MTEP15 Book 4: Regional Energy Information – View All

  • MTEP15 Chapter 9.1: MISO Overview

    MISO is a not-for-profit, member-based organization that administers wholesale electricity and ancillary services markets. MISO provides customers a wide array of services including reliable system operations; transparent energy and ancillary service prices; open access to markets; and system planning for long-term reliability, efficiency and to meet public policy needs.
    By improving grid reliability and increasing the efficient use of generation, MISO saves the average residential customer $40 to $56 a year, at an annual expense of $5 per customer
    MISO has 51 Transmission Owner members with more than $31.4 billion in transmission assets under MISO’s functional control. MISO has 122 non-transmission owner members that contribute to the stability of the MISO markets. The services MISO provides translate into material benefits for members and end users. By improving grid reliability and increasing the efficient use of generation, MISO saves the average residential customer $40 to $56 a year at an annual expense of $5 per customer. The MISO 2014 Value Proposition explains the various components of this benefits calculation. The value drivers are:
    1. Improved Reliability, which captures the value of MISO’s broader regional view and state-of-the art reliability tool set. Improved Reliability in the region is measured by the availability of the transmission system.
    2. Dispatch of Energy, which quantifies the real-time and day-ahead energy market’s use of security constrained unit commitment and centralized economics dispatch. Improved Reliability and Dispatch of Energy optimize the use of all resources within the region based on bid and offers by market participants.
    3. Regulation, which represents the savings created by use of MISO’s regulations market. With the regulation market in place, the amount of regulation required within the MISO footprint dropped significantly. The drop results from a regional move to a centralized common footprint regulation target rather than several non-coordinated regulation targets.
    4. Spinning Reserve, which includes the formation of the Contingency Reserve Sharing Group and the implementation of the Spinning Reserves Market. Both aspects contributed to the decline of the total spinning reserve requirement, freeing low-cost capacity to meet energy requirements.
    5. Wind Integration, which quantifies the value of regional planning of wind resources. The centralized look at the footprint allows for more economic placement of wind resources. Economic placement of wind resources reduces the overall capacity needed to meet required wind energy output.
    6. Compliance, which shows the time and money savings associated with MISO consolidating FERC and NERC compliance obligations. Before MISO, utilities in the MISO footprint were responsible for managing FERC and NERC compliance.
    7. Footprint Diversity, which captures the value of MISO’s large footprint. MISO’s size increases the load diversity, allowing for a decrease in regional planning reserve margins from 18.08 percent to 14.98 percent. The decrease in the planning reserve margins delays the need to construct new capacity.
    8. Generator Availability Improvement, which displays the savings created by improved power plant availability. MISO’s wholesale markets increased power plant availability by 1.9 percent, which delays the need to construct new capacity.
    9. Demand Response, which MISO enables through dynamic pricing, direct load control and interruptible contracts. MISO-enabled demand response further delays the need to construct new capacity.
    10. Cost Structure, through which MISO provides these services. It is expected to stay relatively flat. The costs of these services represent a small percentage of the benefits and real savings to MISO customers.
    MISO provides these services for the largest RTO geographic footprint in the U.S. MISO undertakes this mission from control centers in Carmel, Ind.; Eagan, Minn.; and Little Rock, Ark., with regional offices in Metairie, La., and Little Rock, Ark. (Figure 9.1-1).
    Figure 9.1-1: The MISO geographic footprint

    Figure 9.1-1: The MISO geographic footprint

    MISO By The Numbers

    Generation Capacity (as of June 2015)
    • 178,396 MW (market)
    • 192,803 MW (reliability)[2]
    Historic Peak Load (set July 20, 2011)
    • 127,125 MW (market)
    • 133,181 MW (reliability)[3]
    Miles of transmission
    • 65,800 miles of transmission
    • 8,400 miles of new/upgraded lines planned through 2023
    • Markets
    • $37 billion in annual gross market charges (2014)
    • 2,446 pricing nodes
    • 413 Market Participants serving over 42 million people
    Renewable Integration
    • 15,215 MW active projects in the interconnection queue
    • 14,162 MW wind in service
    • 14,532 MW registered wind capacity (Jun. 2015)
  • 9.2 Electricity Prices

