Frequently Asked Questions About MISO

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2 Frequently Asked Questions About MISO Industry observers often hear about our benefits, but want to know more in the context of a member or potential member s business model. We receive many questions regarding the membership process, how to participate in MISO s stakeholder process, or the steps necessary for a new transmission-owning member to fully integrate into MISO s market operations. Here are some of the frequently asked questions MISO receives regarding our services, benefits of membership, our Value Proposition, contractual obligations, and resource planning. Although not comprehensive of the entire MISO Tariff, nor intended to modify the energy markets Tariff or MISO s business practice manuals, we present these questions and answers to generate further discussion. Thank you for your interest in MISO. We look forward to hearing from you. MISO At-A-Glance MISO is an independent, not-forprofit regional transmission organization responsible for maintaining reliable transmission of power in 15 U.S. states and the Canadian province of Manitoba market participants $18.4 billion annual gross market charges (2012) Key Dates December 2001 RTO approval from FERC February 1, 2002 Transmission service begins under MISO s first Open Access Transmission Tariff April 1, 2005 Midwest Markets begin January 6, 2009 Ancillary Services Market begins MISO assumes Balancing Authority responsibilities for region December 1, 2013 MISO begins Independent Coordinator of Transmission Services for Entergy. Control Centers Carmel, IN (headquarters) St. Paul, MN Revised

3 Table of Contents MISO Membership Benefits Q. What services would a transmission owner receive as a member of MISO?...1 Q. What is MISO s Value Proposition?...1 Q. What are the benefits of MISO membership?...2 Q. What benefits are available to members of MISO?...2 Q. Are there any additional benefits of MISO membership?...2 Q. What improved reliability would a new member receive by joining MISO?...4 Q. What improved market commitment and dispatch efficiencies would a new member receive?...5 Q. What are the improved opportunities for utilization and development of generation and transmission infrastructure from joining MISO?...6 Contractual Obligations and Other Agreements Q. What is MISO s governance structure?...7 Q. What agreements must a Transmission Owner execute to integrate into MISO?... 8 Q. What is the significance of the integration date?...9 Q. What are the specific requirements of the MISO Tariff and market rules?...10 Q. How are existing transmission agreements handled in MISO?...11 Q. How does a transmission owner withdraw from MISO?...12 MISO Operations Q. How do the MISO Energy and Operating Reserve Markets operate?...13 Q. How does MISO s congestion market-based management mechanism reduce congestion costs?.14 Q. What is MISO s resource adequacy construct?...14 Q. What benefit does a regional resource adequacy construct provide for member entities?...15 Q. Describe MISO s resource adequacy enhancements Q. What demand response services does MISO offer as part of its wholesale markets?...17 Q. Who is eligible to participate in MISO with wholesale demand response?...19 Q. Does MISO s demand response construct conflict with state regulatory requirements? Q. What are the improved opportunities for demand response in MISO markets?...19 Q. How does the market for Financial Transmission Rights (FTRs) operate in MISO?...20 Q. How do the MISO markets determine the price for energy?...21 MISO Transmission Planning Q. What is MISO s regional planning process?...22 Q. How are the costs of transmission expansion paid for?...25 Q. How does MISO membership affect integrated resource planning (IRP) and local regulatory review of the IRP?...24 Acronyms...25

4 MISO Membership Benefits Q. What services would a Transmission Owner receive as a member of MISO? A. The services that MISO provides to a Transmission Owner (TO) are documented in Article Three of the Transmission Owners Agreement. These services include: Monitoring energy transfers on the high voltage transmission system. Scheduling transmission service and performing tariff administration. Managing transmission congestion in and around the system through securityconstrained economic dispatch. Operating the Day-Ahead and Real-Time energy markets. Balancing load and generation in real time. Performing regional transmission planning. In order to provide these services, MISO registered with NERC as a Reliability Coordinator (RC), Planning Authority (PA), Transmission Service Provider (TSP), Balancing Authority (BA), and Interchange Authority (IA). On Jan. 6, 2009, MISO began administering an operating reserves market, often referred to as our Ancillary Services Market (ASM), and performing Balancing Authority functions. When MISO began operating as a NERC-certified BA, the obligation to carry reserves shifted from the multiple, smaller BAs in the MISO footprint to the new MISO Balancing Authority. MISO now performs the majority of BA responsibilities including Automatic Generation Control (AGC), Control Performance Standard (CPS), and Disturbance Control Standard (DCS), while Local Balancing Authorities (LBAs) perform an important subset of these requirements such as tie line metering, load shedding, and the development and implementation of restoration plans. During October 2009, MISO underwent a comprehensive NERC audit of these functions, with no violations or NERC recommendations for corrective measures. Q. What is MISO s Value Proposition? A. MISO s Value Proposition is a detailed calculation that measures whether the benefits derived from MISO services exceed the cost of running the RTO. Because RTOs are voluntary organizations, if a transmission owner or its regulator perceive that the cost of participation does not provide a commensurate value to the ultimate end-users of electricity, the transmission owner will terminate membership. MISO updates its Value Proposition annually and publishes the most current calculations on its public website, with supporting work papers illustrating and explaining the calculations. The Value Proposition breaks the MISO business model into certain recognized categories of 1

5 benefits to the footprint as a whole and calculates a range of dollar values for each defined category. Q. What are the benefits of MISO membership? A. Members receive several significant benefits, many of which are quantified in MISO s Value Proposition. 1. Improved local and regional reliability. 2. Efficient use of existing transmission and generation assets within the MISO footprint. These benefits are delivered through the operation of MISO s Day-Ahead and Real-Time Energy and Ancillary Services Market. These markets allow for efficient, market-based congestion management mechanisms to assure the most cost efficient resources are used to serve load while also accounting for the reliable operation of the system. The large market footprint also allows members to gain access to a larger, and more diverse, generation mix. 3. Capacity Diversity. MISO s large, geographically diverse footprint allows members to share capacity across the region, reducing the planning reserve requirements for each of the members. 4. Scale. MISO s size allows economies of scale to reduce administrative costs. Q. What benefits are available to members of MISO? A. Our members accrue significant direct and indirect benefits from participation in MISO, many of which are not necessarily entirely captured by traditional production cost analyses. These additional benefits fall into three general categories: 1) Improved reliability. 2) Improved efficiency (in areas in addition to the efficiencies of a regional dispatch of energy). 3) Improved opportunities for development of generation and transmission infrastructure. Q. Are there any additional benefits of MISO membership? A. Members also accrue quantitative benefits through wind integration and compliance. Wind Integration MISO s regional planning enables more economic placement of wind resources in the region. Economic placement of wind resources reduces overall capacity needed to meet required wind energy output. MISO s regional planning results in a wind integration benefit of $244 to $285 million annually. 2

