LOLE is expressed as hours per year with the usual target criteria being (0.1 days/year) or 1- day in 10-years MISO Tariff: Module E-1 - The

LOLE is expressed as hours per year with the usual target criteria being (0.1 days/year) or 1- day in 10-years MISO Tariff: Module E-1 - The Transmission Provider will calculate and post the Planning Reserve Margin such that the LOLE for the next Planning Year is one (1) day in ten (10) years, or 0.1 day per year. 5

Assessments MISO performsthe following NERC Assessments which are also presented at MISO Informational Forums: Summer Seasonal Assessment Long Term Reliability Assessment (LTRA) The key function of these assessments related to the LOLE/PRM study is a comparison of reserve levels of installed capacity to the PRM target under various scenarios and sensitivities. A water-fall chart is how these capacity levels are measured and displayed. MISO also performs a NERC Probabilistic Assessment every two years which is used to track LOLE trends. Planning Reserve Margin (PRM) Study ThePRM study results are used in a variety of different MISO process and these will be covered in more detail in the following slides: First, MISO Value Based Planning process of the annual MTEP study Second, Resource Adequacy construct (Tariff Module-E) 6

Resource Adequacy Overview Achieving reliability in the bulk electric systems requires, among other things, that the amount of resources exceeds customer demand by an adequate margin. The margins necessary to promote Resource Adequacy need to be assessed on both a near-term operational basis and on a longer-term planning basis. The focus of MISO s RA Construct (RA) is on the longer-term planning margins that are used to provide sufficient resources to reliably serve Load on a forwardlooking basis. In the real-time operational environment, only resources dedicated to meet Demand --including resources to meet the Planning Reserve Margin Requirement (PRMR) --have an obligation to be available to meet real-time customer demand and contingencies. Planning Reserve Margins (PRMs) must be sufficient to cover: Planned maintenance Unplanned or forced outages of generating equipment Deratings in the capability of Generation resources and Demand Response Resources System effects due to reasonably anticipated variations in weather Variations in customer demands or forecast demand uncertainty The resources used to achieve long-term Resource Adequacy are called Planning Resources (PRs), and consist of Capacity Resources, Load Modifying Resources 7

and Energy Efficiency Resources. The relationships and key attributes of the PR types are: Capacity Resources (CR)-electrical generating units or stations known as Generation Resources or External Resources (if located outside of MISO), and loads that can be dispatched to reduce demand known as Demand Response Resources (DRR). Load Modifying Resources (LMR)-include Behind-the-Meter Generation (BTMG) that are available for use during emergencies and loads that can be interrupted or directly controlled to reduce demand during emergencies known as Demand Resources (DR). Energy Efficiency Resources - A Planning Resource consisting of installed measures on retail customer facilities that achieves a permanent reduction in electric energy usage while maintaining a comparable quality of service Capacity Resources are quantified by applying forced outage rates to installed capacity values (ICAP) to calculate an unforced capacity value (UCAP) for the resource. A Market Participant can use Capacity Resources up to their UCAP values to contribute towards Resource Adequacy to the extent the MP is willing to subject the Capacity Resource to MISO s must offer commitment and meet all other RAR obligations. A MP may designate Zonal Resource Credits (ZRC) that are subject to the must offer commitment. Important Note:Resource Adequacy, at any particular Commercial Pricing Node (CPNode) is achieved if a Load Serving entity (LSE) has at least as many ZRCs as its forecasted peak demand for that month plus its PRM. 7

Stakeholder involvement in the design of MISO s Resource Adequacy is the cornerstone of the RA Constructfollowed by a State s authority to set PRM and MISO s determination of PRM. 8

MISO s footprint is divided into nine (9) zones The zones have been configured taking into account geographical boundaries of Local Balancing Authorities (LBAs), state boundaries, the relative strength of the transmission interconnections between LBAs, the results of prior analysis, the location of existing and proposed resources, and the relative size of zones. 10

Single-slidesummary of planning resources is provided in the Level 100 training. The following slides provide a detailed look at each Planning Resource with respect to: Qualification Requirements Generation Verification Test Capacity (GVTC) Requirements UCAP Determination Must Offer Obligation (Deliverability Requirement in the case of LMRs) Note: Requirements outlined in this training refer to Planning Year 3 (2011/2012) and beyond Requirements for Planning Years1 & 2, while provided in the BPM for reference, are not presented here. 11

Qualification for each type of Planning Resource is defined in the BPM. 12

Definition of Generation Resources does not include Intermittent Generation and Dispatchable Intermittent Resources. Qualification Requirements Generation Resources may qualify as Capacity Resources provided that: a. They are registered with MISO as documented in the Market Registration BPM. b. Generation Resources must be deliverable to Load within the MISO Region. Generation Resources 10 MW, based on GVTC, must submit generator availability data (including, but not limited to, NERC GADS) into a database through the Market Portal. Generation Resources < 10 MW, based upon GVTC, that begin reporting generator availability data must continue to report such information. New Generation Resources must submit GVTC and, if 10 MW based on GVTC, must submit GADS prior to being approved as a Capacity Resource. The XEFORd for new Generation Resources in service less than twelve full calendar months will be the class average for the resource type. A Generation Resource will use the class average value until 12 consecutive months of data is available and a new Planning Year has 13

occurred. GVTC Generation Resources must demonstrate capability on an annual basis. All Generation Resources being used as a Planning Resource are required to perform a real power test, according to the MISO Generator Test Requirements, and submit the GVTC to the MISO PowerGADS no later than October 31 st in order to qualify as a Planning Resource. GVTC tests are performed between September 1 st and August 31 st of the prior Planning Year and corrected to the average temperature of the date and times of MISO coincident Summer peak, measured at or near the generator s location, for the last 5 years, or provide past operational data that meets these requirements to determine its GVTC and submit to the MISO PowerGADS. Real Power Test is required To demonstrate a modification that increases the rated capacity of a unit, and then submit the revised GVTC. When returning from a mothballed state, and then submit the GVTC. When any existing or new unit returns to MISO after an absence (including but not limited to, catastrophic events, or not qualified as a Planning Resource under Module E) or being qualified as a Planning Resource for the first time. Reporting GVTC results is accomplished through the MISO PowerGADS reporting system as described in the MISO Net Capability Verification Test User Manual, which is located on the MISO website under Documents> Resource Adequacy> Documents> GADS Information Link> PowerGADS Documentation> Generator Testing Documents. UCAP Determination The unforced capacity calculation is based on theresource stype and volume of interconnection service, GVTC, and forced outage rate (XEFORd). The first step is to determine the total installed capacity that the Planning Resource can reliably provide, which is the Total Interconnection ICAP. The next step is to convert the resultant Total Interconnection ICAP value to unforced capacity value, Total Interconnection UCAP, by applying its forced outage rate (XEFORd). Appendix H of the ResourceAdequacy BPM describes the processes and calculations for determining both ICAP and UCAP values. The UCAP methodology is implemented to address the fact that not all Generation Resources contribute equally to Resource Adequacy. By adjusting the capacity rating of a unit, based on its XEFORd, UCAP provides a 13