    Wholesale Electric Rates

    MISO operates a market for the buying and selling of wholesale electricity. The price of energy for a given hour is referred to as the Locational Marginal Price (LMP). The LMP represents the cost incurred, expressed in dollars per megawatt hour, to supply the last incremental amount of energy at a specific point on the transmission grid. The MISO LMP is made up of three components: the Marginal Energy Component (MEC), the Marginal Congestion Component (MCC) and the Marginal Loss Component (MLC). MISO uses these three components when calculating the LMP to capture not only the marginal cost of energy but also the limitations of the transmission system. In a transmission system without restrictions, the LMP across the MISO footprint would be the same. In reality, the existence of transmission losses and transmission line limits result in adjustments to the cost of supplying the last incremental amount of energy. For any given hour, the MEC of the LMP is the same across the MISO footprint. However, the MLC and MCC differ to create the variance in the hourly LMPs. The 24-hour average day-ahead LMP at the Indiana hub over a two-week period highlights the variation in the components which make the LMP. The time frame includes portions of the extreme weather events of 2015 (Figure 9.2-1). A real-time look at the MISO prices can be found on the LMP Contour Map[1] (Figure 9.2-2).
    Figure 9.2-1: Average day-ahead LMP at the Indiana hub

    Figure 9.2-1: Average day-ahead LMP at the Indiana hub

    [1] Market Analysis Monthly Operations Report
    Figure 9.2-2: LMP contour map

    Figure 9.2-2: LMP contour map


    Retail Electric Rates

    The MISO-wide average retail rate, weighted by load in each state, for the residential, commercial and industrial sector, is 8.79 cents/kWh, about 15 percent lower than the national average of 10.3 cents/kWh. The average retail rate in cents per kWh varies by 3.1 cents/kWh per state in the MISO footprint (Figure 9.2-3).
    Figure 9.2-3: Average retail price of electricity per state[2]

    Figure 9.2-3: Average retail price of electricity per state[2]

        3 May 2014 EIA Electric Power Monthly with Load Ratio Share data calculated from December 2013 MISO Attachment O data
  • 9.3 Generation Statistics

    The energy resources in the MISO footprint continue to evolve. Environmental regulations, improved technologies and ageing infrastructure have spurred changes in the way electricity is generated. Fuel availability and fuel prices introduce a regional aspect into the selection of generation, not only in the past but also going forward. Planned generation additions and retirements in the U.S. from 2014 to 2018 separated by fuel type shows the increased role natural gas and renewable energy sources will play in the future (Table 9.3-1).
    Table 9.3-1: Forecasted generation capacity changes by energy source[1]

    Table 9.3-1: Forecasted generation capacity changes by energy source[1]

    The increased fuel-mix diversity from the addition of the South region helps limit the exposure to the variability of fuel prices.
    The majority of MISO North and Central regions’ dispatched generation comes, historically, from coal. With the introduction of the South region, MISO added an area where a majority of the dispatched generation comes from natural gas. The increased fuel-mix diversity from the addition of the South region helps to limit the exposure to the variability of fuel prices. This adjustment to the composition of resources contributes to MISO’s goal of an economically efficient wholesale market that minimizes the cost to deliver electricity. After the December 2013 integration of the South region, the percentage of coal units decrease as the amount of gas units increase as shown by trend lines (Figure 9.3-2).
    Figure 9.3-2: Real-time generation by fuel type

    Figure 9.3-2: Real-time generation by fuel type

     Different regions have different makeups in terms of generation (Figure 9.3-3). A real time look at MISO fuel mix can be found on the MISO Fuel Mix Chart.[2] * Based on 5-minute unit level dispatch target
    Figure 9.3-3: Dispatched generation fuel mix by region

