BOOK 1 PJM 2014 RTEP in Review February 28, 2015 Book 2 Book Book Input Data and Process Scope 3 Baseline and Market Efficiency Results 4 Scenario and Interregional Results Book 5 State RTEP Summaries 2014 Public Policy Reliability Population of 61+ million Over 62,000 miles of transmission lines PJM Regional Transmission Expansion Plan 15-year long-term horizon Economy Collaboration with more than 900 members 13 states + DC
Book 1: Preface Preface PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV Book 1, PJM 2014 RTEP in Review, is the first in a series of five books that comprise PJM s 2014 Regional Transmission Expansion Plan Report: Book 1: PJM 2014 RTEP in Review Book 2: Input Data and Study Processes Book 3: Baseline and Market Efficiency Results Book 4: Scenario and Interregional Study Results Book 5: State RTEP Summaries Book 1, PJM 2014 RTEP in Review, provides an executive summary of 2014 RTEP process results: deactivation studies that drive baseline upgrades; baseline and market efficiency studies that drive RTEP proposal windows; as well as scenario and interregional studies that inform PJM understanding of system impacts driven by public policy and other external factors. Book 1 also describes evolving RTEP process and methodology enhancements. RTEP Process Description Summary level RTEP process description is provided in each book. The online resources noted below provide a more detailed description of RTEP process business rules and methodologies: i
Book 1: Preface 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 upgrades derived from them. PJM Manual 14B, Regional Planning Process can be found on PJM s website via the following URL: http:// www.pjm.com/~/media/documents/manuals/ m14b.ashx. Schedule 6 of the PJM Operating Agreement codifies the overall provisions under which PJM effects 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 URL: http://www.pjm.com/documents/ agreements/~/media/documents/agreements/ oa.ashx. 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 upgrade specific requests. The PJM OATT can be found via the following URL: http://www.pjm.com/ documents/agreements/~/media/documents/ agreements/tariff.ashx. Stakeholder Forums The Planning Committee (PC), 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 PC makes recommendations regarding generating capacity reserve requirement and demand-side valuation factors. Committee meeting materials and other resources are accessible from PJM s website via the following URL: http://www.pjm.com/ committees-and-groups/committees/pc.aspx. Transmission Expansion Advisory Committee (TEAC) and Sub-Regional RTEP Committee activities 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, resources for which are accessible from PJM s website via the following URL: http://www.pjm.com/committees-and-groups/ committees/teac.aspx. Additionally, each Sub-Regional RTEP Committee provides a forum for stakeholders to discuss more local planning concerns. Interested stakeholders can access Sub-regional RTEP Committee planning process information from PJM s website via the following URLs: PJM Western Sub-Regional RTEP Committee: http://www.pjm.com/committees-and-groups/ committees/srrtep-w.aspx PJM Southern Sub-Regional RTEP Committee: http://www.pjm.com/committees-and-groups/ committees/srrtep-s.aspx The Independent State Agencies Committee (ISAC), commissioned in December 2011, 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 via the following URL: http://pjm.com/committees-andgroups/isac.aspx. The status of individual PJM Board-approved baseline and network RTEP upgrades, as well as that of supplemental upgrades, can be found on PJM s website via the following URL: http:// www.pjm.com/planning/rtep-upgrades-status. aspx. PJM Mid-Atlantic Sub-Regional RTEP Committee: http://www.pjm.com/committeesand-groups/committees/srrtep-ma.aspx ii
Book 1: Table of Contents Book 1: Table of Contents PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV Section 1: 2014 Executive Summary 1 1.0: 2014 RTEP Activity 1 1.0.1 Scope of PJM Regional Planning 1 1.0.2 2014 Highlights 3 1.0.3 Transmission Upgrade Types 4 1.1: Transmission Expansion Drivers in 2019 and Beyond 5 1.1.1 Conventional Drivers 5 1.1.2 Impacts of Public Policy 5 1.1.3 FERC Order No. 1000 6 1.2: 2014 Baseline Highlights 9 1.2.1 Overview 9 1.2.2 Generating Unit Deactivations 9 1.2.3 RTEP Proposal Window No. 1 12 1.2.4 RTEP Proposal Window No. 2 13 1.2.5 2014/15 Long-Term Proposal Window 17 1.2.6 Artificial Island RTEP Window 17 1.3: Scenario Study Results 19 1.3.1 Winter Peak Scenario Study 19 1.3.2 EPA Clean Power Program 19 1.4: NERC Criteria Changes 21 1.4.1 RTEP Process Context 21 1.4.2 RTEP Process Impacts 22 Section 2: Process Evolution Regulatory Compliance 25 2.0: Order No. 1000 Implementation 25 2.0.1 Background 25 2.0.2 July 14, 2014 FERC Compliance Filing 26 2.0.3 Designated Entity Agreement 26 2.0.4 Interconnection Coordination Agreement 26 2.0.5 RTEP Windows Next Steps 26 PJM 2014 iii
Book 1:Table of Contents 2.1: Multi-Driver Process 29 2.1.1 Overview 29 2.1.2 State Agreement Approach 30 2.1.3 Methodology 30 Section 3: Process Evolution Modeling and Methodology 31 3.0: Modeling Improvements 31 3.0.1 RTEP Process Context 31 3.0.2 Model on Demand 31 3.0.3 NERC Standard MOD-032 Modeling Parameters Implementation 32 3.0.4 NERC Standards MOD-026-1 and MOD-027-1 32 3.1: Methodology Improvements 33 3.1.1 RTEP Process Context 33 3.1.2 Easily Resolved CETL Constraints 33 3.1.3 Small Generator Interconnection Process 34 3.1.4 Enhanced Inverters 34 3.1.5 Modeling MISO Facilities and Queue Coordination 34 Section 4: Process Evolution Resource Adequacy 35 4.0: RTEP Process Context 35 4.0.1 RTO Perspective 35 4.0.2 Capacity Performance Product 35 4.0.3 Demand Resources / Order 745 36 4.0.4 Load Forecasting Improvements Energy Usage Variable 36 Topical Index 39 Glossary 43 iv PJM 2014
