnection project which would have imposed flow on the overloaded line. At the time the 2015 Proposal Window No. 1 opened, the generator had a signed Facilities Study Agreement (FSA), but not an Interconnection Service Agreement (ISA). PJM does not recommend baseline upgrades based on studies that have modeled projects without a signed ISA, unless a compelling reason exists to do so. The project ultimately did sign an ISA in late PJM is obligated to consider a new window addendum if major assumptions have changed since the window that preceded it. Such was the case here given the generation now modeled on the basis of ISA execution, coupled with PJM s 2016 load forecast and additional updates to queued generators in the area since 2015 Proposal Window No. 1. The results of reliability studies with those model updates indicated that a new proposal Table 5.1: 2016 RTEP Proposal Window No. 1 Violations Analysis Type Overloaded Facility TO Contingency Generator Delivery and Common Mode Outage Overload of the Chesterfield-Messer Rd 230 kv line Dominion LN 576 Generator Delivery and Common Mode Outage Overload of the Chesterfield-Messer Rd 230 kv line Dominion LN 259 Generator Delivery and Common Mode Outage Overload of the Chesterfield-Messer Rd 230 kv line Dominion LN 563 Generator Delivery and Common Mode Outage Overload of the Chesterfield-Messer Rd 230 kv line Dominion LN 284 Generator Delivery and Common Mode Outage Overload of the Chesterfield-Messer Rd 230 kv line Dominion LN 228 Generator Delivery and Common Mode Outage Overload of the Messer Rd- Charles City Rd 230 kv line Dominion LN 576 Generator Delivery and Common Mode Outage Overload of the Messer Rd- Charles City Rd 230 kv line Dominion LN 259 Generator Delivery and Common Mode Outage Overload of the Messer Rd- Charles City Rd 230 kv line Dominion LN 563 Generator Delivery and Common Mode Outage Overload of the Messer Rd- Charles City Rd 230 kv line Dominion LN 284 Generator Delivery and Common Mode Outage Overload of the Messer Rd- Charles City Rd 230 kv line Dominion LN 228 Generator Delivery and Common Mode Outage Overload of the Rodgers Rd-Carson 500 kv line Dominion LN 511 Generator Delivery and Common Mode Outage Overload of the Chesterfield-Messer Rd 230 kv line Dominion LN Generator Delivery and Common Mode Outage Overload of the Messer Rd- Charles City Rd 230 kv line Dominion LN window was warranted. Importantly during this same time frame, Dominion identified both facilities as nearing end-of-life based on their respective FERC Form No. 715 criteria condition assessments. PJM 2016 Regional Transmission Expansion Plan 41

50 5 Book 3: 2016 RTEP Proposal Windows Map 5.1: 2016 RTEP Proposal Window No. 1 Violations 42 PJM 2016 Regional Transmission Expansion Plan

51 Book 3: 2016 RTEP Proposal Windows Proposals PJM s 2016 RTEP Proposal Window No. 1 yielded 25 proposals from seven entities to solve the identified reliability criteria violations. Three were Transmission Owner upgrades to existing facilities that ranged in cost from $7.7 million to $48.5 million. Twenty-two were greenfield projects that ranged in cost from $15.6 million to $111.5 million. The proposals were located in the Dominion as shown in Table 5.2 and Map 5.2. Evaluation and Selection Once the window closed, PJM staff performed analytical, constructability and company evaluations to identify which proposals most effectively solved all reliability criteria violations and did not introduce new ones. Following Transmission Expansion Advisory Committee stakeholder review, PJM recommended to the PJM Board in July 2016 that the Carson-Rodgers Road 500 kv line and Chesterfield-Messer Road 230 kv line be rebuilt, as shown in Table 5.2 and Map 5.2: PJM 2016 Regional Transmission Expansion Plan 43

52 5 Book 3: 2016 RTEP Proposal Windows Table 5.2: 2016 RTEP Proposal Window No. 1 Proposals Project ID Upgrade/ Greenfield Proposing Entity Cost ($M) Major Components 2016_1-1A Greenfield Transource 61.1 Establish a new 500 kv circuit from Carson station to Rawlings station. This new circuit will eliminate the violation for the generation delivery flowgate involving Carson-Rogers Road 500 kv Circuit for the loss of the existing Carson- Rawlings 500 kv Circuit. 2016_1-1B Greenfield Transource 70.5 Establish a new 500 kv circuit from Carson station to Rogers Road station. This new circuit will eliminate the violation for the generation delivery flowgate involving Carson-Rogers Road 500 kv Circuit for the loss of the existing Carson-Rawlings 500 kv Circuit. 2016_1-2A Greenfield Northeast Transmission Development 2016_1-2B Greenfield Northeast Transmission Development 2016_1-2C Greenfield Northeast Transmission Development 24.0 Build a 500/230/115 kv substation ( Cornerstone ) interconnecting the Wake-Heritage 500 kv line, the Thelma- Lakeview 230 kv line, and the Eatons Ferry-Carolina 115 kv line 88.7 Build a 500 kv line from the 500 kv Rogers Road switching station to the existing 500 kv Carson substation 27.5 Build a new 500/230 kv interconnection from the existing 500 kv Rogers Road switching station to the existing 230 kv Clubhouse substation Recommendation for Board Approval 2016_1-3A Upgrade Dominion 48.5 Rebuild 500 kv line from Rogers Road-Carson with new structures X 2016_1-3B Upgrade Dominion 22 Rebuild miles of existing line between Chesterfield and Lakeside. X 2016_1-3C Greenfield Dominion 59.8 New 32 miles long 500 kv line from Carson-Rogers Road 2016_1-3D Greenfield Dominion miles of new 500 kv line from Carson-Rawlings 2016_1-3E Greenfield Dominion 34.5 A 500 kv line from Rogers Rd substation to new substation called Maclins. A 500/230 kv TX at Maclins substation and a 4.8 mile 230 kv line from Maclins to Clubhouse. 2016_1-3F Greenfield Dominion 58.8 Build a new 500 kv switching station called Dabney on the Carson-Midlothian 500 kv line, 15.5 miles away from Carson. Connect Rawlings 500 kv substation with the Dabney station with a 23-mile 500 kv line. Retire the 230 kv line from Chesterfield to Lakeside. Tap the 230 kv line from Darbytown to Northeast, 1.23 miles away from Darbytown, and connect Charles City Road load to the line. Upgrade a 0.14-mile section on the Chesterfield-Basin 230 kv line. 2016_1-3G Upgrade Dominion 7.7 Connect 217 Line into existing 230 kv bus at Northeast Substation. Rebuild 7.91 miles of existing 217 Line between Lakeside and Northeast. Retire Existing 217 Line between Northeast and Chesterfield. Move Charles City substation tap from 217 Line to 2053 Line. Reconductor 0.14 miles of 259 Line. 2016_1-4A Greenfield PSE&G 25.8 Build a new 230 kv line from the Planned 500 kv Rogers Road station to the existing 230 kv Clubhouse station. 2016_1-4B Greenfield PSE&G 55.8 Build a new 230 kv line from the new 500/230 kv Green Acres station to the new 230 kv Jasper station. 2016_1-5A Greenfield Mid-Atlantic MCN 41.7 Tap Elmont-Chickahominy 500 kv line and the Charles City-Lakeside 230 kv line at a new station location that is adjacent to the existing line corridor (station called East Highland Park). Install 500/230 kv phase shifting transformer in new substation. The new station to tie these lines together will be built with ring bus configuration on the 500 kv and 230 kv buses three 500 kv breakers and three 230 kv breakers. Build new 3.5- mile 230 kv circuit from Chesterfield substation to Tyler substation. Install breakers and terminal equipment in Tyler and Chesterfield substations. 2016_1-5B Greenfield Mid-Atlantic MCN 15.6 Build new 3.5- mile 230 kv circuit from Chesterfield substation to Tyler substation. Install breakers and terminal equipment in Tyler and Chesterfield substations. 2016_1-5C Greenfield Mid-Atlantic MCN 26.0 Tap Elmont-Chickahominy 500 kv line and the Charles City-Lakeside 230 kv line at a new station location that is adjacent to the existing line corridor (station called East Highland Park). Install 500/230 kv phase shifting transformer in new substation. The new station to tie these lines together will be built with ring bus configuration on the 500 kv and 230 kv buses three 500 kv breakers and three 230 kv breakers. 2016_1-6A Greenfield ITC Construct a new 500 kv line from the existing Rawlings 500 kv switchyard to a new switchyard (Steers) which taps the existing Carson-Midlothian 500 kv line 44 PJM 2016 Regional Transmission Expansion Plan

53 Book 3: 2016 RTEP Proposal Windows 5 Table 5.2: 2016 RTEP Proposal Window No. 1 Proposals (Continued) Project ID Upgrade/ Greenfield Proposing Entity Cost ($M) Major Components 2016_1-6B Greenfield ITC Construct a new 500 kv line from the existing Rawlings 500 kv switchyard to the existing Carson 500 kv substation. Upgrade the existing Rawlings Switchyard and Carson Substation to accommodate the new 500 kv line 2016_1-6C Greenfield ITC 61.8 Construct a new 500/230 kv substation cutting in the Brunswick-Wake 500 kv line. Construct new 230 kv line from the new 500/230 kv substation to the existing Clubhouse 230 kv substation. Upgrade the existing Clubhouse 230 kv substation to accommodate the new 230 kv line 2016_1-6D Greenfield ITC 59.8 Construct a new kv substation cutting in the Brunswick-Wake 500 kv line. Construct new lines on double circuit 230 kv towers from the new 500/230 kv substation to cut into the existing Clubhouse-Lakeview 230 kv line. This forms the new Lewis-Clubhouse and new Lewis-Lakeview 230 kv lines. 2016_1-7A Greenfield Nextera 62.9 New 29-mile transmission line from Rogers Road-Carson 500 kv 2016_1-7B Greenfield Nextera 57.7 New 29-mile transmission line from Rogers Road-Carson 500 kv 2016_1-7C Greenfield Nextera 46.6 New 22-mile transmission line from Carson-Rawlings 500 kv 2016_1-7D Greenfield Nextera 47.5 New Pleasant Shade 500/230 kv Substation connecting to Rogers Road 500 kv and Clubhouse 230 kv substations Recommendation for Board Approval PJM 2016 Regional Transmission Expansion Plan 45

54 5 Book 3: 2016 RTEP Proposal Windows Map 5.2: 2016 RTEP Proposal Window No. 1 Proposals 46 PJM 2016 Regional Transmission Expansion Plan

55 Book 3: 2016 RTEP Proposal Windows 5 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 5.1: 2016 RTEP Proposal Window No Window Process PJM opened the 2016 RTEP Proposal Window No. 2 from June 29, 2016 to July 29, 2016; additional detailed project costs were due by August 15, The window sought solutions to a number of PJM reliability criteria violations identified as part of Baseline N-1 (thermal and voltage), Generation Deliverability, Common Mode Outage, N-1-1 (thermal and voltage), and Load Deliverability (thermal and voltage) tests on a 2021 study year power flow case modeling peak summer conditions. The methodologies for those analyses are discussed in Book 2, 4.1. Analyses identified nine individual transmission line and transformer facilities and voltage violations on nine facilities, under one or more test conditions, associated with 137 flowgates. These are summarized in Table 5.3 and Map 5.3. PJM 2016 Regional Transmission Expansion Plan 47

56 5 Book 3: 2016 RTEP Proposal Windows Table 5.3: 2016 RTEP Proposal Window No. 2 Violations Analysis Type Overloaded Facility TO Contingency 1 N-1-1 Contingency 2 N-1 Thermal Overload of the Eugene-Dequine 345 kv line No. 1 American Electric Power AEP_P1-2_#8905 n/a N-1 Thermal Overload of the Eugene-Dequine 345 kv line No. 1 American Electric Power AEP_P1-2_#362 n/a N-1 Thermal Overload of the Bredinville- Cabrey Tap 138 kv line Allegheny Power AP-P7-1-WPP n/a Generator Delivery and Common Mode Outage Generator Delivery and Common Mode Outage Generator Delivery and Common Mode Outage Overload of the North Meshoppen 2 Reactor-North Meshoppen 230/115 kv transformer Overload of the North Meshoppen 2 Reactor-N. Meshoppen 115 kv line Overload of the Dequine-Meadow Lake 345 kv line No. 2 Pennsylvania Electric Company PN-P1-2-PN n/a Pennsylvania Electric Company PN-P1-2-PN n/a American Electric Power AEP_P1-2_#6472 n/a Generator Delivery and Common Mode Outage Overload of the E. Towanda-Canyon 230 kv line Pennsylvania Electric Company Base Case n/a Generator Delivery and Common Mode Outage Overload of the E. Towanda-Canyon 230 kv line Pennsylvania Electric Company PL:P12: n/a Generator Delivery and Common Mode Outage Overload of the E. Towanda-Canyon 230 kv line Pennsylvania Electric Company PL:P12: n/a Generator Delivery and Common Mode Outage Overload of the Eugene-Dequine 345 kv line No. 1 American Electric Power AEP_P1-2_#363 n/a Generator Delivery and Common Mode Outage Overload of the Eugene-Dequine 345 kv line No. 1 American Electric Power AEP_P1-2_#8905 n/a Generator Delivery and Common Mode Outage Overload of the Eugene-Dequine 345 kv line No. 1 American Electric Power AEP_P1-2_#362 n/a Generator Delivery and Common Mode Outage Overload of the Eugene-Dequine 345 kv line No. 1 American Electric Power COMED_P1-2_345-L8001 -S n/a Generator Delivery and Common Mode Outage Overload of the Saltville-Tazewell 138 kv line American Electric Power AEP_P1-2_#1371 n/a Generator Delivery and Common Mode Outage Overload of the Conastone-Peach Bottom 500 kv line PJM 500 kv Base Case n/a Generator Delivery and Common Mode Outage Overload of the Conastone-Peach Bottom 500 kv line PJM 500 kv PJM_P1_39-2 n/a Generator Delivery and Common Mode Outage Overload of the Conastone-Peach Bottom 500 kv line PJM 500 kv PECO_P1-2_5007 n/a Generator Delivery and Common Mode Outage Overload of the Walters 138-Sullivan 138 kv line Carolina Power & Light Company- West/American Electric Power AEP_P1-3_#321 Generator Delivery and Common Mode Outage Overload of the Hazard 161/138 kv transformer American Electric Power AEP_P7-1_#8634 n/a Generator Delivery and Common Mode Outage Overload of the Hazard 161/138 kv transformer American Electric Power AEP_P7-1_#8345 n/a Generator Delivery and Common Mode Outage Overload of the Clifty Creek-Miami Fort 138 kv line Ohio Valley Electric Corporation/Duke Energy Ohio/Kentucky AEP_P7-1_#632 Generator Delivery and Common Mode Outage Overload of the Hazard-Wooton 161 kv line American Electric Power AEP_P7-1_#8634 n/a Generator Delivery and Common Mode Outage Overload of the Hazard-Wooton 161 kv line American Electric Power AEP_P7-1_#8345 n/a Generator Delivery and Common Mode Outage Generator Delivery and Common Mode Outage Overload of the Spurlock 138 KV series reactor node- KU Kenton line-kenton 138 kv bus 138kV line Overload of the Spurlock substation 138 KV bus- Spurlock 138 kv series reactor node-ku Kenton line 138 kv line East Kentucky Power Coop./Louisville Gas and Electric/Kentucky Utilities EKPC_P7-1_SPUR 345 DBL East Kentucky Power Coop. EKPC_P7-1_SPUR 345 DBL n/a Generator Delivery and Common Mode Outage Overload of the Nickel-Warren 138 kv line Duke Energy Ohio/Kentucky DEO&K P7-1 CIRCUIT5689 & 4515FOSTERGARVER n/a Generator Delivery and Common Mode Outage Overload of the Beaver-Black River 138 kv line FirstEnergy ATSI ATSI-P7-1-OEC n/a Generator Delivery and Common Mode Outage Overload of the Bredinville- Cabrey Tap 138 kv line Allegheny Power AP-P7-1-WPP n/a n/a n/a n/a 48 PJM 2016 Regional Transmission Expansion Plan

57 Book 3: 2016 RTEP Proposal Windows 5 Table 5.3: 2016 RTEP Proposal Window No. 2 Violations (Continued) Analysis Type Overloaded Facility TO Contingency 1 N-1-1 Contingency 2 Generator Delivery and Common Mode Outage Overload of the Homer City 345/230 kv S Pennsylvania Electric Company PN-P2-3-PN AT n/a transformer Generator Delivery and Common Mode Outage Overload of the Lackawanna 500/230 kv transformer PPL Electric Utilities/PJM 500 kv PL:P42: n/a Generator Delivery and Common Mode Outage Overload of the Lackawanna 500/230 kv transformer PPL Electric Utilities/PJM 500 kv PL:P42: n/a Generator Delivery and Common Mode Outage Overload of the Four mile-erie South East 115 kv line Generator Delivery and Common Mode Outage Overload of the Walters 138-Sullivan 138 kv line Carolina Power & Light Company- West/American Electric Power Generator Delivery and Common Mode Outage Overload of the Walters 138-Sullivan 138 kv line Carolina Power & Light Company- West/American Electric Power Pennsylvania Electric Company PN-P2-3-PN-230-6G n/a AEP_P4_#2875 AEP_P4_#2873 Generator Delivery and Common Mode Outage Overload of Haumesser Road- W De Kalb 138 kv line Commonwealth Edison Co. COMED_P4_ BT3-4 n/a Generator Delivery and Common Mode Outage Overload of the Goudey-Laurel Lake 115 kv line New York ISO/Pennsylvania Electric Company Generator Delivery and Common Mode Outage Overload of the Clifty Creek-Miami Fort 138 kv line Ohio Valley Electric Corporation/Duke Energy Ohio/Kentucky PN-P2-3-PN G AEP_P4_#1760_05JEFRSO 765 Generator Delivery and Common Mode Outage Overload of the Olive-Bosserman 138 kv line American Electric Power AEP_P4_#675_05NEWCAR 138- n/a Generator Delivery and Common Mode Outage Overload of the Nagel-West Kingsport 138 kv line American Electric Power AEP_P4_#9191 n/a N-1-1 Thermal Overload of the Carlisle Pike-Gardners 115 kv line Pennsylvania Electric Company/ Metropolitan Edison Company ME-P1-2-ME N-1-1 Thermal Overload of the Fairview-Flat Run 138 kv line Allegheny Power AP-P1-2-MP BASE CASE N-1-1 Thermal Overload of the Carlisle Pike-Gardners 115 kv line Pennsylvania Electric Company/ Metropolitan Edison Company N-1-1 Thermal N-1-1 Thermal N-1-1 Thermal N-1-1 Thermal N-1-1 Thermal N-1-1 Thermal N-1-1 Thermal Overload of the Port Union 1-E. Provident Dr. 138 kv line Overload of the Port Union 1-E. Provident Dr. 138 kv line Overload of the Todhunter-Todhunter M17 345/138 kv transformer Overload of the Todhunter-Todhunter M16 345/138 kv transformer Overload of the Todhunter-Todhunter M17 345/138 kv transformer Overload of the Todhunter-Todhunter M15 345/138 kv transformer Overload of the Todhunter-Todhunter M15 345/138 kv transformer Duke Energy Ohio/Kentucky Duke Energy Ohio/Kentucky ME-P1-2-ME DEO&K P1-* P2-1 LOE BRKR OPEN AT PORT UNION 3885 DEO&K P1-* P2-1 LOE BRKR OPEN AT PORT UNION 3889 n/a n/a n/a n/a ME-P1-2-ME ME-P1-2-ME DEO&K P1-* P2-1 LOE BRKR OPEN AT PORT UNION 3889 DEO&K P1-* P2-1 LOE BRKR OPEN AT PORT UNION 3885 Duke Energy Ohio/Kentucky DEO&K P1-* P2-1 TODHUNTER 345/138 TB15 DEO&K P1-* P2-1 TODHUNTER 345/138 TB16 Duke Energy Ohio/Kentucky DEO&K P1-* P2-1 TODHUNTER 345/138 TB15 DEO&K P1-* P2-1 TODHUNTER 345/138 TB17 Duke Energy Ohio/Kentucky DEO&K P1-* P2-1 TODHUNTER 345/138 TB16 DEO&K P1-* P2-1 TODHUNTER 345/138 TB15 Duke Energy Ohio/Kentucky DEO&K P1-* P2-1 TODHUNTER 345/138 TB16 DEO&K P1-* P2-1 TODHUNTER 345/138 TB17 Duke Energy Ohio/Kentucky DEO&K P1-* P2-1 TODHUNTER 345/138 TB17 DEO&K P1-* P2-1 TODHUNTER 345/138 TB16 N-1-1 Low Voltage Voltage Criteria Violation at Valley 138 kv FirstEnergy ATSI ATSI-P1-2-OEC ATSI-P1-3-SYS N-1-1 Low Voltage Voltage Criteria Violation at Theiss Road 138 kv FirstEnergy ATSI ATSI-P1-2-OEC ATSI-P1-3-SYS N-1-1 Voltage Drop Voltage Criteria Violation at Woodbridge 230 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Lafayette 230 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT PJM 2016 Regional Transmission Expansion Plan 49

58 5 Book 3: 2016 RTEP Proposal Windows Table 5.3: 2016 RTEP Proposal Window No. 2 Violations (Continued) Analysis Type Overloaded Facility TO Contingency 1 N-1-1 Contingency 2 N-1-1 Voltage Drop Voltage Criteria Violation at Lafayette 230 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Woodbridge 230 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Woodbridge 230 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Metuchen 230 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Sewaren 230 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Pierson Ave. G 230 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at New Dover 230 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Metuchen 138 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Metuchen 138 kv PSE&G PS_P1-2_S-2219_LT PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Woodbridge 230 kv PSE&G PS_P1-2_S-2219 PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Lafayette 230 kv PSE&G PS_P1-2_S-2219 PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Woodbridge 230 kv PSE&G PS_P1-2_S-2219 PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Lafayettete 230 kv PSE&G PS_P1-2_S-2219 PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Woodbridge 230 kv PSE&G PS_P1-2_S-2219 PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Metuchen 230 kv PSE&G PS_P1-2_S-2219 PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Pierson Ave. G 230 kv PSE&G PS_P1-2_S-2219 PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at Sewaren 230 kv PSE&G PS_P1-2_S-2219 PS_P1-2_R-2218_LT N-1-1 Voltage Drop Voltage Criteria Violation at New Dover 230 kv PSE&G PS_P1-2_S-2219 PS_P1-2_R-2218_LT 50 PJM 2016 Regional Transmission Expansion Plan

59 Book 3: 2016 RTEP Proposal Windows 5 Map 5.3: 2016 RTEP Proposal Window No. 2 Violations PJM 2016 Regional Transmission Expansion Plan 51

60 5 Book 3: 2016 RTEP Proposal Windows Proposals PJM received 87 proposals shown in Table 5.4 and Map 5.4 from 13 entities in 12 Transmission Owner zones to solve the identified reliability criteria violations. Transmission Owner upgrades to existing facilities comprised 41 of the proposals and ranged in cost from $0.03 million to $125 million. Fortysix of the proposals were greenfield projects that ranged in cost from $5 million to $136.9 million. Evaluation and Selection Once the window closed, PJM staff performed analytical, constructability and company evaluations as described in Book 2, 7.0 to identify which proposals most effectively solved all reliability criteria violations and did not introduce new ones. Following stakeholder review with the Transmission Expansion Advisory Committee (TEAC), PJM recommended to the PJM Board in December 2016 a set of eleven as noted in Table 5.4 recommendations to address 21 flowgate violations. The recommended projects address violations in the following transmission zones: AEP, APS, ATSI, BGE, Met-Ed, PECO and Penelec. The recommended projects include line sag mitigation to raise line ratings, transformer replacement, new transformer addition, transmission line reconductoring, substation equipment upgrades, and new circuit breakers installations. NOTE: In addition to the eleven recommendations approved at the December 2016 PJM Board meeting, the PJM Board approved four additional projects from the 2016 Window No. 2 at their February 2017 meeting. Those projects are: 2016_2-5A, 2016_2-1B, 2016_2-1D and 2016_2-1A. NOTE: Line Sag: Overhead conductors rely on ambient air for cooling caused by the heat generated by the amount of current flowing across them. Eventually more heat is generated than can be dissipated to the surrounding air. This causes the wire to heat up, and like any metal that is heated the wire begins to expand and lengthen; this is known as sag. A sagging line that contacts and object can lead to flash over, or direct contact causing a line to trip. 52 PJM 2016 Regional Transmission Expansion Plan