6 Compliance Before MISO, utilities in the MISO region managed FERC and NERC compliance. With MISO, many FERC and NERC compliance responsibilities have been consolidated. As a result, member responsibilities decreased, saving them time and money. MISO s compliance efforts result in an annual benefit of $62 million to $95 million. Four general categories of qualitative benefits are worth noting: Price / Informational Transparency, Planning Coordination, Seams Management, and Scalable Administrative Cost Structure. Improved Price / Informational Transparency Improved price / informational transparency enables decision-making through market forces by signaling market participants to supply energy when it is scarce, invest in transmission to free constraints, and invest in generation to meet long-term and shortterm needs. MISO s market provides this information at a level of granularity and locational specificity that extends beyond the capabilities of decentralized, bilateral energy markets. Planning Coordination In a traditional transmission planning process, a transmission owner focuses on relieving transmission constraints and reliability issues in the transmission system it owns. MISO coordinates among all transmission owners in its footprint, creating a bottoms-up approach, which is combined with a top-down approach that analyzes the regional footprint as well as surrounding regions to determine which transmission investments will allow the reliable delivery of energy at the lowest cost for the footprint. Seams Management Better understanding neighboring transmission systems is critical to heading off potential congestion problems. Through advances in software, development of new visualization tools and ongoing collaboration with neighboring grid operators, MISO is working to provide more transparent and efficient markets across the seam where our service territory electrically interconnects with other grid operators. Scalable Administrative Cost Structure MISO s systems are scalable and provide service to new members at a modest incremental cost while reducing each member s administrative costs. The technical infrastructure required to accomplish these services further utilizes the economies of scale already available within the information technology systems. As a potential member of MISO, a new TO will gain these general benefits on the same basis as existing members, and with no distinction based on corporate utility structure. In an 3

7 RTO, transmission owners who are public power entities, cooperatives, and investorowned utilities enjoy the same rights and obligations. Q. What improved reliability would a new member receive by joining MISO? A. Reliability of electrical service is a function of sufficient supply and consistent transmission capability. Reliability is compromised if there is too little energy generated, or if too little transmission capacity exists to deliver energy to the customer. MISO s broad regional view and state-of-the-art reliability tools enable improved reliability for the region as measured by transmission system availability. Transmission system availability is based on an analysis of NERC and EIA disturbance data. The benefits are several, and can be further broken down into the subcategories of: (a) improved reliability compared with stand-alone operations, (b) seams and tariff management functions; and (c) regulatory compliance. In all three of these subcategories, the obligations and responsibilities for these complicated and resource-demanding functions is either taken on completely by MISO, or shared with the new entity. MISO s 2012 Value Proposition analysis calculated these improved reliability benefits of between $182 million and $273 million annually. The inclusion of the new TO s generation in the expanded footprint in the Day-Ahead Energy and Operating Reserve Market will enable the application of Security Constrained Unit Commitment (SCUC) within the next-day Reliability Assessment Commitment (RAC) process. This allows for access to generators that the new TO cannot access today for its own dispatch needs (i.e., automatically in real time, without the need to schedule a purchase and arrange for transmission service). This will ensure that there is a set of generators available at the appropriate times to be able to manage the power system within established operating limits. Because MISO can see developments in the entire region surrounding its footprint, it allows preemptive rather than reactive action to protect reliability. These benefits are reciprocal - adding a new TO system to the MISO pool improves reliability for the entire footprint, including the new TO, for the reasons described. This expanded and more detailed data flow increases MISO s range of vision, which allows timely action to prevent system degradation and ensure system stability. If a TO chooses not to join MISO, there may be no degradation, but certainly no improvement in reliability for either MISO or the new TO. The only tool available to resolve congestion in the TO s system would continue to be the suboptimal Transmission Loading Relief (TLR) solution. 4

8 Q. What improved Market Commitment and Dispatch efficiencies would a new member receive? A. The benefits of dispatch and market efficiencies fall into four categories: more efficient dispatch of energy compared with stand-alone operations, better dispatch and utilization of assets for necessary regulation reserves, and more efficient dispatch of assets to provide for contingency reserves. Efficient Dispatch of Energy Energy dispatch occurs when MISO schedules, monitors and controls the energy. MISO s Real-Time and Day-Ahead energy markets use centralized security-constrained unit commitment and economic dispatch programs. This optimizes the use of all resources within the region based on bids and offers by market participants while managing congestion on the transmission system. Incorporating transmission security into the economic dispatch replaces TLR functions, resulting in optimized transmission utilization, reduced transaction costs, high market transparency, elimination of pancaked transmission rates, and centralized unit commitment and dispatch. MISO s 2012 Value Proposition analysis calculated benefits between $182 million and $201 million annually in efficient dispatch of energy savings. Efficient Dispatch of Regulation System operators dispatch energy to continuously regulate the balance of electrical supply and demand. With the start of the MISO Ancillary Services Market and with MISO s assumption of the role as the region s Balancing Authority, the region has moved from several non-coordinated Regulation targets to a centralized common footprint Regulation target. As a result, the required amount of Regulation reserves dropped significantly within MISO s footprint. In addition to lowering the total cost of producing Regulating reserves, this reduction frees up generation units that can, in turn, sell into the market to buyers who need energy. MISO s 2012 Value Proposition analysis calculated benefits between $104 million and $115 million annually in efficient dispatch of energy savings. Better Dispatch and Utilization of Assets Spinning Reserves provide energy to meet demand on the system in the event of a sudden and unexpected loss of a generation or transmission resource. Starting with 5