Book 1: 2014 Executive Summary Section 1: 2014 Executive Summary PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV Section 1 1.0: 2014 RTEP Activity Map 1.1: PJM Backbone Transmission System 1.0.1 Scope of PJM Regional Planning 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 identifies transmission system additions and improvements needed to keep the lights on for more than 61 million people throughout 13 states and the District of Columbia. The PJM system includes many 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 900 members, PJM dispatches more than 183,600 MW of generation capacity over 62,000 miles of transmission lines. 1
Section 1 Book 1: 2014 Executive Summary Integrated Nature of Regional Planning PJM addresses transmission expansion planning from a regional perspective, spanning transmission owner (TO) zonal boundaries and state boundaries to address system-wide impacts caused by a range of upgrade drivers. The relationship between reliability criteria violation and upgrade location generally takes one of two forms. Reliability criteria violations in a given TO 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 a future overload on that facility. Also, reliability criteria violations in one or more TO zones may be driven by some combination of system factors including those potentially arising some distance away. For example, voltage criteria violations in eastern portions of the PJM system may not be caused by a local problem but rather by heavier west-to-east transfers from the Midwest to eastern PJM load centers. In this manner, PJM can identify one comprehensive set of expansion plans that comprise more economical and optimal solutions to resolve reliability criteria violations and congestion constraints. Otherwise, consideration of reliability criteria violations individually, and perhaps mutually exclusive of one another, may lead to economically inefficient solutions. Reliability planning keeps the lights on. PJM s RTEP process encompasses a comprehensive assessment of system compliance with the thermal, reactive, stability and short circuit NERC standards for Category A (TPL-001), Category B (TPL-002) and Category C (TPL-003) events, over a five-year near-term horizon and 15-year long-term horizon. Transmission projects that improve reliability can also improve economics, and vice versa. The RTEP process examines market efficiency to identify transmission enhancements that lower costs to consumers by relieving congested lines, allowing lower cost power to flow to consumers. NOTE: PJM continues to implement RTEP process changes in compliance with NERC s new Reliability Standard TPL-001-4 as discussed later in Section 1.4. 2
Book 1: 2014 Executive Summary Section 1 1.0.2 2014 Highlights Since 1999, the PJM Board has approved transmission system enhancements totaling nearly $25.6 billion to ensure compliance with NERC and regional planning criteria. This includes $21.5 billion of baseline transmission upgrades throughout the RTO and $4.1 billion of additional facilities to enable the interconnection of more than 60,000 MW of new generating resources. A summary of upgrades by status as of December 31,2014 appears in Figure 1.1. The numbers in Figure 1.1 though only provide a snapshot at one point in time, as with an end-ofyear balance sheet. The $25.7 billion total actually reflects a net $3.2 billion reduction over that of December 31, 2013, further broken down in Table 1.1. In 2014, the PJM Board approved 197 new baseline and 148 new network upgrades to address reliability criteria violations, totaling $1.09 billion and $604.9 million, respectively. These approvals in 2014, however, were more than offset by the removal of 651 network upgrades totaling $4.743 billion and the removal of 40 existing RTEP baseline elements comprising $176.9 million. Figure 1.1: Approved RTEP Upgrades December 31, 2014 $ Millions Active Baseline Upgrades 8,270.2 Network Upgrades 3,179.8 $25,000.0 Total 11,450.0 $20,000.0 $15,000.0 $10,000.0 $5,000.0 $0.0 Baseline Upgrades In Service 9,202.1 792.5 9,994.6 Under Construction 4,012.7 202.2 4,214.9 Network Upgrades Total 21,485.0 4,174.3 25,659.3 Under Construction In Service Active Table 1.1: RTEP Upgrade Cost Differential December 31, 2014 vs. December 31, 2013 Baseline Differentials ($, millions) Network Differentials ($, millions) New upgrade costs 1,092.0 604.9 Costs of cancelled upgrades (176.9) (4,743.0) Existing upgrade cost increases 41.9 14.6 Existing upgrade cost decreases (22.0) (34.8) Net Difference 935.0 (4,158.3) 3
Section 1 Book 1: 2014 Executive Summary Interconnection Request Withdrawals Network upgrade cancellations in 2014 were caused by the withdrawal of 212 generation interconnection requests totaling 15,302 MW, 25 percent of which comprised wind-powered units. Queue withdrawals often reflect ongoing business decisions by developers in light of PJM RPM auction activity and the impacts of renewable fuel public policy. Network upgrades allow a customer to interconnect reliably to the PJM grid and obtain requested capacity rights. Those upgrades are recommended to the PJM Board after system impact studies are completed and facility study agreements are tendered to developers. Shifting Baseline Upgrade Drivers Digging a bit further into the numbers, however, reveals emerging shifts in baseline upgrade driver behavior. The smaller magnitude and number of approved baseline upgrades expected to be needed by 2019 reflect a new PJM reality characterized by flatter load growth and a generation fleet shift from coal to natural gas-fired units. Coal-fired unit deactivation eased in 2014 4,291 MW in comparison to 2013 and 2012 7,745 MW and 14,444 MW, respectively. Holistically, the need for new large-scale baseline upgrades long-distance transmission lines, for example driven by these factors has diminished. PJM has begun to assess the potential impacts of recent EPA carbon regulations as summarized in Section 1.3.2, which may cause additional coal-fired generator deactivation requests and consequent need for related transmission system upgrades. 