61 Book 3: 2016 RTEP Proposal Windows 5 Table 5.4: 2016 RTEP Proposal Window No. 2 Proposals Project ID Upgrade/ Greenfield Proposing Entity Cost ($M) Major Components 2016_2-1A Upgrade DEO&K 18.7 Expand Garver 345 kv sub to include 138 kv 2016_2-1B Upgrade DEO&K 1.0 Install 5 percent reactors at Miami Fort to limit current. 2016_2-1C Upgrade DEO&K 10.5 Reconductor circuit from Nickel to Warren. Replace wooden structures with steel poles. 2016_2-1D Upgrade DEO&K 2.2 Reconductor Feeder from Port Union to East Provident for 300 MVA 2016_2-2A Upgrade ComEd 4.59 Rebuild 138 kv line for 1.6 miles from Haumesser to West Dekalb Tap with double circuit towers and install two twisted ACSR conductors per phase in both circuit positions, to be operated tied together as a single circuit. Upgrade line switch and revise relay settings. 2016_2-3A Greenfield Transource 58.0 Construct a new double circuit 345 kv line between ATSI s Carlisle Station and a new station, Rocky River West, along the Avon Lake-Juniper 345 kv line. 2016_2-3B Greenfield Transource 36.0 Establish a 500/345 kv greenfield station by cutting into the existing Keystone - Conemaugh 500 kv circuit. Construct a 345 kv tie line between the new station and the existing Homer City 345 kv yard. 2016_2-3C Greenfield Transource 19.0 Build a new 345/138 kv Station (Russ Station) which taps the Stuart (DAY) Clinton (DAY) 345 kv line and connects to both the Hillsboro (AEP) Clinton County (DEO&K) 138 kv and Middleboro (DAY) Hillsboro (AEP) 138 kv lines 2016_2-3D Greenfield Transource 12.0 Establish a new 138 kv switch station near Seneca by cutting into the Markwest-Seneca 138 kv line section. Construct a new 138 kv line from the new station to McCalmont station. 2016_2-3E Greenfield Transource 10.0 Establish 230/115 kv transformation at PPL Williams Grove station. Construct double circuit 115 kv line to cut into existing Met-Ed Allen-Round Top 115 kv circuit. 2016_2-3F Greenfield Transource 63.0 Tap the Tanners Creek-Losantville 345 kv line and build a single circuit line approximately 13.5 miles to a new 345/138 kv station (Coyote) next to Wiley. 2016_2-4A Upgrade BGE/PECO 2.0 Upgrade Substation Equipment at Conastone and Peach Bottom to increase facility rating to 2,598 MVA normal and 2,863 MVA emergency 2016_2-4B Upgrade BGE/PECO 7.0 Upgrade Substation Equipment at Conastone and Peach Bottom to increase facility rating to 2,826 MVA normal and 3,525 MVA emergency 2016_2-5A Upgrade EKPC 2.5 The current 5 percent impedance 1,200 A line reactor, which connects the 4SPURLOCK - 4SPUR-KENT-R and 4SPUR-KENT-R - 4KENTON 138 kv line sections, will be upgraded to a 6.5 percent impedance 1,600 A line reactor. This upgrade will mitigate the 104 percent post-contingent overload of these line sections for the loss of the 345 kv lines from Spurlock-Stuart and from Spurlock-Meldahl Dam which share a common tower. The reactor will lower the post-contingent flow to 90 percent LTE, providing a sufficient buffer for operations. The new limiting element is the Spurlock-Kenton 138 kv line conductor. 2016_2-6A Greenfield Nextera 17.1 New 345/138 kv Substation Looping in Foster-Bath 345 kv, Foster-Sugar 345 kv, and Warren-Clinton 138 kv lines 2016_2-6B Greenfield Nextera 32.5 New 345 kv line from Eugene - Dequine Recommendation for Board Approval 2016_2-7A Upgrade AEP 2.3 Replace Hazard XF / Sag Study Hazard - Wooton X 2016_2-7B Upgrade AEP Replace Hazard XF / Rebuild Hazard - Wooton 2016_2-7C Upgrade AEP 10.1 Install second 500/138 kv transformer at Nagel station 2016_2-7D Upgrade AEP 0.1 Sag Study of Nagel to West Kingsport 138 kv line X 2016_2-7E Upgrade AEP 0.1 Sag Study of Saltville to Tazewell 138 kv line X 2016_2-7F Upgrade AEP 1.2 This project proposes the installation of a 4 percent series reactor at Sullivan Gardens towards the Walters line. 2016_2-7G Upgrade AEP 2.6 Loop existing West Kingsport-North Bristol 138 kv line into Holston 138 kv bus. Presently, the subject line dead ends at the Holston bus but is not electrically connected to Holston. This project proposes to establish the connection of this line effectively creating line exits to West Kingsport and North Bristol from Holston. Additionally, this proposal also includes the installation of a four percent series reactor at Sullivan Gardens towards the Walters line. X PJM 2016 Regional Transmission Expansion Plan 53

62 5 Book 3: 2016 RTEP Proposal Windows Table 5.4: 2016 RTEP Proposal Window No. 2 Proposals (Continued) Project ID Upgrade/ Greenfield Proposing Entity Cost ($M) Major Components 2016_2-7H Upgrade AEP 33.7 Rebuild the Dequine-Meadow Lake 345 kv double circuit corridor using AEP BOLD Lattice Tower Configuration. 2016_2-7I Greenfield AEP 29.1 Construct a greenfield Dequine-Meadow Lake 345 kv Circuit No. 3 as a single circuit line. 2016_2-7J Upgrade AEP 6.6 Reconductor the enitre Dequine-Meadow Lake 345 kv circuit No. 2. Recommendation for Board Approval 2016_2-7K Upgrade AEP 28.1 Rebuild the Dequine-Meadow Lake 345 kv double circuit corridor using AEP Traditional Tower Configuration. X 2016_2-7L Upgrade AEP Rebuild the Dequine-Eugene 345 kv double circuit corridor using AEP BOLD Lattice Tower Configuration. 2016_2-7M Greenfield AEP 99.1 Construct a greenfield Dequine-Eugene 345 kv Circuit No. 2 as a single circuit line. 2016_2-7N Upgrade AEP Reconductor the enitre Dequine-Eugene 345 kv circuit. X 2016_2-7O Upgrade AEP 99.3 Rebuild the Dequine-Eugene 345 kv double circuit corridor using AEP Traditional Tower Configuration. 2016_2-7P Greenfield AEP Construct a greenfield Eugene-Meadow Lake 345 kv Circuit single circuit line ~60 miles. 2016_2-7Q Upgrade AEP 0.6 Reconfigure New Carlisle station and install an additional 138 kv bus tie breaker. 2016_2-7R Greenfield AEP 24.2 Rebuild sections of the 34.5 kv line b/w New Carlisle and Silver Lake as double ckt 138 kv, operating one ckt as 34.5 kv while the other as 138 kv. Extend the 138 kv ckt to Liquid Carbonics by constructing a green field single ckt line. 2016_2-7S Upgrade AEP 0.82 Replace the existing reactor at Clifty Creek 138 kv with a larger one (19 Ohms). 2016_2-8A Upgrade First Energy 16.1 Reconductor the Beaver-Black River 138 kv line; upgrade the wave trap at Black River to 2,000 Amps. 2016_2-8B Upgrade First Energy 1.8 Install one 138 kv 50 MVAR Capacitor Bank, one Capacitor switcher, one MOAB s, three CCVT, one Standard Relay panel, tap on Valley-Theiss 138 kv Line, fiber communication and associated relay revisions at Valley & Theiss Substations. 2016_2-8C Upgrade First Energy 3.8 Add second 345/138 kv transformer at Chamberlin substation X 2016_2-8D Upgrade First Energy 0.1 Upgrade bus conductor Gardners substation. Upgrade bus conductor and adjust CT ratios at Carlisle Pike X 2016_2-8E Upgrade First Energy 0.03 Upgrade breaker risers and disconnect leads; Replace 500 CU breaker risers and 556 ACSR disconnect leads with 795 ACSR. X 2016_2-8F Upgrade First Energy 3.9 North Meshoppen 230/115 kv No. 3 Transformer: -Replace the existing transformer with a new 168/224 MVA transformer. -Remove the existing reactor. 2016_2-8G Upgrade First Energy 6.6 At Homer City: -Construct a new 345 kv breaker string with three 345 kv breakers. -Move the North autotransformer connection to this new breaker string. 2016_2-8H Upgrade First Energy 3.9 Erie South - Four Mile 115 kv -Reconductor 4.62 miles of 636 ACSR with 636 ACSS high temperature conductor. -Replace the 636 ACSR substation conductor with new conductor exceeding the conductor rating -Replace the 795 SCCIR bus conductor 2016_2-8I Upgrade First Energy 12.1 East Towanda-Canyon 230 kv, Reconductor ~12.18 miles of 1033 ACSR line with 1033 ACSS high temp conductor, Upgrade 230 kv disconnect switch and line drop to East Towanda at Canyon Substation, Upgrade 230 kv line drop to Canyon line at East Towanda Substation 2016_2-8J Upgrade First Energy 2.4 At North Meshoppen: Convert the 230 kv yard to a ring bus. 2016_2-8K Upgrade First Energy 0.97 Replace the Breaker Risers and Wavetrap at Bredinville Substation on the Cabrey Junction terminal X 2016_2-9A Greenfield Northeast Transmission Development 12.5 Build a 230 kv switching station ( Bookers Run ) interconnecting the Muddy Run to Peach Bottom 230 kv line and the Peach Bottom Tap to Cooper 230 kv line with a series reactor X 54 PJM 2016 Regional Transmission Expansion Plan

63 Book 3: 2016 RTEP Proposal Windows 5 Table 5.4: 2016 RTEP Proposal Window No. 2 Proposals (Continued) Project ID Upgrade/ Greenfield Proposing Entity 2016_2-9B Greenfield Northeast Transmission Development 2016_2-9C Greenfield Northeast Transmission Development 2016_2-9D Greenfield Northeast Transmission Development 2016_2-9E Greenfield Northeast Transmission Development 2016_2-9F Greenfield Northeast Transmission Development 2016_2-9G Greenfield Northeast Transmission Development 2016_2-9H Greenfield Northeast Transmission Development 2016_2-9I Greenfield Northeast Transmission Development 2016_2-9J Greenfield Northeast Transmission Development 2016_2-9K Greenfield Northeast Transmission Development 2016_2-9L Greenfield Northeast Transmission Development 2016_2-9M Greenfield Northeast Transmission Development 2016_2-9N Greenfield Northeast Transmission Development 2016_2-9O Greenfield Northeast Transmission Development Cost ($M) Major Components 19.2 Build a 230 kv line from the existing Graceton substation to the new 230 kv switching station ( Bookers Run ) interconnecting the Muddy Run to Peach Bottom 230 kv line 7.4 Build a 138 kv switching station ( Butchers Run ) interconnecting the Cabrey Junction to Butler 138 kv line, the Cabrey Junction to Bredinville 138 kv line, the Cabrey Junction to Cabot 138 kv line, and the Lawson to MC Calmont 138 kv line 23.0 Build a 500/345 kv substation ( Chestnut Ridge ) interconnecting the Keystone to Conemaugh 500 kv line to the existing Homer City 345 kv substation 15.8 Build a 345/138 kv substation ( Coffee Creek ) interconnecting the Green Acres to Olive 345 kv line and the Flint Lake to Luchtman Road 138 kv line 13.3 Build a 230/115 kv substation ( Dogwood Run ) interconnecting the Allen to Roundtop 115 kv line and the existing William Grove 230 kv substation 18.7 Build a 500/115 kv substation ( Dogwood Run ) interconnecting the Juniata to Three Mile Island 500 kv line and the Allen to Roundtop 115 kv line 32.1 Build a 230 kv line from the existing 230 kv East Towanda substation to the existing 230 kv North Meshoppen substation 80.5 Build a 345 kv line from the existing 345 kv Eugene switching station to the existing 345 kv Meadow Lake switching station 17.0 Build a 345 kv line from the existing Garver substation to a new 345/138 kv substation ( Green tree ). Interconnect Greentree with the existing 138 kv Rockies Express substation with a new 138 kv connection Build a 500/230 kv substation (Hubbard) interconnecting the 230 kv line from the existing 230 kv Oxbow substation that currently goes to the existing Lackawanna substation. Remove the existing 230 kv line from Hubbard-Lackawanna from service. Build a new 500 kv line from the new Hubbard substation to the Lackawanna 500 kv substation 29.9 Build a 500/230 kv substation (Laurel Run) interconnecting the Lackawanna-Hopatcong 500 kv line and a new 230 kv line to a point of interconnection outside the Lackawanna Energy Center. The existing 230 kv line from the Lackawanna 230 kv substation to the point of interconnection outside the Lackawanna Energy Center will be removed from service Build a 500/230 kv substation (Laurel Run) interconnecting the existing Lackawanna-Hopatcong 500 kv line and the existing Lackawanna-Lackawanna Energy Center 230 kv line Build a 230/115 kv substation ( LeBoeuf ) interconnecting the Erie South-Warren 230 kv line and the Erie South-Union City 115 kv line 9.3 Construct a double circuit 138 kv line to loop the existing 138 kv Richwood Hill to Metz transmission line into the existing 138 kv Dents Run substation Recommendation for Board Approval PJM 2016 Regional Transmission Expansion Plan 55

64 5 Book 3: 2016 RTEP Proposal Windows Table 5.4: 2016 RTEP Proposal Window No. 2 Proposals (Continued) Project ID Upgrade/ Greenfield Proposing Entity 2016_2-9P Greenfield Northeast Transmission Development 2016_2-9Q Greenfield Northeast Transmission Development 2016_2-9R Greenfield Northeast Transmission Development 2016_2-9S Greenfield Northeast Transmission Development 2016_2-9T Greenfield Northeast Transmission Development 2016_2-9U Greenfield Northeast Transmission Development 2016_2-9V Greenfield Northeast Transmission Development 2016_2-10A Greenfield Mid-Atlantic MCN 2016_2-10B Greenfield Mid-Atlantic MCN Cost ($M) Major Components 26.8 Build a 230 kv line from the existing Muddy Run to Peach Bottom 230 kv line to a new switching station ( Orson Run ) interconnecting the existing Safe Harbor to Graceton 230 kv line. Reconfigure the Muddy Run to Peach Bottom 230 kv line to have a Muddy Run to Orson Run 230 kv line and retire the remaining 230 kv line to Peach Bottom. Build a 230 kv line from the existing Peach Bottom 230 kv substation to the existing Graceton 230 kv substation 13.4 Build a 230 kv line from the existing Muddy Run to Peach Bottom 230 kv line to a new switching station ( Orson Run ) interconnecting the existing Safe Harbor to Graceton 230 kv line. Reconfigure the Muddy Run to Peach Bottom 230 kv line to have a Muddy Run to Orson Run 230 kv line and retire the remaining 230 kv line to Peach Bottom 18.7 Build a 345/138 kv substation ( Paddys Run ) interconnecting the Miami Fort to West Milton 345 kv line, the Morgan to Fairfield 138 kv line and the Willey to Fairfield 138 kv line 12.1 Build a 138 kv switching station ( Patterson Run ) interconnecting the Bull Creek to Cabot 138 kv line, the Bull Creek to Houseville 138 kv line, the Bull Creek to Mountain Gathering 138 kv line, the Lawson to Cabot 138 kv line, the Lawson to Fawn 138 kv line, and the Lawson to MC Calmont 138 kv line 6.1 Build a 138 kv switching station ( Ramsey ) interconnecting the Clifty Creek-Northwest 138 kv line and the Madison-Madison West 138 kv line 12.2 Build a 138 kv switching station ( Middle Ridge ) interconnecting the Carlisle to Concast 138 kv line and the Beaver to Johnson 138 kv line. Build a 138 kv switching station ( West Ridge ) interconnecting the Carlisle to Concast 138 kv line and the Murray to Gates 138 kv line Build a 138 kv switching station ( Sougan ) interconnecting the Orebank to Holston 138 kv line, the Orebank to Wolf Hills 138 kv line, and the Indian Springs to North Bristol 138 kv line 33.5 Build second 230 kv circuit from East Towanda to North Meshopppen Build a new station adjacent to the existing Shaker Run substation. Split the Warren to Nickell 138 kv line to bring in and out of new station. Split the Todhunter to Foster 345 kv line to bring in and out of new station. Install a 345/138 kv transformer in the new station. Build 138 kv between existing Shaker Run and new station. 2016_2-11A Upgrade PSE&G Convert existing 138 kv circuits between Brunswick and Metuchen to 230 kv. 2016_2-11B Upgrade PSE&G 1.68 Eliminate the overhead line crossing of Fanwood-Metuchen and Deans-Linden circuits. Reconfigured circuits become Fanwood-Linden and Deans-Metuchen. 2016_2-11C Greenfield PSE&G Build a new 345 kv circuit from Eugene to Meadow Lake 2016_2-11D Greenfield PSE&G 44.3 Build a new 345 kv circuit from Ghent to East Bend 2016_2-11E Greenfield PSE&G 85.7 Build a new 345 kv circuit from Clifty Creek to East Bend 2016_2-12A Greenfield/ Upgrade Nipsco 5.5 Reconductor existing NIPSCO line section between AEP Bosserman and Olive substations at approximately 12 miles with 397 ACSS 2016_2-12B Greenfield Nipsco 95.0 New 345 kv Circuit from Michigan City to Olive at approximately 26 miles using ACSR 2016_2-13A Upgrade PPL Move Lackawanna Energy generation termination point from 230 kv bus to 500 kv bus at Lackawanna: Expand Lackawanna 500 kv yard to the east of the East 500 kv bus. 2016_2-13B Upgrade PPL 19.0 Lackawanna 230 kv Phase Angle Regulators: Recommendation for Board Approval Add two new 230 kv 450 MVA phase angle regulators (PARs) at Lackawanna in series with the Lackawanna-Oxbow 230 kv line and a new normally open motor-operated disconnect switch in parallel with the PARs to allow for the PARs to be bypassed when necessary. The new Lackawanna PARs would have an angle range of +/- 30 degrees with 64 tap steps 56 PJM 2016 Regional Transmission Expansion Plan

65 Book 3: 2016 RTEP Proposal Windows 5 Table 5.4: 2016 RTEP Proposal Window No. 2 Proposals (Continued) Project ID Upgrade/ Greenfield Proposing Entity Cost ($M) Major Components 2016_2-13C Upgrade PPL 2.59 Lackawanna 230 kv Series Reactors: Recommendation for Board Approval 2016_2-13D Upgrade PPL Lackawanna 500/230 kv Transformer T3 Retermination: 2016_2-13E Upgrade PPL Lackawanna 500/230 kv Transformer T3 & T4 Replacement: Add two new 10 ohm series reactors on the low side of the T3 and T4 500/230 kv transformers respectively. The new reactors will be in service under all normal operating conditions. Each reactor would be purchased as three single phase units. Substation Component: Expand Lackawanna 500 kv bus to have a third bay that includes three breakers (4 MODs). Add a third breaker to bay 1 at Lackawanna 500 kv. Move the Lackawanna 500/230 kv transformer T3 to bay position on bay 1 (between existing CB-1W and new CB-1T breakers) Transmission Line Component: Move Susquehanna-FRPO -Lackawanna 500 kv line termination to the new bay 3 (between CB-3W and CB-3T breakers) and make necessary protections upgrades at both substations Replace the existing Lackawanna 500/230 kv T3 and T4 transformers with two new 1,050 MVA transformers. 2016_2-13F Greenfield PPL 12.4 New 4.8 mile 138 kv line from Clifty Creek (OVEC) to Madison (DEI) 138 kv stations. 2016_2-13G Greenfield PPL Build a new 13.7 mile 345 kv line from Meadow Lake to Dequine and a new 48 mile 345 kv line from Dequine to Eugene. 2016_2-13H Greenfield PPL 47.9 Build 23 mile new 230 kv circuit from East Towanda to N. Meshoppen. 2016_2-13I Greenfield PPL New 6 mile 138 kv ckt from Todd Hunter to Rockies Express. PJM 2016 Regional Transmission Expansion Plan 57

66 5 Book 3: 2016 RTEP Proposal Windows Map 5.4: 2016 RTEP Proposal Window No. 2 Proposals 58 PJM 2016 Regional Transmission Expansion Plan

67 Book 3: 2016 RTEP Proposal Windows 5 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 5.2: 2016 RTEP Proposal Window No Window Process PJM conducted 2016 Regional Transmission Expansion Plan (RTEP) Proposal Window No. 3 from September 30, 2016 to October 31, 2016, with additional detailed costs due on November 15, 2016, to solicit solutions to a number of PJM reliability criteria violations. In addition to short circuit study violations, the window also addressed reliability criteria violations arising out winter and light load condition studies: Baseline N-1 (thermal and voltage), Generation Deliverability, Common Mode Outage, N-1-1 (thermal and voltage), and Load Deliverability (thermal and voltage). Violations were associated with 25 flowgates transmission facility and contingency or outage pairs shown in Table 5.5. and Map 5.5. Light Load Criteria Light load system conditions, with system demand as low as 30 percent of summer peak in some Transmission Owner areas, have begun to present system dispatchers with operational performance issues. Generation dispatch under such conditions, for most fuel types, differs markedly from that under peak load conditions. PJM system operators have experienced thermal overloads and high-voltage events driven by low demand dispatch patterns and the capacitive effects of lightly loaded transmission lines. Light load reliability analysis ensures that the transmission system is capable of delivering generating capacity under such conditions and that PJM operators have adequate reactive control. Light Load Criteria analysis and related study procedures are described in Book 2, 4.4. Winter Criteria The winter peak reliability analysis ensures that the Transmission System is capable of delivering the system generating capacity at winter peak. The PJM 50/50 winter peak demand level from the PJM Load Forecast was chosen as representative of typical winter peak conditions. The system generating capability modeling assumption for this analysis is that the generation modeled reflects generation by fuel class that historically operates during the winter peak demand level. Winter Criteria analysis and related study procedures are described in Book 2, 4.5. Short Circuit Analysis PJM performs short circuit analysis also known as breaker interrupting studies as part of the annual RTEP baseline assessment. This analysis includes a study of the entire PJM system based on its current configuration and equipment to determine if the short circuit current interrupting duty of circuit breakers is sufficient for two-year and five-year planning cases. PJM conducts short circuit analysis to ensure circuit breakers on the transmission system are sufficiently rated to safely interrupt fault currents. Since breaker replacement lead times are relatively short compared to transmission lines these analysis are only conducted within the five-year planning horizon. Short Circuit Analysis and related study procedures are described in Book 2, 4.6. PJM 2016 Regional Transmission Expansion Plan 59