9 the formation of the Midwest Contingency Reserve Sharing Group (CRSG) in 2006, and continuing with the implementation of the Ancillary Services Market, the total spinning reserve requirement has been reduced by more than 30%. This reduction in spinning reserves frees up generation units to serve the broader energy demands within the region. In each of these three market-commitment and dispatch subcategories, the obligations and responsibilities for these functions are either taken over by MISO by virtue of participation by the new TO or brought into uniformity and compliance through FERC- approved market rates, terms, and conditions. Q. What are the improved opportunities for utilization and development of generation and transmission infrastructure from joining MISO? A. The advantages listed here result from the broader advantages that MISO provides to Load Serving Entities (LSEs). Within the MISO footprint, each LSE s peak does not normally coincide with MISO s system peak. This footprint diversity allows MISO to shift power as individual peaks occur at different times within the MISO region, thus better utilizing available capacity. As a result, the regional planning reserve margin established by a Loss of Load Expectations study showed a decrease from a typical 16.7% down to 11.32% (absent power import limitations). The significantly lower planning reserve margin enabled by MISO s larger coordinated footprint creates considerable benefits for the region, allowing participating entities to defer investments in new generation. MISO s 2012 Value Proposition analysis calculated benefits between $764 million and $954 million annually in footprint diversity savings. Competitive wholesale power markets provide incentives for generation owners to take actions to achieve higher generator availability and lower forced outage rates, and thus maximize revenues generated from the energy produced and sold within the market. MISO s wholesale power market has quantified this benefit as a Generator Availability Improvement of 2.9%. Each participant and the region as a whole benefit through deferred investments in generation that would otherwise be necessary. MISO s 2012 Value Proposition analysis calculated benefits between $455 million and $569 million annually in generator availability improvement savings. 6

10 Contractual Obligations and Other Agreements Q. What is the governance structure of MISO? A. MISO is governed by an independent eight-member Board of Directors, with seven independent directors elected by the membership, plus the president/chief executive officer of MISO. MISO s Board meetings occur at least quarterly and are open to the public. In 2011 MISO s Board meetings were hosted at its headquarters in Carmel, Indiana, in St. Paul, Minnesota, and in New Orleans, Louisiana. No board member may have been a director, officer or employee of a MISO member, user, or affiliate of a member or user for two years before or after election to the Board. Under MISO s Standards of Conduct, all MISO board members, employees and their immediate family members are required to divest any holdings in member or user companies. MISO benefits from an open stakeholder process that invites participation by all members, market participants, state and federal regulators and special interest groups. The views of state regulators are represented through an independent stakeholder group, the Organization of MISO States (OMS). At the pinnacle of MISO s stakeholder governance structure is the Advisory Committee. Nine stakeholder segments elect a representative to the Advisory Committee to recommend actions to MISO management. Several key technical and policy subcommittees and work groups meet regularly to address developing issues, and make recommendations to the Advisory Committee. With only a few exceptions, MISO committee and board meetings are posted on MISO s website and open to the public. 7

11 Q. What agreements must a Transmission Owner execute to integrate into MISO? A. Each prospective Transmission Owner must apply for membership. Membership Application Complete the MISO Membership Application, which is then voted on by MISO s Board of Directors. Memorandum of Understanding If a new member requests a phased integration to be completed at a later date rather than immediate integration, MISO and the new member will enter into a Memorandum of Understanding (MOU). If the new member declines to complete the integration process, it must reimburse MISO for legal and staff costs incurred on behalf of the cancelled integration. TO Agreement Following the Board s acceptance of its application, a new member executes the Agreement of Transmission Facilities Owners to Organize the Midwest Independent Transmission System Operator, Inc., a Delaware Non-Stock Corporation (TO Agreement). The TO Agreement is the original source document creating MISO, its Board of Directors and its committees. The TO Agreement sets forth the relationship of the RTO to the owners and other stakeholders, and preserves certain rights exclusively to the owners regarding the ability to set and alter their individual rates for the use of their facilities. Particularly, Appendix K of the TO Agreement sets out in detail the division of filing rights among MISO, the TOs collectively, and individual TOs. Appendix I Supplemental Agreement Each new member must also sign the Appendix I Supplemental Agreement among MISO, International Transmission Company and each of the MISO Transmission Owners to acknowledge the status of ITC as an independent, stand-alone transmission company operating under Appendix I of the TO Agreement. Funds Trust Agreement Each new TO also executes the Funds Trust Agreement, pursuant to which money paid by users of the transmission system is wired immediately to a trustee, without ever being under the control of MISO, for distribution to the Transmission Owners. This 8

12 insulates TOs from the remote risk of financial insolvency of MISO that might otherwise tie up funds in litigation before they could be distributed to the TO. Agency Agreement Under the TO Agreement, each new transmission owning member must transfer to the functional control of MISO all transmission facilities rated at or above 100kV. The lower voltage transmission facilities (determined using FERC s Seven Factor Test) are subject to the Agency Agreement executed by the new member, found in Appendix G of the TO Agreement. This document allows MISO to grant seamless transmission service under the MISO Tariff to customers served at those lower voltages, and permits the transmission owner to include those lower voltage facilities in its Attachment O rate calculation, assuring that it recovers its revenue requirement associated with those facilities. Balancing Authority Agreement If the new member is a NERC-registered Balancing Authority, it will need to sign the Balancing Authority Agreement to delegate certain BA tasks and responsibilities to MISO. This document was developed to permit MISO to initiate the Ancillary Services Market and take on the associated Balancing Authority function. Other Documents In addition to these documents that require signature, MISO and the new TO will work jointly on several steps to effect the integration. These include preparing a formal listing of transferred facilities, reviewing existing transmission service contracts for grandfathered agreement (GFA) treatment, calculation of allocated Financial Transmission Rights, training for the new TO personnel, establishing communication links, and registration of assets in our models. The list is not exhaustive. Q. What is the significance of the integration date? A. To correctly model the new TO loads and resources in the MISO Commercial Model for integration, the new TO must have assurance that it can join MISO in advance of a Commercial Model update. Commercial Model update options for new TOs include June 1, September 1, and December 1. To meet a Commercial Model update target of June 1, the assurance must be achieved by October 1 of the previous year to allow sufficient time to complete registration and FTR activities. For Commercial Model updates on September 1 or December 1, the new TO must have assurance two months prior to the update. If the assurance date cannot be met, integration will be postponed 9