1.0.3 Transmission Upgrade Types The RTEP includes PJM Board-approved baseline and network upgrades to resolve reliability criteria violations identified by PJM. Baseline Upgrades Baseline upgrades are transmission 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 BES facilities, tie lines to neighboring systems, critical neighboring system facilities and lower voltage facilities operated by PJM. Network Upgrades PJM s RTEP also includes transmission upgrades identified through interconnection process System Impact Studies. These network upgrades are necessary to interconnect new generation and merchant transmission facilities or to provide new long-term firm transmission service. Direct connection network upgrades are transmission enhancements that serve to deliver power to a defined point of interconnection. Non-direct connection network upgrades serve to mitigate transmission system impacts beyond the point of interconnection. A Range of System Elements RTEP upgrades include a range of power system elements: circuit breaker replacements to accommodate higher current interrupting duty cycles; new reactive devices including shunt capacitors and static var compensation to enhance reactive support and improve generating unit stability; and, new lines, transformers, existing line reconductoring and bus reconfigurations to accommodate increased power flows. 4
Book 1: 2014 Executive Summary Section 1 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 1.1: Transmission Expansion Drivers in 2019 and Beyond 1.1.1 Conventional Drivers A 15-year long-term planning horizon allows PJM to consider the effects of many system drivers, shown in Figure 1.2. Initially, beginning with its inception in 1997, PJM s RTEP consisted mainly of upgrades driven by load growth and generating resource interconnection requests. Today, PJM s RTEP process considers the interaction among many drivers including federal and state public policy as well as the impact from FERC Order No. 1000 compliance. The RTEP process culminates in one recommended plan one RTEP for the entire PJM footprint submitted to PJM s independent PJM Board of Managers (PJM Board) periodically throughout the year. Once the PJM Board approves transmission upgrades new facilities and upgrades to existing ones they formally become part of PJM s RTEP. PJM Board approval obligates designated entities to construct those upgrades. The PJM Board also considers PJM recommendations to remove upgrades from the RTEP if need no longer exists. Figure 1.2: System Expansion Drivers Load Forecast, Demand Resources Transmission Service, Operations Operational Performance 1.1.2 Impacts of Public Policy Until recently, conventional PJM RTEP nearterm analysis comprised a five-year-out baseline study focused on summer peak emergency system conditions. However, a single set of baseline and market assumptions are simply not sufficiently flexible to consider all possible impacts of system drivers to their fullest extent. Public Policy RTEP Development Reliability Criteria Capacity Resources, RPM Market Efficiency Interregional Coordination PJM s RTEP process has continued to adapt to assess the effects of many system planning trends. More recently, public policy drivers generator deactivations due to environmental policies, for example coupled with generator operator fuel-of-choice shifts from coal and oil to natural gas, are dramatically shifting the scope and magnitude of upgrades recommended to the PJM Board for approval. 5
Section 1 Book 1: 2014 Executive Summary Environmental Policy PJM has already experienced the impact of regulatory actions that limit power plant emissions. Generation owners are weighing investments and operational costs against anticipated revenues from PJM markets and existing power purchase agreements to determine economic viability. Costs to address environmental regulatory requirements and unit age put plants at-risk, particularly with regard to the ability to clear a capacity auction. These resources face competition from more efficient plants, renewable energy resources, demand response and energy efficiency programs. Looking ahead, new EPA carbon regulations (expected to be promulgated in 2015) will likely drive additional unit deactivations. Those regulations target coal-fired generation by calling for a 30 percent reduction in carbon emissions from 2005 levels by 2030. Environmental policy scenario studies discussed in Book 4, Section 3.2 will examine reliability impacts caused by additional generation put atrisk from these new EPA carbon rules. Renewable-Powered Generation U.S. Federal Energy policy in recent years has encouraged the development of wind generation facilities with legislation that provides tax incentives and Production Tax Credits (PTCs) for wind-powered facilities. The American Recovery and Reinvestment Act (ARRA) enacted in February 2009 provided a three-year extension of the PTC through December 31, 2012. In January 2013, federal legislation, passed as part of fiscal cliff deadline action, extended production tax credits through 2013 and included all wind-powered projects that started construction in 2013, not just those completed in 2013. The Tax Increase Prevention Act of 2014 extended the expiration date for this tax credit to December 31, 2014. Projects that are not under construction prior to January 1, 2015, are ineligible for this credit. Interconnection request withdrawals are driven by developers whose business plans depend on revenue streams enhanced by these energy tax credits. The lack of assurances that those credits will continue has made plant financing and ongoing profitability tenuous. State public policy likewise addresses renewable-powered generation. Ten states and the District of Columbia within PJM have adopted Renewable Portfolio Standard (RPS) mandates, which require electricity suppliers to purchase specified amounts of renewable energy as part of their state supply portfolio. Current RPS goals range from 10 percent to 25 percent over the next decade. Internal and interregional scenario studies over the past several years have explored the transmission infrastructure needed to accommodate the level of renewable powered generation needed to meet the aggregate of state RPS targets. 