Qualification Requirements Intermittent Generation and Dispatchable Intermittent Resources may qualify as Capacity Resources provided that: a. They are registered with MISO as documented in the Market Registration BPM. b. Must be deliverable to Load within the MISO Region. The deliverability of Intermittent Generation and Dispatchable Intermittent Resources to Network Load within the MISO Region shall be determined by System Impact Studies pursuant to the Tariff as conducted by MISO. Intermittent Generation and Dispatchable Intermittent Resources that are not powered by wind must supply MISO with the most recent three years of hourly net output (MW) for hours 1500 1700 EST from June, July and August. For new resources or resources on qualified extended outage where data does not exist for some or all of the previous three years, a minimum of 30 consecutive days worth of historical data during June, July or August for the hours of 1500-1700 EST must be provided. GVTC Not Required UCAP Determination UCAP for Intermittent Generation and Dispatchable Intermittent Resources is determined by the Transmission Provider based on historical performance, 14

availability, and type and volume of interconnection service. Will be assigned a XEFORd of zero. Resources that are powered solely by wind will have their annual UCAP determined based on interconnection service volumes and a Region-wide capacity credit as a percentage of the Maximum Output as modeled in the effective Commercial Model at the time of calculating UCAP values. Note on Wind Capacity Credit: MISO calculates specific wind capacity credit for each wind farm and applies it to its registered maximum capability in the Commercial Model or its registered Capacity through the LMR or External Resource registration process. The wind capacity credit is allocated to each wind farm based on its capacity value (Effective Load Carrying Capability) at each of MISO s highest coincident peaks that occurred during the Summer (June, July and August). A wind farm that does not have any commercial operation history will receive a wind capacity credit equivalent to the system wide wind capacity credit from the ELCC study, for their initial Planning Year, and there after metered data is will be used to calculate its future wind farm specific wind capacity credit, if no metered data is available then the wind farm with receive a capacity credit of 0%. All other Intermittent Generation and Dispatchable Intermittent Resources will have their annual UCAP value determined based on the 3 year historical average output of the resource from 1500-1700 EST for the most recent Summer months (June, July, and August). Note: MPs will need to supply this historical data to MISO by October 31 of each year in order to have UCAP value determined. Non wind powered Intermittent Generation and Dispatchable Intermittent Resources that are new, upgraded or returning from extended outages must submit all operating data of June, July, or August with a minimum of 30 consecutive days, in order to have their new or upgraded capacity registered with MISO. Note: Refer to the BPM for details specific to UCAP adjustments relating from Qualified extended outages Changing nameplate capability Partial outages due to force majeure Must-Offer A must offer requirement applies to the Installed Capacity of a Generation Resource, and not to the UCAP rating of the Generation Resource. Installed Capacity refers to the amount of ZRCs designatedin the PRA divided by (1 XEFORd) of the Capacity Resource. 14

Day-Ahead (DA) Reliability Forecast submissions for Intermittent Generation and Dispatchable Intermittent Resources received by the Day-Ahead Market close and Forward Reliability Assessment Commitment (FRAC) close will be used to monitor for compliance with the must offer requirement when the unit s availability is due to non-mechanical and/or non-maintenance reasons. The must offer monitoring process for Intermittent Generation and Dispatchable Intermittent Resources that submit a DA Reliability Forecast by DA Market close and FRAC close will check that the offers submitted are greater than or equal to the volumes submitted via the DA Reliability Forecast. The same Intermittent Forecast data file used in Day-Ahead Must Offer compliance shall be utilized in FRAC if no further update is provided. DA Reliability Forecast shall replace the Installed Capacity as the Must Offer requirement if a DA Reliability Forecast is submitted. DA Reliability Forecasts must be in the required format and submitted via the portal in order to be used by the must offer compliance monitoring process. The must offer monitoring process for Intermittent Generation and Dispatchable Intermittent Resources that do not provide the DA Reliability Forecast by DA Market close and FRAC close will be based on offers submitted and outages or derates submitted in CROW. For purposes of calculating the must offer requirement for Intermittent Generation and Dispatchable Intermittent Resources powered by wind an XEFORd of one minus the footprint wide capacity credit will be used (80% for the initial Planning Year). For non wind Intermittent Generation and Dispatchable Intermittent Resources the XEFORd will be set equal to the UCAP divided by the ICAP where the ICAP shall be the maximum value registered in the Commercial Model or the Module E Capacity Tracking Tool (MECT). 14

Use Limited Resources are defined as Generation Resources or External Resource(s), that due to design considerations, environmental restrictions on operations, cyclical requirements (such as the need to recharge or refill), or for other non-economic reasons, are unable to operate continuously on a daily basis, but are able to operate for a minimum set of consecutive operating Hours each day. A Capacity Resource may be defined as a Use Limited Resource if it: Is capable of providing the Energy equivalent of its claimed Capacity for a minimum of 4 continuous hours each day across the Transmission Provider s peak. Submits GADS Data to MISO. Notifies MISO of any outage (including partial outages) and the expected return date from the outage. Demonstrates capability and submit the results to MISO. Identifies the resource as use limited when registering the asset. Qualification Requirements Use Limited Resources (that are not Intermittent Generation and Dispatchable Intermittent Resources) may qualify as Capacity Resources provided that: a. They are registered with MISO as documented in the Market Registration BPM. b. Limited Resources must be deliverable to Load within the MISO Region. 15

Use Limited Resources 10 MW, based on GVTC, must submit generator availability data (including, but not limited to, NERC GADS) into a database through the Market Portal. Use Limited Resources < 10 MW, based upon GVTC, that begin reporting generator availability data must continue to report such information. New UseLimited Resources must submit GVTC and,if 10 MW based on GVTC, must submit GADS prior to being approved as a Capacity Resource. The XEFORd for new Limited Resources in service less than twelve full calendar months will be the class average for the resource type. A Limited Resourcewill use the class average value until 12 consecutive months of data is available and a new Planning Year has occurred. GVTC Limited Resources must demonstrate capability on an annual basis. All Limited Resources being used as a Planning Resource are required to perform a real power test, according to the MISO Generator Test Requirements, and submit the GVTC to the MISO PowerGADS no later than October 31 st in order to qualify as a Planning Resource. GVTC tests are performed between September 1 st and August 31 st of the prior Planning Year and corrected to the average temperature of the date and times of MISO coincident Summer peak, measured at or near the generator s location, for the last 5 years, or provide past operational data that meets these requirements to determine its GVTC and submit to the MISO PowerGADS. Real Power Test is required To demonstrate a modification that increases the rated capacity of a unit, and then submit the revised GVTC. When returning from a mothballed state, and then submit the GVTC. When any existing or new unit returns to MISO after an absence (including but not limited to, catastrophic events, or not qualified as a Planning Resource under Module E) or being qualified as a Planning Resource for the first time. Reporting GVTC results is accomplished through the MISO PowerGADS reporting system as described in the MISO Net Capability Verification Test User Manual, which is located on the MISO website under Documents> Resource Adequacy> Documents> GADS Information Link> PowerGADS Documentation> Generator Testing Documents. UCAP Determination 15