13 until the next available model update. Such a delay would have the corresponding effect of delaying the realization of benefits of MISO participation. Q. What are the specific requirements of the MISO Tariff and market rules? A. The MISO Tariff sets forth detailed obligations of market participants (MPs). Those provisions affecting MPs are generally covered in Modules B, C, D, and E of the MISO Tariff. Module B Various requirements applicable to transmission service are found in Module B of the MISO Tariff. If the new TO has an Open Access Transmission Tariff, it will closely resemble Module B, which follows the FERC pro forma tariff. Module C Key provisions dealing with the activities and obligations of MPs in the markets, including Financial Transmission Rights, are located in Module C of the MISO Tariff. Specifically, Section sets out the general rights and responsibilities of market participants, including the right to participate in all market activities, and the obligation to settle for all credits and debits associated with those market activities. Section and Section outline the qualifications and application process as well as obligations for becoming a market participant. Section sets forth the withdrawal and reapplication procedure if a market participant terminates its market participant status. Section outlines additional obligations that each market participant must follow, including, but not limited to, the duty to follow Good Utility Practice and comply with all applicable laws, regulations, Commission requirements, and the operational procedures established by MISO. Section contains certain operational functions and responsibilities that each market participant must follow both prior to the operating day (e.g., reporting status of facilities and planned schedules) and during the operating day (e.g., implementing Reactive Supply and Voltage Control schedules; implementing dispatch instructions). The provisions setting out the rules and requirements for Financial Transmission Rights are found in Section 42 of the Tariff. Module D Module D sets forth the market monitoring function, which provides the Independent Market Monitor (IMM) with certain powers to monitor the actions of both MISO and market participants in order to detect market manipulation. Module D also provides the IMM with authority to mitigate market power in certain circumstances. Every market participant should familiarize himself with Module D. 10

14 Module E Module E sets out the resource adequacy obligations of LSEs. Business Practice Manuals The various Tariff provisions are explained in greater detail in the related Business Practice Manuals (BPMs) for each subject. The current MISO Tariff and BPMs are posted on MISO s public website ( Q. How are existing transmission agreements handled in MISO? A. Existing transmission service agreements must be analyzed to determine whether they qualify as a Grandfathered Agreement as defined in the MISO Tariff. If the existing service is pursuant to an Open Access Transmission Tariff, and it contains a stated rate for the price of the service, that agreement may continue to be served using that rate for the remainder of the service term, under the MISO Tariff. All other transmission service (i.e., pre-open Access Transmission Tariff (OATT) agreements) must meet certain MISO Tariff requirements to continue as GFAs, or to determine which type of GFA treatment they will receive. Grandfathered Agreements (GFAs) GFAs as defined in MISO s Tariff are those transmission service agreements entered into prior to September 16, 1998 (the effective date of MISO s first Tariff). With the initiation of an energy market, the problem of how GFAs should be financially settled raised several questions. Pursuant to a 2005 FERC order resolving those issues, contracts that have clear language stating that the contract is subject to a just and reasonable standard of review (or where the parties are in agreement to do so) are financially settled under the market tariff. Per MISO Tariff, Section (A) a., contracts that have Mobile-Sierra language, or are silent as to the standard of review, or where the transmission service is provided by a non-jurisdictional entity, are eligible to be Carved Out of the energy market. Under Section (A) b., parties may always opt to move from Carved Out status to Option A or Option C status, or to take service under the Tariff. GFAs converted to OATT service cannot revert to GFAs at a later date. 11

15 Option A, Option C or Carved Out GFA For members joining after 2010, non-jurisdictional municipal Generation & Transmission agencies, and Generation & Transmission cooperatives will be able to select Option A or Option C treatment, but not Carved Out treatment, for GFA contracts with their distribution municipal or coop members. Carved Out GFAs are subject to MISO Schedule 17 costs (the costs of running the markets) but not to the Schedule 16 costs (FTRs). In addition to Schedule 17, Carved Out GFAs are subject only to Schedules 3, 5, and 6 (ancillary services, but only to the extent they do not self-supply) and Schedule 10 (administrative cost recovery). The Scheduling Entity (as agreed to by the parties, but usually the MISO Transmission Owner) provides non-binding day-ahead schedules for the GFAs. The Responsible Entity (usually the MISO Transmission Owner) is responsible for making financial settlements with MISO for all applicable charges (although charges under Schedules 10 and 17 are billed directly to the Carved-Out GFA customer pursuant to Schedule 23). At FERC s direction, MISO submits quarterly reports allowing FERC to review GFA market activity to monitor for market manipulation or other tariff violations. Q. How does a Transmission Owner withdraw from MISO? A. FERC has ruled twice that if a MISO Transmission Owner satisfies the requirements of the Transmission Owners Agreement, it has the contractual right to withdraw from MISO for any reason because RTOs are voluntary organizations. If a member or a state commission exercising its regulatory oversight of a transmission owning member decide that the costs of participation are not justified by the benefits received, the Transmission Owner could notify MISO of its intent to withdraw, and (after the initial membership commitment of five years) proceed to do so. Article 5 of the Transmission Owners Agreement sets out the process for members to withdraw from MISO. Withdrawal Requirements Written notice, effective at the end of the calendar year after notice is received (Article Five, Section I). Availability of continued transmission service for existing customers for the term of the service agreement (Article V, Section II.A). Payment of all RTO financial obligations (Article Five, Section II.B). Obligations to construct planned facilities (Article Five, Section II.C). Receipt of applicable federal and state regulatory approvals (Article Five, Section III). 12