1.1.3 FERC Order No. 1000 The landscape in which PJM conducts regional planning has changed. The Federal Energy Regulatory Commission issued Order No. 1000 on July 21, 2011, requiring, in addition to cost allocation and interregional reforms, regional transmission planning processes that evaluate alternative upgrade solution proposals. In keeping with Order No. 1000, PJM has implemented new RTEP Process procedures which took effect on January 1, 2014 so that both incumbent and non-incumbent transmission developers may submit project proposals. Specifically, revisions to PJM s Operating Agreement Schedule 6 permit PJM to implement proposal windows during which a project sponsor who has pre-qualified may submit a proposal. Once PJM selects a project, PJM assigns Designated Entity status to project sponsor(s) who then bear responsibility to construct, own, operate, maintain and finance the proposed facilities. PJM continued efforts in 2014 to implement RTEP process changes initiated in 2013 to address FERC Order No. 1000 compliance. RTEP Windows PJM has opened proposal windows to address RTEP study reliability criteria violations, market efficiency and operational performance issues. The scope and complexity of the identified issue and likely solution set dictate window duration. PJM conducted two initial RTEP proposal windows in 2013 Artificial Island and Market Efficiency consistent with the terms of FERC compliance filings then under development. During each window, developers submitted solution proposals to address posted problem statements and system requirements. Each of those windows provided valuable experience and insights with Order No. 1000 driven RTEP process changes. Since then PJM has undertaken several initiatives to implement additional coordination, documentation, evaluation and selection criteria changes to improve its process further. Indeed, PJM s 2014 RTEP windows have benefited from experience gained in those two initial 2013 windows. 6
Book 1: 2014 Executive Summary Section 1 Future Windows RTEP Window No. 1 in 2014 is likely more typical of the future compared to that experienced in the Artificial Island Operational Performance window. That window yielded 26 proposals from seven entities and is currently under evaluation by PJM. By contrast 2014 RTEP Window No. 1 sought proposals to resolve reliability criteria violations identified by Baseline N-1 thermal, Generator Deliverability and Common Mode Outage, Load Deliverability Thermal and Voltage and, N-1-1 Thermal analyses. Those studies identified 50 individual facilities with NERC reliability criteria violations, affecting over 100 flowgates. Fifteen entities proposed 106 solutions in eight TO zones, spanning ten states. The 106 solutions received by PJM included 46 upgrade proposals to existing facilities ranging in cost from $0.02 million to $139.2 million as well as 60 greenfield proposals ranging in cost from $10.2 million to $1,367 million. PJM reviewed the effectiveness of the proposals with the TEAC. PJM staff recommended 22 of the 106 proposals to the PJM Board to resolve reliability criteria violations, as discussed further in Book 3, Section 4. The 22 recommendations all upgrades to existing facilities included several line reconductor projects, replacement of existing transformers with larger transformers, upgrades to terminal equipment on existing facilities, circuit breaker replacements at several locations and one new 138 kv transmission facility. 7
Section 1 Book 1: 2014 Executive Summary 8
Book 1: 2014 Executive Summary Section 1 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 1.2: 2014 Baseline Highlights Map 1.2: Generator Deactivation Notifications in 2014 1.2.1 Overview PJM s RTEP process encompasses a comprehensive assessment of system compliance with thermal, reactive, stability and short circuit NERC reliability criteria. Baseline analyses in 2014 yielded upgrades to address generating plant deactivations and prompted RTEP proposal windows to resolve identified criteria violations and alleviate congestion identified in market efficiency studies. 1.2.2 Generating Unit Deactivations PJM received 31 generator deactivation requests in 2014 totaling 4,291 MW across PJM as shown in Map 1.2. Baseline deactivation analysis identified reliability criteria violations driving the need for 27 transmission upgrade solutions in Mid-Atlantic PJM and Western PJM as shown in Map 1.3 and Map 1.4. Upgrades included new transmission lines, transformers and shunt capacitors, as well as existing infrastructure enhancements substation improvements to reinforce underlying systems and existing line rebuilds to achieve higher line ratings. 9
Section 1 Book 1: 2014 Executive Summary Map 1.3: Mid-Atlantic PJM 2014 Baseline Upgrades Driven by Generator Deactivations B. L. England Driven Upgrades 10
Book 1: 2014 Executive Summary Section 1 Map 1.4: Western PJM 2014 Baseline Upgrades Driven by Generator Deactivations 11
Section 1 Book 1: 2014 Executive Summary 1.2.3 RTEP Proposal Window No. 1 The 2014 RTEP Proposal Window No. 1 addressed reliability criteria violations identified in the following bodies of analysis: Thermal Baseline Contingency Analysis to identify contingency violations in the RTEP base case based on normal and emergency rating at summer peak conditions. Generator Deliverability & Common Mode Outage Analysis to test the strength of the transmission system to ensure that the aggregate of generators in a given area can be reliably transferred to the rest of PJM. Load Deliverability Thermal and Voltage Analysis to test the ability to deliver energy from an aggregate of all capacity resources to an electrical area experiencing a capacity deficiency. N-1-1 Thermal Analysis to test thermal limits after a single (N-1) contingency assuming optimal re-dispatch and system adjustments; as well as testing applicable emergency thermal ratings after and additional single contingency (N-1-1) condition. In advance of the window, PJM released the results of those analyses: 12 baseline thermal violations 42 generator deliverability thermal violations One load deliverability voltage violation Several N-1-1 thermal violations Study results identified 50 individual facilities with NERC reliability criteria violations affecting more than 100 