The unforced capacity calculation is based on theresource stype and volume of interconnection service, GVTC, and forced outage rate (XEFORd). The first step is to determine the total installed capacity that the Planning Resource can reliably provide, which is the Total Interconnection ICAP. The next step is to convert the resultant Total Interconnection ICAP value to unforced capacity value, Total Interconnection UCAP, by applying its forced outage rate (XEFORd). Appendix H of the ResourceAdequacy BPM describes the processes and calculations for determining both ICAP and UCAP values. The UCAP methodology is implemented to address the fact that not all Use Limited Resources contribute equally to Resource Adequacy. By adjusting the capacity rating of a unit, based on its XEFORd, UCAP provides a means to recognize the relative contribution that each resource makes towards Resource Adequacy. When the PRM requirement is similarly adjusted by the weighted average XEFORd of all the pooled resources, the generating units with better than average availability will reflect higher value than units with below average availability. EFORd <<Not XEFORd>> options for units affected by catastrophic outages and zero service hours are further outlined in the BPM. UCAP MW options for units with derates prior to the GVTC test date is further explained in the BPM. Provisional UCAPS fornew or existing units if provide written notification to MISO by February 15 th prior to the start of the Planning Year if unit will test after March 1 st but before the Planning Year begins GVTC or resource replacement must be completed by May 30 th or the last business day of May, whichever is earlier CONE applies if GVTC or replacement not completed by due date Written notification must be from officer of the company and include unit type, fuel type, MW, estimated date of test, resource name, LRZ, and NERC ID New units must have an executed interconnection agreement and registered in June Commercial Model MP must post credit for provisional UCAPs no later than March 1 st prior to the Planning Year Must-Offer A Use Limited Resource must offer into the Day-Ahead Market for at least 4 continuous hours each day across the Transmission Provider s peak in such a way as to enable MISO to schedule the Resource for the period in which the Use Limited Resource will not be recharging or replacing depleted resources. The Transmission Provider s peak will be based on the peak including 2 hours prior to the beginning of the peak hour through the end of the hour following the peak hour as specified in the Market Report available on the public MISO web site. 15

The peak information from the forecast published one day prior to the operating day will be used in the must offer check process. An MP with a Use Limited Resource is required to submit a must offer for at least the number of minimum capacity hours optimized to match the expected peak load in the Region. Outages and derates for Use Limited Resources need to be reflected in CROW. Thresholds for Use Limited Resources will only be applied during the four continuous hours across the Transmission Provider s peak. MISO will not call upon a Use Limited Resource during its recharge hours, except in the case of an Emergency, in accordance with the must offer provisions detailed in the BPM. 15

Qualification Requirements External Resources can qualify as Capacity Resources as follows: An MP that owns External Resources or contracts for an External Resource via a Power Purchase Agreement (PPA) may also register its External Resources. External Resources that are also Intermittent Generation must meet all requirements as defined for an Intermittent Generation and Dispatchable Intermittent Resource. External Resources that are also Use Limited Resources must meet all requirements as defined for a Use Limited Resources. An MP will submit the completed applicable registration form in the Module Capacity Tracking Tool (MECT) by February 1 st prior to the Planning Year if existing and March 1 st if new. The registration form will require the MP to certify that the qualified MWs from the External Resources are not being registered by another party. MISO will notify the MP within 15 days regarding accreditation of the External Resource. If the External Resource qualifies, it will be given a unique name for tracking purposes. MISO will coordinate with appropriate neighboring entities (RTOs, LBAs, etc.) to ensure External Resources are not being utilized for capacity purposes by such entities; the purpose for this coordination effort is to 16

eliminate double counting of capacity across seams. MPs that register External Resources may receive eligible UCAP provided that the MP: 1. Demonstrates firm Transmission Service from the External Resource to the border of the MISO Region or demonstratingdeliverability as described in 69A.3.1.g in Module E-1. Firm Transmission Service has been obtained to deliver at least the ICAP amount of the Capacity Resource seeking to be qualified on the Transmission System from the External Resource(s) to the CPNode. The CPNode will be interpreted as the LBA the MISO OASIS reservation sinks in for Network Customers, or ; The External Resource has Network Resource Interconnection Service under Attachment X of the Tariff, and can demonstrate use of the Network Resource Interconnection Service by having firm Transmission Service to Load. 2. Demonstrates that any External Resources or portions of External Resources being registered as Capacity Resources to serve the Load of the LSE are not otherwise being used as capacity resources in any other RTO/ISO or in another state resource adequacy program; is available in the event of an Emergency; and performs an annual GVTC test and reports data via GADS. External Resources 10 MW, based on GVTC, must submit generator availability data (including, but not limited to, NERC GADS) into a database through the Market Portal. External Resources < 10 MW, based upon GVTC, that begin reporting generator availability data must continue to report such information. New External Resources must submit GVTC and,if 10 MW based on GVTC, must submit GADS prior to being approved as a Capacity Resource. Note: This 10MW threshold applies to individual generator sizes and not to contracted capacity values in PPAs The XEFORd for new External Resources in service less than twelve full calendar months will be the class average for the resource type. A External Resource will use the class average value until 12 consecutive months of data is available and a new Planning Year has occurred. Note regarding Power Purchase Agreements (PPAs) If the PPA involves a transfer of capacity within the MISO Region then this transaction should be represented in the MECT as a Local ZRC Transaction. If the PPA involves External Resources, once such External Resources are 16

registered and accredited then the associated UCAP MWs may be converted to ZRCs. In order for a PPA to qualify as a Capacity Resource it mustdemonstrate that it complies with the requirements found in the Tariff under 69.3.1.c. GVTC External Resources must demonstrate capability on an annual basis. All External Resources being used as a Planning Resource are required to perform a real power test, according to the MISO Generator Test Requirements, and submit the GVTC to the MISO PowerGADS no later than October 31 st in order to qualify as a Planning Resource. GVTC tests are performed between September 1 st and August 31 st of the prior Planning Year and corrected to the average temperature of the date and times of MISO coincident Summer peak, measured at or near the generator s location, for the last 5 years, or provide past operational data that meets these requirements to determine its GVTC and submit to the MISO PowerGADS. Real Power Test is required To demonstrate a modification that increases the rated capacity of a unit, and then submit the revised GVTC. When returning from a mothballed state, and then submit the GVTC. When any existing or new unit returns to MISO after an absence (including but not limited to, catastrophic events, or not qualified as a Planning Resource under Module E) or being qualified as a Planning Resource for the first time. Reporting GVTC results is accomplished through the MISO PowerGADS reporting system as described in the MISO Net Capability Verification Test User Manual, which is located on the MISO website under Documents> Resource Adequacy> Documents> GADS Information Link> PowerGADS Documentation> Generator Testing Documents. UCAP Determination The unforced capacity calculation is based on theresource stype and volume of interconnection service, GVTC, and forced outage rate (XEFORd). The first step is to determine the total installed capacity that the Planning Resource can reliably provide, which is the Total Interconnection ICAP. The next step is to convert the resultant Total Interconnection ICAP value to unforced capacity value, Total Interconnection UCAP, by applying its forced outage rate (XEFORd). Appendix H of the ResourceAdequacy BPM describes the processes and calculations for determining both ICAP and UCAP values. 16