16 MISO Operations Q. How do the MISO Energy and Operating Reserve Markets operate? A. MISO s energy market is designed to ensure demand and operating reserve requirements are satisfied in a dependable and efficient manner while managing transmission congestion resulting from the physical limitation of the transmission system. MISO provides these services through a coordinated competitive market for electric energy. This market operates on the same principles as markets for other commodities such as corn, wheat or natural gas. MISO s energy and ancillary services markets compare offers to sell energy with bids to buy energy, as well as offers to sell ancillary services (Regulating Reserves and Contingency Reserves), with market requirements for those products. This process determines market clearing quantities and prices while assuring that total demand (load) and reserve requirements are satisfied at the lowest possible cost. This market activity honors the physical limitations of the transmission system used to deliver energy from generation to load. The process of matching supply and demand while maintaining transmission system reliability (whether performed by MISO or an individual non-market operating utility company) is referred to as commitment and dispatch, which is simply the process of deciding which individual generators can most cost effectively meet the anticipated demand. MISO performs its regional commitment and dispatch functions using centralized Security Constrained Unit Commitment, or SCUC and Security Constrained Economic Dispatch, or SCED programs. The SCUC and SCED processes simultaneously evaluate supply offers, demand bids, operating reserve requirements and all physical characteristics of the regional transmission system. These program solutions identify the most cost-effective unit commitment and dispatch, after which instructions are sent to each generator indicating whether the generating unit should inject power into the transmission system, and the quantity and timing of such injections. MISO s energy and ancillary services markets operate over two timeframes. First is a Day-Ahead market, through which MPs may pre-schedule the transactions they plan to engage in on the following operating day. Second is a Real-Time market, in which market participants may buy or sell energy to meet conditions during the operating day that might differ from those anticipated in the Day-Ahead market. 13

17 Q. How does MISO s congestion market-based management mechanism reduce the cost of congestion? A. There are two primary and differing methods for managing congestion on the bulk electric system. They are flow-based congestion management and market-based congestion management. In a flow-based congestion management system, resources are re-dispatched, using a mechanism such as TLR, based on their relative contribution to flow on a constrained transmission facility without recognition of the costs of such actions; that is, the re-dispatch is pro-rata, without regard for the least cost redispatch. Under this approach, multiple Balancing Authorities, multiple merchant generators, and multiple LSEs make individual decisions about how to use resources to solve transmission constraints. These individual solutions results in a sub-optimal use of resources. When using a market-based approach to congestion management, such as MISO s energy markets, the costs of re-dispatching units for congestion management are considered and made transparent through the Locational Marginal Pricing (LMP) calculated by the security constrained economic dispatch programs. The market-based approach to managing congestion results in considerable savings when compared with the flow-based approach to managing congestion. MISO s markets led to a sharp reduction of TLRs among all entities that are members of the market. Q. What is MISO s Resource Adequacy mechanism? A. Unlike the centralized capacity auctions in PJM or ISO New England, MISO s long-term resource adequacy construct 1 allows an LSE to use its own resources or procure capacity bilaterally in order to meet its Planning Reserve Margin Requirement. In addition to generation capacity, acceptable resources include bilateral purchase power contracts with resources outside the MISO footprint with appropriate transmission service, Demand Response (DR) resources, such as interruptible load, and behind the meter generation (BTMG). MISO evaluates each resource type to determine whether it qualifies as capacity that can be used by an LSE to meets its Planning Reserve Margin Requirement. 1 Module E of the MISO Tariff was approved by the Commission in Midwest Independent Transmission System Operator, Inc., 127 FERC 61,054 (2009). 14

18 CONE If an LSE does not meet its Planning Reserve Margin Requirement, it will be assessed an administrative deficiency charge equal to the Cost of New Entry (CONE). The CONE is calculated annually with the Independent Market Monitor. The calculation of CONE includes physical factors such as type, location, fuel cost, and financial factors such as cost of capital, operating, and others costs. MISO determines on a monthly basis whether a LSE has met its Planning Reserve Margin Requirement. Allowing LSEs to procure their own capacity has been used with success for decades by the NERC regions and planned reserve sharing groups prior to MISO s adoption of this approach. MISO performs a Loss of Load Expectation (LOLE) study, a probabilistic analysis, annually to set the Planning Reserve Margin Requirement for the LSEs in the upcoming Planning Year (June 1 through May 31). The Planning Reserve Margin Requirement is the minimum reserves required for each LSE above its forecasted demand to meet the one-day-in-10-years reliability criteria. MISO also performs a LOLE study for years 2-10 in order to provide a forward-looking signal on future reserve requirements and for potential import constrained areas of MISO. That analysis shows a projected reserve requirement of 18.2% on an installed capacity basis for the year 2020 to meet the 1-day-in-10 year reliability criteria. This MISO Resource Adequacy Review (RAR) mechanism was developed through close collaboration with the Organization of MISO States and other stakeholders. In addition to the long-term LOLE study, MISO also performs a long-term reliability assessment. This assessment shows the projected demand and resources for the next 10 years. The most recent Long Term Resource Assessment shows MISO having a reserve margin of 18% in This most recent projection shows sufficient supply for the next 10 years. In June 2012, the Federal Energy Regulatory Commission conditionally approved MISO s proposed modifications to its Resource Adequacy mechanism, beginning with Planning Year The Commission approved foundational elements of MISO s proposal, including determination of long-term resource adequacy on a zonal basis and an annual, rather than monthly, resource adequacy requirement. Q. What benefit does a regional Resource Adequacy mechanism provide? A. Within Module E of the MISO Tariff, individual LSEs maintain reserves based on their monthly peak load forecasts. The sum of the LSEs peak forecasts do not sum to MISO s system coincident peak because they are reported based solely on each entity s own peak, which could occur at a different time than the system peak. To account for this diversity within MISO, a reserve margin was calculated for application to individual LSE peaks utilizing a 4.61% diversity factor for the most recent planning 15