flowgates across PJM. PJM opened Window No. 1 from June 27, 2014 to July 28, 2014. In response, 15 entities submitted 106 proposals to resolve the identified violations including 46 upgrades to existing facilities, which ranged in cost from $0.02 million to $139.2 million. Additionally, PJM received 60 greenfield projects ranging in cost from $10.2 million to $1,367 million. The proposals were located in 18 Transmission Owner zones spanning 10 States DE, IL, IN, KY, MD, NJ, OH, PA, VA and WV, as shown in Map 1.4. Following window closure, PJM staff reviewed the proposals, evaluated their effectiveness and reviewed results with the TEAC. The flowgates included within this window suggested three next step categories. Recommendation PJM s recommendation to the PJM Board in December 2014 encompassed a set of 22 projects to address 56 flowgate violations. They included several line reconductor projects, replacement of existing transformers with larger transformers, upgrades to terminal equipment on existing facilities and circuit breaker replacements. As part of its evaluation, PJM considered 15-year analysis results when developing this set of recommendations to determine if a more robust solution could be justified. That analysis did not yield such need. All 22 recommended projects were upgrades to existing facilities. Retirement/At-risk related upgrades This set of project proposals addressing 51 potential flowgate violations has been set aside pending planned deactivation of several units: Clinch River, Kammer and Tanners Creek. Reliability violations will be re-evaluated following such retirement requests. FSA generation related upgrades PJM differed this set of project proposals in light of two flowgate violations aggravated by queued generators in the facility study stage of PJM s interconnection process. Reliability violations will be re-evaluated if the queued generators are ultimately expected to go in service. 12
Book 1: 2014 Executive Summary Section 1 1.2.4 RTEP Proposal Window No. 2 The scope of PJM s 2014 RTEP Proposal Window No. 2 addressed the need for upgrades to resolve violations identified in the following bodies of analysis conducted during August and September of 2014: 2019 Baseline N-1 Voltage Analysis to test single (N-1) contingencies against applicable thermal and voltage ratings 2019 N-1-1 Voltage Analysis to test voltage limits after a single (N-1) contingency and an additional single contingency (N-1-1) condition for applicable voltage drop and voltage magnitude ratings. 2018 Light Load Reliability Criteria Analysis to test the ability of the transmission system to deliver system generating capacity during a light load (50 percent of 50/50 peak) Transmission Owner (TO) Criteria Analysis to test TO systems against the standards documented by each. Initial findings identified 49 potential thermal limit violations and 69 potential voltage limit violations. Analyses identified 118 individual facilities with reliability criteria violations affecting more than 300 flowgates. PJM opened Window No. 2 between October 17, 2014 and November 17, 2014. In response, 14 entities submitted 79 proposals to resolve the identified violations. These proposals included 45 upgrades to existing facilities which ranged in cost from $0.02 million to $103.7 million. Additionally, PJM received 34 greenfield projects ranging in cost from $6.1 million to $450 million. The proposals addressed nine target Transmission Owner zones as shown in Map 1.5, Map 1.6 and Map 1.7. Evaluating Proposals Following window closure, PJM staff reviewed the proposals, evaluated their effectiveness and reviewed results with the TEAC. The flowgates suggested three next step categories based on the impact to each identified violation by pending deactivations and planned interconnections. The majority of violations had only one solution proposed. For those violations with more than one proposal, the most cost-effective upgrade which resolved the violation was selected. Recommendation PJM s recommendation to the PJM Board in February 2015 encompassed a set of 33 upgrades for approval to address 132 flowgate violations. The recommendations included greenfield solutions, reactor installations, capacitor installations, relay upgrades, line rebuilds and new transformers. FSA Generation Related Upgrades This set of six project proposals was deferred in light of nine potential flowgate violations that were aggravated by queued generators in the facility study stage of PJM s interconnection process. Reliability violations will be reevaluated pending the status of the planned generation. Further analysis of these proposals will be performed if the queued generators in the facility study stage of the interconnection process are expected to go in service. On-going Evaluation PJM will continue to evaluate 20 proposals received for possible solution development. Those 20 included 14 submitted to address issues near the Pratt s substation area along the border between APS and Dominion; and, four submitted to address issues identified as part of a first addendum to Window No. 2. PJM will also conduct a 15-year analysis for this set of proposals to determine if a more robust solution could be justified. 13
Section 1 Book 1: 2014 Executive Summary Map 1.5: 2014 RTEP Window No. 1 Proposals - West 14
Book 1: 2014 Executive Summary Section 1 Map 1.6: 2014 RTEP Window No. 1 Proposals - East 15
Section 1 Book 1: 2014 Executive Summary Map 1.7: 2014 RTEP Proposal Window No. 2 Proposals 16