68 5 Book 3: 2016 RTEP Proposal Windows Table 5.5: 2016 RTEP Proposal Window No. 3 Violations Analysis Type Overloaded Facility TO Contingency 1 Short Circuit Short Circuit Criteria Violation at Bruce Mansfield 345 kv breaker B57 FirstEnergy ATSI n/a Short Circuit Short Circuit Criteria Violation at South Canton 138 kv breaker L American Electric Power n/a Short Circuit Short Circuit Criteria Violation at South Canton 138 kv breaker L2 American Electric Power n/a Winter Generator Delivery and Common Mode Outage Overloaded of the Tanners Creek-Miami Fort 345 kv line American Electric Power/Duke Energy Ohio/ Kentucky Winter Generator Delivery and Common Mode Outage Overloaded of the Kyger Creek-Sporn 345 kv line American Electric Power/Ohio Valley Electric Corporation DEO&K P1-* P2-1 TERMINAL-EAST BEND 4516 AEP_P1-2_#349 Winter Generator Delivery and Common Mode Outage Overloaded of the Maddox Creek-East Lima 345 kv line American Electric Power AEP_P1-2_#7441 Winter Generator Delivery and Common Mode Outage Overloaded of the Admiral Q-3-Avon 138 kv line FirstEnergy ATSI ATSI-P7-1-CEI Winter Generator Delivery and Common Mode Outage Overloaded of the Admiral Q-3-Avon 138 kv line FirstEnergy ATSI ATSI-P2-3-CEI Winter Generator Delivery and Common Mode Outage Overloaded of the Beaver-Black River 138 kv line FirstEnergy ATSI ATSI-P7-1-OEC Winter Generator Delivery and Common Mode Outage Overloaded of the Black River-Lorain-Avon 138 kv line FirstEnergy ATSI ATSI-P7-1-CEI Winter Generator Delivery and Common Mode Outage Overloaded of the Black River-Lorain-Avon 138 kv line FirstEnergy ATSI ATSI-P2-3-CEI Winter Generator Delivery and Common Mode Outage Overloaded of the Lorain Q-2-Admiral Q kv line FirstEnergy ATSI ATSI-P7-1-CEI Winter Generator Delivery and Common Mode Outage Overloaded of the Lorain Q-2-Admiral Q kv line FirstEnergy ATSI ATSI-P2-3-CEI Winter Generator Delivery and Common Mode Outage Overloaded of the Black River-Lorain-Avon 138 kv line FirstEnergy ATSI ATSI-P7-1-CEI Winter Generator Delivery and Common Mode Outage Overloaded of the Black River-Lorain-Avon 138 kv line FirstEnergy ATSI ATSI-P2-3-CEI Winter Generator Delivery and Common Mode Outage Overloaded of the Chemical-Capital Hill 138 kv line American Electric Power AEP_P7-1_#7671 Winter Generator Delivery and Common Mode Outage Overloaded of the Chemical-Capital Hill 138 kv line American Electric Power AEP_P7-1_#8366 Winter Generator Delivery and Common Mode Outage Overloaded of the Chemical-Capital Hill 138 kv line American Electric Power AEP_P7-1_#8365 Winter Generator Delivery and Common Mode Outage Overloaded of the Chemical-Capital Hill 138 kv line American Electric Power AEP_P7-1_#8369 Winter Generator Delivery and Common Mode Outage Overloaded of the Chemical-Capital Hill 138 kv line American Electric Power AEP_P7-1_#8381 Winter Generator Delivery and Common Mode Outage Overloaded of the Richland-Naomi 138 kv line FirstEnergy ATSI ATSI-P2-4-TE T Winter Generator Delivery and Common Mode Outage Overloaded of the Richland-Naomi 138 kv line FirstEnergy ATSI ATSI-P2-2-TE T Winter Generator Delivery and Common Mode Outage Overloaded of the Richland-Naomi 138 kv line FirstEnergy ATSI ATSI-P2-3-TE T Winter Baseline Thermal Overloaded of the Chemical 2-Capital Hill 138 kv line American Electric Power AEP_P7-1_#7671 Summer Gen Delivery and Common Mode Outage Overlap with Window 2 Overloaded of the Beaver-Black River 138 kv line FirstEnergy ATSI ATSI-P7-1-OEC PJM 2016 Regional Transmission Expansion Plan

69 Book 3: 2016 RTEP Proposal Windows 5 Map 5.5: 2016 RTEP Proposal Window No. 3 Violations PJM 2016 Regional Transmission Expansion Plan 61

70 5 Book 3: 2016 RTEP Proposal Windows Proposals Seven entities submitted 29 proposals located in six Transmission Owner zones to resolve the identified reliability criteria violations. Twelve were Transmission Owner upgrades to existing facilities that ranged in cost from $10 thousand to $67.7 million. Seventeen were greenfield projects that ranged in cost from $5.95 million to $69.3 million. The proposals were located in the following transmission zones: AEP, ATSI, DEO&K, and OVEC as shown in Table 5.6 and Map 5.6. Evaluation and Selection Once the window closed, PJM staff performed analytical, constructability and company evaluations as described in Book 2, 7.0 to identify which proposals most effectively solved all reliability criteria violations and did not introduce new ones. Following stakeholder review with the Transmission Expansion Advisory Committee (TEAC), PJM anticipates recommending projects to the PJM Board in February NOTE: At its February 2017 meeting, the PJM Board approved the six recommended projects noted in Table 5.6: 2016_3-1A, 2016_3-4A, 2016_3-4D, 2016_3-4C, 2016_3-4E and 2016_3-6F. 62 PJM 2016 Regional Transmission Expansion Plan

71 Book 3: 2016 RTEP Proposal Windows 5 Table 5.6: 2016 RTEP Proposal Window No. 3 Proposals Project ID Upgrade/ Greenfield Proposing Entity Cost ($M) Major Components 2016_3-1A Upgrade DEO&K/AEP 7.8 This is a joint proposal between Duke Energy, Ohio & Kentucky (DEO&K) and AEP. DEO&K will replace the DEO&K owned portion of the Tanners Creek to Miami Fort 345 kv circuit (3.4 miles, double bundle) with two different types of conductor. Aluminum Conductor Composite Reinforced will be used for the Ohio River crossing with the balance of the circuit using Aluminum Conductor, Steel Supported. The rating for the Duke portion of the circuit will increase to 2,151 MVA. AEP will perform a sag study including a LiDAR survey on the AEP portion of the Tanners Creek to Miami Fort 345 kv Circuit (0.36 miles, double bundle). A successful sag study will allow AEP s conductor to be operated at its Maximum Operating Temperature and thus increase the Summer Emergency rating from 1,409 MVA to 1,956 MVA. If the sag study determines the tie line cannot be operated at its MOT without additional improvements AEP will need to reconductor their portion of the line; which is expected to cost approximately $400, _3-2A Greenfield Transource 14.5 Construct new greenfield 345 kv Switch Station to be called Anson Station. The existing Tanners Creek-East Bend 345 kv, East Bend-Terminal 345 kv and Miami Fort-Terminal 345 kv circuits will all be looped in and out of this station. The station will be comprised of six new 345 kv breakers and will be configured in a ring bus. 2016_3-2B Greenfield Transource 8.3 Construct a new single circuit 138 kv line between Bryan Station and Stryker Station. 2016_3-2C Greenfield Transource 44.9 Construct a new double circuit 345 kv line between ATSI s Carlisle Station and a new station, Rocky River West, along the Avon Lake-Juniper 345 kv line. Also, construct a new Sheffield 138 kv switching station. 2016_3-2D Greenfield Transource 17.2 Construct approximately 14 miles of new 138 kv line establishing a Lockwood Road Stryker 138 kv Circuit. 2016_3-2E Greenfield Transource 59.8 Tap the Tanners Creek-Losantville 345 kv line by constructing a new 345 kv station (York) and build a single circuit 345 kv line to a new 345/138 kv station (Coyote) next to the existing Wiley station 2016_3-3A Greenfield Nextera 5.95 Add series reactor to Maddox Creek-E Lima 345 kv Recommendation for Board Approval X 2016_3-4A Upgrade AEP 7.3 Reconductor and string open position and six wire 6.2 miles of the Capitol Hill to Chemical 138 kv X 2016_3-4B Upgrade AEP 15.5 Reconductor Kyger-Sporn No. 2 circuit 2016_3-4C Upgrade AEP 0.3 Six Wire Kyger-Sporn No. 1 and No. 2 circuits together X 2016_3-4D Upgrade AEP 18.2 Reconductor the Maddox Creek-East Lima 345 kv circuit with ACSS Cardinal conductor. X 2016_3-4E Upgrade AEP 0.78 Replace South Canton 138 kv breakers L & L2 with 80 ka breakers. X 2016_3-4F Upgrade AEP 67.7 Rebuild the Maddox Creek-East Lima 345 kv line utilizing BOLD construction. 2016_3-4G Greenfield AEP 69.3 Construct a new 345 kv single circuit line between Maddox Creek and Southwest Lima stations. 2016_3-5A Greenfield Northeast Transmission Development 2016_3-5B 2016_3-5C 2016_3-5D 2016_3-5E Greenfield Greenfield Greenfield Greenfield Northeast Transmission Development Northeast Transmission Development Northeast Transmission Development Northeast Transmission Development 8.5 Build a 138 kv line from the existing 138 kv City of Bryan substation to the existing 138 kv Stryker substation Build a double circuit 138 kv line from the existing Fieldstone to Johnson 138 kv line and the Carlisle to National Bronze 138 kv line to a new switching station ( Butternut Ridge ) interconnecting the existing Astor to Crystal 138 kv line and the Crestwood TP3 to Fowles 138 kv line. Reconfigure the existing Fieldstone to Johnson 138 kv line and the Carlisle to National Bronze 138 kv line to have a Johnson to National Bronze 138 kv line, a Fieldstone to Butternut Ridge 138 kv line and a Carlisle to Butternut Ridge 138 kv line. Build a 138 kv switching station ( Campbells Branch ) interconnecting the Amos to Lanham 138 kv line and the Sisson to Lanham 138 kv line. Build a 138 kv line from the new Campbells Branch 138 kv switching station to the existing 138 kv Coco switching station. One of the existing 138 kv lines from Campbells Branch to Lanham will be removed from service. Construct a double circuit 345 kv line to loop the existing 345 kv Avon Lake to Juniper transmission line into the existing 345 kv Carlisle substation Build a 345/138 kv substation ( Poplar Ridge ) interconnecting the Kyger Creek to Marquis 345 kv line, the Firebrick to Gavin 138 kv line and the Rio Tap to Sporn 138 kv line PJM 2016 Regional Transmission Expansion Plan 63

72 5 Book 3: 2016 RTEP Proposal Windows Table 5.6: 2016 RTEP Proposal Window No. 3 Proposals (Continued) Project ID 2016_3-5F Upgrade/ Greenfield Greenfield Proposing Entity Northeast Transmission Development 2016_3-5G Greenfield Northeast Transmission Development 2016_3-5H Greenfield Northeast Transmission Development Cost ($M) 12.4 Major Components Build a 138 kv switching station ( Middle Ridge ) interconnecting the Carlisle to Concast 138 kv line and the Beaver to Henrietta 138 kv line. Build a 138 kv switching station ( West Ridge ) interconnecting the Carlisle to Concast 138 kv line and the Murray to Gates 138 kv line Build a 345 kv switching station ( Second Creek ) interconnecting the Tanners Creek to East Bend 345 kv line and the Miami Fort to Terminal 345 kv line 6.1 Build a 138 kv switching station ( Webb Run ) interconnecting the Richland to Lockwood Road 138 kv line and the Richland LJ to Ridgeville 138 kv line 2016_3-6A Upgrade First Energy 0.11 Beaver-Black River 138 kv line replace the GCY51 relay at Beaver substation with SEL. Modify the existing RTU 2016_3-6B Upgrade First Energy 13.4 Expand / Revise the scope of work for the existing PJM RTEP Project b2559 (ISD 2017) to create a bundled 795 ACSS double circuit tower line. Recommendation for Board Approval Black River-Lorain Q2 138kV line upgrade: Rebuild/Reconductor appr ox. 6.5 miles single 795 ACSS/TW conductor between Black River to Charleston and Charleston to Lorain Q2 substations (ISD 2017) with bundle 795 Kcmil ACSS conductor. Terminal upgrades: Upgrade 2,000 A wave trap (ISD2017) at Black River, Lorain and Charleston substation to 3,000 A. The new Black River-Charleston and Charleston-Lorain Q2 138 kv circuit winter (MVA) rating will be 679 WN/753 WE/459 WLD (The limiting element is a substation conductor at Charleston) 2016_3-6C Greenfield First Energy 30.3 Build a new switching sub (Detroit), a new 138 kv line and network Lake Ave, Carlisle and Lorain 138 kv substation. Detroit 138 kv switching substation: Construct new 138 kv three circuit breakers ring bus switching substation on Carlisle-Lorain Q4 138 kv line per FE standard. Lake Ave 138 kv substation: Build a new 138 kv breaker bay with breaker and half configuration, a second breaker bay for future exit, to create a dedicated line exit for Lake Ave-Detroit 138 kv line-per FE standard. Lake Ave-Detroit 138 kv line: Build a new 1.7 miles single circuit line with 795 Kcmil ACSR conductor from Lake Ave to National Bronze and rebuild/ reconductor 0.7 miles National Bronze tap with 795 Kcmil ACSR conductor to extend the exiting Carlisle-Lorain Q4 138 kv line to Lake Ave. Install fiber communication (OPGW) on the line (Lake Ave-National Bronze-Detroit). Install 2,000 A switches with whip at National Bronze sub new tap. Carlisle-Lorain Q4 138 kv line: Loop the Carlisle-Lorain Q4 138 kv line in/out of the new Detroit switching substation. Rebuild (~2.8 miles) Carlisle-Detroit 138 kv line with 954 Kcmil ACSR conductor and install fiber communication (OPGW). Replace poles and exiting switch on the Carlisle-Detroit 138 kv line (~13.1 miles) to install fiber communication (OPGW) reusing the existing conductor. Detroit-Lake Ave-Lorain Q4: Loop the Lake Ave-National Bronze-Lorain Q4 138 kv line section in/out of the new Detroit switching substation Lorain-Upgrade line relaying at Lorain to Detroit substation, upgrade line drops at Lorain on Q4 line to Admiral and Detroit Substation. Terminal upgrade: Carlisle-Upgrade line relaying at Lorain to Detroit sub and substation conductor (line drops) on Admiral Q4 and Detroit 138 kv line exit. Carlisle-Upgrade line relay at Carlisle to Detroit Substation 64 PJM 2016 Regional Transmission Expansion Plan

73 Book 3: 2016 RTEP Proposal Windows 5 Table 5.6: 2016 RTEP Proposal Window No. 3 Proposals (Continued) Project ID Upgrade/ Greenfield Proposing Entity Cost ($M) Major Components 2016_3-6D Upgrade First Energy 3.2 Reconductor the Avon-Lorain 138 kv line segment (~4.5 miles) with 795 Kcmil ACSS conductor. Upgrade the line drops at Avon. New ratings WN 521 MVA/WE611MVA (Avon-Admiral) and WN 438 MVA/WE459 MVA (Admiral-Lorain) 2016_3-6E Upgrade First Energy 9.1 Eliminate three terminal line at Naomi Junction by constructing a double circuit line towards Wauseon substation. Wauseon substation will need to incorporate a new 138 kv line exit by adding a 138 kv breaker and relaying. 2016_3-6F Upgrade First Energy 0.01 Replace Mansfield Substation Breaker B57 with a breaker having 80 ka interrupt capability. Also replace associated gang-operated disconnect switches, D56 and D58. First Energy is already planning to replace B57 (as well as four other remaining ITE GA breakers at Mansfield) and associated disconnect switches based on condition, and Breaker B57 is expected to be in service November of _3-7A Greenfield PSE&G 55.9 Build a new 345 kv line from Maddox Creek to Southwest Lima Recommendation for Board Approval X PJM 2016 Regional Transmission Expansion Plan 65

74 5 Book 3: 2016 RTEP Proposal Windows Map 5.6: 2016 RTEP Proposal Window No. 3 Proposals 66 PJM 2016 Regional Transmission Expansion Plan

75 Book 3: 2016 RTEP Proposal Windows 5 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 5.3: 2016 RTEP Proposal Window No. 3 Addendum Window Process PJM conducted 2016 RTEP Proposal Window No. 3 Addendum from November 28, 2016 to December 13, 2016, because incorrect ratings brought to PJM s attention in system modeling were following the conclusion of the earlier Window No. 3 on October 31, Those incorrect ratings affected the magnitude of overloads identified under Generation Deliverability and Common Mode Outage study tests in Window No. 3. Given that transmission developers could otherwise have been relying on potentially inaccurate study results, PJM updated the ratings and reran the Generation Deliverability and Common Mode Outage study tests the results of which drove the subsequent need for the Window No. 3 Addendum. Window No. 3 Addendum also included both winter and summer analyses. Identified reliability criteria violations were associated with 10 flowgates (a monitored element and contingency pair) transmission facility and contingency or outage pairs shown in Table 5.7. Addendum and Map 5.7. Addendum. Table 5.7:2016 RTEP Proposal Window No. 3 Addendum Violations Project ID Upgrade/ Greenfield Proposing Entity Cost ($M) Major Components 2016_3A-1A Greenfield Transource Construct a new double circuit 345 kv line between ATSI s Carlisle Station and a new station, Rocky River West, along the Avon Lake-Juniper 345 kv line. Also, construct a new Sheffield 138 kv switching station. 2016_3A-1B Greenfield Transource Construct a new double circuit 345 kv line between ATSI s Carlisle Station and a new station, Rocky River West, along the Avon Lake-Juniper 345 kv line. Also, construct a new Sheffield 138 kv switching station. Construct a new Middle Ridge 345 kv Station connecting the existing Beaver-Davis Besse 345 kv and Beaver-Carlisle 345 kv lines. 2016_3A-2A Greenfield Northeast Transmission Development 62.8 Construct a double circuit 345 kv line to loop the existing 345 kv Avon Lake to Juniper transmission line into the existing 345 kv Carlisle substation. Construct a single circuit 345 kv line from the existing X1-027A Tap to Beaver transmission line to the existing 345 kv Carlisle substation. Reconfigure the existing Beaver to X1-027A Tap 345 kv transmission line to have an X1-027A Tap to Carlisle 345 kv transmission line. Remove the remaining 345 kv transmission line between the new X1-027A Tap to Carlisle 345 kv line and the existing Beaver substation from service 2016_3A-3A Upgrade First Energy Reconductor the Beaver-Black River 138 kv line (~9.8 Miles) 795 Kcmil ACSR, including the six wire section (~7.0 miles) with 954 Kcmil ACSS conductor, upgrade the wave trap at Black River to 2,000 A, replace the GCY51 relay at Beaver substation with SEL and modify the existing RTU. New ratings after all components are complete: SN 540 MVA / SE 540 MVA, WN 540 MVA / WE 540 MVA 2016_3A-3B Upgrade First Energy Note: Existing PJM RTEP Project b2559 (ISD 2017) reconductors Black River-Lorain 138 kv line to 795 ACSS single circuit tower line. Black River-Lorain Q2 138 kv line ugrade. Rebuild/Reconductor approx. 6.5 miles single 795 ACSS/TW conductor between Black River to Charleston and Charleston to Lorain substations with bundle 795 Kcmil ACSS conductor. Terminal upgrades: Upgrade 2,000 A wavetrap at Black River, Lorain and Charleston substation to 3,000 A. The new Black River-Charleston and Charleston-Lorain 138 kv circuit winter (MVA) rating will be 679 WN / 753 WE / 459 WLD (The new limiting element is a substation conductor at Charleston) 2016_3A-3C Upgrade First Energy 3.2 Reconductor the Avon-Lorain 138 kv line segment (~4.5 miles) with 795 Kcmil ACSS conductor. Upgrade the line drops at Avon. New ratings: WN 521 MVA / WE 611 MVA (Avon - Admiral) and WN 438 MVA / WE 459 MVA (Admiral - Lorain) PJM 2016 Regional Transmission Expansion Plan 67

76 5 Book 3: 2016 RTEP Proposal Windows Map 5.7: 2016 RTEP Proposal Window No. 3 Addendum Violations 68 PJM 2016 Regional Transmission Expansion Plan

77 Book 3: 2016 RTEP Proposal Windows 5 Table 5.8: 2016 RTEP Proposal Window No. 3 Addendum Proposals Analysis Type Overloaded Facility TO Contingency 1 Winter Generator Delivery and Common Mode Outage Overlap with Window No. 3 Overloaded of the Admiral Q-3-Avon 138 kv line FirstEnergy ATSI ATSI-P7-1-CEI Winter Generator Delivery and Common Mode Outage Overlap with Window No. 3 Overloaded of the Admiral Q-3-Avon 138 kv line FirstEnergy ATSI ATSI-P2-3-CEI Winter Generator Delivery and Common Mode Outage Overlap with Window No. 3 Overloaded of the Beaver-Black River 138 kv line FirstEnergy ATSI ATSI-P7-1-OEC Winter Generator Delivery and Common Mode Outage Overlap with Window No. 3 Overloaded of the Black River-Lorain-Avon 138 kv line FirstEnergy ATSI ATSI-P7-1-CEI Winter Generator Delivery and Common Mode Outage Overlap with Window No. 3 Overloaded of the Black River-Lorain-Avon 138 kv line FirstEnergy ATSI ATSI-P2-3-CEI Winter Generator Delivery and Common Mode Outage Overlap with Window No. 3 Overloaded of the Lorain Q-2-Admiral Q kv line FirstEnergy ATSI ATSI-P7-1-CEI Winter Generator Delivery and Common Mode Outage Overlap with Window No. 3 Overloaded of the Lorain Q-2-Admiral Q kv line FirstEnergy ATSI ATSI-P2-3-CEI Winter Generator Delivery and Common Mode Outage Overlap with Window No. 3 Overloaded of the Black River-Lorain-Avon 138 kv line FirstEnergy ATSI ATSI-P7-1-CEI Winter Generator Delivery and Common Mode Outage Overlap with Window No. 3 Overloaded of the Black River-Lorain-Avon 138 kv line FirstEnergy ATSI ATSI-P2-3-CEI Summer Gen Delivery and Common Mode Outage Overlap with Window No. 2 Overloaded of the Beaver-Black River 138 kv line FirstEnergy ATSI ATSI-P7-1-OEC Window No. 3 focused mainly on two specific flowgates identified in study year 2021 reliability analysis. In addition to these two flowgates, PJM also identified eight additional flowgates that taken together could potentially be addressed by a single proposal. Proposals in this window were required to address the two main flowgates; addressing the remaining eight flowgates was optional. PJM noted though that the degree to which the eight were also addressed could impact proposal selection. Evaluation and Selection Once the window closed, PJM staff performed analytical, constructability and company evaluations as described in Book 2, 7.0 to identify which proposals most effectively solved all reliability criteria violations and did not introduce new ones. Following stakeholder review with the Transmission Expansion Advisory Committee (TEAC), PJM anticipates recommending projects to the PJM Board in Proposals PJM received six proposals from three entities targeting the identified reliability criteria violations in the ATSI zone, as shown in Table 5.8. Addendum and Map 5.8. Addendum. Three proposals were Transmission Owner upgrades to existing facilities that ranged in cost from $3.2 million to $19.9 million. Three were greenfield projects ranging in cost from $44.6 million to $62.8 million. PJM 2016 Regional Transmission Expansion Plan 69

78 5 Book 3: 2016 RTEP Proposal Windows Map 5.8: 2016 RTEP Proposal Window No. 3 Addendum Proposals 70 PJM 2016 Regional Transmission Expansion Plan