19 year (June May 2013). This resulted in an individual LSE reserve level of 11.32% for the planning year, reduced from what would otherwise be a 16.7% reserve without accounting for diversity. This diversity factor is the primary calculation component of the MISO Value Proposition: Generation Investment Deferral. The lower planning reserve margin calculated as result of the regional diversity by MISO translates into the deferral of constructing new electric generating resources in the future. In addition, allowing alternative resources like demand resources and BTMG to be used to meet an LSE s resource adequacy obligations further enhances the value proposition. This, in turn, reduces the capital cost for new generation to be recovered from end-use customers. The shift from localized use of the electrical system to regional use allows more efficient and effective use of the generation assets and allows for a reduction in the planning reserve margins for the region. The Resource Adequacy benefits are reflected in Generator Availability Improvement in MISO s Value Proposition. Q. Describe MISO s resource adequacy enhancements conditionally approved by FERC. A. MISO s approved resource adequacy enhancements include establishing planning reserve zones and identifying the transmission import and export capability for each of the zones. The establishment of the zones and limits will meet compliance obligations established in the June 8, 2010, FERC order (ER ). Other key elements of MISO s resource adequacy modifications include: Establishing system and zonal planning reserve margins. Transition from a monthly to annual planning period. Leveraging existing rules for resource qualification. Establishing rules to allow energy efficiency to qualify as a resource. Allowing load-serving entities the option to either submit a resource plan or selfschedule their resources to opt-out of the residual auction. Allowing use of bilateral contracts to meet resource adequacy requirements. Conducting an annual residual auction to ensure resource deliverability between zones and to establish market clearing prices for capacity in each zone. Establishing a process to track and settle retail load switching to ensure that the obligations for resource adequacy are assigned to the appropriate retail suppliers. 16

20 Q. What demand response services does MISO offer as part of its wholesale markets? A. MISO developed market mechanisms to allow demand response to participate in all aspects of its markets through reducing loads whose values to end-use customers are less than the costs of serving those loads (Economic Demand Response), providing Regulation or Contingency Reserves (Operating Reserve Demand Response), reducing demand during system emergencies (Emergency Demand Response or EDR), and substituting for generating capacity (Planning Resources Demand Response). Demand response has the duplicate benefit of reducing demand at critical times as well as benefiting customers by enhancing the competitive markets through downward price pressure on the affected LMPs. MISO s market instruments for demand response participation are described further below: Economic Demand Response Resource A Demand Response Resource (DRR) is a demand resource or behind-the-metergenerator that can respond to MISO s dispatch instructions. DRRs are the only demand resources that can inject energy on an economic basis, i.e., to replace higher-priced energy offered by generators. 2 There are two types of DRRs under the MISO Tariff: DRR Type I supplies a fixed, pre-specified quantity of energy, through physical load reduction, to the energy and Operating Reserve Market when instructed to do so by MISO. DRR Type II supplies a range (continuum) of energy or Contingency Reserves, through physical load reduction or behind-the-meter generation, to the Energy and Operating Reserve Market. MPs may submit DRR offers into the Day-Ahead Market and/or the Real-Time Market. MPs with DRR offers that clear the market, and that subsequently follow MISO dispatch instructions within acceptable tolerances, are paid the hourly LMPs for the energy they return to the market through their load reductions. In addition, they are made whole for their one-time shutdown costs if committed by MISO through its SCUC process (except for must run offered resources, which are not entitled to recovery of shutdown costs). However, for DRRs, the MPs are charged for acquiring the energy they injected into 2 Additionally, the market participant with demand response assets is free to manage its purchases of energy in the MISO markets by self-scheduling its demand resource assets, or controlling its metered load by calling on its demand resource assets directly, to mitigate potential price exposures in the markets or to address local reliability concerns. 17

21 the market. This charge is applied because a demand resource cannot produce energy; it can only inject energy that would have otherwise been delivered to it for consumption. The LSE within which the load reduction occurs is charged for the demand responder price settlements. DRR Cost Recovery In response to FERC Order 745, MISO changed its cost recovery structure for DRRs. The LSE will not be charged for the load if the DRR provides energy, and the LMP is above a monthly price threshold. If a DRR provides energy, but the LMP is below the monthly price threshold, the cost recovery remains as described above. The FERC accepted MISO s changes, which went into effect June 12, Operating Reserve Demand Response Operating reserve services consist of three forms: Regulation Service, Spinning Reserve Service, and/or Supplemental Reserve Service. Together, Spinning Reserve and Supplemental Reserve are referred to as Contingency Reserve. In addition to providing energy, DRR-Type I and DRR-Type II resources that are technically qualified to do so may provide one or more forms of Operating Reserve Service. DRR-Type I resources can provide either energy or Contingency Reserve Service, but cannot simultaneously provide both. DRR Type II Resources may provide energy and/or one or more Operating Reserve products simultaneously. Emergency Demand Response (EDR) Market participants with demand resources and/or behind-the-meter generation (the MP s EDR resources) that do not qualify as DRRs, or that are not offered into the Energy or Operating Reserve Markets, may still offer to reduce their gross loads when MISO declares an Energy Emergency event (e.g., NERC Energy Emergency Alert or EEA). MISO s Emergency Demand Response Initiative allows, but does not require, EDR resources to provide Emergency Demand Response during such events unless they are also claiming capacity credit as Planning Resources. Each day an MP may decide how much of each of its EDR resources to make available to MISO for EDR service the following day, and at what prices. In addition to providing hourly curtailment prices in its daily EDR offer, the MP may also specify one-time shutdown cost and a number of operational constraints for each EDR resource. When an emergency event occurs, MISO will use the information in the EDR offers to decide the order in which to curtail the associated EDR resources and to determine a single market-clearing price to be paid for the curtailments. 18

