MTEP15 Book 2: Resource Adequacy – View All

  • MTEP15 Chapter 6: Resource Adequacy Introduction and Enhancements

    MISO’s ongoing goal is to support the achievement of Resource Adequacy, i.e., ensure enough capacity is available to meet the needs of all consumers in the MISO footprint during peak times and at just and reasonable rates. The responsibility for Resource Adequacy does not lie with MISO, but rather rests with Load Serving Entities and the states that oversee them (as applicable by jurisdiction). Additional Resource Adequacy goals include maintaining confidence in the attainability of Resource Adequacy in all time horizons, building confidence in MISO’s Resource Adequacy assessments and providing sufficient transparency and market mechanisms to mitigate potential shortfalls. Five guiding principles provide the framework necessary to achieve these goals.
    1. Resource adequacy processes must ensure confidence in Resource Adequacy outcomes in all time horizons
    2. MISO will work with stakeholders to ensure an effective and efficient Resource Adequacy construct with appropriate consideration of all eligible internal and external resources and resource types and recognition of legal/regulatory authorities and responsibilities
    3. MISO will determine adequacy at the regional and zonal level and provide appropriate regional and zonal Resource Adequacy transparency and awareness for multiple forward time horizons
    4. MISO will administer and evolve processes in a manner that provides transparency and reasonable certainty, appropriately protects individual market participant proprietary information in order to support efficient stakeholder resource and transmission investment decisions
    5. MISO’s resource planning auction and other processes will support multiple methods of achieving and demonstrating Resource Adequacy, including self-supply, bilateral contracting and market-based acquisition.
    To date, the Resource Adequacy Requirements process has been a successful tool for facilitating and demonstrating Resource Adequacy in the near term, through such tools as the Loss of Load Expectation (LOLE) analysis, the Planning Resource Auction (PRA), and the Organization of MISO States (OMS)-MISO Survey. With the resource portfolio now evolving due to coal retirements and the increase in gas-fired generation, MISO is evaluating the Resource Adequacy Requirements. This work has begun in Resource Adequacy forums and will focus upon key areas to strengthen the Resource Adequacy framework; including defining seasonal risks; ensuring locational signals are clear and appropriate; and refining generator interconnection procedures to ensure new capacity can efficiently interconnect to the system. More information is detailed within the Issues Statement on Facilitating Resource Adequacy in the MISO Region.
  • MTEP15 Chapter 6.1: Planning Reserve Margin

    The MISO Installed Capacity Planning Reserve Margin (PRMICAP) for the 2015-2016 planning year, spanning from June 1, 2015, through May 31, 2016, is 14.3 percent, decreasing 0.5 percent from the 14.8 percent PRM set in the 2014-2015 planning year (Figure 6.1-1). The PRMICAP is established with resources at their installed capacity rating at the time of the system-wide MISO coincident peak load. The 0.5 percent PRMICAP decrease was the net effect of several modeling parameters such as changes to the modeling of external regions, changes to load forecast, load forecast uncertainty and resource characteristics.
    Figure 6.1-1: Comparison of recent PRM

    Figure 6.1-1: Comparison of recent PRM

    As directed under Module E-1 of the MISO Tariff, MISO coordinates with stakeholders to determine the appropriate Planning Reserve Margin (PRM) for the applicable planning year based upon the probabilistic analysis of the ability to reliably serve MISO Coincident Peak Demand for that planning year. The probabilistic analysis uses a Loss of Load Expectation (LOLE) study that assumes no internal transmission limitations within the MISO Region. MISO calculates the PRM such that the LOLE for the next planning year is one day in 10 years, or 0.1 days per year. The minimum amount of capacity above Coincident Peak Demand in the MISO Region required to meet the reliability criteria is used to establish the PRM. The PRM is established as an unforced capacity (PRMUCAP) requirement based upon the weighted average forced outage rate of all Planning Resources in the MISO Region. The LOLE study and the deliverables from the Loss of Load Expectation Working Group (LOLEWG) are based on the Resource Adequacy construct per Module E-1. MISO performs an LOLE study to determine the congestion-free PRM on an installed and unforced capacity basis for the MISO system. In addition, a per-unit zonal Local Reliability Requirement (LRR) for the planning year is determined for each Local Resource Zone (LRZ) (Figure 6.1-2), which is defined as the amount of resources a particular area needs to meet the LOLE criteria of one day in 10 years without the benefit of the Capacity Import Limit (CIL). These results are merged with the CIL, Capacity Export Limit (CEL) and Wind Capacity Credit results to form the deliverables to the annual Planning Resource Auction. .
    Figure 6.1-2: Local resource zones (LRZ)

    Figure 6.1-2: Local resource zones (LRZ)

    2015-2016 Deliverables to the Planning Resource Auction

    The PRM deliverables are needed for the Planning Resource Auction (PRA). These deliverables include the PRMUCAP, a per-unit zonal LRR, and CIL and CEL values (Table 6.1-1). The PRMUCAP decreased from 7.3 percent to 7.1 percent due to the modeling parameter changes. More information on the decrease is available in the LOLE report. Under the existing construct, the PRMUCAP is applied to the peak of each Load Serving Entity coincident with the MISO peak. A zonal CIL and CEL for each LRZ was calculated with the monitored and contingent elements reported (Tables 6.1-2 and 6.1-3; Figures 6.1-3 and 6.1-4). The ultimate PRM, CIL and CEL values for a zone could be adjusted within the PRA depending on the demand forecasts received and offers into the auction to assure that the resources cleared in the auction can be reliably delivered.
    RA and LOLE Metrics LRZ 1 LRZ 2 LRZ 3 LRZ 4 LRZ 5 LRZ 6 LRZ 7 LRZ 8 LRZ 9
    Default Congestion Free PRM UCAP 7.1% 7.1% 7.1% 7.1% 7.1% 7.1% 7.1% 7.1% 7.1%
    LRR UCAP per-unit of LRZ Peak Demand 1.111 1.151 1.137 1.214 1.211 1.108 1.142 1.270 1.112
    Capacity Import Limit (CIL) (MW) 3,735 2,903 1,972 4,125 3,899 5,649 3,813 2,074 3,320
    Capacity Export Limit (CEL) (MW) 604 1,516 1,477 2,353 0 2,930 4,804 3,022 3,239
    Table 6.1-1: Deliverables to the 2015-2016 Planning Resource Auction (PRA)
     