    Figure 9.3-3: Dispatched generation fuel mix by region

    Renewable Portfolio Standards

    Renewable portfolio standards (RPS) require utilities to use or procure renewable energy to account for a defined percentage of their retail electricity sales. Renewable portfolio goals are similar to renewable portfolio standards but are not a legally binding commitment. Renewable portfolio standards are determined at the state level and differ based upon state-specific policy objectives (Table 9.3-1). Differences may include eligible technologies, penalties and the mechanism by which the amount of renewable energy is being tallied.
    State RPS Type Target RPS (%) Target Mandate (MW) Target Year
    AR None
    IA Standard 105
    IL Standard 25% 2025
    IN Goal 10% 2025
    KY None
    LA None
    MI Standard 10% 1100 2015
    MN Standard – all utilitiesXcel Energy   Solar standard – investor-owned utilities 25%30%   1.5% 20252020   2020
    MO Standard 15% 2021
    MS None
    MT Standard 15% 2025
    ND Goal 10% 2015
    SD Goal 10% 2015
    TX Standard 5880 2015
    WI Standard 10% 2015
    Table 9.3-1: Renewable portfolio policy summary for states in the MISO footprint


    Wind energy is the most prevalent renewable energy resource in the MISO footprint. Wind capacity in the MISO footprint has increased exponentially since the start of the energy market in 2005. Beginning with nearly 1,000 MW of installed wind, the MISO footprint now contains 13,661.85 MW of wind capacity as of June 3, 2015. Wind energy offers lower environmental impacts than conventional generation, contributes to renewable portfolio standards and reduces dependence on fossil fuels. Wind energy also presents a unique set of challenges. Wind energy is intermittent by nature and driven by weather conditions. Wind energy also may face unique siting challenges. A real-time look at the average wind generation in the MISO footprint can be seen on the MISO real time wind generation graph[3]. Data collected from the MISO Monthly Market Assessment Reports[4] determines the energy contribution from wind and the percentage of total energy supplied by wind (Figure 9.3-4).
    Figure 9.3-4: Monthly energy contribution from wind

    Figure 9.3-4: Monthly energy contribution from wind

    Capacity factor measures how often a generator runs over a period of time. Knowing the capacity factor of a resource gives a greater sense of how much electricity is actually produced relative to the maximum the resource could produce. The graphic compares the total registered wind capacity with the actual wind output for the month. The percentage trend line helps to emphasize the variance in the capacity factor of wind resources (Figure 9.3-5).
    Figure 9.3-5: Total registered wind and capacity factor

    Figure 9.3-5: Total registered wind and capacity factor

        __________________________ [1] EIA, [2] [3] [4] [5] [6]
  • 9.4 Load Statistics

    The withdrawal of energy from the transmission system can vary significantly based on the surrounding conditions. The amount of load on the system varies by time of day, current weather and the season. Typically, weekdays experience higher load then weekends. Summer and winter seasons have a greater demand for energy than do spring or fall. In 2014, with the addition of the South region, MISO set a new all-time winter instantaneous peak load of 109.3 GW on January 6. The new peak surpassed the previous all-time winter peak of 99.6 GW set in 2010. Less cyclical factors also impact the demand for energy. The increased focus on energy efficiency programs, implementation of demand response initiatives and the rise of energy storage technologies all change the patterns around how energy is consumed. The role of energy efficiency programs have increased over the years with a resulting effect on peak load (Figures 9.4-1 and 9.4-2). The figures use data published in the U.S. Energy Information Administration (EIA) Electric Power Annual[1].
    Figure 9.4-1: U.S. energy efficiency and energy savings by end-use sector

    Figure 9.4-1: U.S. energy efficiency and energy savings by end-use sector

    Figure 9.4-2: U.S. energy efficiency and actual peak load reduction

    Figure 9.4-2: U.S. energy efficiency and actual peak load reduction

    End-Use Load

    It is a challenge to develop accurate information on the composition of load data. Differences in end-use load can be seen at a footprint-wide, regional and Load-Serving Entity levels. To keep up with changing end-use consumption, MISO relies on the data submitted to the Module E capacity tracking (MECT) tool. MECT data is used for all of the long-term forecasting including Long Term Reliability Assessment and Seasonal Assessment as well as to determine Planning Reserve Margins. The EIA Electric Power Monthly provides information on the retail sales of electricity to the end-use customers by sector for each state in the MISO footprint (Table 9.4-1).
    Table 9.4-1: Retail sales of electricity to ultimate customers by end-use sector, April 2015[2]