79 Book 3: 2016/2017 Market Efficiency Analysis 6: 2016/2017 Market Efficiency Analysis PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 6 6.0: Window Scope RTEP Process Context PJM s RTEP process includes Market Efficiency Analysis, the goal of which is to accomplish the following objectives: 1. Determine which reliability-based enhancements have economic benefit if accelerated. 2. Identify new transmission enhancements that may realize economic benefit. 3. Identify economic benefits associated with modification to reliability-based enhancements already included in the RTEP that when modified would relieve one or more economic constraints. Such enhancements, originally identified to resolve reliability criteria violations, may be designed in a more robust manner to provide economic benefit as well. PJM identifies the economic benefit of proposed transmission projects by conducting production cost simulations which show the extent to which congestion is mitigated by the project, for given transmission topologies and generation dispatch. The benefit metrics are determined by comparing future year simulations with and without the proposed transmission enhancement. The set of metrics and methods Figure 6.1: Market Efficiency 24-Month Cycle Year 0 Year 1 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Develop assumptions (Year 1 and Year 5) Market Efficiency Analysis (Year 1 and Year 5) accelerations and modifications Develop assumptions (Year 1, Year 5, Year 8, Year 11, Year 15) Identify and evaluate solution options accelerations and modifications Market Efficiency Criteria Analysis (Year 1, Year 5, Year 8, Year 11, Year 15) 24-month cycle Market Efficiency Analysis (Year 1, Year 5, Year 8, Year 11, Year 15) Identify proposed solutions Update significant assumptions (Year 0, Year 4, Year 7, Year 10, Year 14) Analysis of market solutions and support of benefits of reliability solutions (Year 0, Year 4, Year 2, Year 10, Year 14) Independent consultant reviews of buildability Adjustments to solution options by PJM based on analysis Develop assumptions (Year 1, Year 5) Market Efficiency Analysis (Year 1, Year 5) Accelerations and Modifications Final review with TEAC and approval by the PJM Board Identify and evaluate solution options Accelerations and Modifications Final review with TEAC and approval by the PJM Board 12-month cycle 12-month cycle PJM 2016 Regional Transmission Expansion Plan 71

80 6 Book 3: 2016/2017 Market Efficiency Analysis used to determine economic benefit are described in PJM Manual 14B, 2.6 and PJM Operating Agreement, Schedule 6, Accessible on-line via the following links: PJM Manual 14B, 2.6: com/~/media/documents/manuals/m14b.ashx PJM Operating Agreement, Schedule 6, 1.5.7: library/governing-documents.aspx The PJM Market Efficiency Analysis employs a market simulation tool that models an hourly security-constrained generation commitment and economic dispatch. In order to accomplish the market efficiency objectives discussed above, several base cases are developed. The primary difference between these cases is the transmission topology to which the simulation data is mapped. The As-Is base case maps to a near-term transmission topology case and includes significant upgrades expected to be in service by June 1 of the near-term year. The As-Planned base case maps to a five-year out transmission system that includes PJM RTEP projects approved by the PJM Board through the RTEP cycle. Comparing results of multiple simulations with the same input assumptions and operating constraints but with differing transmission topologies, allows PJM to determine a transmission upgrade s economic value. Utilizing this basic technique coupled with additional benefit analysis allows PJM to perform the following tasks: 1. Collectively value the approved RTEP portfolio of enhancements, 2. Evaluate if acceleration or modification of RTEP projects are economically beneficial 3. Evaluate if specific proposed transmission enhancements are economically beneficial. Importantly, the simulated transmission congestion results also provide important system information to PJM stakeholders and potential transmission developers. 24-month Cycle PJM s 2016 market efficiency analysis represents the first year of the market efficiency 24-month RTEP cycle, shown in Figure 6.1. The results discussed in 6.2, warranted a 2016/2017 long-term window on November 1, 2016, with a closing date of February 28, Near-Term Simulations PJM s 2016 Market Efficiency Analysis includes near-term simulations to assess the collective economic impact of not in-service RTEP enhancements and to identify potential accelerations or modifications to individual RTEP projects. By comparing the total simulation differences from the As-Is base case to the As-Planned base case for both 2017 and 2021 study years, PJM can quantify the total transmission congestion reduction due to recently planned RTEP enhancements. Similarly, comparison of the near-term As- Is and As-Planned simulations can identify constraints which may cause significant congestion and whether already planned upgrades may eliminate or relieve this congestion to the point that the constraint is no longer an economic concern. A comparison of these simulations can reveal if a particular RTEP upgrade may provide economic benefit that would make the upgrade a candidate for acceleration or modification. For example, if a constraint causes significant congestion in the 2017 As-Is simulation but not in the 2021 As-Planned simulation then the system enhancements, which eliminates this congestion in 2021, may be a candidate for acceleration. The benefit of accelerating this upgrade is then compared to the cost of the acceleration before any recommendation can be made to the PJM Board. 72 PJM 2016 Regional Transmission Expansion Plan

81 Book 3: 2016/2017 Market Efficiency Analysis Long-Term Simulations In order to quantify future longer-range transmission system market efficiency needs, PJM identified base congestion for study years 2017, 2021, 2024 and The base cases for these evaluations include a 2021 RTEP As-Planned transmission system topology that contains RTEP projects submitted for approval through the 2015 RTEP cycle. Market efficiency projects submitted during the 2016/17 long-term proposal window, which will be open from November 2016 through February 2017, will initially be evaluated using these base cases developed in However, during the 2017 project evaluation phase, PJM will develop a 2017 mid-cycle update case that will incorporate significant RTEP changes approved through the 2016 RTEP cycle. This mid-cycle update case will include potentially significant forecast changes in topology, generation, load, and fuel costs. The 2017 mid-cycle evaluates the effectiveness of potential projects using an updated forecast of future conditions Benefit-to-Cost Threshold Test PJM performs a benefit-to-cost threshold test to determine if market efficiency justification exists for a particular upgrade for PJM Board recommendation. Market Efficiency transmission proposals that meet or exceed the 1.25 benefit-to-cost ratio threshold test are further assessed to examine their respective economic, system reliability, and constructability impacts. For projects with a total cost exceeding $50 million, PJM s Operating Agreement requires an independent review of project costs to ensure consistent estimating practices and project scope development. The benefit-to-cost ratio is calculated by comparing the net present value of annual benefits determined for the first 15 years of the project life to the net present value of project revenue requirement for the same 15-year period. The market efficiency benefits for the majority of evaluations are derived solely through energy market simulations and resulting metrics. Other transmission evaluations, which may prospectively affect the capacity market, may derive additional benefits through capacity market simulations and metrics. PJM s annual energy benefit calculation for regional facilities is weighted 50 percent to change in system production cost and 50 percent to change in net load energy payments for zones with a decrease in net load payments as a result of the proposed project. Change in system production cost comprises the change in system generation variable cost (fuel costs, variable operating and maintenance (O&M) costs, and emissions costs) associated with total PJM energy production. Change in net load energy payment comprises the change in gross load payment offset by the change in transmission rights credits. The net load payment benefit is calculated only for zones in which the proposed project decreases the net load payments. Zones for which the net load payments increase because of the proposed project are excluded from the net load energy payment benefit. PJM s annual energy benefit calculation for lower voltage facilities is weighted 100 percent to zones with a decrease in net load payments as a result of the proposed project. Change in net load energy payment comprises the change in gross load payment offset by the change in transmission rights credits. The net load payment benefit is only calculated for zones in which the proposed project decreases the net load payments. Zones for which the net load payments increase because of the proposed project are excluded from the net load energy payment benefit. PJM s annual capacity benefit calculation for regional facilities is weighted 50 percent to change in total system capacity cost and 50 percent to change in net load capacity payments for zones with a decrease in net load capacity payments as a result of the proposed project. PJM s annual capacity benefit calculation for lower voltage facilities is weighted 100 percent to zones with a decrease in net load capacity payments as a result of the proposed project. Change in net load capacity payment comprises the change in gross capacity payment offset by the change in capacity transfer rights. PJM s RTEP Market Efficiency Study process and the benefit-to-cost ratio methodology are described in 2 of PJM Manual 14B, PJM Region Transmission Planning Process, available on PJM s website via the following link: com/~/media/documents/manuals/m14b.ashx PJM 2016 Regional Transmission Expansion Plan 73

82 6 Book 3: 2016/2017 Market Efficiency Analysis 74 PJM 2016 Regional Transmission Expansion Plan

83 Book 3: 2016/2017 Market Efficiency Analysis 6 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 6.1: 2016 Input Parameter Overview PJM licenses a commercially available database containing the necessary data elements to perform detailed PJM market simulations. This database is periodically updated permitting up-to-date representation of the Eastern Interconnection, and in particular, PJM markets. Because this data is used in developing forecasted system conditions, consistent with established RTEP process practice, the PJM Transmission Expansion Advisory Committee reviews the key analysis input parameters, including those shown in Figure 6.2. These parameters include fuel costs, emissions costs, load forecasts, demand resource projections, generation projections, expected future transmission topology, and several financial valuation assumptions. Transmission Topology Market efficiency power flow models were developed to represent (1) a 2017 As-Is transmission system topology and (2) the expected 2021 As- Planned system topology for the five-year out RTEP year. PJM derived the As-Is system topology from review of the Eastern Interconnection Reliability Assessment Group Multi-Regional Modeling Working Group 2015 Series 2017 summer peak case. It included significant transmission enhancements expected to be in-service by the summer of System topologies for 2021 and beyond were derived from the PJM 2021 RTEP base case used for baseline reliability studies. Figure 6.2: Market Efficiency Analysis Parameters Transmission Topology Generation Fuel Costs Market Efficiency Analysis Monitored Constraints Specific thermal and reactive interface transmission constraints are modeled for each base topology. Monitored thermal constraints are based on actual PJM market activity, historical PJM congestion events, other PJM planning studies, and their representation in the NERC Book of Flowgates. PJM reactive interface limits are modeled as thermal values that correlate to power flows beyond which voltage violations may occur. The Demand Resources Emissions Costs Load Forecasts modeled interface limits are based on voltage stability analysis and a review of historical values. Modeled values of future-year reactive interface limits incorporated the impact of approved RTEP enhancements on the reactive interfaces. PJM 2016 Regional Transmission Expansion Plan 75

84 6 Book 3: 2016/2017 Market Efficiency Analysis Generation Modeled Market efficiency simulations model existing in-service generation plus actively queued generation with at least an executed Facilities Service Agreement (FSA), less planned generator deactivations that have given formal notification. The modeled generation provides enough capacity to meet PJM s installed reserve requirement through all study years, as shown in Figure 6.3. This figure includes existing and projected PJM internal capacity based on PJM generation queue information and 2021 RTEP machines list. Fuel Price Assumptions PJM uses a commercially available database tool which includes generator fuel price forecasts. Forecasts for short-term gas and oil prices are derived from NYMEX future prices. Long-term forecasts for gas and oil are obtained from commercially available databases, as are all coal price forecasts. In addition, vendor-provided basis adders are applied to account for commodity transportation cost to each PJM zone. The fuel price forecasts used in PJM s 2016 Market Efficiency Analysis are represented in Figure 6.4. Figure 6.3: PJM Market Efficiency Reserve Margin Capacity MW 210, , , , , , , , ,000 Figure 6.4: Fuel Price Assumptions $/MMBtu Forecasted Summer Peak Net Internal Demand Reserve Requirement Existing + Not Suspended ISA Generation - Retirement Existing + ISA and FSA Queue Generation - Retirement Coal Gas Oil - Heavy Oil - Light PJM 2016 Regional Transmission Expansion Plan

85 Book 3: 2016/2017 Market Efficiency Analysis 6 Load and Energy Forecasts PJM s load forecast report provides the transmission zone peak load and energy data modeled in market efficiency simulations. Table 6.1 shows the PJM peak load and energy values to be used in the 2016 Market Efficiency Cases. Demand Resources The amount of demand resource modeled in each transmission zone is based on the 2016 PJM Load Forecast Report. Table 6.2 shows the PJM demand resource totals by year. Within the market efficiency models, the transmission zone breakdown is consistent with the PJM Load Forecast Report. Table 6.1: PJM Peak Load and Energy Forecast for Market Efficiency Load Peak (MW) 154, , , , ,469 Energy (GWh) 821, , , , ,168 Notes: 1.) Peak and energy values from PJM Load Forecast Report, Table B-1 and Table E-1, respectively. 2.) Model inputs are at the zonal level, to the extent zonal load shapes create different diversity modeled PJM peak load may vary. Table 6.2: Demand Resource Forecast Load Demand Resource (MW) 8,883 3,424 3,478 3,543 3,651 Notes: Values from PJM Load Forecast Report, Table B-7. PJM 2016 Regional Transmission Expansion Plan 77

86 6 Book 3: 2016/2017 Market Efficiency Analysis Emission Allowance Price Assumptions PJM currently models three major effluents SO 2, NO x and CO 2 within the market efficiency simulations. SO 2 and NO x emission price forecasts reflect implementation of the Cross State Air Pollution Rule (CSAPR) and are shown in Figure 6.5 and Figure 6.6, respectively. PJM unit CO 2 emissions are modeled as either part of the national CO 2 program or, for Maryland and Delaware units, as part of the Regional Greenhouse Gas Initiative (RGGI) program. The base emission price assumption for both the national CO 2 and RGGI CO 2 program are shown in Figure 6.7. Figure 6.5: SO 2 Emission Price Assumption $/Ton CSAPR Group 1 SO Figure 6.6: NO x Emission Price Assumptions $/Ton CSAPR Annual NO x CSAPR Seasonal NO x (May - Sep) PJM 2016 Regional Transmission Expansion Plan

87 Book 3: 2016/2017 Market Efficiency Analysis 6 Carrying Charge Rate and Discount Rate In order to determine and evaluate the potential economic benefit of RTEP projects, PJM performs market simulations and calculates a benefit-to-cost ratio for each candidate project. Doing so requires that the net present value of annual benefits be calculated for the first 15 years of project life and compared to the net present value of revenue requirement for the same 15-year period. A discount rate and levelized carrying charge rate is developed using information contained in Transmission Owner formula rate sheets (Attachment H) as posted on PJM s website: billing-settlements-and-credit/formula-rates.aspx. The discount rate is a weighted average aftertax embedded cost of capital (average weighted by Transmission Owner total capitalization). The levelized annual carrying charge rate is based on weighted average net plant carrying charge (average weighted by Transmission Owner total capitalization) levelized over an assumed 45-year life of the project. PJM s 2016 Market Efficiency Studies will use a levelized annual carrying charge rate of 15.3 percent and a discount rate of 7.4 percent. Figure 6.7: CO 2 Emission Price Assumptions $/Ton RGGI CO 2 5 National CO PJM 2016 Regional Transmission Expansion Plan 79

88 6 Book 3: 2016/2017 Market Efficiency Analysis 80 PJM 2016 Regional Transmission Expansion Plan

89 Book 3: 2016/2017 Market Efficiency Analysis 6 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 6.2: Study Results from 2016 Analysis Near-Term Simulation Results PJM s 2016 cycle of analysis included near-term simulations to identify the collective and constraintspecific transmission system impacts of previously approved RTEP projects not yet in service. PJM conducted market simulations for study years 2017 and 2021 under two alternative transmission topologies: As-Is PJM transmission system topology As-Planned RTEP PJM transmission system topology By comparing results of multiple simulations with the same fundamental supply and demand operating constraints but with differing transmission topologies, the economic value of a transmission enhancement can be determined. This basic technique allows PJM to perform the following: 1. Collectively value the congestion benefits of approved RTEP upgrades 2. Evaluate congestion benefits of accelerating or modifying specific RTEP projects Figure 6.8: Simulated PJM Congestion Costs 2017 and 2021 Millions ($) Congestion with 2017 Topology Congestion with 2021 Topology PJM congestion costs from market simulations for study years 2017 and 2021 are shown in Figure 6.8. Results show annual congestion cost reductions of more than $22 million or 10 percent for 2017 and over $185 million or 51 percent for 2021 using the 2021 RTEP topology. The reduction in congestion can be attributed to approved, but not yet in-service, RTEP enhancements PJM 2016 Regional Transmission Expansion Plan 81

90 6 Book 3: 2016/2017 Market Efficiency Analysis Acceleration Analysis PJM identified and evaluated specific RTEP enhancements that were most responsible for the congestion reductions identified in the near-term simulations. Table 6.3 identifies approved RTEP reliability projects and related congestion reductions considered as part of the 2021 study year acceleration analysis. PJM determined that the identified reliability enhancements, viewed within the context of the short-term analysis, did not provide congestion benefits significant enough to justify acceleration. Moreover, these enhancements would be unlikely acceleration candidates given in-service dates and project scopes Long-Term Simulation Results To identify and quantify long-term transmission system congestion, market simulations were conducted for study years 2017, 2021, 2024 and These simulations used the 2021 RTEP as-planned transmission system topology and included RTEP projects approved through the 2015 RTEP cycle. The largest congestion cost constraints from the long-term analysis, which represent over 95 percent of the PJM related congestion in the 2021 and 2024 simulations, are listed in Table 6.4. Overall, congestion levels in PJM s 2016 Market Efficiency Analyses have remained relatively low and continue to decline compared to previous RTEP cycles. Factors contributing to this include the following: Table 6.3: RTEP Projects Reducing Specific Congestion Drivers: 2021 Analysis Congestion Decreases Associated with Approved Reliability Projects 2021 Study Year Constraint Name Area Type Susquehanna-Harwood 230 kv Line Milford-Steele 230 kv Line 2017 Topology Year 2021 Congestion ($M) 2021 Study Year 2017 Topology Year 2021 Congestion ($M) Congestion Savings ($M) Upgrade Responsible for Congestion Reduction PPL Line $9.8 $3.7 $6.1 PJM RTEP S1107: Upgrade Harwood 230 kv Substation by building 230 kv yard to current standards and replacing old equipment DP&L Line $4.4 $0.0 $4.4 PJM RTEP B2633.1: New 230 kv transmission line between Salem and Silver Run Gable-Tidd 138 kv Line AEP Line $3.6 $0.0 $3.6 PJM RTEP S1067: Rebuild Tidd-Gable 138 kv circuit East Towanda-East Sayre 115 kv Line McDowell-Shenango 138 kv Line Juniata-Cumberland 230 kv Line Bayway Q-Doremus Place 138 kv Line Zion Energy Center-Zion Station 345 kv Line PENELEC Line $2.4 $0.0 $2.4 PJM RTEP B2621: Replace relays at East Towanda and East Sayre 115 kv substations. ATSI Line $2.3 $0.0 $2.3 PJM RTEP B2413: Replace a relay at McDowell 138 kv substation PPL Line $2.0 $0.0 $2.0 PJM RTEP S0945.8: Rebuild the Juniata-Cumberland 230 kv Line. PSE&G Line $2.0 $0.0 $2.2 PJM RTEP B2436: PSE&G Northern NJ 345 kv Project CE Line $1.3 $0.0 $1.3 MISO MTEP P8065: Reconfigure the Pleasant Prairie-Arcadian 345 kv and Zion-Libertyville 345 kv transmission lines to loop into new station 1. Lower gas price assumptions coupled with generation portfolio shifts that include more high efficiency gas-fired generation 2. Load forecast levels continue to be lower compared to the previous forecasts In-Service Year RTEP transmission enhancements are improving or eliminating potential congestion causing constraints 82 PJM 2016 Regional Transmission Expansion Plan

91 Book 3: 2016/2017 Market Efficiency Analysis 6 Table 6.4: Market Efficiency Long-Term Simulation Results Facility Name Area Type 2017 Market Congestion ($M) 2021 Market Congestion ($M) 2024 Market Congestion ($M) 2027 Market Congestion ($M) Graceton-Conastone 230 kv Line BGE PJM Flowgate $51.80 $58.26 $72.10 $68.88 Bagley-Graceton 230 kv Line BGE PJM Flowgate $23.59 $33.01 $49.55 $59.57 AP-South Interface for the loss of Bedington-Black Oak 500 kv line 500 kv system Interface $37.64 $36.68 $32.83 $40.57 Keystone-Juniata and Conemaugh-Juniata 500 kv lines for the loss of Lackawanna-Hopatcong 500 kv Line 500 kv system Interface $24.35 $24.46 $22.33 $18.12 Central Interface 500 kv system Interface $4.18 $9.56 $6.93 $4.60 Susquehanna-Harwood 230 kv Line PPL PJM Flowgate $0.00 $3.98 $5.60 $8.32 AEP-DOM Interface for the loss of Bedington-Black Oak 500 kv line 500 kv system Interface $1.46 $2.34 $6.33 $10.45 Red Oak B-Raritan River 230 kv Line JCPL PJM Flowgate $0.19 $3.63 $4.03 $5.21 Peach Bottom-Conastone 500 kv Line BGE PJM Flowgate $32.78 $1.78 $3.84 $1.90 RINGA-Red Oak A 230 kv Line JCPL PJM Flowgate $0.00 $2.03 $3.51 $4.52 Maple-Hoytdale 138 kv Line FE-ATSI PJM Flowgate $1.29 $1.55 $2.96 $2.77 North Waverly-East Sayre 115 kv Line PENELEC PJM Flowgate $0.00 $1.13 $1.82 $1.20 Bosserman-Olive 138 kv Line AEP Market-to-market $0.00 $0.36 $1.98 $1.04 Yellow highlighting indicates solution alternatives are being sought in the 2016/17 RTEP Long-term Proposal Window /17 RTEP Long-Term Proposal Window Market Efficiency Proposals PJM solicited stakeholder proposals for market efficiency projects as part of an RTEP proposal window focusing on long-term analysis. The 2016/17 RTEP Long-Term Proposal Window opened on November 1, 2016, and closed on February 28, It sought technical solution alternatives to resolve or alleviate market efficiency congestion identified in the long term simulation congestion results shown earlier in Table 6.4 those that are highlighted in yellow. Proposals that address other congested elements within the long-term analysis will also be evaluated, as appropriate. In preparation for the proposal window, PJM developed and posted a Problem Statement and Requirements Document that can be accessed as a link on PJM s website at link: planning/rtep-development/expansion-plan-process/ ferc-order-1000/rtep-proposal-windows.aspx. Continuation of 2014/15 Long-Term Window Evaluation NOTE: Evaluations of several PJM Board approved projects that were initiated as part of the 2014/15 Long-Term Window extended into These projects were evaluated as part of a simulation database that originated in 2014, but was periodically updated to capture more contemporaneous forecast conditions, either as part of mid-cycle model update or as an analysis sensitivity. 4 describes the evaluation of these projects. PJM 2016 Regional Transmission Expansion Plan 83

92 6 Book 3: 2016/2017 Market Efficiency Analysis 84 PJM 2016 Regional Transmission Expansion Plan