    Zone Tier 15-16 Limit (MW)[1] Monitored Element Contingent Element Figure 6.1-3 Map ID Initial Limit (MW)[2] Generation Redispatch Details 14-15 Limit (MW)
    MW Area(s)
    1 1 3,735 Worth County – Colby 161 kV Barton – Adams 161 kV 1 3,376 2,000 MEC, ITCM, XEL, GRE 4,347
    2 1 2,903 Turkey River – Stoneman 161 kV Genoa 161/69kV AT5/AT7 2 2,104 694 WEC, ALTE, MGE, ALTW 3,083
    3 1 1,972 Palmyra 345/161 kV transformer Hills – Sub T – Louisa 345 kV 3 727 2,000 XEL, ALTW, MEC 1,591
    4 1 3,130 Tazewell 345/138 kV transformer 1 Tazewell 345/138 kV transformer 2 4 850 2,000 NIPS, BREC, AMMO, AMIL, ITCM, MEC 3,025
    5 1 3,899 White Bluff – Keo 500 kV Sheridan – Mabelvale 500 kV 5 3,899 Not Applicable 5,273
    6 1&2 5,649 Neoga – Holland 345 kV Xenia – Mount Vernon 345 kV 6 5,090 2,000 METC, AMIL 4,834
    7 1&2 3,813 Clifty Creek – Trimble County 345 kV Rockport – Jefferson 765 kV 7 2,412 Not Applicable 3,884
    8 1 2,074 Mt Olive – Vienna 115 kV Mt Olive – Eldorado 500 kV 8 482 2,000 CLEC, AMMO, EES 1,602
    9 1 3,320 Junction City to Bernice 115 kV Mount Olive to El Dorado 500 kV 9 3,320 Not Applicable 3,585
    Table 6.1-2: 2015-2016 Planning Year Capacity Import Limits
    Figure 6.1-3: 2015-2016 Capacity Import Limit Map

    Figure 6.1-3: 2015-2016 Capacity Import Limit Map

     
    Zone 15-16 Limit (MW) Monitored Element Contingent Element Figure 6.1-4 Map ID Initial Limit (MW) Generation Redispatch Details 14-15 Limit (MW)
    MW Area
    1 604 Lakefield – Dickinson 161 kV Webster 345 kV Station 1 604 Not Applicable 286
    2 1,516 Zion Station – Zion Energy Center 345 kV Pleasant Prairie – Zion 345 kV 2 1,167 1,188 WEC, MGE, ALTE, CE 1,924
    3 1,477 Byron – Cherry Valley 345 kV Red Byron – Cherry Valley 345 kV Blue 3 648 1,610 MEC, NIPS, WEC 1,875
    4 4,125 Hutsonville – Robinson 138 kV Newton – Robinson 138 kV 4 4,125 Not Applicable 1,961
    5 0[3] Palmyra 345/161 kV Transformer Hills – Sub T – Louisa 345 kV 5 0 Not Applicable 1,350
    6 2,930 Clifty Creek – Trimble County 345 kV Rockport – Jefferson 765 kV 6 2,930 Not Applicable 2,246
    7 4,804 Benton Harbor 345/138 kV Transformer Benton Harbor – Cook 345 kV 7 4,799 53 METC, ITCT 4,517
    8 3,022 Woodward – Stuttgart Ricusky 230 kV Keo – West Memphis 500 kV 8 2,767 2,000 EAI 3,080
    9 3,239 White Bluff – Keo 500 kV Sheridan – Mabelvale 500 kV 9 951 2,000 EES, CLEC 3,616
    Table 6.1-3: 2015-2016 Planning Year Capacity Export Limits
     Figure 6.1-4: 2015-2016 Capacity Export Limit Map