MISO will determine UCAP values for External Resources that are Intermittent Generation as described for Intermittent Generation and Dispatchable Intermittent Resources. EFORd <<Not XEFORd>> options for units affected by catastrophic outages and zero service hours are further outlined in the BPM. UCAP MW options for units with derates prior to the GVTC test date is further explained in the BPM. Provisional UCAPS fornew or existing units if provide written notification to MISO by February 15 th prior to the start of the Planning Year if unit will test after March 1 st but before the Planning Year begins GVTC or resource replacement must be completed by May 30 th or the last business day of May, whichever is earlier CONE applies if GVTC or replacement not completed by due date Written notification must be from officer of the company and include unit type, fuel type, MW, estimated date of test, resource name, LRZ, and NERC ID New units must have an executed interconnection agreement and registered in June Commercial Model MP must post credit for provisional UCAPs no later than March 1 st prior to the Planning Year Must-Offer The maximum must offer requirement applies to the registered Capacity of the External Resource. An MP that converts the External Resource UCAP MW into ZRC must submit the full operable capacity of the Resource but no less than the registered Capacity of what was designatedin the Planning Resource Auctionfor each hour of each day during the Operating Month and make an Offer in the Day-Ahead and each pre- Day-Ahead and first post Day-Ahead RAC, except to the extent that the External Resource is unavailable due to a full or partial forced or scheduled outage. The full operable capacity for an offer into the Day-Ahead Market that is using firm MISO Network Integration Transmission Service will be the Network Customer s forecasted peak Demand for the day being offered. Offers in the Day-Ahead Energy Market can be either fixed or dynamic. Day-Ahead cleared schedules are accounted for in the FRAC process; however, schedules that do not clear Day-Ahead are not evaluated in FRAC. The must offer requirement for External Resources in FRAC is met by being available for declared capacity emergencies via Emergency Operating Procedure (EOP-002). 16

The MP that converts the External Resource UCAP MW to ZRC must ensure the resource operator is reporting its outages and derates with their respective reliability coordinator via System Data Exchange (SDX). External Resources must be available to schedule Energy into the Transmission Provider Region during emergencies if needed by the Transmission Provider. EOP-002 includes a mechanism to schedule all external Capacity Resources into the MISO Balancing Authority Area (BAA). BPM-007,Physical Scheduling Systems,explains how External Resources should be identified as Capacity Resources. Note: External Resources that are Use Limited Resources must follow the Day-Ahead must offer requirements for Use Limited Resources. 16

Qualification Requirements Note: GVTC and GADS requirements stated below only apply for DRR Type I and Type II when backed by generation. DRR Type I and Type II may qualify as Capacity Resources provided that they are registered with MISO as documented in the Market Registration BPM and satisfy the requirements: DRR Type I and Type II (that are not Intermittent Generation and Dispatchable Intermittent Resources) must submit generator availability data (including, but not limited to, NERC GADS) into a database through the Market Portal DRR Type I and Type II < 10 MW based upon type and volume interconnection service, GVTC that begin reporting generator availability must continue to report such data. New DRR Type I and Type II Resources must submit GVTC and if 10 MW based on GVTC must submit GADS prior to being approved as a Capacity Resource. The XEFORd for new DRR Type I and Type II Resources in service less than 12 full calendar months will be the class average for the resource type. A DRR Type I and Type II Resource will use the class average value until 12 consecutive months of data is available and a new Planning Year has 17

occurred. GVTC DRR Type I and Type II must demonstrate capability on an annual basis. All DRR Type II backed by a generator being used as a Planning Resource are required to perform a real power test, according to the MISO Generator Test Requirements, and submit the GVTC to the MISO PowerGADS no later than October 31 st in order to qualify as a Planning Resource. GVTC tests are performed between September 1 st and August 31 st of the prior Planning Year and corrected to the average temperature of the date and times of MISO coincident Summer peak, measured at or near the generator s location, for the last 5 years, or provide past operational data that meets these requirements to determine its GVTC and submit to the MISO PowerGADS. Real Power Test is required To demonstrate a modification that increases the rated capacity of a unit, and then submit the revised GVTC. When returning from a mothballed state, and then submit the GVTC. When any existing or new unit returns to MISO after an absence (including but not limited to, catastrophic events, or not qualified as a Planning Resource under Module E) or being qualified as a Planning Resource for the first time. Reporting GVTC results is accomplished through the MISO PowerGADS reporting system as described in the MISO Net Capability Verification Test User Manual, which is located on the MISO website under Documents> Resource Adequacy> Documents> GADS Information Link> PowerGADS Documentation> Generator Testing Documents. UCAP Determination MISO will determine the UCAP value for each DRR that is a behind the meter generation facility based on an evaluation of GVTC value and XEFORd values of such behind the meter generation facility. If such behind the meter generation facility is interconnected to the Transmission System, MISO will consider the type and volume of the interconnection service when determining the Unforced Capacity. If GADS data is not required to be submitted by the MP, then a class average EFORd of the resource type will used to calculate the forced outage rate. MISO will determine the UCAP value for each DRR that interrupts or controls load based on an evaluation of the GVTC value of such programs. A XEFORd value of zero will be applied to all DRR that interrupts or controls load. 17

EFORd <<Not XEFORd>> options for units affected by catastrophic outages and zero service hours are further outlined in the BPM. UCAP MW options for units with derates prior to the GVTC test date is further explained in the BPM. Provisional UCAPS fornew or existing units (DRR if backed by generator) granted if provide written notification to MISO by February 15 th prior to the start of the Planning Year if unit will test after March 1 st but before the Planning Year begins GVTC or resource replacement must be completed by May 30 th or the last business day of May, whichever is earlier CONE applies if GVTC or replacement not completed by due date Written notification must be from officer of the company and include unit type, fuel type, MW, estimated date of test, resource name, LRZ, and NERC ID New units must have an executed interconnection agreement and registered in June Commercial Model MP must post credit for provisional UCAPs no later than March 1 st prior to the Planning Year Must-Offer Applies to the Installed Capacity of DRR Type I and Type II, and not the UCAP rating. Installed Capacity refers to the amount of ZRCs divided by (1 XEFORd) of the Capacity Resource. The MP that designate ZRCs in the Planning Resource Auction for a DRR Type I must submit the total target reduction of the resource designated. The MP that converts the DRR Type II UCAP MWs into ZRCS must submit the full operable capacity of the Resource but no less than the ICAP value of what was designated in the PRAfor each hour of each day during the Operating Month and Offer in the Day-Ahead Energy and all pre Day-Ahead and the first post Day-Ahead RAC, except to the extent that the DRR is unavailable due to a full or partial forced or scheduled outage and that the outage is reported to MISO. 17

Load Modifying Resources are not Capacity Resources and are classified as either a Demand Resource (DR) or Behind the Meter Generation (BTMG). A Demand Resource is defined as Interruptible Load or Direct Control Load Management and other resources that result in additional and verifiable reductions in end-use customer demand during an emergency. Behind the Meter Generation is defined as a generation resource used to serve wholesale or retail load that is located behind a CPNode. BTMG is not included in MISO s Dispatch Instructions. LMRs do not have a must offer requirement but they must be available for use during Emergency events declared by MISO. MISO s Emergency Operations Manuals, RTO-EOP-002 and RTO-EOP- 004, include the procedures on how and when LMRs will be called on in an Emergency situation. There are penalty provisions for LMR that fail to perform when called upon during Emergencies declared by MISO. DRR Type I and Type II are categorized as Capacity Resources under Module E and therefore are not an LMRs. If a DR or BTMG does not qualify as an LMR under Module E, that does not necessarily disqualify it from being an Emergency Demand Response (EDR) resource under Schedule 30. 18

Obligations and Penalties Accredited LMRs that have been designated in a Planning ResourceAuction must be available for use in the event of an Emergency declared by MISO. Subject to penalties if that LMR fails to respond To an amount greater than or equal to the target level of Load reduction for DRs -or- To the target level of generation increase for BTMG as directed by MISO or LBA in accordance with emergency operating procedures. The target level of Load reduction for a DR will take into account the specified firm service level if specified at registration. Outages for maintenance or Force Majeure may be exempt from penalties. Section 69A.3.9 of the Tariff describes the requirements,penalties, and exemptions for an LMR not meeting it s requirements. 18