93 Book 3: Transmission End-of-Life Assessments 7: Transmission End-of-Life Assessments PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 7 7.0: Dominion FERC No. 715 Criteria Violations The PJM Operating Agreement specifies that Transmission Owner planning criteria are to be evaluated as a part of the RTEP process. PJM has observed over the past several years that TO criteria, particularly with respect to aging infrastructure, are increasingly driving the need for baseline projects. In the fall of 2014, Dominion added an end-of-life criteria to its TO planning criteria as a part of its FERC Form No. 715 filing. The criteria specified an equipment condition assessment for facilities that have or will reach end-of-life together with a reliability evaluation to determine the system impacts due to facility removal. The Dominion criteria states that facility end-of-life can be determined by a third-party assessment or by industry recommendations for particular facility structures. Recommendations have been based on the following: Wood structures 35 to 55 years Conductors and connectors 40 to 60 years Porcelain insulators 50 years Facilities built in the 1960s and earlier at 115 kv and above have been identified under these criteria. As one example, 500 kv line steel lattice structure joints and members have deteriorated to the point that they are at risk of failure. Aging Infrastructure Planning Not New Planning for aging infrastructure is not new to PJM. In 2006, PJM completed a Probabilistic Risk Assessment (PRA) initiative to address an aging 500/230 kv transformer fleet. Over the course of the several years prior, the PJM system experienced transformer failures and loss-of-life degradation, impacting reliability and causing hundreds of million dollars of congestion. Based on the outcome of the transformer PRA, the PJM Board approved the addition of seven new spares to enhance system reliability and mitigate congestion costs in the event of transformer failure. Subsequent annual PRA analyses have shown that the initial spares approved and installed through the RTEP continue to mitigate transformer failure risk. The Mt. Storm-Doubs 500 kv Line rebuild offers another prime example. The Mt. Storm- Doubs 500 kv transmission line approximately 100 miles long was built in Over the course of the ensuing 45 years, despite ongoing maintenance efforts, tower structures, foundations and conductor hardware have deteriorated to the point where the line was approaching its end-oflife and was at risk of major failure. Consequently, the PJM Board approved PJM s recommendation in 2011 to add the rebuild to the PJM RTEP as an operational performance upgrade. NOTE: Transmission projects required to solve TO FERC filed Form No. 715 planning criteria violations are included in the RTEP consistent with section 1.2(e) of Schedule 6 of the Operating Agreement. Based on a recent FERC Order the cost for transmission upgrades that are driven exclusively by TO FERC filed form No. 715 planning criteria are allocated to the local TO zone. PJM 2016 Regional Transmission Expansion Plan 85

94 7 Book 3: Transmission End-of-Life Assessments 2016 RTEP Process Activity End-of-life assessments in 2016 continued that begun in 2014 as described in the PJM 2015 RTEP Report, Book 3, 3.2: com/~/media/documents/reports/2015-rtep/2015- rtep-book-3.ashx. PJM and Dominion continued their work categorizing facilities which were nearing their end-of-life and for which continued operating risks would negatively impact transmission system reliability. Dominion s condition assessment identified the nearness of each facility s expected end-of-life yielding the four facility categories summarized in Table 7.1. Doing so has allowed PJM to assess what lies ahead in terms of baseline transmission need and to inform transmission developers and other stakeholders accordingly. Going forward, PJM must address these facilities as part of RTEP process either as Immediate Need or as part of an RTEP proposal window if sufficient time permits. Treating end-of-life issues on a window basis could take one of two forms: 1. To the extent that NERC reliability criteria violations are identified on a given facility that is also otherwise shortly expected to face end-of-life issues then a window-based approach can seek proposals to address both. 2. If no NERC reliability criteria violations are identified that would drive RTEP need, then end-of-life concerns would otherwise drive need for window-based solutions to address facility deterioration and associated reliability criteria violations if the facility was to be lost. Table 7.1: Dominion End-of-Life Facilities Summary End-of-Life Need Date Number of Facilities Voltage Level 0 3 years (immediate need) kv 3 5 years kv 5 10 years kv Beyond 10 years kv A window approach was adopted in 2016 for the Carson-Rogers Road 500 kv transmission line that is expected to be at its end-of-life within 15 years and for the Chesterfield-Charles City Road Messer Road 230 kv line that has already reached its end-of-life. PJM had already identified NERC criteria violations on both facilities as part of 2016 RTEP process Generator Deliverability and Common Mode Outage tests. Given both sets of drivers, PJM conducted 2016 RTEP Proposal Window No. 1 for 30 days to seek solutions to both. Going forward, Dominion condition assessments and PJM reliability studies will continue to prioritize which facilities are likely to have greater reliability impacts and must be addressed first. NOTE: PJM is currently awaiting clarification from FERC that Transmission Owner issues alone do not require that PJM conduct an RTEP window. 86 PJM 2016 Regional Transmission Expansion Plan

95 Book 3: Transmission End-of-Life Assessments Immediate Need During 2016, PJM and Dominion assessment identified four 500 kv transmission lines comprising immediate need projects as shown Map Mt. Storm-Valley 500 kv Transmission Line 2. Valley-Dooms 500 kv Transmission Line 3. Elmont-Ladysmith 500 kv Transmission Line 4. Ladysmith-Bristers 500 kv Transmission Line PJM and Dominion have completed additional analysis of the Mt. Storm-Valley and Valley-Dooms 500 kv transmission lines. PJM will continue to analyze the remaining two facilities that will approach their end-of-life during Mt. Storm-Valley 500 kv Line Third party evaluation has confirmed that the Mt. Storm-Valley 500 kv line (designation No. 550) shown on Map 7.1 has reached its end-of-life. PJM reliability assessments without the line identified numerous thermal and voltage criteria violations for various contingencies on the Dominion system in an area encompassing Barrack Road, Charlottesville, Bath County, Lexington, Clifton, Endless Caverns, Ox, and Possum 500 kv substations. Given the immediate need for a solution, alternatives that would require new lines to be built were not considered. The approved solution is to rebuild the line at an estimated cost of $225 million and a projected in-service date of June 1, 2021, and expected to be approved by the PJM Board at its February 2017 meeting. Dooms-Valley 500 kv Line Third party evaluation has also confirmed that the Dooms Valley 500 kv line (designation No. 549) shown on Map 7.1 has reached its end-of-life. PJM reliability assessments without the line result in numerous thermal and voltage violations for various contingencies around and at Bath County, Lexington, Clifton, Lowmoor, and Dooms. Alternatives that would require new lines to be constructed were not considered. The approved solution is to rebuild line the Dooms-Valley 500 kv line at an estimated cost of $58.16 million and with a projected in-service date of June 1, The project is expected to be approved by the PJM Board at its February 2017 meeting. Colington 230 kv SVC Facilities nearing their end-of-life include not only 500 kv transmission lines. As a case-in-point, the existing static var compensator (SVC) at Colington shown on Map 7.1 is at the end of its life. The SVC is located in a harsh environment with high salt contamination that has led to component corrosion. The facility has a non-redundant design and has unique components with no spares. The approved solution is to install a +/- 125 MVAr SVC at Colington 230 kv. The estimated project cost is $30 million and the projected in-service date is June 1, 2017, as approved by the PJM Board at its February 2017 meeting. PJM 2016 Regional Transmission Expansion Plan 87

96 7 Book 3: Transmission End-of-Life Assessments Map 7.1: Dominion Immediate Need Facilities (within three years) 88 PJM 2016 Regional Transmission Expansion Plan

97 Book 3: Transmission End-of-Life Assessments Three to Five Year Out Need Table 7.2 lists the facilities shown on Map 7.2 that will approach their end of life within five years and will need to be replaced. Importantly, given the number of facilities expected to reach their end-of-life in three to five years, not all can be taken out of service at the same time to implement solutions. PJM planning staff has initiated efforts with Dominion and PJM operations to sequence and coordinate project work so as to ensure system reliability throughout the period. Table 7.2: Dominion Facilities Reaching End-of-Life in Three to Five Years Line Voltage (kv) In-Service Year Lexington-Rockbridge Portsmouth - Greenwich Portsmouth - Great Bridge New Road-Middleburg Lanexa-Waller Earleys-Everetts STR 551-STR Chesterfiled-Lanexa Northwest-Chesterfield Staunton-Harrisonburg Goshen-Craigsville Portsmoth-Churchland Chesterfiled-Plaza Staunton-Craigsville Northeast-Carver Great Bridge-Hickory Yorktown-Peninsula Fudge Hollow-Greenbrier Interconnection Carolina-Roanoke Rapids Hydro Elmont-Four Rivers Whealton-Peninsula Northwest-Acca Acca-Lakeside Brmo-Scottsville Interconnection Chase City-Boydton Plank Poe-Waverly Mt Storm Valley Valley Dooms Elmont Ladysmith Ladysmith - Bristers Chesterfiled-Hopewell Yadkin-Landstown Brambleton-Pleasant View Line Voltage (kv) In-Service Year Clifton-Sully Loudoun-Bull Run Hayfield-Van Dorn Lakeview-Hornertown Dooms-Grottoes Gum Springs-Jefferson Street Chesterfield-Locks Chesterfield-Allied Everretts-Edgecomb NUG Clifton-Glen Loudoun-Dulles Hornertown-Hathaway PJM 2016 Regional Transmission Expansion Plan 89

98 7 Book 3: Transmission End-of-Life Assessments Map 7.2: Dominion Facilities Reaching End-of-Life within Three to Five Years 90 PJM 2016 Regional Transmission Expansion Plan

99 Book 3: Transmission End-of-Life Assessments Beyond Five Years Table 7.3 and Map 7.3 show facilities expected to reach their end-of-life in five to ten years. Table 7.4 and Map 7.4 show facilities expected to reach their end-of-life after ten years. Here again, given the number of facilities expected to reach their end-oflife beyond five years can be taken out of service to implement solutions. PJM planning staff has initiated efforts with Dominion and PJM operations to sequence and coordinate project work so as to ensure system reliability throughout the period. Table 7.3: Dominion Facilities Reaching End-of-Life in Five to Ten Years Line Voltage (kv) In-Service Year Line Voltage (kv) In-Service Year Surry-Septa Bristers-Morrisville North Anna-Ladysmith Heritage-Wake Intertie Surry-Yadkin Morrisville-Spotsylvania Septa-Yadkin Possum Point-Ladysmith Chickahominy-Elmont Carson-Midlothian Septa-Carson Morrisville-Front Royal Surry-Chickahominy Meadobrook-Morrisville Yadkin-Fentress Loudoun-Clifton Bath County-Valley North Anna-Midlothian Bath County-Lexington Clifton-Ox North Anna-Spotsylvania Table 7.4: Dominion Facilities Reaching End-of-Life After Ten Years Line Voltage (kv) In-Service Year Lanexa-Harmony Villiage Fredericksburg-Possum Point Surry-Hopewell Winchester-Surry Surry-Churchland Chickahominy-Waller Yadkin-Surry Northern Neck-Lanexa Chickahominy-Lanexa Marsh Run Ct-Remington Possum Point-Occoquan Waller-Yorktown Northwest-Elmont Basin-Chesterfiled Roanoke Valley-Earleys Suffok-Earleys Northeast-Elmont Line Voltage (kv) In-Service Year Earleys-Trowbridge No Earleys-Trowbridge No Suffolk-Chuckatuck Lexington-Clifton Forge Dooms-Valley Lexsngton-Lowmoor Staunton-Dooms Midlothian-Spruance Charlottesville-Dooms Charlottesville-Bremo Fentress-Shawboro Morrisville-Marsh Run Landstown-Fentress Harrisonburg-Valley Farmville-Clover Roanoke Valley-Carolina PJM 2016 Regional Transmission Expansion Plan 91

100 7 Book 3: Transmission End-of-Life Assessments Map 7.3: Dominion Facilities Reaching End-of-Life in Five to Ten Years 92 PJM 2016 Regional Transmission Expansion Plan

101 Book 3: Transmission End-of-Life Assessments 7 Map 7.4: Dominion Facilities Reaching End-of-Life After Ten Years PJM 2016 Regional Transmission Expansion Plan 93

102 7 Book 3: Transmission End-of-Life Assessments 94 PJM 2016 Regional Transmission Expansion Plan

103 Book 3: Transmission End-of-Life Assessments 7 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 7.1: PSE&G FERC 715 Criteria Violations Metuchen-Edison-Trenton-Burlington Corridor PSE&G FERC No. 715 TO criteria address equipment condition assessments. In particular, VII Equipment Assessment and Storm Hardening addresses the requirement for periodic assessments of facility physical condition and age, among other items. During 2016, PSE&G identified facilities along its Metuchen-Edison- Trenton-Burlington 138 kv corridor that based on condition assessment failed its VII criteria. The Metuchen to Trenton section of the transmission corridor shown on Map 7.5 comprises a 30 mile circuit at 138 kv with an average structure age of 86 years. The Trenton to Burlington section comprises a 22 mile circuit at 138 kv with an average structure age of 75 years. PSE&G Facility Condition Assessment Consultants engaged by PSE&G assessed the equipment condition of the entire Metuchen- Burlington corridor and determined that facilities had reached their end-of-life. Foundation and tower structure deterioration was significant. Twentythree percent and thirty percent of the Metuchen- Trenton and Trenton-Burlington circuit structures, respectively, require extensive foundation rehabilitation or total foundation replacement. The assessment also discovered tower leg, gusset plate and angle deterioration due to corrosion. Twenty-five percent of the tower structures exceed the tower load carrying design capability; 25 percent of the towers are at percent of tower load bearing capability; and, 81 percent of the towers are at percent of tower load bearing capability. The assessment also reported 50 percent thickness loss of steel members. PJM RTEP Process Evaluation Prior to PSE&G identification of end-of-life criteria violations, PJM had already identified N-1-1 voltage violations in the Metuchen area as part of standard RTEP process analyses. PJM included those violations as part of 2016 RTEP Window No. 2 as discussed in 5.2. Subsequent to opening the window, PSE&G alerted PJM to the Metuchen-Burlington corridor end-of-life criteria violation. None of the window proposals that PJM received solved both the identified violations and corridor issues. Working with PSE&G, four alternatives were considered to solve PSE&G FERC No. 715 TO criteria VII violations: 1. Remove the existing 138 kv corridor without replacing it. 2. Install a new parallel circuit on a new rightof-way and remove the existing corridor. 3. Replace/rebuild the 138 kv corridor in kind with new foundations, 138 kv structures and hardware. 4. Convert the 138 kv corridor to 230 kv. Evaluation of alternatives No.1, No. 2 and No. 3 identified significant challenges along the corridor which removed them consideration: Alternative load supply for 544 MVA would be required at nine substations at some of which transmission supply would be unavailable Extensive 69 kv line construction would be required An existing transmission corridor would be lost Extensive underground construction would be required given the high population density of the area Securing new rights-of-way would be challenging The fourth alternative, conversion of the three 138 kv corridor circuits to 230 kv proved to be the most viable option. PJM 2016 Regional Transmission Expansion Plan 95

104 7 Book 3: Transmission End-of-Life Assessments Map 7.5: Metuchen-Edison-Trenton-Burlington 138 kv Corridor 96 PJM 2016 Regional Transmission Expansion Plan

105 Book 3: Transmission End-of-Life Assessments 7 Metuchen-Brunswick Circuit Conversion of the Metuchen-Brunswick R-1318 and Q-1317 circuits to one 230 kv circuit shown in Figure 7.1 would eliminate the need for Metuchen 138 kv substation and associated 230/138 transformer. The new circuit would terminate at the existing Metuchen and Brunswick 230 kv substations. The estimated cost of the project is $125 million. The project solves the N-1-1 voltage violations identified by PJM in the Metuchen area, strengthening the system and creating a stronger tie between southern and central PSE&G. Doing so is expected to provide positive economic benefit insofar as transfer capability into central New Jersey increases. Finally, the project also eliminates the need for baseline project b2590 identified in the 2014 RTEP comprising two 75 MVAr capacitors at the Sewaren 230 kv substation. Figure 7.1: Metuchen-Brunswick Conversion to 230 kv Brunswick D-2204 Deans Before Meadow Rd R-1318 Q-1317 Edison S-2219 Pierson Ave H-2286 Metuchen Brunswick D-2204 Meadow Rd Deans After R-1318 Edison S-2219 Pierson Ave H-2286 Metuchen Brunswick-Trenton Conversion of the Brunswick-Trenton N-1340 and T-1372 / D kv circuits from 138 kv to 230 kv shown in would also solve N-1-1 voltage violations identified by PJM in the area, strengthening the system by creating a stronger tie between southern and central PSE&G. Here again, doing so is also expected to provide positive economic benefit insofar as transfer capability into central New Jersey increases. The converted circuits would terminate at the existing Brunswick 230 kv station with two 230/138 kv transformers at the Trenton terminus. The estimated project cost is $302 million. Figure 7.2: Brunswick-Trenton Conversion to 230 kv To Peco Mercer Before Devils Brook Trenton To Metuchen R-1318 Brunswick D-2204 Plainsboro Deans Q-1317 S-2219 To Peco Mercer After Brunswick D-2204 To Metuchen Deans Plainsboro Devils Brook Trenton S-2219 To Burlington To Burlington PJM 2016 Regional Transmission Expansion Plan 97

106 7 Book 3: Transmission End-of-Life Assessments Trenton-Burlington This part of the corridor project converts the Trenton-Burlington F-1358 / Z-1326 and K-1363 / Y kv circuits to 230 kv, as shown in Figure 7.3. The Trenton 138 kv substation would be replaced with a six bay breaker-and-a-half 230 kv substation. A 230/138 kv transformer would be installed at Trenton to feed the Trenton-US Steel 138 kv circuit. The project eliminates the need for baseline project B2589 comprising a 100 MVAr 230 kv shunt reactor at Mercer substation, identified as part of PJM 2014 RTEP process. As with the two other circuits in the corridor, conversion to 230 kv strengthens the system by improving solving voltage criteria violations and increasing cross system transfer capability. The estimated project cost is $312 million. Figure 7.3: Trenton-Burlington Conversion to 230 kv Burlington Before To PECO Mercer To Lawrence Crosswicks Bustleton Yardville To Brunswick/ Metuchen Trenton Burlington To PECO After Mercer To Lawrence Crosswicks Bustleton Yardville To Brunswick/ Metuchen Trenton 98 PJM 2016 Regional Transmission Expansion Plan

107 Book 3: Transmission End-of-Life Assessments 7 Alternative Comparison Considerations PSE&G performed a study comparing the costs of Alternative No. 3 (replace circuits with 138 kv) and Alternative No. 4 (replace circuits with 230 kv), summarized in Table 7.5. The higher cost of the 230 kv option is attributed to replacement of the existing Brunswick 230/138 kv transformer which would not be required in the 138 kv option. However, replacing the existing corridor with new 138 kv does not address the voltage issues in the Metuchen area. Conversion to 230 kv will eliminate the need for the following projects totaling $67 million: Table 7.5: Metuchen-Burlington Corridor Alternatives Cost Comparison Alternative No. 3 (138 kv Replacement) $M Alternative No. 4 (Conversion to 230 kv) $M Metuchen-Brunswick $126 $125 Brunswick-Trenton $265 $302 Trenton-Burlington $293 $312 Total $684 $739 Metuchen and Edison 138 kv stations approaching end-of-life and require replacement in the near term. ($28 million) Sewaren capacitors and Mercer reactors, otherwise required with the 138 kv option. ($15.6 million) Class-H transformers require replacement in the near term.($10.5 million) Autotransformers (3) savings from other projects. ($7.1 million) Refurbishment of the Trenton control house building. ($1 million) Refurbishment of the Metuchen autotransformer and installation of Brunswick autotransformer. ($5 million) PJM anticipates recommending this project to the PJM Board for approval in NOTE: The PJM Board approved the Metuchen-Burlington corridor project at its February 2017 meeting. NOTE: Here again, transmission projects required to solve TO FERC filed Form No. 715 planning criteria violations are included in the RTEP consistent with section 1.2(e) of Schedule 6 of the Operating Agreement. Based on a recent FERC Order the cost for transmission upgrades that are driven exclusively by TO FERC filed form 715 planning criteria are allocated to the local transmission owner zone. PJM 2016 Regional Transmission Expansion Plan 99

108 7 Book 3: Transmission End-of-Life Assessments Newark Switch Built in 1957, the PSE&G Newark Switch 138 kv substation shown on Map 7.6 is housed in an urban building in downtown Newark and includes four transformers: two installed in 1958, one in 1972 and a spare in The substation house has a rooftop 138 kv transmission system and lower level, indoor transformers, oil rooms, distribution reactors and 26 kv switch gear. PSE&G s equipment condition assessment has determined that substation equipment has reached its end-of-life, characterized by common modes of failure, aging and obsolete equipment as well as environmental and structural concerns. Equipment failure or a transformer fire would be catastrophic at this location because of the indoor equipment. This would jeopardize 300 MVA of critical customer load. Map 7.6: Newark Switch Substation Alternatives Considered: In concert with PSE&G, several alternatives have been developed: 1. Build a new Newark Gas Insulated Switchgear (GIS) station in an adjacent building and demolish the existing one at a cost of $353 million. 2. Build a new Newark GIS station elsewhere in Newark and relocate all transmission and distribution cables and protection equipment. This would entail finding a large property and build a new substation, the relocation of four 138 kv transmission lines, more than thirty 26 kv and 13 kv distribution feeders and extended transmission and distribution outages. A critical hurdle is the lack of a necessary largescale property within the city of Newark. The estimated cost would be $458 million. 3. Do nothing. This alternative was viewed as unacceptable given the risk of transformer fire that could mean the loss of the entire building and the subsequent loss of about 300 MVA of load for a long duration. PJM and PSE&G will continue to analyze this project in PJM 2016 Regional Transmission Expansion Plan

109 Book 3: Interregional Coordination 8: Interregional Coordination PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 8 8.0: Interregional Scope Adjoining Systems PJM continues to expand and improve its successful, collaborative transmission planning efforts with its neighbors. In recent years, PJM s interregional planning responsibilities have grown in parallel with the evolution of broader organized markets and interest at the state and federal level in favor of increased interregional coordination. The nature of these activities includes structured tariff-driven analyses as well as targeted issues that arise each year. This is expected to continue as the terms of FERC Order No compliance filings transition to implementation. PJM currently has interregional planning arrangements with New York Independent System Operator, the Independent System Operator of New England, and Mid-Continent Independent System Operator, North Carolina Transmission Planning Collaborative, Duke Energy, Tennessee Valley Authority (TVA), and Southeastern Regional Transmission Planning (SERTP), shown on Map 8.1. FERC Order No interregional planning processes with the Carolinas and TVA will be conducted under the SERTP process embodied in the Tariff provisions of PJM and the SERTP sponsors subject to FERC jurisdiction. SERTP sponsors include Duke Energy Progress (jurisdictional), TVA, Southern Company (jurisdictional), Georgia Transmission Corporation, Municipal Electric Authority of Map 8.1: PJM Interregional Coordination NC Collaborative TVA Georgia, PowerSouth, Louisville Gas & Electric and Kentucky Utilities (jurisdictional), Associated Electric Cooperative, Ohio Valley Electric MISO SERTP ISO New England PJM New York ISO Corporation (jurisdictional), and Dalton Utilities. In addition, PJM actively participates in the Eastern Interconnection Planning Collaborative. PJM 2016 Regional Transmission Expansion Plan 101