    Figure 6.1-4: 2015-2016 Capacity Export Limit Map

    MTEP and Capacity Import and Export Limit Alignment

    The Capacity Import and Export Limits are deliverables to the PRM for the Planning Resource Auction and are considered in the development of the MTEP. The initial limits, the limits before applying additional generation redispatch, have been identified in the LOLE study for the 2015-2016 Planning Year and the 2016-2017 Near-Term planning horizon. Three MTEP projects are anticipated to mitigate or alleviate the constraint identified as a limiting element in the LOLE study (Table 6.1-6).
    Year LRZ CEL or CEL Monitored Element Contingent Element MTEP Project ID Target Appendix Project Name Min Expected ISD
    15-16, 16-17 7 CIL Battle Creek to Argenta 345 kV Argenta to Tompkins 345 kV 4509 A in MTEP15 Argenta – Battle Creek 345kV Sag Remediation and Station Equipment 12/31/2016
    15-16, 16-17 5, 9 CIL & CEL White Bluff to Keo 500 kV Sheridan to Mabelvale 500 kV 8940 A in MTEP15 White Bluff – Keo 500 kV: Upgrade terminal equipment 12/1/2016
    15-16, 16-17 2 CIL Turkey River to Stoneman 161 kV Seneca to Genoa 161 kV 3828 A in MTEP13 Lore-Turkey River-Stoneman 161kV Rebuild 12/31/2015
    Table 6.1-6: Directly Impacting MTEP Projects 
    LOLE study CIL and CEL constraints outlined have MTEP Projects near or at one of the facilities listed as a constraint. These projects are not expected to fully mitigate or alleviate the constraint, rather they may affect the identified constraint either positively or negatively (Table 6.1-7).
    Year LRZ CEL or CEL Monitored Element Contingent Element MTEP Project ID Target Appendix Project Name Min Expected ISD
    15-16, 16-17 7 CIL & CEL Battle Creek to Argenta 345 kV Argenta to Tompkins 345 kV 4149 A in MTEP13 Argenta – Tallmadge 345 kV Sag Remediation 12/31/2015
    15-16, 16-17 7 CIL & CEL Battle Creek to Argenta 345 kV Argenta to Tompkins 345 kV 662 A in MTEP09 Weeds Lake 3/31/2016
    16-17 1 CEL Briggs Road to Mayfair 161 kV La Crosse to Marshland 161 kV 4360 A in MTEP14 Rebuild Marshland-Briggs Road 161 kV 12/11/2015
    16-17 1 CEL Briggs Road to Mayfair 161 kV La Crosse to Marshland 161 kV 7664 A in MTEP15 Rebuild Briggs Road-La Crosse Tap 161 kV 6/1/2016
    16-17 1 CEL Briggs Road to Mayfair 161 kV La Crosse to Marshland 161 kV 4685 A in MTEP14 Install Tremval 2nd 161-69 kV Transformer 12/15/2016
    16-17 7 CEL Dorr Corners Junction to Beals 138 kV Line Argenta to Talmadge 345 kV 8067 A in MTEP15 Beals Road 138 kV Station Equipment Replacement 6/1/2017
    15-16 4 CEL Hutsonville to Robinson Marathon North Tap 138 kV Newton to Robinson Marathon 138 kV 7800 A in MTEP15 Newton-Robinson-1 138 kV Reconductoring 12/1/2015
    15-16, 16-17 8, 9 CIL & CEL Montgomery to Clarence 230 kV Montgomery to Winnfield 230 kV 2996 A in MTEP14 Montgomery-Spencer Creek-Palmyra Tap-Sub T-Hills – Increase Ground Clearance 6/1/2015
    15-16, 16-17 6 CIL Newton to Casey 345 kV Casey to Neoga 345 kV 4481 A in MTEP14 Casey, West Terminal Equipment 11/15/2015
    15-16, 16-17 3, 4, 5 CIL & CEL Palmyra Transformer Montgomery to Spencer 345 kV 3017 A in MTEP11 Proposed MVP Portfolio 1 – Palmyra Tap -Quincy-Meredosia – Ipava & Meredosia-Pawnee 345 kV Line 11/15/2015
    15-16 4 CIL Tazewell 138/345 kV Xfr 1 Tazewell 138/345 kV Xfr 2 7824 A in MTEP15 Tazewell 345 kV Breaker Replacements 9/15/2015
    16-17 4, 6 CIL & CEL West Point to Lafayette 230 kV Eugene to Caysub 345 kV 4037 A in MTEP13 Lafayette 230 kV Ring Bus – Ph. 2 12/31/2016
    16-17 4, 6 CIL & CEL West Point to Lafayette 230 kV Eugene to Caysub 345 kV 3561 A in MTEP14 Lafayette 230-W. Laf. 138 kV Rebuild 6/1/2015
    15-16, 16-17 2, 7 CIL & CEL Zion Energy Center to Zion Station 345 kV Zion Station to Pleasant Prairie 345 kV 3898 A in MTEP13 Reconductor Pleasant Prairie-Zion 345 kV 12/31/2020
    15-16, 16-17 2, 7 CIL & CEL Zion Energy Center to Zion Station 345 kV Zion Station to Pleasant Prairie 345 kV 8065 A in MTEP15 Construct Southeast Wisconsin – Northeast Illinois 345 kV transmission reinforcement 12/31/2020
    Table 6.1-7: Potential Impacting MTEP Projects

    Wind Capacity Credit

    A wind capacity credit of 14.7 percent was established for the 2015-2016 planning year by determining the Effective Load Carrying Capability (ELCC) of wind resources. The wind capacity credit increased 0.6 percent from the wind capacity credit of 14.1 percent established in the 2014-2015 Planning Year (Table 6.1-5). For more information, refer to the complete 2015 Wind Capacity Credit Report[4].

    Table 6.1-5: MISO Local Resource Zones and distribution of wind capacity

    For more information related to the LOLE study please refer to the Planning Year 2015 LOLE study report.
    [1] The 15-16 Limit represents the limit after redispatch has been considered. [2] The Initial Limit represents the limit before considering redispatch. [3] Limit is initially determined by transmission constraint listed above, then is limited by generation
  • MTEP15 Chapter 6.2: Long Term Resource Assessment

    The Long-Term Resource Assessment (LTRA) examines the balance between projected resources and the projected load. These resources are compared with Planning Reserve Margin Requirement (PRMR) to calculate a projected surplus or shortfall.

    MISO forecasts the reserve margin will drop below the PRMR of 14.3 percent beginning in 2020, and will remain below the PRMR for the rest of the assessment period (Table 6.2-1). Falling below the PRMR signifies that the MISO region is projected to operate at a reliability level lower than the one-day-in-10 standard in 2020 and beyond. MISO anticipates the projected margin shortfall will change significantly as Load Serving Entities and state commissions solidify future capacity plans.

    This is an expected result, as 91 percent of the load in the MISO footprint is served by utilities with an obligation to serve. This obligation is reflected as a part of state and locally jurisdictional integrated resource plans that only become certain upon the receipt of a Certificate of Public Convenience and Need (CPCN). Five years is sufficient lead time for Load Serving Entities to plan, build and operate new resources to meet the projected shortfall in 2020 and beyond.