Qualification Requirements MPs with BTMGs can qualify as LMRs by: Deliverable to Load located within the MISO Region Be available to provide energy with no more than 12 Hours advance notice from MISO or LBA. Sustain energy production for a minimum of 4 consecutive Hours. Capable of being interrupted at least 5 times during the summer season when called on by MISO or LBA for emergency purposes during the Planning Year. 100 kw (aggregation of smaller resource that can produce energy may qualify in meeting this requirement). BTMG 10 MW, based on GVTC or NDC, must submit generator availability data (including, but not limited to, NERC GADS) into a database through the Market Portal. BTMG < 10 MW, based upon GVTC, that begin reporting generator availability data must continue to report such information. New BTMG resources must submit GVTC and, if 10 MW based on GVTC, must submit GADS prior to being approved as a LMR. The XEFORd for new BTMG Resources in service less than 12 full calendar months will be the class average for the resource type. A BTMG resource will use the class average value until 12 consecutive months of 19

data is available and a new Planning Year has occurred. GVTC BTMG Resources must demonstrate capability on an annual basis. All Resources being used as a Planning Resource are required to perform a real power test, according to the MISO Generator Test Requirements, and submit the GVTC to the MISO PowerGADS no later than October 31st in order to qualify as a Planning Resource. GVTC tests are performed between September 1st and August 31st of the prior Planning Year and corrected to the average temperature of the date and times of MISO coincident Summer peak, measured at or near the generator s location, for the last 5 years, or provide past operational data that meets these requirements to determine its GVTC and submit to the MISO PowerGADS. Real Power Test is required To demonstrate a modification that increases the rated capacity of a unit, and then submit the revised GVTC. When returning from a mothballed state, and then submit the GVTC. When any existing or new unit returns to MISO after an absence (including but not limited to, catastrophic events, or not qualified as a Planning Resource under Module E) or being qualified as a Planning Resource for the first time. Reporting GVTC results is accomplished through the MISO PowerGADS reporting system as described in the MISO Net Capability Verification Test User Manual, which is located on the MISO website under Documents> Resource Adequacy> Documents> GADS Information Link> PowerGADS Documentation> Generator Testing Documents. UCAP Determination The unforced capacity calculation is based on theresource stype and volume of interconnection service, GVTC, and forced outage rate (XEFORd). The first step is to determine the total installed capacity that the Planning Resource can reliably provide, which is the Total Interconnection ICAP. The next step is to convert the resultant Total Interconnection ICAP value to unforced capacity value, Total Interconnection UCAP, by applying its forced outage rate (XEFORd). Appendix H of the ResourceAdequacy BPM describes the processes and calculations for determining both ICAP and UCAP values. The UCAP methodology is implemented to address the fact that not all Generation Resources contribute equally to Resource Adequacy. By adjusting the capacity rating of a unit, based on its XEFORd, UCAP provides a 19

means to recognize the relative contribution that each resource makes towards Resource Adequacy. When the PRM requirement is similarly adjusted by the weighted average XEFORd of all the pooled resources, the generating units with better than average availability will reflect higher value than units with below average availability. Provisional UCAPS fornew or existing units granted if MP provides written notification to MISO by February 15 th prior to the start of the Planning Year if unit will test after March 1 st but before the Planning Year begins GVTC or resource replacement must be completed by May 30 th or the last business day of May, whichever is earlier CONE applies if GVTC or replacement not completed by due date Written notification must be from officer of the company and include unit type, fuel type, MW, estimated date of test, resource name, LRZ, and NERC ID New units must have an executed interconnection agreement and registered in June Commercial Model MP must post credit for provisional UCAPs no later than March 1 st prior to the Planning Year Obligation BTMG should be deliverable to Load located within the MISO Region using one of the following: BTMG that is located at the same node as the LSE s demand LSE has obtained firm transmission service from the BTMG to its load BTMG may be used by any Network Customer within the LBA in which the BTMG is located provided that the Network Customer identifies the BTMG as a Network Resource on the MISO OASIS. The load is a network customer and the BTMG has been determined to be aggregate deliverable by acquiring Network Resource Interconnection Service, or the Market Transition Deliverability test provided the BTMG is interconnected to the MISO Transmission System. Must perform when deployed during capacity emergencies; penalty applies to non-performance Note: The BPM outlinesspecific information regarding penalties when a BTMG fails to perform during emergency conditions and the Measurement & Verification of BTMG. 19

Qualification Requirements MPs with DR can qualify the DR as an LMR by: Deliverable to Load located within the MISO Region Be available to provide energy with no more than 12 Hours advance notice from MISO or LBA. Sustain energy production for a minimum of 4 consecutive Hours. Capable of being interrupted at least 5 times during the summer season when called on by MISO or LBA for emergency purposes during the Planning Year. 100 kw (aggregation of smaller resource that can produce energy may qualify in meeting this requirement). Documenting capability to reduce demand to a targeted reduction or firm service level using one of the following: 1. Documentation from the state with jurisdiction that provides the amount and type of DR and the procedures for achieving the Demand reduction. 2. Verification from third party auditor that documents the DR s ability to reduce to the targeted Demand reduction or firm service level when called upon. 3. Provide past performance data from the previous Planning Year that demonstrates the DR s ability to reduce to the targeted Demand reduction or firm service level when called upon. 20

Note: If past performance data does not exist from the previous Planning Year, a mock test can be used to support the validity of the DR. The mock test should employ all systems necessary to initiate a Demand reduction short of actual Demand reduction. Refer to the BPM for specific requirements regarding a mock test. An MP that registers a DR as a Planning Resource must confirm that the DR is able to meet all of the requirements specified in the Tariff under 69.3.5. UCAP Determination A qualified Demand Resource will receive 100% of its capacity rating for the initial Planning Year. Capacity values for Demand Resources will be based on documentation from the state, third party auditor, or past performance. MPs that registered the LMR can elect to convert all or part of the LMR s accredited MWs into ZRCs. An LSE that designates ZRCs from an qualifiedlmr, or uses Demand Resources in its Resource Plan, will be subject to the penalty provisions, contained in the Tariff under 69.2.2.3, for not responding during an Emergency. EFORd <<Not XEFORd>> options for units affected by catastrophic outages and zero service hours are further outlined in the BPM. UCAP MW options for units with derates prior to the GVTC test date is further explained in the BPM. Obligation The owner of the local ZRCs from a DR may not designate the ZRCs to an LSE located outside of the LBA in which the DR physically resides. Must perform when deployed during capacity emergencies; penalty applies to non-performance Note: The BPM outlinesspecific information regarding penalties when a DR fails to perform during emergency conditions and the Measurement & Verification of DR. 20