110 8 Book 3: Interregional Coordination Coordination Activities Under each interregional agreement, provisions governing coordinated planning include assessment of current operational issues to ensure that critical cross-border interface issues are identified and addressed before they impact system reliability or dilute effective market administration. The planning processes applicable to each of PJM s three external transmission interfaces include provisions to address issues of mutual concern: Cross-border impacts of regional transmission plans Impacts of queued generator interconnection requests and deactivation requests for units impacting an interregional interface Opportunities for efficiencies at interregional interfaces Solutions to reliability and congestion constraints on seams National and state public policy objectives that have interregional planning impacts Increased power flow modeling accuracy within individual RTO planning processes through periodic modeling data and information exchange Studies are conducted in accordance with a specifically defined scope and may include crossborder analyses that examine reliability, market efficiency or public policy needs. Reliability studies may examine transfers, stability, short circuit, generation and merchant transmission interconnection analyses, generator deactivations and public policy. Importantly, the development and maintenance of updated joint planning system models is a necessary element of all interregional study activities and marks an important achievement for all regions involved. Together, fulfillment of these coordinated planning activities ensures reliability, efficiency and cost effectiveness of the regional transmission plans. Whenever transmission planning or operational issues arise that affect PJM and adjoining systems, PJM addresses them as part of its own RTEP process FERC Order No Compliance Filings Interregional regulatory filings and subsequent compliance filings have been submitted over the past four years to effect compliance with FERC Order No While PJM s established interregional planning was already largely compliant with the Order s requirements, PJM filed enhancements to improve processes and transparency of transmission planning with adjoining systems. The exchange of planning information and the annual review process required to coordinate regional plans was formalized. The filings also included provisions to allocate the costs of interregional transmission facilities between regions. All categories of potential transmission with neighbors are addressed by the Order 1000 provisions including reliability, economic and public policy types of projects. These provisions ensure that the PJM and neighbor regional plans at each interface are the most efficient, cost effective plans. During 2016, the final filings to memorialize the Order No interregional provisions on all PJM interfaces became effective. MISO Joint Operating Agreement The MISO interface continues to be PJM s most active for coordinated planning arising out of the overlapping nature of transmission facilities and service territories along PJM s border with MISO. Specifically, the Commission has accepted revisions to the Joint Operating Agreement (JOA) (with only minor additional clarifications yet to be accepted) between PJM and MISO including: Added Details for the Coordinated System Plan study steps and timeline (subject to further compliance) Removed the interregional benefit to cost ratio eligibility criteria for interregional economic transmission projects between PJM and MISO Established the use of regional models and benefits determinations to calculate the split of interregional economic project costs between PJM and MISO Memorialized generator interconnection and deactivation coordination procedures Reduced MISO s regional voltage eligibility criteria, applicable to interregional economic projects, to 100 kv and removed MISO s regional capital cost criteria applicable to interregional economic projects. New JOA provisions have created a new category of interregional transmission enhancement called the Targeted Market Efficiency Project, as discussed in PJM 2016 Regional Transmission Expansion Plan

111 Book 3: Interregional Coordination 8 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 8.1: Interregional Activities Map 8.2: PJM-MISO Interregional Coordination PJM-MISO Joint Operating Agreement Article IX of the Joint Operating Agreement (JOA) between PJM and MISO codifies coordinated regional transmission expansion planning processes between the two systems as shown on Map 8.2. Recent JOA revisions include coordinated system plan development, transmission system expansion and enhancement identification to maintain reliability, operational performance improvement, and enhancement of electricity market competitiveness. Joint studies take into consideration the unique, complex nature of the PJM-MISO seam and the power transfers across it. Results from reliability and production cost market simulation studies are documented and formally reviewed by the JOA s Interregional Planning Stakeholder Advisory Committee (IPSAC). MISO PJM Evolving Metrics Studies prior to 2015 focused on extensive evaluation of both historic and projected congestion along the PJM-MISO seam based on metrics codified in the JOA at the time. Those study efforts generated extensive discussions regarding how to improve process and results. During 2015, PJM and MISO examined and prioritized process solutions into two groups: one near-term and one requiring more intensive discussion. A year-end 2015 filing approved by the FERC in February 2016 eliminated a JOA cost threshold that limited cross-border market efficiency transmission solutions to only those greater than $20 million. This metric has prevented consideration of more efficient and cost effective interregional options. Eliminating the threshold should increase the number of potential transmission projects to relieve congestion. JOA FERC filings during 2016 provided the foundation for interregional market efficiency project metric and process enhancements. PJM 2016 Regional Transmission Expansion Plan 103

112 8 Book 3: Interregional Coordination Targeted Market Efficiency Project Based on past joint study work experience, PJM and MISO created a new classification of interregional transmission project in These projects will address historical congestion on reciprocal coordinated flowgates a set of specific flowgates subject to joint and common market congestion management. Such congestion arises from the joint market operations creating significant financial consequences for market participants. PJM and MISO agreed that in addition to evaluating the need for interregional transmission based on future system projections, the need also exists to remedy historical congestion on reciprocal coordinated flowgates. This new project type was defined in conjunction with stakeholders and is referred to as a targeted market efficiency project. Modifications to the Joint Operating Agreement to incorporate this project type were filed with the Commission in The first targeted market efficiency project analysis was completed during The filed process provides an innovative approach to interregional coordination that is attracting notice from other entities interested in enhancing interregional coordination results. Key features include the following: A single joint review and analysis process that selects projects culminating in recommendations to both PJM and MISO boards A limitation on project capital cost to no more than $20 million (larger projects are considered under the longer and more involved JOA process for market efficiency projects) Table 8.1: Proposed PJM/MISO Targeted Market Efficiency Projects Transmission Project Cost Project Benefit Benefit Allocation Facility Owner(s) ($M) ($M) PJM MISO Burnham-Munster 345 kv Line CE-NIPSCO $7.00 $ % 12% Bayshore-Monroe 345 kv Line ATSI-ITC $1.00 $ % 11% Michigan City-Bosserman 138 kv Line NIPSCO-AEP $4.60 $ % 10% Reynolds-Magnetation 138 kv Line NIPSCO $0.15 $ % 59% Roxana-Praxair 138 kv Line NIPSCO $4.50 $ % 76% Notes: AEP American Electric Power ATSI American Transmission Systems, Incorporated CE Commonwealth Edison ITC ITC Transmission Company NIPSCO Northern Indiana Public Service Company The expectation of project completion by the summer peak season three years from the study year Expected four year market congestion savings equal to or greater than the capital cost of the project During 2016, PJM and MISO analysis led to the development of five projects for recommendation to their respective Boards. However, this is contingent on FERC acceptance of the TMEP process filed at the commission and cost allocation procedures soon to be filed. The five projects, shown in Table 8.1 and on Map 8.3, are estimated to cost approximately $17 million and produce market congestion savings totaling $100 million in the first four years of operation. 104 PJM 2016 Regional Transmission Expansion Plan

113 Book 3: Interregional Coordination 8 Map 8.3: PJM/MISO Proposed Targeted Market Efficiency Projects Burnham-Munster and Praxair-Roxana (138 kv) Michigan City-Bosserman (138 kv) Monroe-Bayshore (345 kv) Magnetation-Reynolds (138 kv) PJM 2016 Regional Transmission Expansion Plan 105

114 8 Book 3: Interregional Coordination Duff-Rockport-Coleman The PJM-MISO Joint Operating Agreement (JOA) comprehensively addresses a range of planning activities including a JOA-directed coordinated system plan. Plan development includes identifying and coordinating regional analysis that may impact the other party s system. For example, the new Duff-Rockport-Coleman 345 kv transmission line is a direct result of such an analysis. During 2014 and 2015, MISO conducted planning analysis aimed at mitigating congestion in the southern Indiana portion of their system caused by a Newtonville-Coleman 161 kv transmission line constraint, shown on Map 8.4. As part of that analysis, in coordination with PJM, MISO evaluated a new Duff-Coleman 345 kv line, at an estimated cost of $67.2 million, which yielded a 15.9 benefitto-cost ratio. PJM analysis demonstrated that an option to loop the Duff-Coleman 345 kv solution into PJM s Rockport generating station produced significant benefits to PJM at only relatively small incremental cost. This solution was adopted by both PJM and MISO thereby achieving a successful collaboration and yielding a joint solution to address issues in both regions at far lower cost than the sum of each region s individual solutions. The Duff-Coleman 345 kv single circuit was approved by the MISO Board of Directors on December 10, 2015, as part of the 2015 MISO Transmission Expansion Plan (MTEP). During 2016 MISO conducted and concluded a developer selection process as the final step toward realization of this project. The project is now proceeding to the implementation stage with an expected in-service date of January 1, Coordination with the PJM portion of the project involving the loop into Rockport has begun. The Rockport portions will be implemented as a PJM Supplemental project. Michigan and Quad Cities Interface Analyses The targeted study work of previous interregional study cycles identified local congestion issues on PJM s Michigan interface with the rest of Michigan and PJM s interface with MISO near the Quad Cities generating facility as described in the 2015 RTEP report, Book 3, 7.2: rtep/2015-rtep-book-3.ashx. Analyses were completed early 2016, and revealed the following: Economic analysis confirmed historical congestion patterns The fundamental driver for the analysis, historic Michigan import congestion, was alleviated by new patterns emerging in MISO generation dispatch Upcoming generation interconnection (the Covert generator) and associated electrical reconfiguration would act to reduce the impacts of potential future congestion if MISO dispatch patterns revert to those that caused the historical congestion Expected future system conditions do not warrant interregional transmission system enhancements at this time. Conditions will continue to be monitored As part of the Quad Cities Interface analysis, MISO identified reliability issues during the course of their last several MISO Transmission Expansion Plan regional evaluations. After loads and system representations were updated MISO concluded that the underlying factors driving for a more in depth assessment of transmission upgrades were no longer evident. This concluded the Quad Cities analysis. PJM and MISO will continue to monitor area system conditions. 106 PJM 2016 Regional Transmission Expansion Plan

115 Book 3: Interregional Coordination 8 Map 8.4: Duff-Rockport-Coleman 345 kv Line PJM 2016 Regional Transmission Expansion Plan 107

116 8 Book 3: Interregional Coordination NYISO and ISO-NE PJM activities with the NYISO and ISO-NE, shown on Map 8.5, focused in 2016 on compliance with the newly effective provisions of FERC Order No per the Northeast Protocol. Work in 2016 continued to ensure interregional coordination enabling the reliable and economic system performance. Stakeholder input is coordinated through the activities of the Interregional Planning Stakeholder Advisory Committee for NYISO and ISO-NE activities (IPSAC) consistent with the requirements of the effective agreements. The coordinated work for the preceding planning cycles was memorialized in the Northeast Coordinated System Plan report and posted for stakeholder review with the May 2016 IPSAC meeting materials: committees-and-groups/stakeholder-meetings/ ipsac-ny-ne.aspx. During the second half of 2016, along with ongoing interconnection and transmission service coordination, data exchange and economic database updates continued. In December 2016 the second annual IPSAC was conducted to review the year s regional analyses and transmission plans. No opportunities for interregional transmission were identified. Map 8.5: PJM, NYISO and ISO-NE Coordination ISO New England New York ISO PJM Interconnection 108 PJM 2016 Regional Transmission Expansion Plan

117 Book 3: Interregional Coordination Adjoining Systems South of PJM During 2016, PJM and the Southeastern Regional Transmission Planning (SERTP) shown earlier on Map 8.2 continued organizational efforts to develop FERC Order No interregional processes for data exchange and interregional planning efficiencies. SERTP activities include several entities under FERC jurisdiction as well as voluntary participation among six nonjurisdictional entities. The jurisdictional entities include Southern Company, Duke Energy (including Duke Energy Carolinas and Duke Energy Progress), Louisville Gas and Electric Company and Kentucky Utilities (LGE / KU), and Ohio Valley Electric Cooperative (OVEC). Duke Energy, LGE / KU and OVEC are directly connected to PJM. Only the Tennessee Valley Authority (TVA) is directly connected to PJM. The remaining five are planning areas south and west of Duke Energy and TVA.Interregional coordination with systems south of PJM also include planning activities with the North Carolina Transmission Planning Collaborative (NCTPC) and SERC. Southeastern Regional Transmission Planning SERTP interregional planning provisions are distinct in that the provisions for coordination are included in each jurisdictional entity s Open Access Transmission Tariff. The PJM provisions are codified in Schedule 6-A of the PJM Operating Agreement. SERTP input occurs through each region s respective planning process stakeholder forums. Stakeholders who have reviewed their respective region s needs and transmission plans may provide input regarding any potential interregional opportunities that may be more efficient or cost effective than individual regional plans. Successful interregional project proposals can displace the respective regional plans. PJM discussions of SERTP planning, as well as reports on other interregional planning, occur at the Transmission Expansion Planning Advisory Committee. The SERTP regional process can be followed at Coordinated planning activities in 2016 included PJM follow-up to commitments to Duke Energy to coordinate the calculation of its Capacity Import Limit with respect to PJM annual Base Residual Auction parameters. Efforts focused on potential limits on the Duke Energy system caused by imports from SERTP zones. PJM also provided notification to Duke Energy as to SERTP units that have cleared PJM auctions. This coordination, which occurred under confidentiality provisions of operating arrangements with Duke Energy ensured advance notice of potential planning issues for the Duke Energy system. PJM and Duke Energy also implemented closer operational coordination to ensure reliability during the first year of coordinating PJM external capacity resources located in the SERTP region. In April 2016, PJM and its SERTP counterparts also reviewed new interregional coordination requirements, each region s regional process, and current results from individual regional planning processes. No opportunities for interregional transmission were identified. However, recent PJM RTEP results identified issues along the interface with Duke Energy, TVA, LGE / KU and OVEC warranting additional future monitoring. Data exchange requirements under the FERC Order No provisions were scheduled. The new Planning Coordinator and Transmission Planner Critical Energy Infrastructure Information (CEII) and Non-Disclosure Agreement (NDA) crafted by the Eastern Interconnection Planning Collaborative provided the means to accomplish meaningful planning data exchanges in the second half of the calendar year. SERC Activities PJM continues to support SERC activities on behalf of its members. PJM participates actively in the Regional Studies Steering Committee, Long-Term Studies Group, the Dynamic Studies Group, the Short Circuit Database Working Group, and the Near-Term Studies Group. PJM contributed to the SERC committee and working group discussions to coordinate 2016 model building and study activities. SERC activities continue to grow as its practices evolve to recognize more accurately the expanding operational and market areas adjoining it. During 2016, PJM continued to implement past coordinated process improvements to improve Eastern Interconnection firm power flow transaction modeling. NOTE: PJM notes that the SERTP is an interregional effort, not to be confused with SRRTEP, PJM s own southern subregional RTEP committee. PJM 2016 Regional Transmission Expansion Plan 109

118 8 Book 3: Interregional Coordination Eastern Interconnection Planning Collaborative The Eastern Interconnection Planning Collaborative (EIPC) represents a unique Interconnection-wide transmission planning coordination effort among Planning Authorities in the Eastern Interconnection, shown on Map 8.6. The EIPC consists of twenty Planning Coordinators comprising approximately 95 percent of the Eastern Interconnection electricity demand. EIPC coordinates eastern interconnection transmission analysis of regional transmission plans to ensure their coordination and also provides the resources to provide analysis of emerging issues affecting the transmission grid in the Eastern Interconnection. Through this work, the EIPC coordinates with Federal and State organizations. The EIPC was formed in 2008 and initially funded by a $16 million American Recovery and Reinvestment Act grant administered by the U.S. Department of Energy (DOE), through Since then, the EIPC s work has been self-funded by the member organizations. The EIPC coordinates closely with a parallel Eastern Interconnection organization of states known as the Eastern Interconnection States Planning Council (EISPC). The EISPC is comprised of representatives from Governors Offices, State Regulatory Commissions, and State Energy Offices from 39 States, the District of Columbia, the city of New Orleans, and six Canadian Provinces located within the Eastern Interconnection and convenes regularly for the purpose of studying transmission planning. This project is supported by funding from the DOE. EISPC also works closely with the National Association of Regulatory Utility Commissioners (NARUC) and the DOE National Map 8.6: U.S. Interconnections Western Interconnection Texas Interconnection Laboratories. The EIPC work builds on, rather than replaces, existing regional and interregional transmission planning processes already in place by the participating EIPC planning authorities. Individual regional planning process studies are informed by EIPC s broader interconnection-wide study activities. EIPC initiatives have represented an expansion of power system planning analysis beyond the requirements of FERC Order No Eastern Interconnection 110 PJM 2016 Regional Transmission Expansion Plan

119 Book 3: Interregional Coordination 8 Two-year Planning Cycle Activity Work in 2015 began a new EIPC Non-grant twoyear planning cycle. Year One activity included completion of a reliability gap and transfer analysis of summer and winter performance. Activity in 2016 continued with Year Two of the cycle. Initial plans to solicit scenario analysis ideas produced several suggestions. After consideration and consultation with the EISPC an alternative scope was developed. It addresses the need for general education on how the planning coordinators accomplish eastern interconnection regional and interregional transmission planning in accordance with NERC and FERC requirements. The EIPC prepared and presented a series of open stakeholder Webinars in November These were recorded and can be viewed by navigating to the Non-DOE Stakeholder Activities of the EIPC website: Increasing attention to public policy impacts led to another major EIPC undertaking development of an Eastern Interconnection production cost database. Doing so creates a uniform set of assumptions for studying future system scenarios. During 2016, parties completed complex negotiations with a vendor for suitable software and completed compilation of starting point data. With the license and related EIPC agreement in place, parties began work to assemble, review and test the Eastern Interconnection model. This work will continue in EIPC Data Exchange During 2016 EIPC also responded to the need to implement FERC Order No mandated data exchanges and related NERC responsibilities to take the lead in assembling eastern interconnection power flow cases. To fulfill these requirements EIPC Planning Coordinators recognized the need to alleviate administrative burdens imposed by each entity s CEII confidentiality requirements. In light of that, the EIPC created a single CEII NDA for planning coordinators and transmission planners to facilitate that work. PJM 2016 Regional Transmission Expansion Plan 111

120 8 Book 3: Interregional Coordination 112 PJM 2016 Regional Transmission Expansion Plan

121 Book 3: Planning Parameters 9: Planning Parameters PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 9 9.0: Reliability Pricing Model Map 9.1: PJM Locational Deliverability Areas Recognizing Locational Constraints The Reliability Pricing Model (RPM), PJM s capacity market, is designed to provide a sufficient amount of capacity resources to ensure grid reliability at all times. Through RPM auctions, PJM seeks to procure target capacity levels for the entire RTO and for locational deliverability areas in a least-cost manner. PJM s RPM provides a transparent forward market mechanism for selecting resources to meet defined target capacity levels at least-cost while recognizing locational constraints. Market participants have the opportunity to put forward such resources as generation, demand side response, energy efficiency and transmission solutions. RPM aligns capacity pricing with system reliability requirements and provides advance, transparent information to all market participants. PJM s Regional Transmission Expansion Plan (RTEP) process resource adequacy function provides key pieces of that RPM information in terms of locational deliverability area parameters: Capacity Emergency Transfer Objective (CETO) and Capacity Emergency Transfer Limit (CETL) values Reliability requirement Base Capacity reliability constraints PJM 2016 Regional Transmission Expansion Plan 113

122 9 Book 3: Planning Parameters RPM includes locational constraints to recognize and quantify the locational value of capacity. To do so, PJM establishes a separate target capacity reserve level for each locational deliverability area (the locational deliverability area s reliability requirement) and a maximum limit on the amount of capacity that can be imported from resources located outside the locational deliverability area. Dividing the RTO into locational deliverability areas recognizes the reality that transmission system limitations may restrict the delivery of capacity resources. PJM s RTEP process has identified 27 such locational deliverability areas as listed in Table 9.1 and shown on Map 9.1. Table 9.1: PJM Locational Deliverability Areas LDA Description AE Atlantic City Electric AEP American Electric Power APS Allegheny Power ATSI American Transmission Systems, Incorporated BGE Baltimore Gas and Electric Cleveland Cleveland Area ComEd Commonwealth Edison DAYTON Dayton Power and Light DEO&K Duke Energy Ohio and Kentucky DLCO Duquesne Light Company Dominion Dominion Virginia Power DPL Delmarva Power and Light DPLSOUTH Southern Portion of DPL Eastern Mid-Atlantic Global area PJM 500, JCPL, PECO, PSE&G, AE, DPL, RECO EKPC East Kentucky Power Cooperative JCPL Jersey Central Power and Light Met-Ed Metropolitan Edison Mid-Atlantic Global area PJM 500, Penelec, Meted, JCPL, PPL, PECO, PSE&G, BGE, Pepco, AE, DPL, UGI, RECO PECO PECO PENELEC Pennsylvania Electric PEPCO Potomac Electric Power Company PPL PPL Electric Utilities Corporation, UGI PSE&G Public Service Electric and Gas PS-NORTH Northern Portion of PSE&G Southern Mid-Atlantic Global area BGE and PEPCO Western Mid-Atlantic PJM 500, Penelec, Meted, PPL, UGI Western PJM APS, AEP, Dayton, DUQ, Comed, ATSI, DEO&K 114 PJM 2016 Regional Transmission Expansion Plan

123 Book 3: Planning Parameters CETO and CETL Development Prior to each base residual auction, the import capability requirement CETO and the import capability limit known as the CETL are calculated for each locational deliverability area, as described in Book 2, 4.2. An locational deliverability area with a CETL less than 1.15 times its CETO is modeled in RPM as an import-constrained locational deliverability area. The PJM Open Access Transmission Tariff also requires that each auction also specifically models the Mid-Atlantic, eastern Mid-Atlantic and southwestern Mid-Atlantic locational deliverability areas regardless of prior CETL/CETO tests or auction results. In addition, PJM has the discretion to model any locational deliverability area in the auction arising out of reliability concerns. PJM determines the CETO value for each locational deliverability area using a probabilistic model of the load and capacity located within each locational deliverability area. The model recognizes, among other factors, historical load variability, load forecast error, generating unit maintenance requirements and generating unit forced outage rates. A number of factors drive CETO value increases, including the following: The reverse of these factors would drive locational deliverability area CETO value decreases. A locational deliverability areas CETL value is impacted by changes in transmission system topology including the addition (or removal) of transmission facilities as well as by changes in a zone s load distribution profile. The addition or retirement of generation facilities impacts power flows, and consequently CETL values, as well. An increase in the locational deliverability area peak load A decrease in the amount of locational deliverability area capacity resources including generation, demand resource programs and energy efficiency A decrease in the availability factor of the locational deliverability area capacity resources. PJM 2016 Regional Transmission Expansion Plan 115

124 9 Book 3: Planning Parameters Table 9.2: CETO and CETL Comparison: Base Residual Auction Values 2018/2019 BRA 2019/2020 BRA Change CETO CETL CETL/CETO CETO CETL CETL/CETO CETO CETL LDA MW MW Ratio MW MW Ratio MW Percent MW Percent MAAC -1,900 7,883 NA -6,930 7,385 NA -5, EMAAC 2,850 8, ,580 8, , SWMAAC 5,160 9, ,920 9, , PS 5,800 7, ,590 7, PSNORTH 2,350 3, ,280 3, DPLSOUTH 1,360 1, ,230 1, PEPCO 3,470 7, ,870 6, ATSI 4,520 9, ,490 9, ATSI-Cleveland 3,340 4, ,390 5, ComEd 860 5, , BGE 4,550 6, ,060 6, PPL ,538 NA ,168 NA NA: Not applicable because CETO is negative Locational Deliverability Area CETO and CETL Values Table 9.2 compares the amount of transmission import capability into the locational deliverability area i.e., CETL and the CETO for each locational deliverability area as used in the 2018 / 2019 and 2019 / 2020 Base Residual Auctions. All but two of the 2019 / 2020 CETO values reported in Table 9.2 are lower than those for the 2018 / 2019 Delivery Year. The exceptions are the ATSI-Cleveland and PPL locational deliverability areas. The table shows increases and decreases in 2019 / 2020 CETL values relative to those for the 2018 / 2019 Delivery Year. Yet despite the decreases, all CETL / CETO ratios are greater in 2019 / Capacity Performance Early in 2016, PJM conducted a series of analyses to set the planning parameters necessary for PJM Markets staff to conduct the May 2016 RPM Base Residual Auction for the 2019 / 2020 Delivery Year. This RPM auction marked the second conducted under Capacity Performance provisions, allowing for two capacity product types: Capacity Performance and base capacity. PJM introduced the Capacity Performance product into the RPM capacity market structure in response to concerns regarding poor generator performance under extreme winter weather conditions. The chief objective has been to improve generator availability and enhance operational performance of all capacity resources, particularly during peak load periods. Base Capacity Constraint The second auction under capacity performance rules was conducted in May 2016, for the 2019 / 2020 Delivery Year. This was the last auction in which the base capacity product was allowed to participate. Beginning June 1, 2020 (2020 / 2021 Delivery Year), the base capacity product will be phased out at which point Capacity Performance will become the sole RPM product. Resource Availability The base capacity constraint was introduced because base capacity resources do not provide the same availability as Capacity Performance resources. Thus, they do not provide the same reliability value. Furthermore, the availability of Base capacity resources varies by resource type: while demand resources and energy efficiency resources are summer-only products, generation 116 PJM 2016 Regional Transmission Expansion Plan