    In GW (ICAP) PY 2016/17 PY 2017/18 PY 2018/19 PY 2019/20 PY 2020/21 PY 2021/22 PY 2022/23 PY 2023/24 PY 2024/25 PY 2025/26
    (+) Existing Resources 151.9 151.5 151.2 150.5 150.4 150.4 150.4 150.4 150.4 150.4
    (+) New Resources 0.7 2.1 2.1 2.5 2.6 2.6 2.6 2.6 2.6 2.6
    (+) Imports 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3
    (-) Exports 3.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8
    (-) Low Certainty Resources 0.6 0.5 1.1 1.0 2.3 3.0 3.7 4.4 5.7 8.6
    (-) Transfer Limited 3.4 3.0 2.6 1.9 1.6 1.4 1.2 1.0 0.8 0.6
    Available Resources 149.1 151.5 151.1 151.5 150.5 150.1 149.6 149.1 148.0 145.3
     
    Demand 128.9 130.4 131.2 132.4 133.3 134.1 134.9 135.9 136.6 137.7
    PRMR 147.3 149.0 150.0 151.3 152.3 153.2 154.2 155.3 156.2 157.4
     
    PRMR Shortfall 1.7 2.6 1.1 0.2 -1.8 -3.2 -4.6 -6.2 -8.2 -12.2
    Reserve Margin Percent (%) 15.6% 16.3% 15.1% 14.5% 13.0% 11.9% 10.9% 9.7% 8.3% 5.5%
    Table 6.2-1: MISO anticipated PRMR details (cumulative)

    The anticipated PRMR shows significant improvements from the 2014 LTRA results, which projected a shortfall against the reserve requirements of 2.3 GW in 2016. The conclusions from the long-term resource assessments are:

    • All zones within MISO are sufficient from a resource adequacy point of view in the near term, when considering available capacity and transfer limitations. Regional shortages in later years may be rectified by the utilities and, as such, do not cause immediate concern.
    • The change in LTRA results was driven primarily by a combination of an increase in resources committed to serving MISO load and a decrease in load forecasts.
    • The increase in committed resources reflects action taken by MISO load-serving entities and state regulators to address potential capacity shortfalls.
    • MISO anticipates that each zone within the MISO footprint will have sufficient resources within their boundaries to meet their Local Clearing Requirements or the amount of their local resource requirement, which must be contained within their boundaries.
    • Several zones are short against their total zonal reserve requirement, when only resources within their boundaries or contracted to serve their load are considered. However, those zones have sufficient import capability and the MISO region has sufficient surplus capacity in others zones to support this transfer. Surplus-generating capacity for zonal transfers within MISO could become scarce in later years if no action is taken in the interim by MISO load-serving entities.

    Policy and changing generation trends continue to drive new potential risks to resource adequacy, requiring continued transparency and vigilance to ensure long-term needs.

    • MISO projects that reserve margins will continue to tighten over the next five years, approaching the reserve margin requirement
    • Operating at the reserve margin creates a new operating reality for MISO members where the use of all resources available on the system and emergency operating procedures are more likely. This reality will lead to a projected dependency in the use of Load Modifying Resources (LMR), such as Behind-the-Meter Generation (BTMG)and Demand Response (DR).

    Assumptions

    At the end of 2013 MISO and Organization of MISO States (OMS) conducted a Resource Adequacy survey of load-serving entities to help bridge the gap of limited visibility that exists between the annual Module E Tariff process and Forward Resource Assessment. MISO finished the survey in June, 2014, and it was instrumental in the development of the Long-Term Resource Assessment and the Resource Adequacy outlook for the MISO region.

    Demand Growth

    In 2016, MISO anticipates that the MISO Region’s coincident demand will be 128,885 MW, which is a 50/50 weather-normalized load forecast.

    Load-serving entities submit demand forecasts for the upcoming 10 years. MISO utilizes these forecasts to calculate a MISO business-as-usual load growth. Based on these forecasts, MISO anticipates a system-wide average growth rate of 0.8 percent for the period from 2015 to 2025.

    In 2016, MISO anticipates that the MISO Region’s coincident demand is projected to be 128,885 MW, which is a 50/50 weather-normalized load forecast

    Resources

    In 2016, MISO expects a total of 143,877 MW of Anticipated Capacity Resources to be available on-peak. MISO’s current registered capacity (nameplate) of 173,289 MW steps down to Existing-Certain Capacity Resources of 141,100 MW by accounting for summer on-peak generator performance, transmission limitations and energy-only capacity (Existing-Other Capacity Resources). MISO only relies on 141,100 MW towards its PRMR to meet a loss-of-load expectation of one day in 10 years.

    In 2016, MISO expects a total of 143,877 MW of Anticipated Capacity Resources to be available on-peak

    BTMG, Interruptible Load (IL), Direct Control Load Management (DCLM) and Energy Efficiency Resources (EER) are eligible to participate as registered LMRs. All of these are emergency resources available to MISO only during a Maximum Generation Emergency Event Step 2b per MISO’s Emergency Operating Procedures. MISO assumes the 4,400 MW of BTMG dropping to 4,200 in 2020 and 6,400 MW of LMR DR that was qualified in the 2015 Planning Resource Auction to be available throughout the assessment period.

    This year, MISO and OMS completed the second iteration of the Resource Adequacy Survey. In the survey, resources that were identified to have a low certainty of serving load were not included (Table 6.2-1).

    Through the Generator Interconnection Queue (GIQ) process, MISO anticipates 2,584 MW of future firm capacity additions and uprates to be in-service and expected on-peak during the assessment period (Figure 6.2-1). This is based on a snapshot of the GIQ as of June 2015 and is the aggregation of active projects with a signed Interconnection Agreement.

    Figure 6.2-1: Anticipated resource additions and uprates (cumulative) in the MISO Region

    Figure 6.2-1: Anticipated resource additions and uprates (cumulative) in the MISO Region

    Imports and Exports

    MISO assumes a forecast of 3,157 MW of capacity from outside of the MISO footprint to be designated firm for use during the assessment period and cannot be recalled by the source transmission provider. This capacity was designated to serve load within MISO through the Module E process for summer 2015. It’s assumed that the firm imports continue at this level for the assessment period. MISO assumes a forecast of 3,806 MW of firm capacity exports in year 2016 to regional transmission operator PJM based on PJM Base Residual Auction cleared results. Exports are projected to decrease to 2,780 MW in 2017 and remain at that level for the rest of the assessment period.