1.2.5 2014/15 Long-Term Proposal Window Consistent with established practice, PJM s 15-year planning horizon encompassed both reliability and market efficiency analysis. PJM s planning horizon exceeds the scope of that specified by NERC and permits PJM to identify potential reliability criteria violations, that may require larger-scale, longer lead-time solutions. Results are reviewed to identify violations that occur across multiple deliverability areas or multiple violations clustered in a specific area. Long-term reliability analyses included the following test procedures for model year 2022: Generator Deliverability & Common Mode Outage Analysis that tested the strength of the transmission system to ensure that the aggregate of generators in a given area can be reliably transferred to the rest of PJM. Load Deliverability Thermal and Voltage Analysis that examined the ability to deliver energy from an aggregate of all capacity resources to an electrical area experiencing a capacity deficiency. These results were then extrapolated out through 2029 based on distribution factor calculations and applying incremental load increases based on PJM s 2014 Load Forecast Report. None of the identified reliability criteria violations suggested the need for a long leadtime, larger scope transmission solution. PJM communicated to stakeholders that while it intended to open a long-term RTEP proposal window, PJM did not believe that a transmission solution at this point was needed to resolve these specific violations. Rather, the major focus of the window would be to seek technical solution alternatives to relieve market efficiency congestion identified in related 2014 RTEP analyses, as discussed in Book 3, Section 6. PJM opened its 2014/15 Long-Term Proposal Window on October 30, 2014, with an expected end date of February 27, 2015. Once the window closes, PJM will evaluate the proposals and recommend projects to the PJM Board for RTEP consideration as warranted. Book 1: 2014 Executive Summary 1.2.6 Artificial Island RTEP Window PJM opened an RTEP window in April 2013 seeking proposals to improve operational performance on BES facilities in the southern New Jersey Artificial Island area, site of PSE&G s Salem 1 and 2 and Hope Creek 1 nuclear generating plants, shown in Map 1.8. PJM specified that solution proposals must improve limited stability margins, minimum Artificial Island MVAR output requirements and previously identified high voltage reliability issues. PJM continued to evaluate proposals throughout 2014 to assess submitted proposals and address additional regulatory, technical and cost considerations raised by the PJM Board, as discussed in Book 3, Section 3. Section 1 Specific Load Deliverability tests that examined LDAs where the CETL is less than 150 percent of CETO in 2018, the most recent set of CETO/CETL data available at the time. These Locational Deliverability Areas included BGE, CLEV, DEO&K, DPL South, PEPCO, PSE&G, PS North and SWMAAC. 17
Section 1 Book 1: 2014 Executive Summary Map 1.8: Artificial Island Area Artificial Island 18
Book 1: 2014 Executive Summary Section 1 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 1.3: Scenario Study Results 1.3.1 Winter Peak Scenario Study January 2014 was an extremely challenging month for much of the U.S. energy industry, particularly the electricity and natural gas sectors. Power system operators, power producers and consumers both in PJM and surrounding regions endured prolonged periods of bitterly cold temperatures that drove up energy use, increased uncertainty for grid operators and stressed available power supplies. Throughout January 2014, PJM experienced tight operational conditions and a significantly higher number of forced generator outages compared to a more typical January caused by physical plant mechanical problems and natural gas market inflexibility. PJM conducted several scenario analyses in 2014, the key objective of which was to determine if PJM should make changes to planning study assumptions to better model the risks posed by severe winter conditions. Analysis included generator deliverability and load deliverability tests to identify constraints limiting transfer capability into capacity deficient areas. In particular, the scenarios studied reflected increasing levels of unavailable generation, particularly that powered by natural gas. PJM identified minor transmission issues subsequently shared with TOs and the TEAC. The results will also be used to inform discussions about planning process improvements and the possible need for the development of winter planning criteria. 1.3.2 EPA Clean Power Program The U.S. Environmental Protection Agency released its Clean Power Plan on June 2, 2014, to reduce greenhouse gas emissions caused by carbon dioxide from existing fossil-fueled power plants. The Plan sets an emissions rate standard in terms of pounds of carbon dioxide per megawatthour for each state. Energy produced by renewable resources and verifiable energy savings from energy efficiency would count toward a reduction in a state s emission rate. Each state is individually responsible for developing compliance plans. The plan allows states the opportunity to convert to a mass-based standard, effectively converting pounds of carbon dioxide per megawatt-hour to total tons of carbon dioxide. States also have the latitude to comply with the proposed rule on a regional basis in collaboration with other states. OPSI Request for Section 111(d) The Organization of PJM States, Inc. (OPSI) submitted a request on September 2, 2014 asking PJM to evaluate several possible Plan driven scenarios assessing the impacts on carbon dioxide prices and their consequent impact on energy market prices, load energy payments, compliance costs, net generator revenues, and carbon dioxide emissions. Further, OPSI asked PJM to compare regional compliance options with state-by-state compliance options under several scenarios as well. PJM, in addition to the OPSI request, also intends to evaluate scenarios to examine the effects of varying assumptions for natural gas prices, available energy efficiency, renewable energy resources and available new entry of renewable resources and natural gas resources. PJM markets staff are in the process of conducting economic analysis of coal, oil and natural gas powered generation to assess the impacts of both the proposed EPA 111(d) greenhouse gas rule and soon-to-be finalized 111(b) New Source Performance Standards. These analyses will help identify units at risk for deactivation. PJM Planning will use the results as inputs into its reliability studies to assess corresponding system impacts. PJM presented results of the OPSI economic analysis to the PJM TEAC on January 7, 2015, which is accessible via this link: http://pjm. com/~/media/committees-groups/committees/ teac/20150107/20150107-pjm-economicand-reliability-analysis-of-the-epas-cpp.ashx. A report is also accessible via this link: http:// pjm.com/~/media/committees-groups/ committees/teac/20150107/20150107-pjmeconomic-analysis-of-generation-retirementpotential.ashx. 19