125 Book 3: Planning Parameters 9 resources are expected to be available throughout the entire delivery year subject to non-performance penalties during the summer. The constraint must reflect this resource availability difference. In previous rulings, FERC has found that PJM s practice of increasing loss-of-load expectation (LOLE) risk by 10 percent (from the base 1 in 10 LOLE) to facilitate the commitment of lessavailable resources, to be an acceptable level of risk. In that same vein, PJM developed a procedure to compute a necessary base capacity constraint that divides that 10 percent LOLE increase evenly between 1) base capacity demand resources and energy efficiency and 2) base capacity generation. Setting Constraints Base capacity constraint is set at the combined amount of base capacity generation, demand resources and energy efficiency that produces no more than a 10 percent LOLE increase. And, the base capacity demand resource constraint is set at the amount of demand resources and energy efficiency that produces no more than a five percent LOLE increase. Both constraints are computed for the RTO and for the locational deliverability areas modeled in RPM and are stated as a percentage of the corresponding unrestricted annual peak load forecast Reserve Requirements Parameters The installed reserve margin (IRM) and forecast pool requirement (FPR) represent the level of capacity reserves needed to satisfy the PJM reliability criterion of a LOLE not exceeding one occurrence in ten years. The IRM and FPR represent the same level of required reserves but are expressed in different terms. The IRM expresses required installed capacity reserve as a percent Table 9.3: Reserve Requirement Comparison: Base Residual Auctions Reserve Requirement Parameters 2018/2019 BRA 2019/2020 BRA Delta Installed Reserve Margin 15.70% 16.50% 0.80% Pool Wide 5-Year Average EFORd 6.35% 6.60% 0.25% Forecast Pool Requirement of forecasted annual peak load. The FPR, when multiplied by forecasted annual peak load, provides total unforced capacity required. The FPR is equal to (1 + IRM) times (1 PJM AverageEFORd). Outside of Management Control Events PJM introduced outside of management control (OMC) events into the equivalent forced outage rate demand (EFORd) computation beginning in This gave generation owners the option to classify some forced outages as outside plant management control. Examples include acts of nature such as tornadoes and ice storms, strikes or labor disputes, grid connection or substation failure, among others. Forced outages associated with OMC events were then subtracted from the unit s EFORd computation yielding a performance metric called XEffective Forced Outage Rate on Demand. As with the EFORd metric which preceded it, the average XEFORd of the generating units in the reserve requirement study case for a given year was used to compute the FPR. FPR is used to establish target capacity levels for RTO and locational deliverability areas in RPM auctions. The introduction of the Capacity Performance product eliminates OMC events. Consequently, the XEFORd metric is also eliminated and the FPR under capacity performance rules is computed by using the average EFORd of the generating units in Reserve Requirement Study cases. Table 9.3 compares the IRM and FPR for the RTO for the 2018/2019 and 2019/2020 Base Residual Auction. Demand Resources Prior to delivery year 2018 / 2019, the load management and energy efficiency capacity values in RPM were determined by using a demand resource factor. With the introduction of Capacity Performance, the demand resource factor is phased out. As part of PJM s 2014 winter weather event evaluation, PJM assessed the role of demand resources in meeting the region s capacity needs and found significant value in available year-round capacity load reductions. However, the demand resources PJM called upon had no obligation to perform and reduced load solely on a voluntary basis. The significant value provided by demand resources during these winter events and the lack of performance obligation demonstrated a need to shift them to Capacity Performance Resources in parallel with the transition for generation. As such, load management and energy efficiency Capacity Performance Resources are permitted for the 2018/2019 and 2019/2020 Delivery Years, as base capacity resources. Starting with the 2018/2019 Delivery Year, PJM will determine the unforced capacity value of demand resources, whether base capacity resources or Capacity Performance Resources and eliminate the step of multiplying that product by the demand resource factor. PJM 2016 Regional Transmission Expansion Plan 117

126 9 Book 3: Planning Parameters 118 PJM 2016 Regional Transmission Expansion Plan

127 Book 3: Clean Power Plan Reliability Studies 10: Clean Power Plan Reliability Studies PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV : Scenario Studies The U.S. Environmental Protection Agency (EPA) issued its final Clean Power Plan (CPP) on August 3, 2015, limiting carbon dioxide emissions from existing power generation resources. The proposed federal plan for states set forth rules that would allow for regional mass-based or rate-based emissions trading. In light of the EPA s rule, the Organization of PJM States, Inc. (OPSI) requested that PJM conduct an economic and reliability analysis as follow-up to the one completed in 2015 on the proposed CPP. In response to the OPSI s request, PJM markets staff conducted scenario studies in 2016, per the evaluation process summarized in Figure That evaluation examined potential market outcomes and reliability impacts under a reference scenario without CPP in place and a number of possible compliance pathways that states may choose to implement, as discussed in the following reports: Figure 10.1: CPP Evaluation Process Inputs External Generator Capital and Maintenence Costs Unit Operation Characteristics Fuel Prices Environmental Emissions Prices (NO X, SO 2, RGGI-CO 2 ) Wind and Solar Shapes Policy & Regulation CO 2 Emissions Constraints Renewable Portfolio Standards Federal Investment Tax Credit/Production Tax Credit Resource Adequacy Long-Term Markets Model Processes Short-Term Markets Operations Model Outputs Resource Mix Emission Market Price Renewable Energy Credit Long-Term Energy Market Price Transmission Congestion Nodal Market Prices Emissions Quantity and Market Price Fuel Supply Mix Interface Limits PJM Report, EPA s Final Clean Power Plan Compliance Pathways Economic and Reliability Analysis, September 1, 2016: notices/clean-power-plan/ cpp-compliance-assessment.ashx Load Forecast BTM Solar Demand Response Energy Efficiency Transmission Planning Power Flow Cases Transmission Contingencies Voltage Limits Reliability Model Deliverability Study Limits Deliverability Study Thermal/Voltage Constraints Loss of Load Expectation PJM 2016 Regional Transmission Expansion Plan 119

128 10 Book 3: Clean Power Plan Reliability Studies September 15, 2016 TEAC meeting presentation summarizing the final report: committees/teac/ / clean-power-plan-teac-presentation.ashx. Results of the economic analysis identified generation entry and exit scenarios that became input to RTEP process power flow load deliverability, generation deliverability and common mode tower contingency studies conducted in Specifically, those power flow studies tested a 2025 study year PJM bulk electric system model power flow case to identify reliability criteria violations driven by generation exit and entry under CPP economic scenarios. Reliability Analyses Fundamentally, transmission delivers power from point of generation to point of consumption. An area that cannot meet its load-serving requirement from internally generated power whether an individual locational deliverability area or the PJM area as a whole must import it. Transmission lines become more heavily loaded to the degree that generation is removed from an area and not replaced with the same quantity MW at the same location. If either location or quantity differ from that originally there, transmission flows are altered. PJM RTEP analyses begun in 2016 focused on identifying potential reliability criteria violations on monitored facilities at 230 kv and above for a 2025 study year case and will continue into Only extra high voltage transmission lines 230 kv and above that exceeded their conductor limits were identified given that they typically justify the need for higher capacity, long lead-time transmission projects like those at 500 kv and higher voltages. CPP reliability scenario study scope has included RTEP process load deliverability, generator deliverability and common mode analyses as described in Book 2, 4.2. Generator deliverability tests have examined generation patterns across the PJM footprint to determine if they could be delivered under contingency conditions involving either single breaker-to-breaker events or double circuit tower line outages. Results to date have shown that the two CPP scenarios examined are not anticipated to have significantly higher impact to system reliability under the generator deliverability test than the reference scenario (without CPP). In 2017, PJM will continue its reliability analysis by performing load deliverability studies for several CPP scenarios, focusing on load deliverability areas whose forecasted CETO exceed forecasted CETL values. PJM will also conduct power-voltage (P-V) curve analysis on CPP scenarios to identify maximum transfer levels on the AP-South interface. PJM conducts P-V analysis to examine potential voltage collapse phenomena that is more rigorous than what NERC and regional voltage magnitude and voltage drop criteria violations may indicate, as described in Book 2, 4.3. Reliability analyses are expected to be completed and presented in the first quarter of PJM and MISO are also conducting interregional market efficiency assessments of congestion impacts. Resource Neutral PJM provides CPP scenario study information as an independent source of subject matter expertise. PJM takes no policy position on the EPA s proposed CPP. PJM does not advocate particular energy or environmental policies, forecast market outcomes or advocate any replacement strategies driven by them. PJM s primary focus is reliability, followed by the operation of efficient and non-discriminatory electricity markets in which PJM is resource neutral. PJM does not forecast market outcomes but rather models outcomes based on specific sets of assumptions. PJM will continue to monitor federal environmental policy. The scope of PJM regional and interregional studies will be revised accordingly. NOTE: Initial CPP reliability scenario study results to date were presented at the January and February 2017 PJM Transmission Expansion Advisory Committee (TEAC) meetings: committees/teac.aspx. 120 PJM 2016 Regional Transmission Expansion Plan

129 Book 3: Subregion Summaries 11: Subregion Summaries PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV : Mid-Atlantic PJM Summary Map 11.1: Locational Deliverability Areas RTEP Context PJM operates the bulk electric system transmission facilities (and others monitored at lower voltage levels) throughout PJM s Mid-Atlantic Subregion, shown in Map Systems include those of Atlantic City Electric Company (AEC), Baltimore Gas and Electric (BGE), Delmarva Power and Light (DPL), Jersey Central Power and Light (JCPL), Metropolitan Edison Company (Met-Ed), Neptune, Old Dominion Electric Corporation (ODEC), PECO Energy (PECO), Pennsylvania Electric Company (PENELEC), PEPCO, PPL Electric Utilities Corporation (PPL), Public Service Electric and Gas (PSE&G), Rockland Electric (Rockland) and UGI Corporation (UGI). The Neptune Regional Transmission System interconnects with PJM at Sayreville substation in Northern New Jersey. The Linden Variable Frequency Transformer (VFT) interconnects with PJM at the Linden 230 kv substation in New Jersey. A 15-year long-term planning horizon allows PJM to consider the aggregate effects of many drivers. At its inception in 1997, PJM s RTEP consisted mainly of system enhancements driven by load growth and generating resource interconnection requests. Today, PJM s RTEP process identifies one optimal, comprehensive set of solutions to resolve baseline reliability PJM 2016 Regional Transmission Expansion Plan 121

130 11 Book 3: Subregion Summaries criteria violations, operational performance issues and congestion constraints as well as network reinforcements to accommodate generator interconnection and other new queued service requests. Specific system enhancements are justified to deliver needed power to distant load centers as well to meet local, subregional needs. Common mode contingency analysis Short circuit analysis Baseline stability analysis Transmission Owner criteria tests Stakeholder Participation Subregional RTEP committees increase the opportunity for direct stakeholder participation in the planning process from initial assumption setting stages through review of planning analyses, violations and alternative transmission expansion plans. Each subregional RTEP committee provides a more local forum for surfacing and considering planning issues. Interested parties can access PJM Mid-Atlantic Subregional RTEP Committee information from PJM s website: Baseline Projects Baseline transmission projects are system enhancements identified through analysis of operational performance issues, market efficiency studies and conventional NERC criteria tests that include the following: Base case thermal and voltage analysis Load deliverability thermal and voltages analysis Generation deliverability thermal analysis N-1-1 thermal and voltage analysis Contingency analysis includes all bulk electric system facilities, tie lines to neighboring systems, critical neighboring system facilities and lower voltage facilities operated by PJM. Baseline projects with cost estimates greater than $5 million approved by the PJM Board in 2016, are listed in Table 11.1 and shown on Map NOTE: Additional detail including current status for each baseline, network and supplemental project can be found on PJM s website: com/planning/rtep-upgrades-status/constructstatus.aspx. NOTE: *Designated Entity: Once the PJM Board approves a baseline project recommended by PJM staff from among proposals received during an RTEP Window, that project s developer is assigned Designated Entity status. The Designated Entity then bears responsibility for project construction, ownership, operation and financing. A project may consist of more than one element each of which can have its own developer. 122 PJM 2016 Regional Transmission Expansion Plan

131 Book 3: Subregion Summaries 11 Table 11.1: Mid-Atlantic Baseline Subregional Projects Map ID Baseline Load Growth/ Deliverability & Reliability Mid-Atlantic Baseline Subregional Projects Project Required Cost Designated ID Project Date ($M) Entity* 1 b2716 Add a 200 MVAR shunt reactor at Lackawanna 500 kv substation p 12/1/2018 $10.00 PPL 12/3/ b2722 Reconductor the one mile Bergen-Bergen GT 138 kv circuit (B-1302) p 10/30/2016 $6.50 PSE&G 12/8/ b Tap the Conemaugh-Hunterstown 500 kv line and create new Rice 500 kv and 230 kv stations. Install two 500/230 kv transformers, operated together. Congestion Relief- Economic p Operational Performance Generator Deactivation TO Criteria Violation 6/1/ TEAC Review Transource 6/9/2016 b Tie in new Rice substation to Conemaugh-Hunterstown 500 kv p 6/1/2020 PENELEC 6/9/2016 b Upgrade terminal equipment at Conemaugh 500 kv: on the Conemaugh-Hunterstown 500 kv circuit b Upgrade terminal equipment at Hunterstown 500 kv: on the Conemaugh-Hunterstown 500 kv circuit b Build new 230 kv double circuit line between Rice and Ringgold 230 kv, operated as a single circuit. b Tap the Peach Bottom TMI 500 kv line and create new Furnace Run 500 kv and 230 kv stations. Install two 500/230 kv transformers, operated together. p p p p 6/1/2020 PENELEC 6/9/2016 $ /1/2020 ME 6/9/2016 6/1/2020 Transource 6/9/2016 6/1/2020 Transource 6/9/2016 b Tie in new Furnace Run substation to Peach Bottom-TMI 500 kv p 6/1/2020 PECO 6/9/2016 b Upgrade terminal equipment and required relay communication at Peach Bottom 500 kv: on the Peach Bottom-TMI 500 kv circuit b Upgrade terminal equipment and required relay communication at TMI 500 kv: on the Peach Bottom-TMI 500 kv circuit b Build new 230 kv double circuit line between Furnace Run and Conastone 230 kv, operated as a single circuit. b Conastone 230 kv substation tie-in work (install a new circuit breaker at Conastone 230 kv and upgrade any required terminal equipment to terminate the new circuit) b Reconductor/Rebuild the two Conastone-Northwest 230 kv lines and upgrade terminal equipment on both ends p p p p p 6/1/2020 PECO 6/9/2016 6/1/2020 ME 6/9/2016 $ /1/2020 Transource 6/9/2016 6/1/2020 BGE 6/9/2016 6/1/2020 BGE 6/9/ b2755 Build a third 345 kv source into Newark Airport p 6/1/2018 $43.00 PSE&G 7/14/ b2756 Install 2 percent reactors at Martins Creek 230 kv p 6/1/2018 $10.00 PPL 8/11/ b2767 b Upgrade substation equipment at Conastone 500 kv (on the Peach Bottom-Conastone 500 kv circuit) to increase facility rating to MVA normal and 3,525 MVA emergency b Upgrade substation equipment at Peach Bottom 500 kv (on the Peach Bottom- Conastone 500 kv circuit) to increase facility rating to 2,826 MVA normal and 3,525 MVA emergency Construct a new 345 kv breaker string with three (3) 345 kv breakers at Homer City and move the North autotransformer connection to this new breaker string p p 6/1/2021 BGE 10/6/2016 $7.00 6/1/2021 PECO 10/6/2016 p 6/1/2021 $6.60 PENELEC 10/6/2016 PJM 2016 Regional Transmission Expansion Plan 123

132 11 Book 3: Subregion Summaries Map 11.2: Mid-Atlantic Baseline Subregional Projects 124 PJM 2016 Regional Transmission Expansion Plan

133 Book 3: Subregion Summaries Network Projects PJM s RTEP also includes system reinforcements identified through interconnection process system impact studies. These transmission projects are necessary to interconnect new generation, merchant transmission facilities and other new services. Direct connection network projects are transmission enhancements that deliver power to a defined point of interconnection. Non-direct connection network projects mitigate transmission system impacts beyond the point of interconnection. Network projects with cost estimates greater than $5 million approved by the PJM Board in 2016, are listed in Table 11.2 and shown on Map Table 11.2: Mid-Atlantic Network Subregional Projects Mid-Atlantic Network Subregional Projects Map ID Project ID Project Generation Interconnection Merchant Transmission Interconnection Long-term Firm Transmission Service Required Date Cost ($M) TO Zone(s) 1 n3907 Install a second 900 MVA kv transformer and associated equipment. Y /4/2015 $25.00 PPL 10/6/ n3908 Rebuild the Eldred-Frackville 230 kv line using double 1590 ACSR conductor (12 miles) Y /4/2015 $34.62 PPL 10/6/ n3911 Replace the substation conductors with 1,590 ACSR. Replace two breakers, 4 switches and associated equipment with 3,000 amp rated equipment TEAC Review Y /4/2015 $71.77 PPL 10/6/ n4356 Install new 500/230 kv substation on of Y2-015 Y /1/2017 $ PPL 10/6/ n4357 Expand the W kv switchyard to accommodate the connection to Catawissa Y /1/2017 $5.17 PPL 10/6/ n4358 Tie in W kv switchyard to Catawissa/Frackville 230 kv line Y /1/2017 $10.42 PPL 10/6/ n n4660 Rebuild 4.5 miles of the conductor using 556 ACSR, remove 110 structures, install 55 new conductors, remove 24,000 ft of three 336 MCM 30/7 ACSR. Adding a new 500/345 kv transformer and constructing a 500 kv yard in breaker and a half layout is required. The proposed 500 kv yard will tap into the existing Keystone-Conemaugh 500 kv line. Z /31/2017 $13.50 PPL 10/6/2016 AA /1/2015 $33.85 PENELEC 10/6/ n4682 Construct new 500 kv three breaker ring bus substation to connect the AA1-076 project. AA /1/2021 $15.24 PENELEC 10/6/ n4698 Build new 230 kv three breaker ring bus for the AA1-144 project AA /29/2017 $7.89 PENELEC 10/6/ n n4929 Construct a new three breaker ring bus interconnection substation near the South Reading-North Boyertown 230 kv Line; Location South Reading-North Boyertown 230 kv Line Building a new 345 kv string on the east side of the substation, remove existing North Transformer breaker, and re-terminating Transformer connection on new 345 kv string are required. AA /1/2019 $7.63 ME 10/6/2016 AA /31/2019 $6.67 PENELEC 10/6/2016 PJM 2016 Regional Transmission Expansion Plan 125

134 11 Book 3: Subregion Summaries Map 11.3: Mid-Atlantic Network Subregional Projects 126 PJM 2016 Regional Transmission Expansion Plan

135 Book 3: Subregion Summaries Supplemental Projects Prior to FERC Order No. 890 in 2008, supplemental projects were referred to as Transmission Owner Initiated or TOI Projects. A Supplemental Project is not required for compliance with system reliability, operational performance or economic criteria, as determined by PJM. Supplemental projects frequently address aging infrastructure, provide support to serve underlying systems and add connections to new, large load customers. PJM reviews supplemental projects to ensure that they do not introduce other reliability criteria violations. And, while not subject to PJM Board approval, they are included in PJM s RTEP. Transmission Owners submitted a number of supplemental projects throughout Projects with cost estimates greater than $5 million are listed in Table 11.3 and shown on Map Table 11.3: Mid-Atlantic Supplemental Subregional Projects Map ID Project ID Project 1 s Relocate the Bergen 138 kv 40P and 90P breakers to the Bergen generation station and install additional one 138 kv breaker Mid-Atlantic Supplemental Subregional Projects Required Date Cost ($M) TO Zone(s) 2016 TEAC Review 12/31/2017 $6.16 PSE&G 7/26/ s1097 Upgrade the Otter Creek 230 kv Yard to three bays breaker and a half arrangement, and replace relays. 12/31/2026 $10.70 PPL 1/7/ s Montour-Build Bay 5 and 6 to standard breaker and a half configuration and Re-terminate the Montour-Susquehanna T kv Line into Bay 5 and the Montour-Susquehanna 230 kv Line into Bay 6. 12/31/2018 PPL 1/7/2016 s Upgrade relaying at Susquehanna 230 kv Switchyard and Susquehanna T10 Switchyard. 12/31/2018 $6.49 PPL 1/7/2016 s Remove two Montour 230 kv circuits breakers in Bay 1 and Bay 2. 12/31/2018 PPL 1/7/ s1100 Rebuild the existing Foxhill-Shawnee 230 kv line (Approximately 8.25 Miles). 12/31/2020 $24.80 PPL 1/7/ s1101 Rebuild the existing Shawnee-Bushkill 230 kv line (Approximately 2.2 Miles). 5/31/2020 $6.80 PPL 1/7/ s1102 Construct a new 230 kv GIS yard at Sunbury Substation. 4/30/2018 $25.00 PPL 1/7/ s1104 Upgrade Alburtis 500 kv Switchyard by replacing old CBs, Cap bank, installing new control cubicle. 12/31/2017 $6.60 PPL 1/7/ s1106 s Build new 230 kv Line from Dauphin to New Harrisburg kv Substation. 5/31/2026 PPL 1/7/2016 $88.00 s Build new UG 230 kv Line from West Shore to New Harrisburg Substation. 5/31/2026 PPL 1/7/2016 Build new kv Substation and associated transmission work (tap Sunbury-Susquehanna 500 kv and Colombia-Frackville 230 kv). 12/31/2020 $95.00 PPL 1/7/ s1143 Add second circuit to approximately 23.7 miles of the Susquehanna-Jenkins 230 kv line using 1590 ACSR conductor 5/31/2018 $12.50 PPL 6/9/ s1151 Build a new 13 kv class-h substation in Kingsland with two new 230/13 kv transformers 5/31/2019 $29.60 PSE&G 7/26/ s1154 Reconductor the PPL portion (8.5 miles) of the Face Rock-Five Forks 115 kv tie-line as a three-conductor line with a modern high capacity conductor. Evaluate all lattice steel towers for condition and determine structure member repair and remediation 12/31/2019 $10.80 PPL 7/26/ s1177 Install Stop Joints on South Mahwah-Waldwick 345 kv circuit J /23/2017 $6.00 PSE&G 11/3/2016 PJM 2016 Regional Transmission Expansion Plan 127

136 11 Book 3: Subregion Summaries Map 11.4: Mid-Atlantic Supplemental Subregional Projects 128 PJM 2016 Regional Transmission Expansion Plan

137 Book 3: Subregion Summaries 11 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 11.1: Western PJM Summary RTEP Context PJM operates PJM operates the bulk electric system transmission facilities (and others monitored at lower voltage levels) throughout PJM s western subregion shown in locational deliverability Areas Map Systems include those of Allegheny Power (AP), American Electric Power (AEP), American Transmission Systems, Inc. (ATSI), Commonwealth Edison (ComEd), Dayton Power and Light (Dayton), Duquesne Light Company (DLCO), Duke Energy Ohio and Kentucky (DEO&K) and Eastern Kentucky Power Cooperative (EKPC). A 15-year long-term planning horizon allows PJM to consider the aggregate effects of many drivers. At its inception in 1997, PJM s RTEP consisted mainly of system enhancements driven by load growth and generating resource interconnection requests. Today, PJM s RTEP process identifies one optimal, comprehensive set of solutions to resolve baseline reliability criteria violations, operational performance issues and congestion constraints as well as network reinforcements to accommodate generator interconnection and other new queued service requests. Specific system enhancements are justified to deliver needed power to distant load centers as well to meet local subregional needs. Map 11.5: Locational Deliverability Areas PJM 2016 Regional Transmission Expansion Plan 129