    When comparing reserve margin percent numbers between Table 6.2-1 and the NERC LTRA, the percent for each planning year will be slightly lower in the NERC LTRA because of differences in the reserve margin percent calculation. MISO’s resource adequacy construct counts DR as a resource while the NERC calculates DR on the demand side. While the percent will be slightly different, the absolute GW shortfall/surplus is comparable between the two.

     

  • MTEP15 Chapter 6.3 Gas-Electric Coordination

    Over the past several years, MISO has made significant progress on the gas-electric coordination front, enhancing system awareness, furthering coordinating operations, and facilitating cross-industry education and communication. The addition of the PLEXOS Integrated Energy Model to MISO’s planning toolkit represents another step towards better understanding and planning for future gas-electric system interactions.

    This chapter provides historical context for and details on current gas-electric initiatives at MISO in the realm of long-term system planning.

    The addition of the PLEXOS Integrated Energy Model to MISO’s planning toolkit represents another step towards better understanding and planning for future gas-electric system interactions

    Electric and Natural Gas Coordination Task Force

    MISO’s gas-electric coordination efforts originated in 2011 with a series of investigations into the ability of natural gas infrastructure to serve growing demand. The findings from these analyses, published in 2012, spurred an ongoing conversation with MISO stakeholders and the natural gas industry. While MISO held preliminary meetings across the footprint to discuss gas-electric interdependency, the Federal Energy Regulatory Commission (FERC) planned its own set of regional discussions on the topic. The takeaways from these forums and the MISO zonal meetings signaled the need for a separate MISO stakeholder body to address gas-electric interdependency. In response, MISO and its stakeholders established the Electric and Natural Gas Coordination Task Force (ENGCTF) in October 2012.

    Shortly after its formation, the task force initiated a process of gas-electric issue identification and prioritization. Cross-industry teams formed to draft Issue Summary Papers, intended to guide discussion within the task force and provide recommendations on high priority issues, including:

    • System awareness and coordinated operations with the gas industry
    • Cross-industry communications
    • The misalignment of gas and electric industry market timelines

    The ENGCTF also devoted a significant amount of time over the past few years to cross-industry education, increasing understanding between the gas and electric industries of each other’s regulatory, business, operational and planning constructs. The group continues to provide a forum for discussion of key gas-electric topics.

    Gas-Electric Coordination and Long-Term System Planning

    While many of MISO’s current gas-electric coordination efforts focus on operational or market design issues, some of the earliest aimed to better understand the mid- to long-range impact of regulatory, technological and economic developments on future gas-electric system interactions. Specifically, in late 2011, MISO commissioned EnVision Energy to study historical flows and future capacity availability on natural gas pipelines in the Midwest. The results of these analyses (Phase 1, Phase 2 ,Phase 3) highlighted the potential need for gas infrastructure build-out in the MISO North and Central Regions, in a scenario with increasing demand for gas from electric generators.

    The issue of gas infrastructure adequacy was revisited by MISO in 2013. The new analysis featured an expanded study footprint, including the newly integrated South Region, and an enhanced methodology, adding a dynamic pipeline modeling component. Study findings indicated adequate pipeline capacity for the MISO footprint in the near term under a base-demand scenario, with localized exceptions in MISO’s North and Central Regions. These results were attributed to significant and fast-paced developments in the gas industry, including 1) new and increasing supplies from shale gas basins, driving major changes in pipeline flow patterns across the country, and 2) additions to and increasing interconnectivity of natural gas infrastructure. The study report also identified opportunities for future progress on gas-electric coordination, including several recommendations aligned with the goals of the ENGCTF.

    In addition to commissioning studies of long-term gas infrastructure adequacy, MISO also engaged in the Eastern Interconnection Planning Collaborative (EIPC) study of the gas-electric interface. This effort spanned several years and encompassed four major targets:

    • Target 1: Baseline assessment of electric-natural gas infrastructure in the study footprint
    • Target 2: Evaluation of the capability of the natural gas systems to meet long-term gas demand
    • Target 3: Evaluation of natural gas system contingencies
    • Target 4: Review of operational/planning issues affecting the availability of dual-fuel generation

     

    MISO was one of a group of planning authorities participating in the study, providing guidance on scope and methodology, with input from the ENGCTF.

    At a high level, the EIPC study identified few issues of concern with respect to gas-electric interfaces in MISO, resulting from an ample and interconnected pipeline network throughout the footprint, as well as access to numerous gas producing basins. The study also concluded that increasing gas demand in the next five to 10 years, driven by coal retirements and sustained low gas prices, may call for additional efforts to ensure reliability for gas-fired generators in some parts of the MISO footprint.

    Both the MISO-commissioned studies and the EIPC study examined electric and natural gas system interactions using iterative processes. First, a simulation of the electric system was carried out with static assumptions about gas system operations, producing a set of electric system results. Then, a simulation of the gas system was carried out with static assumptions about the electric system, producing a set of gas system results. This description is a simplified characterization of the modeling processes used in these studies, but the hand-offs described are inherent in modeling gas and electric system operations with separate tools.

    While there are advantages to using separate gas and electric models to answer certain questions of gas-electric system operations, there may also be benefits to modeling dynamic system interactions. As MISO plans for a future with increasing reliance upon natural gas, it recognizes that new tools may be needed to understand and plan for the growing interdependency of the two systems.