At a minimum of a monthly basis, MISO monitors whether the offers in the Day-Ahead Energy and Operating Reserve Market and the Forward Reliability Assessment Commitment (FRAC) process meet the must offer requirements of the Asset Owner of each Capacity Resource that created ZRCs. MISO will compare the difference between the Emergency Maximum Limit (MW) or scheduled maximum (MW) offer and the must offer requirement (MW) for each hour of each day. If the Offers for Day-Ahead and/or FRAC are less than the must offer requirement, MISO will then compare the difference to derates in CROW. Timelines for DA Market and FRAC are presented in the training modules and BPM for Energy and Operating Reserve Markets. MISO will apply a threshold, at the CPNode, to all resources based on their Must Offer Requirement reported in the MECT. The thresholds were developed to recognize that data entry errors sometimes occur when providing derate volumes through CROW. This does not, however, relieve the MP of the obligation to meet the must offer requirement for the threshold volume. The thresholds are as follows: The lesser of 10 MW or 10% for Capacity Resources 50 MW The greater of 1 MW or 10% for Capacity Resources < 50 MW If the difference between the market offer and the must offer requirement, including the appropriate threshold, is documented in CROW as a derate, then 23

the MP will have passed the must offer monitoring check. If the difference is not documented as a derate or full outage, then the MP will not pass the must offer monitoring check. MISO will notify MPs through a report published on the MECT portal if they do not pass the monitoring check. The IMM also has access to the reports published on the MECT portal and may contact Market Participants directly regarding any compliance issues. Note: Must Offer requirement violations provide for no explicit penalty. If an MP violates the must-offer requirement, however, the violation may be considered an EMT violation and referred to the IMM for action. The IMM could ultimately refer to the FERC office of violation which could result in financial penalty. 23

Enhancing Load Forecasting LSEs --or Electric Distribution Companies (EDC) in retail choice states --will provide annual peak Demand forecasts coincident with MISO s peak based upon MISO s historical peak demand information Accounting for Load diversity will be moved from the Planning Reserve Margin calculation to Load forecasts by LSEs. MISO will be responsible for calculation, determination, and inclusion of transmission losses in each LSE s Demand forecast. MISO will periodically review LSE or EDC demand forecast methodologies and inputs for acceptability and consistency. 25

Full Responsibility Purchases and Sales (FRP/FRS) An LSE (purchaser) may contract with other entities (sellers) to be responsible for providing ZRC for all or part of its load delivered to the purchaser through an FRP/FRS agreement. FRP/FRS agreements are treated effectively like a transfer of Forecasted Demand and the associated PRMR from one LSE to another. If the seller is not an LSE under the jurisdiction of the MISO, then the purchaser will remain responsible for any RAR deficiencies associated with the FRP/FRS agreement. The purchaser who is responsible for any RAR deficiencies may coordinate with the non-jurisdictional party to ensure that any RAR obligations associated with transferred Demand are met. Purchaser As purchaser, an LSE with an FRP is required to include the transferred Forecasted Demand into the MECT. An LSE s Planning Reserve Margin Requirement (PRMR) will be reduced for such purchases, by the amount of transaction load, which the LSE identifies in an FRP The PRMR of the seller that identifies the complimentary FRS will be increased by the amount of transaction load that the seller identifies as an FRS The purchaser under an FRP agreement must provide MISO the 26

Coincident Peak Forecast Seller As seller, an MP with an FRS is required to designate qualified ZRCs to meet this additional obligation as though it was their own load. The seller under an FRS agreement must include Planning Resources for the transaction load multiplied by 1 plus the PRM in its Resource Plan. All sellers of an FRS to a MISO LSE must be a registered MP and account for the load, multiplied by 1 plus the PRM, for the FRS via their Resource Plan. The obligation to serve the load is shifted but the obligation to forecast the Demand at that CPNode (load) remains with the original LSE (purchaser). Both parties must enter an FRP/FRS transaction into the MECT as a full responsibility transaction to enable the MISO to track the load and reserve obligations shift. Note: ZRCs may be also be transacted between MPs via other means including bilateral trades and the VCA. 102-Executive Training, provides an overview of these processes including a comparison of recent volumes transacted. 26

PRA Mechanisms Will provide a competitive market mechanism to assist LSEs in knowing the competitive market price for Zonal Resource Credits (ZRCs) required to meet Local Resource Requirements, Capacity Export Limits, and Capacity Import Limits in an Local Resource Zone. ZRCs from Planning Resources that clear in a PRA will receive the clearing price for the Local Resource Zone where the Planning Resource is located during the applicable forward Planning Year on a daily basis from the LSEs in that Local Resource Zone. Load and Planning Resources designated in FRAPs will be modeled in the PRA process to accurately account for their impacts to Local Clearing Requirements, Capacity Import Limits and Capacity Export Limits From: MISO Resource Adequacy Construct OMS Outreach Series #5 Auction Purpose The PRA serves several purposes, all related to making sure that an adequate supply of resources not an excess supply is available to meet demand. 1. One purpose of the auction is to determine a market-based value 27

attached to having resources located in certain geographical areas. MISO is required via a FERC Order to construct a resource adequacy approach that takes resource location into account and determines a value for such locations using a market-based approach. 2. Another purpose of the auction is to determine and place a value upon any congestion related to the different locations of capacity and load. While transmission congestion is evaluated in the energy and ancillary services market, such congestion is related to more narrowly defined issues. The auction will identify congestion related to capacity based upon issues that reflect annual peak conditions as opposed to conditions occurring throughout the year. Key Auction Elements The proposed auction will consider available resources with loads on a zonal basis. Key elements related to the auction include the following: Annual peak demand forecasts, prepared by LSEs [Electric Distribution Companies (EDCs) in retail choice states] and is for the total demand of their customers at the time of MISO s annual summer peak, Transmission limitations determined from system engineering studies to allow the maximum amount of low cost resources to provide service, Local Clearing Requirements indicating the amount of capacity that must be secured from resources within each zone to meet the reliability standard, and a Single, sealed-bid auction style designed to minimize the ability for participants to signal or game the auction, while at the same time providing efficient market-clearing prices. The auction mechanisms are a relatively straightforward application of costminimization formulas that also provide a simultaneous solution for all zones. The resulting auction clearing prices will reflect the relative scarcity of available capacity in each zone. Market Participants will see these transparent results and be able to more efficiently and effectively plan for the future. MISO s Proposed PRA vs. PJM s Capacity Auction The PRA envisioned is not PJM s Reliability Pricing Model (RPM). While there are many inherent differences between the two auctions, several significant distinctions are apparent: In MISO, the demand being met by the auction is developed by those with the most local knowledge of the retail customers: the LSEs themselves. In the RPM, PJM (or a surrogate) prepares the demand forecasts. 27

In MISO, the auction is prompt, not 3-years forward. The demand forecast being met by the PRA is MISO is the demand for the immediate following summer. The demand forecast being met by the RPM in PJM is for the summer 38-to-40 months in the future. In MISO, the auction meets a planning resource requirement that must be met and no more. 27

From: MISO Resource Adequacy Construct OMS Outreach Series #2 Under MISO s proposal, Load Serving Entities (LSE) can use the self-scheduling provision or in the alternative, a proposed opt-out provision, to meet their Planning Reserve Margin Requirements (load forecast plus reserve margin). Both provisions are designed to allow the LSE s to remain doing what they do today to satisfy their resource planning requirements. One provision works in conjunction with the Planning Resource auction (self-scheduling) while the other allows you to forego the auction and opt-out. This communication is to further your understanding of the current proposed self-scheduling provision as well as introduce the proposed alternative opt-out provision. Self Scheduling Provision This feature of the proposed Resource Adequacy construct gives the LSE the flexibility to use its resources to meet all or a portion of their load requirements in the auction. The mechanism used to do this netting of resources and load in the auction is called a self-schedule. The LSE has the flexibility to self-schedule all or a portion of their needs and acquire their remaining resource needs through the Planning Resource Auction. These self-schedules are not subject to the economics of the auction. 28