22 Load Modifying Resources (LMRs) and DRRs may qualify as Planning Resources if the market participant registering those assets commits in advance to using them to reduce its gross load when instructed to do so by MISO during an Energy Emergency event. Module E of the MISO Tariff prescribes how DRRs and LMRs are accredited as Planning Resources based on their unforced capacities. LMRs and DRRs have monetary value because they can be substituted for Generation Resources by an LSE in meeting its assigned Planning Reserve Margin Requirement. Q. Who is eligible to participate in MISO with wholesale demand response? A. Two types of market participants may provide demand response in MISO: LSEs and end-use customers who have market participant status. A third type of market participant - Aggregators of Retail Customers (ARCs) - are allowed to aggregate enduse customer demand response and behind-the-meter generation to provide demand response, effective June 12, Q. Does MISO s demand response construct conflict with state regulatory requirements? A. No. In addition to MISO s own standards and requirements for demand response participation in its wholesale markets, the states within the MISO region may also have various requirements and regulations that must be met regarding the participation and use of demand response by the qualified MP. MISO acknowledges the important role state regulatory authorities play, in collaboration with FERC, and has and continues to develop its demand response initiatives to be consistent and compliant with both federal and state requirements. For example, some state regulatory authorities do not plan on allowing ARCs to do business with retail customers served by LSEs subject to their jurisdiction, regardless of MISO s ARC tariff provisions. Authorities with regulatory control over public power entities and cooperatives, which may be outside the jurisdiction of state regulators, may also impose such prohibitions. Q. What are the improved opportunities for demand response participation in the wholesale markets operated by MISO? A. To date, these benefits are derived in two distinct areas: dynamic wholesale pricing and direct load control and interruptibles. Dynamic Pricing Dynamic Pricing is a form of demand response that provides wholesale customers a rate signal that varies throughout the day to reflect the higher cost of electricity during peak times. MISO provides a market framework that enables dynamic pricing programs to realize their full value through the reduction of system peak demand. This demand 19

23 reduction, in turn, results in additional benefits to the new TO and the entire region by allowing additional generation investment deferrals. Direct Load Control and Interruptibles Wholesale market direct load control and interruptibles are two additional forms of demand response. Direct load control provides LSEs the ability to curtail specific end uses of customers, whereas interruptibles provide LSEs the ability to curtail a preset amount of load. MISO provides a market framework that enables direct load control and interruptibles programs to realize their full value through the reduction of system peak demand. This additional demand reduction adds benefits to the new TO and the entire region by allowing additional generation investment deferrals. Q. How does the market for Financial Transmission Rights (FTRs) operate in MISO? A. MISO s Financial Transmission Rights (FTRs) market offers Auction Revenue Rights (ARRs) and annual and monthly FTR auctions. ARRs are financial instruments that entitle their holders to a share of the revenue generated in the annual FTR auction. ARRs are initially allocated to MISO s market participants based on firm historical usage of the transmission network. FTRs are financial instruments whose values are determined by the transmission congestion charges that arise in the Day-Ahead Market, leading to differences in the Marginal Congestion Components (MCCs) of Day-Ahead LMPs at different locations. FTRs may be used to provide a financial hedge to manage the risk of congestion cost in the Day-Ahead Market. Market participants who hold FTRs are protected against paying congestion charges for scheduled injections (e.g., generation, bilateral purchases, etc.) at one location, and withdrawals (e.g., load, bilateral sales) at a different location in the Day-Ahead Market. FTRs are defined as between specified locations, for a specified MW level, in a specific direction and for a specified time period. ARRs are allocated to firm transmission customers under the MISO tariff, which can be used to offset the cost of obtaining FTRs in the annual FTR auction. If a new TO is also a LSE, the new TO would be eligible to nominate and be allocated ARRs and hold FTRs once it becomes a registered market participant and meets the Tariff s terms and conditions. In accordance with the process used to allocate transmission rights, an LSE will be eligible to nominate and receive both short-term and long-term transmission rights. Moreover, the LSE has the flexibility to choose to sell congestion rights in an FTR auction and receive the market value of the congestion rights rather than holding the FTRs. The congestion rights annual allocation and auction process occurs in the first several months of each year. To the extent that an incoming TO integrates prior to the established timelines for participation in the next ARR allocation, the incoming TO 20

24 would be allowed to participate in a partial-year allocation of FTRs for the remainder of the Year 1 allocation period. For that purpose, MISO will conduct a partial year FTR allocation that will provide the LSE with congestion hedges for the rest of the Year 1 allocation period, covering the paths representing its historical transmission usage. The MISO Tariff contains the details of the partial year FTR allocation methodology, including the number of rounds or stages, and the restoration procedure, consistent with Module C of the Tariff. For example, if a TO integrates in September, the partial year FTR allocation would include three seasons (Fall, Winter and Spring) and both peak and off-peak periods. As in the case of the ARR allocation, the allocation of FTRs to market participants will be capped at their annual peak network load and the volume of Transmission Service Requests (TSRs) for point-to-point transmission service. Subject to the availability of time, MISO will attempt to hold the partial year FTR allocation in two stages to give applicants or market participants at least two opportunities to request FTRs for their transmission usage paths. As with all FTRs, any allocated partial year FTRs shall be financially binding for their entire term. Q. How do MISO markets determine the price for energy? A. Clearing prices in the MISO Day-Ahead and Real-Time energy markets are a function of the competitive offers to sell and bids to buy electric energy. Clearing prices may vary at different locations to reflect differences in the cost of meeting load due to the physical limitations of the transmission system and the varying cost structures of generators used to meet the energy balance. For example, if a local load cannot be met with generation from a distant low-cost coal generator because of a transmission constraint, the higher cost of serving that local load from a higher-cost local generator is reflected in the price at that load location. This is referred to as Locational Marginal Pricing or LMP, which simply means that energy prices reflect the relative value of energy, based on where and when it is generated and where and when it is consumed. Market Clearing Prices The process of determining market clearing prices in the MISO energy markets is based on the cost of the marginal generator required to meet the next megawatt of demand. This process is not unique to electric energy. Indeed, it is no different than the process used to determine prices in other commodity markets, or in non-commodity competitive markets such as those for real estate or professional services. Competitive markets are defined as processes whereby sellers attempt to maximize the value of the products they offer, buyers try to minimize their cost of acquiring those products and the competitive interaction of all buyers and sellers determines a market price at which transactions occur. 21