    Using PLEXOS for Gas-Electric Modeling at MISO

    The PLEXOS Integrated Energy Model is an Energy Exemplar optimization platform for energy market simulation and analysis. MISO has used the production cost functionality of the PLEXOS model (electric data only) for two major studies, including the Manitoba Hydro-Wind Synergy Study and the Minnesota Renewable Energy Integration and Transmission Study (MRITS).

    The gas model is a relatively new addition to the Integrated Energy Model. Its initial release included state-level representation of gas production, storage, demand and transportation for the US and Canada. The second iteration of the model disaggregated these elements into separate components, interconnected via hundreds of gas nodes. Future versions of the gas model may incorporate additional granularity, such as representation of gas contracts.

    The outputs of production cost simulation for the gas portion of the model can be grouped into two main buckets:

    • Physical (congestion) metrics: the duration, location and magnitude of pipeline congestion
      • For comparison, the electric-side outputs of the model include transmission line flows and binding hours.
    • Economic (cost/price) metrics: quantification of the cost to produce and transport gas; gas spot prices are provided at each gas node for every interval of the simulation
      • For comparison, the electric-side outputs of the model include locational marginal prices (LMPs).

     

    The outputs for the electric model approximately parallel those of the gas model (see Figure 6.3-2) and are similar to the outputs of PROMOD, another production cost simulation tool used by MISO for long-term transmission planning. Gas and electric infrastructure interconnect in the Integrated Model via gas-fired electric generators.

    Over the past several years, MISO has made significant progress on the gas-electric coordination front, enhancing system awareness, furthering coordinated operations, and facilitating cross-industry education and communication. The addition of the PLEXOS Integrated Energy Model to MISO’s planning toolkit represents another step towards better understanding and planning for future gas-electric system interactions.

    This chapter provides historical context for and details on current gas-electric initiatives at MISO in the realm of long-term system planning.

    Figure 6.3-2: High-level inputs and outputs for co-optimized gas-electric dispatch in PLEXOS

    The results of electric production cost modeling provide insights into long-term transmission system utilization and are used to inform transmission solution development in MISO’s planning processes. Similarly, the outputs of integrated production cost modeling may be able to provide insights into long-term trends not only for electric infrastructure but also for gas infrastructure.

    MISO’s ongoing analysis of the Clean Power Plan (CPP) (see Chapter 7.4, EPA Regulations – Carbon Study) incorporates this proof-of-concept gas-electric simulation tool and tests its potential to inform long-term gas infrastructure expansion needs. The application of the PLEXOS gas-electric model in MISO’s study of the CPP is a first-of-its-kind effort and MISO acknowledges the significant learning curve associated with this endeavor. MISO plans to collaborate with and leverage the expertise of its stakeholders and the broader industry throughout the process.

  • MTEP15 Chapter 6.4 Seasonal Resource Assessment

    MISO conducts seasonal resource assessments for the winter months of December, January and February as well as for summer months of June, July and August. Seasonal assessments primarily evaluate the near-term system performance expected, and prepare the operators with a focused look at the upcoming season. The MISO resource assessments coincide with NERC seasonal reliability assessments and MISO operational readiness workshops held prior to the assessment’s season.

    The finding showed that the projected capacity levels exceed the Planning Reserve Margin Requirement in both the 2014-2015 winter and 2015 summer seasons, with adequate resources to serve load.

    Seasonal Assessment Methods

    MISO studies multiple scenarios at varying capacity resource levels, expected demand levels and forced outage rates. In order to align with intra-RTO expected dispatch, only 1,000 MW above the MISO South load and reserve margin were counted toward aggregate margins at coincident peak demand in all of the projected scenarios.

    MISO coordinates extensively with neighboring reliability coordinators as part of the seasonal assessment and outage coordination processes, and via scheduled daily conference calls and ad-hoc communications as need arises in real-time operations. There is always the potential for a combination of higher loads, higher forced outage rates and fuel limitations. In the summer, unusually hot and dry weather can lead to low water levels and/or high water temperatures. This can impact the maximum operating capacity of thermal generators that rely on water resources for cooling, leading to added deratings in real time and lowering functional capacity. These situations would be resolved through existing procedures depending on the circumstances, and several scenarios are studied for each season to project the possible reserve margins expected.

    Demand

    Based on 20 years of historic actual load data, MISO calculates a Load Forecast Uncertainty (LFU) value from statistical analysis to determine how likely actual load will deviate from forecasts. A normal distribution is created around the 50/50 forecast based on a standard deviation equal to the LFU of the 50/50 forecast. This curve represents all possible load levels with their associated probability of occurrence. At any point along the curve it is possible to derive the percent chance that load will be above or below a load value by finding the area under the curve to the right or left of that point. MISO chooses the 90th percentile for the High Load scenarios. For more information regarding this analysis, refer to the Planning Year 2015 LOLE Study.

    Demand Reporting

    MISO does not forecast load for the Seasonal Resource Assessments. Instead, Load Serving Entities (LSEs) report load projections under the Resource Adequacy Requirements section (Module E-1) of the MISO Tariff. LSEs report their annual load projections on a MISO Coincident basis as well as their Non-Coincident load projections for the next 10 years, monthly for the first two years and seasonally for the remaining eight years. MISO LSEs have the best information of their load; therefore, MISO relies on them for load forecast information.

    For these studies, MISO created a Non-Coincident and a Coincident peak demand on a regional basis by summing the annual peak forecasts for the individual LSEs in the larger regional area of interest.

    Figure 6.4-1: Winter 2014-2015 Projected Reserve Margin scenarios (GW)

    Figure 6.4-1: Winter 2014-2015 Projected Reserve Margin scenarios (GW)

    2014-2015 Winter Overview

    For planning year 2014-2015, MISO’s Planning Reserve Margin Requirement (PRMR) was 14.8 percent. For the 2014-2015 winter peak hour, MISO expected adequate resources to serve load, with a NERC-reported base projected reserve margin of 43.2 percent, which far exceeds the PRMR of 14.8 percent. The winter scenarios project the reserve margin to be in the range of 35.0 to 45.1 percent. Figure 6.4-1 represents an overview of these scenarios.