138 11 Book 3: Subregion Summaries Stakeholder Participation Subregional RTEP committees increase the opportunity for direct stakeholder participation in the planning process from initial assumption setting stages through review of planning analyses, violations and alternative transmission expansion plans. Each subregional RTEP committee provides a more local forum for surfacing and considering planning issues. Interested parties can access PJM Western Subregional RTEP Committee information from PJM s website: committees-and-groups/committees/srrtep-w.aspx. Contingency analysis includes all bulk electric system facilities, tie lines to neighboring systems, critical neighboring system facilities and lower voltage facilities operated by PJM. Baseline projects with cost estimates greater than $5 million approved by the PJM Board in 2016, are listed in Table 11.4 and shown on Map Baseline Projects Baseline transmission projects are system enhancements identified through analysis of operational performance issues, market efficiency studies and conventional NERC criteria tests that include the following: Base case thermal and voltage analysis Load deliverability thermal and voltages analysis Generation deliverability thermal analysis N-1-1 thermal and voltage analysis Common mode contingency analysis Short circuit analysis Baseline stability analysis Transmission Owner criteria tests NOTE: Additional detail including current status for each baseline, network and supplemental project can be found on PJM s website: com/planning/rtep-upgrades-status/constructstatus.aspx. 130 PJM 2016 Regional Transmission Expansion Plan

139 Book 3: Subregion Summaries 11 Table 11.4: Western Baseline Subregional Projects Western Baseline Subregional Projects Map ID Project ID 1 b2721 Project Goodings Grove-Balance Station Load (swap bus positions for 345 kv lines 1312 and and 345 kv lines and 11622) and replace 138 kv bus tie 2-3 Baseline Load Growth/ Deliverability & Reliability Congestion Relief - Economic Operational Performance Generator Deactivation TO Criteria Violation Required Date Cost ($M) Designated Entity* 2016 TEAC Review 6/1/2020 $5.40 ComEd 1/7/2016 Build new 345/138 kv Lake Avenue substation w/breaker and a half high side (2 strings), two 345/138 kv transformers and breaker and a half (2 strings) low side b2725 4/16/2016 ATSI 1/7/ (138 kv). Substation will tie Avon-Beaver 345 kv No. 1 / No. 2 and $40.28 Black River-Johnson No. 1 / No. 2 lines b Replace the Murray 138 kv breaker 453-B-4 with 40 ka breaker. 4/16/2016 ATSI 1/7/ b2728 Mitigate sag limitations on Loretto-Wilton Center 345 kv Line and replace station conductor at Wilton Center 6/1/2019 $11.50 ComEd 2/11/2016 Convert the Sunnyside-East Sparta-Malvern 23 kv sub-transmission network to 69 kv. 4 b2731 8/1/2016 $5.70 AEP 2/4/2016 The lines are already built to 69 kv standards. b Cut-in of line Tazewell-Kendall 345 kv line into Dresden 6/1/2020 ComEd 2/11/ $20.40 b Raise towers to remove the sag limitations on 345 kv line 8012 Pontiac-Loretto 6/1/2020 ComEd 2/11/ b Reconfigure the Ringgold 230 kv substation to double bus double breaker scheme 6/1/2020 APS 6/9/2016 b Replace the two Ringgold 230/138 kv transformers 6/1/2020 $59.02 APS 6/9/2016 b Rebuild/Reconductor the Ringgold-Catoctin 138 kv circuit and upgrade terminal equipment on both ends 6/1/2020 APS 6/9/2016 b b Retire Betsy Layne 138/69/43 kv station and replace it with the greenfield Stanville station about a half mile north of the existing Betsy Layne station Relocate the Betsy Layne capacitor bank to the Stanville 69 kv bus and increase the size to 14.4 MVAr 12/1/2016 AEP 1/24/2017 $ /1/2016 AEP 1/24/2017 NOTE: *Designated Entity: Once the PJM Board approves a baseline project recommended by PJM staff from among proposals received during an RTEP Window, that project s developer is assigned Designated Entity status. The Designated Entity then bears responsibility for project construction, ownership, operation and financing. A project may consist of more than one element each of which can have its own developer. PJM 2016 Regional Transmission Expansion Plan 131

140 11 Book 3: Subregion Summaries Table 11.4: Western Baseline Subregional Projects (Continued) Western Baseline Subregional Projects Map ID 8 8 Project ID b b b b b b b b Project Replace existing George Washington station 138 kv yard with GIS 138 kv breaker and a half yard in existing station footprint. Install 138 kv revenue metering for new IPP connection. Replace Dilles Bottom 69/4 kv Distribution station as breaker and a half 138 kv yard design including AEP Distribution facilities but initial configuration will constitute a three breaker ring bus. Connect two 138 kv six-wired circuits from Point A (currently de-energized and owned by First Energy) in circuit positions previously designated Burger No.1 and Burger No kv. Install interconnection settlement metering on both circuits exiting Holloway St Double capacity for six wire Burger-Cloverdale No kv line and connect at Holloway and Point A Double capacity for six wire Burger-Longview 138 kv line and connect at Holloway and Point A Build double circuit 138 kv line from Dilles Bottom to Point A. Tie each new AEP circuit in with a six wired line at Point A. This will create a Dilles Bottom-Holloway 138 kv circuit and a George Washington-Holloway 138 kv circuit. Retire line sections (Dilles Bottom-Bellaire and Moundsville-Dilles Bottom 69 kv lines) south of First Energy 138 kv line corridor, near Point A. Tie George Washington- Moundsville 69 kv circuit to George Washington-West Bellaire 69 kv circuit. Rebuild existing 69 kv line as double circuit from George Washington-Dilles Bottom 138 kv. One circuit will cut into Dilles Bottom 138 kv initially and the other will go past with future plans to cut in. Baseline Load Growth/ Deliverability & Reliability Congestion Relief - Economic Operational Performance Generator Deactivation TO Criteria Violation Required Date 1/1/2019 Cost ($M) Designated Entity* 2016 TEAC Review AEP 12/15/2016 1/1/2019 AEP 12/15/2016 $ /1/2019 AEP 12/15/2016 1/1/2019 ATSI 12/15/2016 1/1/2019 ATSI 12/15/2016 1/1/2019 AEP 12/15/2016 1/1/2019 $25.02 AEP 12/15/2016 1/1/2019 AEP 12/15/ b2776 Reconductor the entire Dequine-Meadow Lake 345 kv circuit No. 2 6/1/2021 $6.60 AEP 11/3/ b2777 Reconductor the entire Dequine-Eugene 345 kv circuit No. 1 6/1/2021 $22.19 AEP 11/3/ PJM 2016 Regional Transmission Expansion Plan

141 Book 3: Subregion Summaries 11 Map 11.6: Western Baseline Subregional Projects PJM 2016 Regional Transmission Expansion Plan 133

142 11 Book 3: Subregion Summaries Network Projects PJM s RTEP also includes system reinforcements identified through interconnection process system impact studies. These transmission projects are necessary to interconnect new generation, merchant transmission facilities and other new services. Direct connection network projects are transmission enhancements that deliver power to a defined point of interconnection. Non-direct connection network projects mitigate transmission system impacts beyond the point of interconnection. Network projects with cost estimates greater than $5 million approved by the PJM Board in 2016, are listed in Table 11.5 and shown on Map Supplemental Projects Prior to FERC Order No. 890 in 2008, Supplemental Projects were referred to as Transmission Owner Initiated or TOI Projects. A Supplemental Project is not required for compliance with system reliability, operational performance or economic criteria, as determined by PJM. Supplemental projects frequently address aging infrastructure, provide support to serve underlying systems and add connections to new, large load customers. PJM reviews supplemental projects to ensure that they do not introduce other reliability criteria violations. And, while not subject to PJM Board approval, they are included in PJM s RTEP. Transmission Owners submitted a number of supplemental projects throughout Projects with cost estimates greater than $5 million are listed in Table 11.6 and shown on Map PJM 2016 Regional Transmission Expansion Plan

143 Book 3: Subregion Summaries 11 Table 11.5: Western Network Subregional Projects Western Network Subregional Projects Map ID Project ID Project Generation Interconnection Merchant Transmission Interconnection Long-term Firm Transmission Service Required Date Cost ($M) TO Zone(s) 1 n1467 Rebuild the circuit between Lincoln and Anthony Substations i.e. 17 miles of 138 kv circuit T131 10/30/2010 $26.00 AEP 10/6/ n n n1504 Lincoln-Sterling-Construct a three-breaker 138 kv ring bus interconnection substation in the circuit between Project S73 and North Delphos Rebuild, reconductor and replace towers in the approximately 8-mile 138 kv circuit between Haviland and Milan Substations Rebuild, reconductor and replace towers of approximately 17-mile 138 kv circuit between Lincoln and North Delphos Substations 2016 TEAC Review T131 10/31/2010 $5.00 AEP 10/6/2016 T131 10/31/2010 $12.00 AEP 10/6/2016 T131 10/31/2010 $26.00 AEP 10/6/ n3528 Install a new four-breaker 765 kv at the X1-020 Tap switching station laid out in a breaker and one-half arrangement including associated disconnect switch bus work, SCADA and 765 kv X /1/2015 $30.09 AEP 10/6/2016 revenue metering. 6 n4001 Install an extra three 345 kv breakers at TSS 92 Mt. Pulaski substation X /31/2013 $9.00 ComEd 10/6/ n4348 Mitigate line sag limitations to achieve full conductor thermal capability on Loretto-Wilton Center 345 kv line. W /1/2017 $16.70 ComEd 10/6/ n4349 Reconductor or rebuild AEP portion of the University Park-Olive 345 kv line. Also upgrade risers and relays W /31/2016 $45.00 AEP 10/6/ n4387 Build new 345 kv five-breaker ring bus substation to interconnect project Z2-028 Z /1/2017 $11.91 ATSI 10/6/ n4611 Build new 345 kv three-breaker ring bus substation for the AA1-044 project. AA /1/2018 $7.47 ATSI 10/6/ n Reconductor the Rockwood-Somerset 115 kv line and upgrade terminal equipment at Rockwood and Somerset. AA /25/2017 $10.89 APS 10/6/2016 n Replace Keystone 500 kv breaker No. 14 CABOT from 40 ka to 63 ka breaker AA /29/2017 $6.65 APS 10/6/2016 n Replace Keystone 500 kv breaker No. 16 CABOT from 40 ka to 63 ka breaker AA /29/2017 APS 10/6/2016 n Replace Keystone 500 kv breaker No. 1 from 40 ka to 63 ka breaker AA /29/2017 APS 10/6/2016 n Replace Keystone 500 kv breaker Juniata from 40 ka to 63 ka breaker AA /29/2017 APS 10/6/2016 n Replace Keystone 500 kv breaker No. 3 TRANSFO from 40 ka to 63 ka breaker AA /29/2017 APS 10/6/ n4694 Build new 345 kv, three-breaker ring bus for the AA1-123 project. AA /1/2019 $8.36 ATSI 10/6/ n4727 Install new AA kv Interconnection substation AA /31/2017 $18.00 ComEd 10/6/ n n5021 Construct Interconnection Substation with Revenue Metering between Dumont and Greentown 765 kv Circuit Construct a new six breaker 345 kv switching station laid out in a breaker and half arrangement including installation of associated disconnect switches, bus work, SCADA and 345 kv revenue metering. X /1/2015 $30.09 AEP 10/6/2016 AA /1/2020 $14.00 AEP 10/6/2016 PJM 2016 Regional Transmission Expansion Plan 135

144 11 Book 3: Subregion Summaries Map 11.7: Western Network Subregional Projects 136 PJM 2016 Regional Transmission Expansion Plan

145 Book 3: Subregion Summaries 11 Table 11.6: Western Supplemental Subregional Projects Map ID Project ID Project Western Supplemental Subregional Projects Required Date Cost ($M) TO Zone(s) 2016 TEAC Review 1 s1108 Replace the 345 kv circuit breaker at Electric Junction on Electric Junction-Wolf Crossing 345 kv line (line 1223). 12/31/2016 $8.30 ComEd 1/7/ s1115 Replace Northwest 138 kv bus ties 711, 713, 714, 716, 721, 723 & /31/2017 $11.70 ComEd 2/4/ s1116 Replace State Line 138 kv PAR on line 0705 with 300 MVA +/- 15 degree unit 6/1/2017 $8.30 ComEd 2/4/ s1117 Reconductor 138 kv line for 4.2 miles from Dixon to Dixon Tap, replace line circuit breaker at Dixon, replace bus tie circuit breaker and rehab bus 6/1/2017 $17.20 ComEd 2/4/ s1119 Replace Wayne 345/138/34.5 kv transformer TR81 and station conductor 12/31/2017 $7.70 ComEd 2/4/ s1121 Rebuild portions of 138 kv line for 19.4 miles from North Aurora to Waterman 2/26/2016 $24.80 ComEd 2/4/ s1122 Replace State Line 138 kv PAR on line 0702 with 300 MVA +/-15 degree unit 12/31/2016 $8.30 ComEd 2/4/ s s s s s1157 Cherry Valley-Replace 345/138 kv transformer TR82 high-side MOD with a circuit switcher, upgrade secondary conductor, replace 138 kv BT2-3 Construct a new 138 kv transmission network to support the retirement of AEP Ohio s deteriorated 23 kv distribution system in Washington County. Marietta North will build new 138 kv between South Caldwell and Devola stations Tap the existing AEP Delano-Scioto Trail 138 kv circuit, build a 138 kv ring bus station called Tuscany Station, and provide dual feeds to the customer. Construct a new kv substation Lamping connected to AEP s Kammer - Muskingum 345 kv circuit. Build a new 10 mile 138 kv circuit from Lamping to Blue Racer substation. Convert the existing 69 kv Lawyers Tap to 138 kv and construct a new 138 kv line from Brush Tavern to a new Lynbrook Station (retiring Lawyers Station) in order to provide two-way service to Brush Tavern, Lynbrook and George Street. 12/31/2017 $8.30 ComEd 2/4/2016 6/1/2021 $ AEP 2/4/2016 8/1/2017 $10.04 AEP 2/4/2016 6/1/2019 $40.00 AEP 2/4/2016 6/1/2017 $35.00 AEP 7/26/ s1158 Rebuild and upgrade approx. 32 miles of 69 kv line from Summerfield station to Glencoe station 6/1/2019 $37.20 AEP 7/26/ s1160 Construct a new kv substation Lamping, connected to AEP s Kammer-Muskingum 345 kv circuit. Build a new 24-mile 138 kv circuit from Lamping-Devola substation, serving the R.E.C. customer stations along the way. 6/1/2022 $68.00 AEP 7/26/ s1163 Rebuild the existing 3/0 ACSR Airport Rd-Newfoundland-Mazie 69 kv, line section using MCM ACSR/TW conductor 6/1/2021 $6.68 EKPC 7/26/ s1164 Rebuild the existing 4/0 ACSR Hope-Hillsboro 69 kv, line section using MCM ACSR/TW conductor 12/1/2020 $8.32 EKPC 7/26/ s1165 Rebuild the existing 1/0 ACSR Stephensburg-Hodgenville 69 kv, line section using MCM ACSR/TW conductor 12/1/2020 $5.88 EKPC 7/26/ s1168 Reconfigure 138 kv lines (Lancaster-Eleroy Tap) and (ESS B-427-Freeport) in the far western part of our system, and add breakers at Lancaster 6/1/2017 $8.60 ComEd 7/26/ s1169 Expand 138 kv Channahon West substation with five 138 kv circuit breakers and a new 138/34 kv TR 6/1/2017 $22.00 ComEd 7/26/ s1171 Reconfigure Bradley 138 kv substation to add 138 kv bus ties 1-2 and 3-4 and relocate lines 12/31/2017 $9.00 ComEd 7/26/ s1172 Refurbish and reconfigure Hegewisch 138 kv substation into a breaker-and-a-half configuration 12/31/2017 $38.00 ComEd 7/26/2016 PJM 2016 Regional Transmission Expansion Plan 137

146 11 Book 3: Subregion Summaries Map 11.8: Western Supplemental Subregional Projects 138 PJM 2016 Regional Transmission Expansion Plan

147 Book 3: Subregion Summaries 11 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 11.2: Southern PJM Summary Map 11.9: Locational Deliverability Areas RTEP Context PJM operates the bulk electric system transmission facilities (and others monitored at lower voltage levels) throughout PJM s southern subregion, shown in Map 11.9, and includes that of Dominion Virginia Power (Dominion) which operates in Virginia and northeastern North Carolina. A 15-year long-term planning horizon allows PJM to consider the aggregate effects of many drivers. At its inception in 1997, PJM s RTEP consisted mainly of system enhancements driven by load growth and generating resource interconnection requests. Today, PJM s RTEP process identifies one optimal, comprehensive set of solutions to resolve baseline reliability criteria violations, operational performance issues and congestion constraints as well as network reinforcements to accommodate generator interconnection and other new queued service requests. Specific system enhancements are justified to deliver needed power to distant load centers as well to meet local, subregional needs. Stakeholder Participation Subregional RTEP committees increase the opportunity for direct stakeholder participation in the planning process from initial assumption setting stages through review of planning analyses, violations and alternative transmission expansion plans. Each subregional RTEP committee provides a more local forum for surfacing and considering planning issues. Interested parties can access PJM Southern Subregional RTEP Committee information from PJM s website: PJM 2016 Regional Transmission Expansion Plan 139

148 11 Book 3: Subregion Summaries Baseline Projects Baseline transmission projects are system enhancements identified through analysis of operational performance issues, market efficiency studies and conventional NERC criteria tests that include the following: Base case thermal and voltage analysis Load deliverability thermal and voltages analysis Generation deliverability thermal analysis N-1-1 thermal and voltage analysis Common mode contingency analysis Short circuit analysis Baseline stability analysis Transmission Owner Criteria tests Contingency analysis includes all bulk electric system facilities, tie lines to neighboring systems, critical neighboring system facilities and lower voltage facilities operated by PJM. Baseline projects with cost estimates greater than $5 million approved by the PJM Board in 2016, are listed in Table 11.7 and shown on Map NOTE: Additional detail including current status for each baseline, network and supplemental project can be found on PJM s website: com/planning/rtep-upgrades-status/constructstatus.aspx. 140 PJM 2016 Regional Transmission Expansion Plan

149 Book 3: Subregion Summaries 11 Table 11.7: Southern Baseline Subregional Projects Map ID 1 Project ID Project Southern Baseline Subregional Projects Baseline Load Growth/ Deliverability & Reliability Congestion Relief- Economic Operational Performance Generator Deactivation TO Criteria Violation Required Date b Expand Perth substation and add a 115 kv four breaker ring. p 6/1/2017 b b b2729 Extend the Hickory Grove DP tap 0.28 miles to Perth and terminate it at Perth. Split Line No.31 at Perth and terminate it into the new ring bus with 2 breakers separating each of the line terminals to prevent a breaker failure from taking out both 115 kv lines. Optimal Capacitors Configuration: New 175 MVAR 230 kv capacitor bank at Brambleton substation, new 175 MVAR 230 kv capacitor bank at Ashburn substation, new 300 MVAR 230 kv capacitor bank at Shelhorn substation, new 150 MVAR 230 kv capacitor bank at Liber Cost ($M) Designated Entity* 2016 TEAC Review Dominion 12/1/2016 p 6/1/2017 Dominion 12/1/2016 $8.20 p 6/1/2017 Dominion 12/1/2016 p 12/1/2019 $8.98 Dominion 2/11/ b2744 Rebuild the Carson-Rogers Rd 500 kv circuit p 6/1/2020 $48.50 Dominion 5/12/ b b b Rebuild miles of existing line between Chesterfield-Lakeside 230 kv Rebuild Line No.137 Ridge Rd-Kerr Dam 115 kv, 8.0 miles, for 346 MVA summer emergency rating Rebuild Line No.1009 Ridge Rd-Chase City 115 kv, 9.5 miles, for 346 MVA summer emergency rating p 6/1/2020 $22.00 Dominion 5/12/2016 p 6/1/2018 Dominion 7/26/2016 $39.00 p 6/1/2018 Dominion 7/26/2016 b Install a 25 MVAR 115 kv capacitor bank at Ridge Road p 6/1/2018 Dominion 7/26/2016 *Designated Entity: Once the PJM Board approves a baseline project recommended by PJM staff from among proposals received during an RTEP Window, that project s developer is assigned Designated Entity status. The Designated Entity then bears responsibility for project construction, ownership, operation and financing. A project may consist of more than one element each of which can have its own developer. NOTE: PJM 2016 Regional Transmission Expansion Plan 141

150 11 Book 3: Subregion Summaries Map 11.10: Southern Baseline Subregional Projects 142 PJM 2016 Regional Transmission Expansion Plan

151 Book 3: Subregion Summaries Network Projects PJM s RTEP also includes system reinforcements identified through interconnection process system impact studies. These transmission projects are necessary to interconnect new generation, merchant transmission facilities and other new services. Direct connection network projects are transmission enhancements that deliver power to a defined point of interconnection. Non-direct connection network projects mitigate transmission system impacts beyond the point of interconnection. Network projects with cost estimates greater than $5 million approved by the PJM Board in 2016, are listed in Table 11.8 and shown on Map Table 11.8: Southern Network Subregional Projects Map ID Project ID 1 n n5070 Project Build 230 kv switching station (three breaker ring bus) and loop the 230 kv circuit between Fentress and Shawboro into the new switching station Build a new three breaker ring bus at Haslett substation Southern Network Subregional Projects Generation Interconnection Merchant Transmission Interconnection Long-Term Firm Transmission Service Cost ($M) TO Zone(s) AA $5.60 Dominion AA $5.66 Dominion PJM 2016 Regional Transmission Expansion Plan 143

152 11 Book 3: Subregion Summaries Map 11.11: Southern Network Subregional Projects 144 PJM 2016 Regional Transmission Expansion Plan

153 Supplemental Projects Prior to FERC Order No. 890 in 2008, Supplemental Projects were referred to as Transmission Owner Initiated or TOI Projects. A Supplemental Project is not required for compliance with system reliability, operational performance or economic criteria, as determined by PJM. Supplemental projects frequently address aging infrastructure, provide support to serve underlying systems and add connections to new, large load customers. PJM reviews supplemental projects to ensure that they do not introduce other reliability criteria violations. And, while not subject to PJM Board approval, they are included in PJM s RTEP. Transmission Owners submitted a number of supplemental projects throughout Projects with cost estimates greater than $5 million are listed in Table 11.9 and shown on Map Table 11.9: Southern Supplemental Subregional Projects Map ID Project ID 1 s s Project Build a new substation at the tap serving Beechwood DP with a 115 kv three breaker ring to split Line No.90 and terminate the end points. Terminate the Beechwood tap into the ring Network 115 kv Lines No.98 and No.158 by splitting Line No.158 between Crewe and the Jetersville tap and building a four breaker ring switching station. Book 3: Subregion Summaries Southern Supplemental Subregional Projects Required Date Cost ($M) TO Zone(s) 2016 TEAC Review 12/31/2017 $7.40 Dominion 12/1/ /1/2017 $33.80 Dominion 7/26/ PJM 2016 Regional Transmission Expansion Plan 145

154 11 Book 3: Subregion Summaries Map 11.12: Southern Supplemental Subregional Projects 146 PJM 2016 Regional Transmission Expansion Plan