    Table 9.4-1: Retail sales of electricity to ultimate customers by end-use sector, April 2015[2]


    Peak load drives the amount of capacity required to maintain a reliable system. Load level variation can be attributed to various factors, including weather, economic conditions, energy efficiency, demand response and membership changes. The annual peaks, summer and winter, from 2007 through 2014, show the fluctuation (Figure 9.4-3). Within a single year, load varies on a weekly cycle. Weekdays experience higher load. On a seasonal cycle, it also peaks during the summer with a lower peak in the winter, and with low load periods during the spring and fall seasons (Figure 9.4-4). The Load Curve shows load characteristics over time (Figure 9.4-5). Showing all 365 days in 2014, these curves show the highest instantaneous peak load of 115,043.3 MW on July 23, 2014; the minimum load of 51,748.18 MW on April 21, 2014; and every day in order of load size. This data is reflective of the market footprint at the time of occurrence.
    Figure 9.4-3: MISO Summer and Winter Peak Loads – 2007 through 2014[3]

    Figure 9.4-3: MISO Summer and Winter Peak Loads – 2007 through 2014[3]

    Figure 9.4-4: 2014 MISO-Midwest Daily Load[4]

    Figure 9.4-4: 2014 MISO-Midwest Daily Load[4]

    Figure 9.4-5: MISO Load Duration Curve - 2014[5]

    Figure 9.4-5: MISO Load Duration Curve – 2014[5]



    Most MTEP14 appendices[6] are available and accessible on the MISO public webpage. Confidential appendices, such as D2 – D8, are available on the MISO MTEP14 Planning Portal[7]. Access to the Planning Portal site requires an ID and password. Appendix A: Projects recommended for approval

    Section A.1, A.2, A.3: Cost allocations

    Section A.4: MTEP13 Appendix A new projects

     Appendix B: Projects with documented need and effectiveness Appendix D: Reliability studies analytical details with mitigation plan (ftp site)

    Section D.1: Project justification

    Section D.2: Modeling documentation

    Section D.3: Steady state

    Section D.4: Voltage stability

    Section D.5: Transient stability

    Section D.6: Generator deliverability

    Section D.7: Contingency coverage

    Section D.8: Nuclear plant assessment

    Appendix E: Additional MTEP14 Study support Section E.1: Reliability planning methodology Section E.2: Generations futures development Section E.3: HVDC Network – Preliminary Assumptions and Results Section E.4: Market Congestion Planning Study Solution Ideas Appendix F: Stakeholder substantive comments