Section 1
Book 1: 2014 Executive Summary Section 1 PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV 1.4: NERC Criteria Changes Table 1.2: NERC Criteria Reference Table 1.4.1 RTEP Process Context PJM s RTEP process assesses the transmission system s ability to meet all applicable NERC reliability planning criteria. PJM has conducted reliability analyses to ensure compliance since 1997, the inception of PJM s RTEP Process. Analyses test system compliance with thermal, reactive, stability and short circuit criteria as part of established NERC standards TPL-001 through TPL-004 over both five-year and 15-year planning horizons. Each standard comprises one or more facility contingency categories as summarized in Table 1.2. PJM s comprehensive methodology applies rigorous analysis to defined test conditions such as that which PJM models as load and generation deliverability under peak demand. PJM documents each violation and identifies system reinforcements required for compliance. Compliance with NERC criteria is mandatory as required by the 2005 Energy Policy Act. Penalties can be as high as $1 million per violation per day. Standard Category Contingencies TPL-001 A All facilities in service TPL-002 B TPL-003 C1 Bus section faults C2 C3 C5 Fault with normal clearing Loss of all facilities associated with a single contingency Breaker failure Fault with normal clearing followed by re-dispatch followed by a second fault with normal clearing (N-1-1 Contingency) Multiple circuit tower line TPL-004 D Extreme events gaps, ambiguity and fill-in-the-blank aspects of existing standards. The new standard should have the benefit of conforming national standards more closely to common planning practices across the industry and enhance their practical effectiveness. NERC Allows Planned/Controlled Load Loss No Yes PJM Allows Non-Consequential Load Loss No NERC Criteria Changes The new NERC planning standard TPL-001-4 was formally approved under the terms of FERC s October 17, 2013 Final Rule in Docket Nos. RM12-1-000 and RM13-9-000. The standard reflects the consolidation of the four existing ones shown in Table 1.2. FERC directed this consolidation with the goal of advancing overall nationwide planning standard quality by eliminating 21
Section 1 Book 1: 2014 Executive Summary 1.4.2 RTEP Process Impacts Reliability Standard TPL-001-4 introduces significant revisions and improvements to the existing four TPL Reliability Standards, particularly with regard to the following: Increased specificity of data required for modeling conditions Annual assessments addressing near-term and long-term planning horizons for steady state stability Introduction of short circuit assessment requirements Table 1.3 summarizes the eight formal Requirements under TPL-001-4 and the date on which enforcement of each begins. PJM has completed all process changes necessary to meet the January 1, 2015 effective date for Requirements R1 and R7. PJM remains on target to complete changes necessary for Requirements R2 through R6 and R8 which become effective January 1, 2016. PJM RTEP Process Changes Starting in May 2012, PJM began working with stakeholders through the Planning Committee to implement RTEP process changes necessary to reach full compliance. Three impact categories were identified. First, PJM is already compliant with much of Standard TPL-001-4. All necessary testing and requisite Manual 14B language is already in place. No further action has been required. Table 1.3: TPL-001-4 Requirements Requirement Abbreviated Description Second, several requirements have required Manual 14B revisions to align manual language with the new standard. No additional RTEP process testing is needed that PJM is not already performing. Third, several requirements have required both Manual 14B language revisions and new RTEP process testing. Many of these are already performed by PJM either in part or on an ad hoc basis. PJM continued to working throughout 2014 on the necessary enhancements: Dynamic load modeling Transient voltage recovery Increased requirements for transmission facility outages Short circuit assessment Enforcement Date R1 Maintain system models 1/1/2015 R2 Prepare an annual assessment 1/1/2016 R3 Study the near-term and longer-term 1/1/2016 R4 Perform the stability criteria 1/1/2016 R5 Criteria Voltage, including transient voltage response 1/1/2016 R6 Criteria cascading, voltage instability, uncontrolled islanding 1/1/2016 R7 The TPs and PCs shall determine study responsibility for the assessment 1/1/2015 R8 Distribute results of annual assessment 1/1/2016 PJM to Allow Non-Consequential Load Loss These elements have formally become part of PJM s annual RTEP process. Finally, because the requirements of Standards TPL-001, TPL-002, TPL-003 and TPL-004 are consolidated into new TPL Reliability Standard TPL-001-4, they will be retired following the effective date of the new requirements. However, during the 24-month implementation period, all aspects of the currently-effective TPL Reliability Standards, TPL-001 through TPL-004 will remain in effect for compliance monitoring. No 22