MISO has proposed seven zones within the footprint to ensure that resources can be reliably delivered to the load. There may be positive or negative economic impacts when load and resources are located in different zones. LSEs should consider the following scenarios: Planning Resources and Load in the same zone has no price effect on the LSE. If the Planning Resource has existing firm transmission rights to deliver resources to a load in another zone then MISO will grant the LSE a financial hedge (Grandmother Agreement) and there will be no price effect on the LSE. LSEs with Planning Resources located in zones with a higher clearing price than the LSE s load will receive a net benefit. LSEs with Planning Resources located in zones with a lower clearing price than the LSE s load will pay for the congestion through a higher price. New Planning Resources will be eligible for a hedge against congestion in the auction if the LSE invests in new or upgraded transmission to serve the LSE s load in a different zone. Opt-out Provision In response to stakeholders concerns regarding Federal Energy Regulatory Commission (FERC) and Independent Market Monitor (IMM) oversight of the Resource Adequacy process, MISO is also considering an opt-out proposal. This provision allows the LSE to forego the auction altogether and alternatively submit a plan that identifies resources for their load. The LSE s plan must be consistent with current resource qualification provisions. In the case where an LSE is deficient in their resource needs, the LSE may participate in the auction to acquire additional resources to meet their remaining load obligations. In summary, the Opt-Out provision provides LSEs with an alternative to selfscheduling resources in the Planning Resource Auction to meet their Resource Adequacy requirements. This option provides LSE s with protection against IMM mitigation procedures for new investment and allows them to avoid the slippery slope of future changes to Resource Adequacy provisions. 28

Establishing Local Resource Zones Local Resource Zones will be developed to ensure that sufficient qualified Planning Resources can be relied upon to meet Load within each Local Resource Zone The geographic boundaries of a Local Resource Zone will be based upon: The geographical boundaries of Local Balancing Authorities State boundaries The relative strength of transmission interconnections between Local Balancing Authorities The results of Loss of Load Expectation studies The location of existing and proposed Planning Resources The relative size of Load Resource Zones Recognizing import/export constraints on Local Resource Zone capacity requirements Establishing Local Resource Zone capacity requirements will encourage parties to develop or retain the right amount of Planning Resources in the right locations within the MISO Region, consistent with FERC s June 8, 2010 order. Local Reliability Requirements determining the level of capacity needed such that an Local Resource Zone achieves an LOLE of 0.1 day per year, without consideration of transmission ties to systems outside of the Local Resource Zone. LSEs serving load in an Local Resource Zone will meet their RAR 29

obligations through participation in a Planning Resource Auction process. Self-Scheduling will effectively allow Market Participants to financially net out of the Planning Resource Auction. Capacity Export Limits for each Local Resource Zone will represent the maximum amount of Planning Resources located within a Local Resource Zone, that can be exported by Market Participants from an exportconstrained Local Resource Zone. Capacity Import Limits for each Local Resource Zone will represent the maximum amount of Planning Resources located outside a LRC that can be imported by Market Participants into an import-constrained Local Resource Zone. From: MISO Resource Adequacy Construct OMS Outreach Series #6 One of the primary reasons that MISO embarked on enhancing the resource adequacy construct was theferc s June 8, 2010 Order that required MISO and its stakeholders to: evaluate programs of other RTOs/ISOs, such as ISO New England and California ISO, that utilize market mechanisms such as locational pricing and locational market rules that provide incentives for market participants to obtain sufficient local resources to ensure reliability. The Commission s directive was that MISO and its stakeholders, based on this evaluation, would develop a plan that details the steps that will be taken to incorporate these market mechanisms into the Resource Adequacy Plan. MISO worked diligently with stakeholders to address this issue through the creation of zonal requirements and a mechanism to protect Load Serving Entities (LSE) from price risk. Zonal Requirements The proposed resource adequacy Construct introduce location specific requirements that will reflect the limitations of the transmission system. These limits indicate how much capacity needs to be located in a particular zone on a forward looking basis to meet resource adequacy requirements as well as send a transparent market signal. In order to ensure local reliability requirements are maintained, MISO will enforce capacity import and export limitations for each defined zone, as well as a minimum amount of capacity located within 29

each zone. These calculations will be performed annually and evaluated through the MISO stakeholder process. Step 1: Calculate the total resource need for the footprint MISO will calculate the total resources that must be committed to MISO load such that the system does not experience a risk of losing firm load greater than 1 day in 10 years (also known as the Loss of Load Expectation (LOLE) Analysis). MISO evaluates the resource needs of the footprint absent any internal transmission limitations. This calculation results in the MISO system Planning Reserve Margin (PRM). Step 2: Determine the zones that will be modeled to establish local requirements MISO s footprint will be divided into seven (7) zones. The zones have been configured taking into account geographical boundaries of Local Balancing Authorities (LBAs), state boundaries, the relative strength of the transmission interconnections between LBAs, the results of prior analysis, the location of existing and proposed resources, and the relative size of zones. The proposed Local Resource Zone boundaries are essentially collections of Local Balancing Authorities around state boundaries. Step 3: Calculate the transfer limit for each Local Resource Zone In order to determine local resource needs and respect transmission limitations for the delivery of resources, MISO will calculate the transfer limits of each zone. This is essentially how much energy can be delivered to/from the zone. These limits are known as the Capacity Import Limit and the Capacity Export Limit. The Capacity Import Limit drives the level of local resources needed to maintain reliability in that area. The Capacity Export Limit drives a determination of how many total resources can be committed in a zone without violating the capability of the transmission system. These limitations will be calculated using the latest planning models and will be established prior to the Planning Resource Auction. Step 4: Calculate the Local Clearing Requirement 29

In order to determine local resource needs and respect transmission limitations for the delivery of resources, MISO will calculate the transfer limits of each zone. This is essentially how much energy can be delivered to/from the zone without causing congestion. These limits are known as the Capacity Import Limit and the Capacity Export Limit. The Capacity Import Limit drives the level of local resources needed to maintain reliability in that area. The Capacity Export Limit drives a determination of how many total resources can be committed in a zone without violating the capability of the transmission system. Historical Hedging Mechanism A key principle MISO developed for the proposed resource adequacy Construct is to respect prior long term planning performed by state commissions and their LSE s under the existing paradigm. The benefit of the proposed hedging mechanism is that it allows historical service and relationships to continue as they do today. Load Serving Entities that have historically had rights to resources in one zone and load in another are protected from any price separation between those zones. These participants entered into contracts, or built resources themselves, assuming a set of rules that did not have the potential for a differential in prices between the resource and load. These resource/load combinations are considered Grandmother Agreements. In order to qualify for a Grandmother Agreement, the LSE must demonstrate all of the following: Ownership or contractual rights to the resource Firm transmission service from the resource zone to the load zone Contracts and transmission service must be annual (Planning Year basis) Contract must be valid through the 2013/2014 Planning Year Contract must be in place prior to the FERC filing date A Grandmother Agreement expires at the end of the term expressed in the contracts. Future Hedging Mechanism Participants that invest in new or upgraded transmission facilities between resources in one zone and their load in another zone will also receive a hedge for financial protection. Participants using existing available transmission capability will not receive this hedge for the following reasons: Participants will receive a credit that recognizes their share of the import capability 29

used to access lower cost resources outside of the zone where their load is located. Transmission Service is analyzed and awarded on a first-come first-served basis resulting in inefficient allocation of transmission capability for resource adequacy purposes. If granted, it would create an incentive for participants to reserve transmission service in excess of that needed for meeting resource adequacy requirements. 29