    Acronyms in MTEP15

    Editor’s Note: To be updated AFC      Available Flowgate Capacity APC     Adjusted Production Cost APCS   Adjusted Production Cost Savings ARR     Auction Revenue Rights BAU     Business as Usual BPM     Business Practices Manual BRP     Baseline Reliability Projects CBMEP            Cross Border Market Efficiency Project CCR     Coal Combustion Residuals CC        Combined cycle CEII      Critical Energy Infrastructure Information CEL      Capacity Export Limit CIL       Capacity Import Limit CPCN   Certificate of Public Convenience and Need CSP     Coordinated System Plan CWIS    Cooling Water Intake Structures DCLM   Direct control load management DIR       Dispatchable Intermittent Resources DPP     Definitive Planning Phase DR       demand response DRR     Demand Response Resources DSG     Down Stream of Gypsy DSIRE  Database of State Incentives for Renewables & Efficiency DSM     demand-side management EE        energy efficiency EGEAS Electric Generation Expansion Analysis System EIA       Energy Information Agency EIPC     Eastern Interconnection Planning Collaborative ELCC    Effective Load Carrying Capability ENV     Environmental EPA     Environmental Protection Agency (U.S.) ERAG   Eastern Reliability Assessment Group ERIS     Energy Resource Interconnection Service ERR     Energy Efficiency Resources FCA      Facility Construction Agreement FCTTC  First Contingency Total Transfer Capability FERC   Federal Energy Regulatory Commission FTR      Financial Transmission Rights GADS   Generator Availability Data System GIA       Generator Interconnection Agreement GIP       Generator Interconnection Projects GIQ      Generator Interconnection Queue GIS       Geographical Information System GLSF    generation to load shift factor GS       Generation Shift HG       High Growth HVDC   High voltage direct current ICT       Independent Coordinator of Transmission IL          Interruptible load IMM      Independent Market Monitor IPSAC  Interregional Planning Stakeholder Advisory Committee IPTF     Interconnection Process Task Force ISO       Independent System Operators ITP10    Integrated Transmission Plan 10-Year Assessment JCSP    Joint Coordinated System Plan JOA      Joint Operating Agreement JPC      Joint Planning Committee JRPC    Joint RTO Planning Committee LBA      Local Balancing Authority LDC      Local Distribution Companies LFU      Load forecast uncertainty LG        Limited Growth LMP     Locational marginal price LMR     Load Modifying Resources LNG      Liquified natural gas LODF   Line Outage Distribution Factor LOLE    Loss of Load Expectation LOLEWG Loss of Load Expectation Working Group LRR      Local Reliability Requirement LRZ      local resource zones LSE      Load Serving Entity LTRA    Long-Term Resource Assessment LTTR     Long-Term Transmission Rights M2M     Market-to-market MATS   Mercury and Air Toxics Standard MCC     Marginal Congestion Component MCP     Market Congestion Planning MCPS   Market Congestion Planning Studies MEC     Marginal Energy Component (MEC) MECT   Module E Capacity Tracking MEP     Market Efficiency Projects MISO    Midcontinent Independent System Operator MLC     Marginal Loss Component MMWG Multi-regional Modeling Working Group MOD    Model on Demand MRITS  Minnesota Renewable Integration Transmission Study MTEP   MISO Transmission Expansion Plan MVP     Multi-Value Projects MW      megawatt NAESB North American Energy Standards Board NERC   North American Electric Reliability Corp. NITS     Network Integration Transmission Service NLP      Net Load Payments NOPR   Notice of Proposed Rulemaking NPV     net present value NRIS     Network Resource Interconnection Service NSI       Net scheduled interchange NTP      New Transmission Proposal OASIS  Open Access Same-Time Information System OATT?  Include? OMS     Organization of MISO States PAC     Planning Advisory Committee PP        Public Policy PRA     Planning resource auction PRM     Planning Reserve Margin PRMICAP                         PRM installed capacity PRMUCAP           PRM uninstalled capacity PRMR   Planning Reserve Margin Requirement PSC     Planning Subcommittee PV        photovoltaic QTD     Qualified Transmission Developers RE        Robust Economy RE        Regional Entities RECB   Regional Expansion Criteria and Benefits RGOS   Regional Generator Outlet Study RMD     Regional Merit-Order Dispatch ROFR   right of first refusal RPS     Renewable Portfolio Standard RRF      regional resource forecast RTO      Regional transmission operator SCED   Security Constrained Economic Dispatch SFT      simultaneous feasibility test SIS       System Impact Study SPC     System Planning Committee SPM     Subregional Planning Meetings SPP     Southwest Power Pool SUFG   State Utility Forecasting Group SSR     System Support Resource TCFS    Top congested flowgate study TDQS   Transmission Developer Qualification and Selection TDSP   Transmission Delivery Service Project TLR      Transmission Load Relief TO        Transmission Owner TPL      Transmission Planning Standards TRC      Technical Review Committee TSR      Transmission Service Request TSTF    Technical Study Task Forces UNDA   Universal Non-disclosure Agreement VLR      Voltage and Local Reliability Study WECC  Western Electricity Coordinating Council WOTAB West of the Atchafalaya Basin

    Contributors to MTEP15

    MISO would like to thank the many stakeholders who provided MTEP15 report comments, feedback, and edits. The creation of this report is truly a collaborative effort of the entire MISO region.
        [1] 2 3 4 Source: MISO Market Data (2007-2014) 5 Source: MISO Market Data (2014) 6 Source: MISO Market Data (2014) [6] [7]