Book 1: 2014 Executive Summary Section 1 Planning Event Definitions Recategorized Category A, B and C contingencies planning events in NERC parlance were previously applicable only to steady-state analysis under the TPL-001, TPL-002 and TPL-003 standards shown earlier in Table 1.2 and not applicable to stability analysis. Under the new NERC Reliability Standard TPL-001-4, planning events were re-categorized as P0 through P7 which will be applicable to both steady-state and stability analyses, enforceable beginning January 1, 2016. P0 through P7 events are defined in the context of system contingency: Table 1.4: Mapping Existing Event Categories to New NERC Standard Steady-State Analysis NERC TPL-001, TPL-002, TPL-003 NERC TPL-001-4 Basecase N-0 - No Contingency Analysis Category A P0 Basecase N-1 - Single Contingency Analysis Category B1, B2, B3 P1 Basecase N-2 - Multiple Contingency Analysis Category C1, C2, C5 P2, P4, P5, P7 N-1-1 Analysis Category C3 P3, P6 Generator Deliverability Category B1, B2, B3 P1 Common Mode Outage Procedure Category C1, C2, C5 P2, P4, P5, P7 Load Deliverability Category B1, B2, B3 P1 Light Load Reliability Criteria Category B1, B2, B3 P1, P2, P4, P5, P7 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) P6 Multiple Contingency (Two overlapping singles) P7 Multiple Contingency (Common Structure) Table 1.4 shows the translation between planning events for steady state analysis under the previous standards and new standard for PJM s test methods. 23
Section 1 Book 1: 2014 Executive Summary 24
Book 1: Process Evolution Regulatory Compliance Section 2: Process Evolution Regulatory Compliance PJM DE DC IL IN KY MD MI NJ NC OH PA TN VA WV Section 2 2.0: Order No. 1000 Implementation Figure 2.1: RTEP Proposal Window Process 2.0.1 Background January 1, 2014 marked the FERC-approved implementation date for RTEP process changes filed by PJM in 2012 and 2013 in compliance with Order No. 1000. In many respects, PJM had already been largely compliant with the terms of the Order prior to its issuance. Nonetheless, enhancement and refinement continued in 2014 building on the experience gained during the initial, prototype market efficiency and Artificial Island RTEP proposal windows conducted in 2013 prior to formal FERC approval. The extent of Order No. 1000 compliance and early window experience was discussed at length in PJM s 2013 Regional Transmission Expansion Plan Report, accessible online via the following link: http://www.pjm.com/documents/ reports/rtep-documents/2013-rtep.aspx. Revisions to PJM s Operating Agreement Schedule 6 permit PJM to implement windows through which a project sponsor who has prequalified may submit a proposal. PJM then evaluates proposals for project construction, ownership, operation and financial responsibility as shown in Figure 2.1. Once PJM selects a project, PJM assigns Designated Entity status to project sponsor(s) who then bear(s) those responsibilities. Window participants prepare and submit project packages Variable Proposal window ~30 to ~120 days PJM Company Evaluation PJM Constructability Evaluation PJM Analytical Evaluation Project(s) presented and reviewed at TEAC Designated Entity Selection Project Selection PJM Recommendation To Board 25
Section 2 Book 1: Process Evolution Regulatory Compliance 2.0.2 July 14, 2014 FERC Compliance Filing PJM submitted a compliance filing on July 14, 2014 to address commission directives from its May 15, 2014 order on PJM s July 22, 2013 initial submittal. The role of the Independent State Agencies Committee (ISAC) is not to be interpreted as imposing an obligation on the ISAC that would otherwise require ISAC to validate public policy requirements and to assess and prioritize public policy objectives. Any such obligation resides with the states themselves. Sub-Regional RTEP Committee scope was clarified to address the role of transmission owners and how local transmission needs driven by public policy requirements are to be addressed. Rights-of-way, state law and local law are to be considered appropriate for PJM to recognize as part of threshold matters in the evaluation of transmission upgrades, in particular, those submitted as part of RTEP windows. Regarding the RTEP Proposal Window Process in particular, FERC issued a directive to submit a pro forma Designated Entity Agreement for commission review. As part of PJM s Order No. 1000 OATT revisions, PJM included a requirement that an entity accepting Designated Entity status must execute an agreement setting forth the rights and obligations related to being the Designated Entity for the project. 2.0.3 Designated Entity Agreement A Designated Entity Agreement (DEA) defines the terms, duties, accountabilities and obligations of each party, and documents project scope, planning criteria, development schedules, project milestones and other pertinent terms and conditions. Many of the provisions of the Agreement are consistent with, or similar to, provisions in Appendix 2 of PJM s pro forma Interconnection Service Agreement (ISA), other provisions in the PJM Tariff, and the Consolidated Transmission Owners Agreement (CTOA). To that end, the DEA includes language that incorporates by reference PJM s OATT, Operating Agreement and Reliability Assurance Agreement. Once construction is complete and the Designated Entity has met all DEA requirements the Agreement is no longer needed. The Designated Entity must execute the CTOA as a requirement for DEA termination. Once a project is energized, a Designated Entity that is not already a Transmission Owner must become a Transmission Owner, subject to the CTOA. 2.0.4 Interconnection Coordination Agreement The DEA also establishes provisions for coordination with third parties. Because the Designated Entity may not qualify to be a party to the CTOA at the time the Designated Entity is selected, the execution of an Interconnection Coordination Agreement (ICA) acts as a precursor to a wires-to-wires agreement between the existing Transmission Owner and the Designated Entity. The ICA covers only coordination of construction prior to energizing the Designated Entity s project and defines the terms, duties, accountabilities and obligations of each party. 2.0.5 RTEP Windows Next Steps PJM initiated a lessons-learned exercise with the Planning Committee in 2014 to understand from a stakeholder perspective the aspects of the window process that worked well and those that could use improvement. PJM compiled stakeholder feedback, conducted a related informal poll and categorized the issues: Process Documentation Evaluation Communications Submission of secure files Access to data NOTE: PJM s July 14, 2014 FERC compliance filing is accessible online via the following link: http:// www.pjm.com/~/media/documents/ferc/2014- filings/20140714-er13-198-004.ashx. 26