25 MISO Transmission Planning Q. What is MISO s regional planning process? A. RTO planning functions include the provision of long-term Transmission Service, Interconnection Service, and regional planning. These services are provided collaboratively with member TOs, consistent with the Transmission Owners Agreement. MISO is registered with NERC as a Planning Authority and, as such, fully evaluates and plans for the reliability of the transmission system in accordance with NERC s planning standards. MISO develops an annual regional expansion plan based on expected use patterns and analysis of the performance of the transmission system in meeting both reliability needs and the needs of the competitive bulk power market, under a wide variety of contingency conditions. This analysis and planning process integrates into the development of the regional plan among other things: Transmission needs identified from Facilities Studies carried out in connection with specific transmission service requests. Transmission needs associated with generator interconnection service. Transmission needs identified by the Transmission Owners in connection with their planning analyses in accordance with local planning processes to provide reliable power supply to their connected load customers and to expand trading opportunities, better integrate the grid and alleviate congestion. Transmission planning obligations of a Transmission Owner imposed by federal or state laws or regulatory authorities. Plans and analyses developed by the Transmission Provider to provide for a reliable transmission system and to expand trading opportunities, better integrate the grid and alleviate congestion. Identification, evaluation, and analysis of expansions to enable the transmission system to fully support the simultaneous feasibility of all Stage 1A ARRs. Inputs from the Planning Advisory Committee. 22

26 Inputs, if any, provided from state regulatory authorities having jurisdiction over any of the Transmission Owners and by the Organization of MISO States. The development of the regional plan is undertaken in an open and transparent planning process as prescribed by FERC Order 890, which provides multiple opportunities for all stakeholders to review and provide input into the plan. These FERC planning principles also require close inter-regional planning coordination with neighboring systems and are accomplished via the joint operating agreements included as rate schedules to the MISO Tariff. Periodic inter-regional plans are developed that ensure that the systems of MISO members are not negatively impacted by the planning decisions of nearby entities. Planning for the reliable interconnection of new generation, of both affiliated and independent power producers is provided for by MISO as the Transmission Provider. System impact and Facilities Studies are conducted collaboratively with the impacted Transmission Owners and adhere to the local planning criteria of those owners, as well as to national and regional planning criteria under the NERC umbrella. Q. How are the costs of transmission expansion paid for? A. In general, MISO s cost allocation principles follow a cost-benefit methodology. MISO transmission rates are based on a license plate tariff in which Network Customer rates reflect the revenue requirements of the local pricing zone. Under this arrangement, transmission constructed locally for ongoing reliability needs is generally recovered from local customers. Beginning in 2006, MISO instituted regional cost sharing for certain transmission upgrades meeting specified criteria. Under the present tariff, cost sharing for transmission is somewhat different depending upon whether the transmission is needed for ongoing reliability, to reduce congestion and improve market efficiency, or to interconnect new generation. For larger ongoing reliability and market efficiency upgrades of 345 kv voltage and higher and of at least $5 million in direct costs, 80% of the cost is allocated (using load flow studies) to loads that benefit from the project, with 20% of the cost of the upgrades shared equally by all loads. Smaller projects of this type are shared between locally close zones with the majority of the costs remaining in the local zone. Transmission upgrades constructed to reliably interconnect new generation, except for the highest voltage transmission, are paid for entirely by the generator interconnection customer. For high voltage upgrades at 345 kv and above, the interconnection customer pays for 90% of the cost with the remaining costs shared equally by all loads. The mechanism for collecting these allocated expansion costs is Schedule 26, which currently does not apply to grandfathered agreement (GFA) load. These MISO transmission expansion cost allocation methods were revised in a FERC filing in

27 to establish a new category of transmission projects called Multi-Value Project (MVP). Candidate Multi-Value Projects must: (a) reliably and economically enable regional public policy needs; (b) provide multiple types of regional economic value; and (c) provide a combination of regional reliability and economic value. Costs for MVPs will be allocated to all load within MISO through a postage-stamp rate. The MISO Tariff provides that MVPs are reviewed on a portfolio basis, and that MVP usage is not applied to exports or wheel-through transactions sinking in the PJM region. In 2011, MISO requested from FERC a temporary waiver of the MVP tariff provisions to accommodate a transition period during which Entergy Arkansas or the Entergy system might be integrated into MISO. The Commission accepted this transition period in an Order issued April 19, Q. How does MISO membership affect integrated resource planning (IRP) and local regulatory review of the IRP? A. Module E of the MISO Tariff is intended to supplement a state s integrated resource planning process. MISO does not do integrated resource plans. Each state in the MISO footprint is free to establish a different planning reserve margin, if it chooses to do so. The MISO calculated planning reserve margin becomes the default value if no other margin is set by the regulatory authority, or if the state commission affirmatively selects the MISO margin, as all states have done to date. For More Information For additional information about MISO, please consult these helpful resources: MISO Website MISO Tariff MISO Business Practice Manuals MISO One-Pagers Here you will find brief overviews of key issues. MISO Stakeholder Center (This area of our website contains our meeting calendar as well as links to membership lists, committees and work groups, and Client Relations.) MISO Markets and Operations 24

28 Acronyms AGC Automatic Generation Control LMR Load Modifying Resource ARC Aggregators of Retail Customers LOLE Loss of Load Expectation ARR Auction Revenue Rights LSE Load Serving Entity ASM Ancillary Services Market MCC Marginal Congestion Component BA Balancing Authority MP Market Participant BPM Business Practice Manual MVP Multi-Value Project BTMG Behind the Meter Generation CONE Cost of New Entry OATT Open Access Transmission Tariff OMS Organization of MISO States CPS Control Performance Standard PA Planning Authority CRSG Midwest Contingency Reserve Sharing Group PRMR Planning Reserve Margin Requirement DCS Disturbance Control Standard RAC Reliability Assessment DR Demand Response Commitment DRR Demand Response Resource RAR Resource Adequacy Review EDR Emergency Demand Response RC Reliability Coordinator EEA Energy Emergency Alert RTO Regional Transmission Organization FTR GFA Financial Transmission Rights Grandfathered Agreement SCUC Security Constrained Unit Commitment IA Interchange Authority TLR Transmission Loading Relief IMM Independent Market Monitor TO Transmission Owner LBA Local Balancing Authority TSP Transmission Service Provider LMP Locational Marginal Pricing TSR Transmission Service Request 25