    MISO’s 50/50 coincident peak demand for the 2014-2015 winter season was forecasted to be 103,238 MW including transmission losses, with 147,793 MW of capacity to serve MISO load during the 2014-2015 winter season. Excluded from the capacity are 3,811 MW of MISO South resources to align with the 1,000 MW intra-RTO contract path.

     

    2014-2015 Winter Rated Capacity

    For the 2014-2015 winter season, MISO projected 147,793 MW of existing certain capacity to serve MISO load during the winter. The capacity includes 1,614 MW of Behind-the-Meter Generation (BTMG) and 3,645 MW of Demand Resource (DR) programs, with 2,022 MW of Net Firm Imports. MISO expected 1,070 MW of wind capacity to be available to serve load for the winter.

    MISO arrived at the Winter Rated Capacity value by reducing the Nameplate Capacity of its market footprint by multiple variables. The majority of the derates expected at-peak are due to resource interconnection limitations of 6,160 MW; thermal unit winter output reductions of 4,796 MW; and reductions due to the Effective Load Carrying Capability of wind resources of 10,052 MW. Capacity from the South, equal to its load and reserve margin requirement, was included in the regional total. Additionally, it assumed that 1,000 MW of excess capacity transferred to the North/Central region of the footprint.

    For more information regarding methodology and assumptions of the Winter Rated Capacity, refer to Appendix A.2 of the 2014-2015 Winter Resource Assessment.

    Winter Reserve Margin Scenarios

    MISO’s projected 2014-2015 MISO Winter Rated Capacity varies by scenario (Figures 6.4-2 through 6.4-6). MISO chose the 90th percentile of the normal distribution around a 50/50 load forecast for the High Load scenarios, which was 110,597 MW for the 2014-2015 winter. For more information regarding each scenario, refer to Appendix A.3 of the 2014-2015 Winter Resource Assessment.

    The Anticipated Scenario contains additional assumptions (Figure 6.4-3). MISO expects that any Energy Resource without firm point-to-point Transmission Service Rights will serve load locally, termed Energy Only. The portion of Energy Only from the MISO South region is excluded from the calculation to align with 1,000 MW contract path limitation.

     

    In real-time, during normal operating conditions, MISO must carry Operating Reserves above load to maintain system reliability. The amount of Operating Reserves required to clear on a daily basis for the 2014/2015 winter season was 2,400 MW, which is called on as a last resort before load shed (Figure 6.4-4). These reserves are made up of a combination of Regulating Reserves, Spinning Reserves and Supplemental Reserves.

    The High Demand, High Outage Scenario has added assumptions (Figure 6.4-5). Beginning with the Anticipated Reserves from the Anticipated Scenario (Figure 6.4-3), the load is increased to show the higher load from a 90/10 forecast. A higher forced outage rate is assumed, using the highest historical forced outage rate applied to the capacity resources available. An extreme forced outage rate is applied to the Extreme Scenario (Figure 6.4-6), based on information from the polar vortex of the 2013-2014 winter.

     

     

    2015 Summer Overview

    For planning year 2015-2016, MISO’s PRMR is 14.3 percent, which is 0.5 percentage points lower than the previous year’s requirement of 14.8 percent. During the 2015 summer peak hour, MISO expected adequate resources to serve load, with a NERC-reported base projected reserve margin as 18.0 percent, which exceeds the requirement of 14.3 percent by 3.7 percentage points. The summer scenarios project the reserve margin to be in the range of 14.4 to 20.1 percent (Figure 6.4-7).

    MISO’s 50/50 coincident peak demand for the 2015 summer season was forecasted to be 127,319 MW including transmission losses, with 150,270 MW of capacity to serve MISO load. Excluded from the capacity are 3,806 MW of MISO South resources to align with the 1,000 MW intra-RTO contract path.

    2015 Summer Rated Capacity

    For 2015, MISO projected 150,270 MW of capacity to serve MISO load during the 2015 summer season. The capacity includes 4,413 MW of Behind-the-Meter Generation and 5,938 MW of Demand Resource programs, while removing 56 MW of Net Firm Exports. MISO expected 1,325 MW of wind capacity to be available to serve load this summer. Capacity from the South equal to its load and reserve margin requirement was included in the regional total. Additionally, 1,000 MW of excess capacity was assumed to be transferred to the North/Central region of the footprint.

    MISO arrived at the Summer Rated Capacity value by reducing the Nameplate Capacity of its market footprint by multiple variables. The majority of the derates expected at-peak are due to resource interconnection limitations (3,616 MW); thermal unit summer output reductions (11,765 MW); and reductions due to the Effective Load Carrying Capability of wind resources (9,534 MW). Also, any MISO South capacity over the total of South Load, South reserve margin requirement, and 1,000 MW of contract path was not included in the regional value. This means that 3,806 MW of MISO South excess capacity was excluded from the calculation to align with 1,000 MW contract path limitation.

    For more information regarding methodology and assumptions of the Summer Rated Capacity, refer to Figure 6.4-13.

    Reserve Margin Scenarios

    MISO’s projected 2015 MISO Summer Rated Capacity varies by scenario (Figures 6.4-8 through 6.4-10). MISO chose the 90th percentile of the normal distribution around a 50/50 load forecast for the High Load scenarios, which was 133,599 MW for the 2015 summer. For more information regarding each scenario, refer to the MISO 2015 Summer Resource Assessment.

    The Probable Scenario uses additional assumptions (Figure 6.4-9). MISO expects that any Energy Resource without firm point-to-point Transmission Service Rights will serve load locally, termed Energy Only. The portion of Energy Only from the MISO South region is excluded from the calculation to align with 1,000 MW contract path limitation. In addition, 0.2 GW of capacity is included from provisional wind that is connected to the system but with an incomplete interconnection process. Finally, any units designated as System Support Resources (SSR) or Under Study through the Attachment Y process are considered available, as well as units that received a waiver from participating in the Planning Resource Auction but will still run for the summer.