Grandmother Agreement Hedge Grandmother Agreement are defined as contractual rights to Planning Resources having firm transmission service rights that are executed prior to July 20, 2011 Grandmother Agreements for existing capacity agreements hold LSEs harmless to changes in capacity rules that were unforeseen at the time the capacity agreements were made. Simple process Financial A Market Participant with a valid Grandmother Agreement will be made-whole for any Auction Clearing Price (ACP) differences between the ACP in the Local Resource Zone (LRZ), where the Demand is located, and the ACP in the LRZ where the Planning Resource specified in the Grandmother Agreement is located. Funds come from excess PRA payments collected by the Transmission Provider After-the-Auction (not a financial instrument) Load pays/resource receives identical amount Revenue Neutrality is detailed under 69.7 of the RAR Tariff Filing Criteria: LSE must have ownership or contractual rights to the resource Must have firm transmission service from the resource zone to the load zone 30

Contracts must be annual interm but can be combination of multiple contracts Planning Resources must have firm transmission service for the entire Planning Year Contract must be valid through entire Planning Year Contract must have been in place prior to July 20, 2011 Hedge will expire at the end 2014/2015 Planning Year forexisting LSEs and new LSEs will expire two Planning Years after integration 30

Charge Hedge Zonal Deliverability Charge is the cost of congestion between zones Recognizes that transfer capability is increased when a participant funds transmission upgrades between a planning resource and load in different zones. Participant that funds the transmission upgrades will be eligible for this hedge. Participants will be eligible for this hedge if they: Have approved firm transmission service where the source and sink are in separate Local Resource Zones that results in required Network Upgrades; Maintain annual firm transmission service between the planning resource and their load; and Maintain all Planning Resource qualification requirements for the resources used to obtain the ZDC hedge. Volume Determination MISO will determine the incremental increase in Capacity Import Limit as a result of the network upgrades as follows: Determine Capacity Import Limits for the sink zone identified in the Transmission Service Request without the new network upgrades Determine Capacity Import Limits for the sink zone identified in the Transmission Service Request with the new network upgrades 31

The difference between the two cases above will determine the volume of the ZDC Hedge in MW This process will be studied based on the order in which the corresponding request Transmission Service Request is received Incremental ZDC hedges will be effective for thirty years or the service life of the facility or upgrade, whichever is less Benefit Hedge Network Transmission Customers pay for transmission service (right to have load served) based on their actual demand Rate is based on existing transmission system (schedule 9) Network Transmission Service Requests that do not result in new network upgrades for resources do not result in additional payments by the transmission customer (customer pays for peak demand not based on locations of DNR) Since all load within a zone pays for transmission service (transfer capability) based on demand (same rate regardless of location of DNR) all load should benefit equally from the transfer capability The benefit results from accessing cheaper resource located outside the zone the load is located in This has also been referred to as congestion rents or over collection from load (previously known as Revenue Neutrality) The resulting benefit is commensurate with each Network Customer network transmission charge 31

Retail Load Switching MISO Tariff identifies flexible options for retail suppliers, EDCs, and Relevant Electric Retail Regulatory Authorities(RERRAs) to develop procedures for tracking retail load switching and assigning RAR obligation to the appropriate retail suppliers Backup Default Method Daily capacity charges related to obligations will be apportioned on a daily Energy pro-rata basis to load served within the EDC Default Method Submitted to and approved by MISO Describe procedures and data used to determine assignment of forecast Coincident Peak Demand in detail Subject to mutual agreement between an LSE and the EDC Must be approved by the Transmission Provider 32

The IMM provisions in Module D are enhanced to address capacity issues that may arise including but not limited to: Potential physical withholding of resources from a Planning Resource Auction ZRC offers made in a Planning Resource Auction that may reflect the exercise of potential market power. From: MISO Resource Adequacy Construct OMS Outreach Series #4 MISO s market power mitigation measures permit MISO to mitigate the market effects of any conduct that substantially distorts competitive outcomes in the MISOadministered markets, while avoiding unnecessary interference with competitive price signals. Mitigation of Supplier Market Power The mitigation measures authorize the mitigation of specific conduct and market outcomes only when the conduct/market outcomes exceed well-defined thresholds. The mitigation measures are designed to allow prices to rise 33

efficiently to reflect legitimate supply shortages while effectively mitigating inflated prices associated with artificial supply shortages in constrained areas resulting from physical or economic withholding. These conduct and impact thresholds remain essentially unchanged from those in use today by the Independent Market Monitor (IMM) for the voluntary capacity auction. The biggest difference between the proposed and existing mitigation is the consideration of mitigation on a zonal basis. Mitigation of Buyer Market Power The Minimum Offer Price Rule (MOPR), is the mitigation measure designed to mitigate the potential for capacity buyers to exercise market power and artificially suppress or collapse capacity market prices. This MOPR mitigation measure is designed to allow capacity prices to fall efficiently to reflect legitimate supply surpluses, but effectively mitigate deflated prices caused by an artificial supply surplus in a zone resulting from apparent uneconomic investment in new generation. Since it is designed to mitigate the effects of someone building an asset just to collapse capacity prices, it will apply to only a very small segment of newgeneration units. Key features of the MOPR: The following resources are not subject to the MOPR: Existing Planning Resources including generation assets, demand resources, external resources, and behind the meter generation; or Pending resources that have been announced and that have received either company or state regulatory authority approval. The cutoff is based on the date that the new tariff becomes effective; or New generation assets used by a Load Serving Entity (LSE) to meet its own requirements or sold bilaterally to another LSE to count towards that LSE s capacity requirements. The portion of the unit that does not meet this requirement may be subject to the MOPR if it meets the requirements below; or Any renewable energy technologies. The following new resources may be subject to the MOPR: The only new resources that maybe subject to MOPR are: Resources not used to cover an LSE s capacity requirement, and; Where such resources receive retail tariff cost recovery, and; Where such resources are combined cycle or combustion turbine natural gas technologies and; Where the capacity surplus in the zone is expected to be more than 500 MW or 5% of the total zonal capacity requirement, and; 33

Where the IMM s forecast of capacity prices in the zone is less than the MOPR (including the subject resource). The MOPR will be set at 75% of the Net Cost of New Entry (Net CONE). The 75% is used to account for the uncertainty associated with the calculation of Net CONE. An Asset Owner may request an exemption from the MOPR for a new resource: An Asset Owner may request an IMM mitigation exemption test for new unit capacity not used to cover LSE (or bilateral) requirements at any time. The ability to request exemption before the build decision reduces uncertainty regarding exemption status. The ability to request exemption after the build decision preserves existing state planning processes. Note: The IMM continues to have the right to seek immediate FERC action if it has evidence of any resources being built to unfairly impact capacity and energy prices, but the IMM is not in charge of investment decisions. 33

For the Planning Year that commenced on June 1, 2009, the monthly CONE was established as $80,000/MW. For Planning Years afterthe initial, MISO works with the Independent Market Monitor (IMM) to recalculate CONE annually by August 1 of each year. In calculating the CONE value, the IMM and MISO consider the following factors: Physical factors: type of resource, location, costs for fuel Financial factors: debt/equity ratio, cost of capital, ROE, taxes, interest, insurance Other factors: permitting, environmental, Operating and Maintenance costs, etc. MISO and IMM will not consider anticipated net revenues from the sale of capacity, Energy, or Ancillary Services as factors in the annual recalculation of the CONE. Once the IMM and MISOhave calculated the CONE, MISO MAKES a filing with the FERC, under 205 of the Federal Power Act, seeking approval from the Commission for the recalculated CONE. 34