    The High Demand, High Outage scenario has added assumptions (Figure 6.4-10). Beginning with the Probable Reserves from the Probable Scenario (Figure 6.4-9), the load is increased to show the higher load from a 90/10 forecast. Also a higher forced outage rate is assumed, using the highest historical forced outage rate applied to the capacity resources available.

    2015 Summer Risk Assessment

    MISO performs a probabilistic assessment on the region to determine the percent chance of utilizing Load Modifying Resources and Operating Reserves or having to curtail firm load. A risk profile is generated from this analysis (Figure 6.4-11).

    It is always possible for a combination of higher loads, higher forced outage rates, fuel limitations, low water levels and other factors to lead to the curtailment of firm load. The Loss of Load Expectation (LOLE) model that MISO utilizes for PRMR takes into account the uncertainties associated with load forecasts (i.e., 50/50 v. 90/10) and generation outages (both forced and scheduled).

    The chance of realizing an event is where the risk profile intersects the event range (Figure 6.4-11). As shown, the probabilistic analysis indicated a 74.1 percent chance of MISO calling a Maximum Generation Emergency Event Step 2b to access Load Modifying Resources; a 7.8 percent chance of initiating further steps to access Operating Reserves; and a 2.7 percent chance of curtailing firm load during 2015 summer peak hour.

    The reserves available in the Probable Scenario are shown after forced outages are applied, showing the amount of Generation, Behind-the-Meter Generation, Demand Resource and Operating Reserves expected (Figure 6.4-12). In real-time, during normal operating conditions, MISO must carry Operating Reserves above load to maintain system reliability. The amount of Operating Reserves required to clear on a daily basis for the 2015 summer season was 2,400 MW, which is called on as a last resort before load shed. These reserves are made up of a combination of Regulating Reserves, Spinning Reserves and Supplemental Reserves.

    For more information regarding the risk assessment methodology, assumptions and variables, refer to Appendix A.1 of the MISO 2015 Summer Resource Assessment.

    MISO Summer Rated Capacity Methodology

    The calculation of MISO Summer Rated Capacity resources is easier to describe by separating into thirteen parts (Figure 6.4-13) and as described in the following list. Separation of the Winter Rated Capacity is similar, with additional details found in the MISO 2014-2015 Winter Resource Assessment.

    1. Nameplate capacity is the summation of the maximum output from the latest commercial model. This reflects the amount of registered generation available internal to MISO.
    2. Inoperable resources is the summation of approved mothballed or retired units determined through the Attachment Y process, which are still represented in the latest commercial model.
    3. Thermal derates on-peak is the summation of differences in unit nameplate capacities and the latest Generator Verification Test Capacity (GVTC) results, excluding inoperable resources.
    4. All other derates is the summation of differences in non-wind intermittent resource nameplate capacities and the resource averages of historical summer peak performance, excluding inoperable resources.
    5. Transmission-limited resources is the summation of differences in GVTC and the unit’s Total Interconnection Service (TIS) rights based on latest unit deliverability test results. Transmission-limited resources for wind is the summation of differences in nameplate capacity and TIS.
    6. Not-in-service units and provisional wind: Units that are registered in the latest commercial model, but are not in service yet; the wind units that are connected to the system but their interconnection process is not completed yet.
    7. Wind derates on-peak is the summation of the differences in wind unit Nameplate Capacities and the unit wind capacity credit, which is determined based on the Effective Load Carrying Capability of wind. This excludes Inoperable Resources and Transmission-Limited MWs.
    8. Energy-only resources are the ones that have Energy Resource Integration Rights (ERIS) without a firm point to point Transmission Service Right.
    9. Scheduled maintenance: Scheduled generator outages from June 1, 2015 through August 31, 2015 were pulled from MISO’s Control Room Operator’s Window (CROW) outage scheduler on March 17, 2015. The data pulled met the following criteria: 1. Mapped to the latest commercial model; 2. Outage Request Status is equal to Active, Approved, Pre-Approved, Proposed, Study, or Submitted; 3. Request priority is equal to planned; 4. Equipment request type is equal to Out of Service (OOS) or “Derated To 0 MW.” This calculation amounts to an expected scheduled maintenance of 574 MW. In order to calculate the expected scheduled outages on peak, MISO calculates the amount of outages on a daily basis assuming that if a unit is out for as little as one hour, that unit will be out for that entire day. The highest amount of outages during the month of July is assumed to be equal to the amount of outage during summer peak conditions.
    10. MISO anticipated the net firm interchange to be exporting 56 MW for the 2015 summer.
    11. 3,806 MW of MISO South resources were excluded from the available capacity to align with 1,000 MW intra-RTO contract path.
    12. Behind-the-Meter Generation is the summation of approved and cleared load-modifying resources identified as Behind-the-Meter Generation through the Resource Adequacy (Module E) process. Based on the planning year 2015-2016 Planning Resource Auction, 4,413 MW of BTMG cleared to be available for the 2015 summer season.
    13. Demand resource: MISO currently separates contractual demand resource into two separate categories, Direct Control Load Management (DCLM) and Interruptible Load (IL).IL is the magnitude of customer demand (usually industrial) that, in accordance with contractual arrangements, can be interrupted at the time of peak by direct control of the system operator (remote tripping) or by action of the customer at the direct request of the system operator. The amount of registered and cleared load-modifying resources identified as demand resource through the Resource Adequacy (Module E) process is 5,938 MW for the 2015 summer season. DCLM is the magnitude of customer service (usually residential) that can be interrupted at the time of peak by direct control of the applicable system operator. DCLM is typically used for “peak shaving.” In MISO, air conditioner interruption programs account for the vast majority of DCLM during the summer months.