Appendix:ICCP and Open- and Closed-Loop Testing

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Integration Readiness:Generator ICCP and Open- and Closed-Loop Testing

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The process diagram below shows detailed steps related to ICCP set-up.

Link Setup

MISO and Entity complete test link setup testing with MISO IT-EMS MISO and Entity complete production link setup testing with MISO IT-EMS

Data Setup

1. Entity provides Commercial Model data 2. MISO defines the outbound market points it will send and provides to Entity 3. Entity configures the list of outbound market points in models4. Entity defines the inbound market points it will send and provides to MISO 5. MISO configures the list of inbound market points in models

ICCP Data Exchange Specification: https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=117550

Integration Readiness:Generator ICCP and Open- and Closed-Loop Testing

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Prepare to Test

1. Test ICCP link established2. MISO will pre-enter the testing

values for all the outbound market points, and the Entity will do the same for inbound market points

3. MISO and the Entity will exchange lists for verification

Test and Validate

4. MISO and the Entity will test the prepared lists and will also spot check them by changing outbound or inbound values, and both parties will validate that these changes can be seen

5. This can be an iterative process, as both groups often are required to troubleshoot SCADA to SCADA data mismatches

Prepare to Test

1. Production ICCP link established2. Repeat Step 2 from Test

Environment3. Repeat Step 3 from Test

Environment

Test and Validate

4. Repeat Step 4 from Test Environment

5. Repeat Step 5 from Test Environment

The process diagram below shows detailed steps related to complete open-loop testing Open-loop testing can begin once a direct ICCP link with MISO is in place Entities that register assets in March can begin testing in June, while others will likely begin in August MISO ICCP Modeling Engineers will coordinate with the respective ICCP provider to set up the inbound and

outbound ICCP data points for each registered market unit

Test Environment Production Environment

Data Exchange To MISO (Inbound)1. Net Generator Output (MW AND MVar)2. Echo Back of MISO Setpoint3. Arming Status of Any Special Protection System4. Switching Device Status (Open/Closed)5. Circuit Breaker Flows (MW and MVar) (generator status

breaker, as a minimum)7. Generation Auxiliaries (MW and MVar) 8. Bus Voltages magnitudes (Kv) 9. Generator Voltage Regulation status (On AVR, Off AVR) AVR:

Automatic Voltage Regulation (Optional)

10. Control Mode 0 offline (not available) 1 online, following dispatch and optionally CR 2 online, providing regulation and CR 3 online and off control

Data Exchange From MISO (Outbound)1. UDS Solve Date 2. UDS Solve Time 3. Dispatch Target Energy (MW)4. Dispatch Status for the Resource from the Last UDS Solution5. Cleared Spinning Reserves 6. Cleared Supplemental Reserves 7. Cleared Regulation 8. Deployed Spinning Reserves 9. Deployed Online Supplemental Reserves10. Deployed Offline Supplemental Reserves11. Deployed Regulation 12. Real-Time Control Setpoint13. Control Mode 14. Permissive Blocking Up 15. Permissive Blocking Down 16. Resource Band Number 17. Regulation Maximum Limit18. Regulation Minimum Limit 19. Regulation Minimum Limit 20. Economic Maximum Limit 21. Economic Minimum Limit 22. MISO ACE 23. Echo of Resource Output 24. Regulation Mileage25. Regulation Test

Data sent to MISO (inbound) MISO scans all analogs at a two-second rate (allows receipt of data as soon as it changes), and status measurements are scanned by exception with a 10-minute integrity scan

Data from MISO (outbound) MISO recommends that analog data requested should be scanned at a two-second rate (allows receipt of data as soon as it changes), and status measurements are scanned by exception.

Note: items in bold are required

Integration Readiness:Generator/GOP Reporting Requirements to MISO and LBAs

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Appendix:Resource Adequacy Partial vs. Normal Year Requirements

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Appendix:Resource Adequacy Partial Year vs. Annual Timeline

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Process Responsible EntityPartial Year

(12/19/13 5/31/14)Annual (PY14-15)(6/1/14 5/31/15)

File New Local Resource Zones with FERC MISO 7/15/13 Varies

Generation Resource Test Data (GVTC) and Availability Data (GADS) Due for all generators Resource Owner 7/31/13 10/31/13, 3/1/141

File new Cost of New Entry (CONE) values for each Local Resource Zone with FERC MISO 8/15/13 9/1/13

Capacity Resource UCAP values published to Module E Capacity Tracking Tool MISO 9/1/13 12/1/13

Data for facility ZRC reference levels due 45 days prior to the close of the Planning Resource Auction MISO/IMM 9/27/13 2/16/14

Post initial generic ZRC reference level 30 days prior to the close of the Planning Resource Auction IMM 10/14/13 3/1/14

Annual Coincident Peak Forecast Data Due LSE, EDC 10/18/13 11/1/13

Load Modifying Resource, EER, External Resource Registrations Due Resource Owner 10/18/13 2/1/14, 3/1/141

Grandmother Agreement Hedge Registrations Due LSE 10/18/13 11/1/13

Fixed Resource Adequacy Plans (FRAP) Due LSE 10/23/13 3/11/14

FRAP review by MISO completed MISO 10/25/13 3/15/14

LOLE study results published (Publish PRM, Develop LRZs2, Determine CIL and CEL, Establish LRR) MISO 11/1/12 11/1/13

Transmission losses by LBAs are posted MISO 11/1/13 1/2/14

MISO completes Coincident Peak Demand forecast review process MISO 11/1/13 3/1/14

Grandmother Agreement Zonal Deliverability Charge hedge information posted by MISO MISO 11/1/13 3/1/14

Provide facility specifics 5 days prior to the close of the auction IMM 11/7/13 3/25/14

Resource Auction Offer Window Open MISO 11/8 -11/12/13 3/27-3/31/14

Deadline to elect to pay Capacity Deficiency Charge LSE 11/12/13 3/31/14

Transitional Planning Resource Auction Results Published MISO 11/19/13 4/7/14

Loss of Load Expectation study begins for next Planning Year MISO N/A 2/1/14

Planning Year and daily settlements starts All 12/19/13 6/1/14

Footnotes1For new resources2 LRZs will change

Appendix:List of Acronyms

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Appendix:List of Acronyms

Acronym DescriptionAGC Automatic Generation Control

ARR Auction Revenue Rights

BA Balancing Authority

CCE Customer Connectivity Environment

CEL Capacity Export Limits

CIL Capacity Import Limits

CONE Cost of New Entry

CROW Control Room Operations Window

DART Day-Ahead and Real-Time Energy Market Operation System

DRR Demand Response Resource

EDC Electric Distribution Company

EER Energy Efficiency Resources

ERIS Energy Resource Interconnection Service

FRAP Fixed Resource Adequacy Plan

FTR Financial Transmission Rights

GADS Generator Availability Data System

GIA Generator Interconnect Agreement

GMA Grandmothered Agreement

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Appendix:List of Acronyms (Contd)

Acronym DescriptionGOP Generator Operator

GVTC Generator Verification Test Capacity

ICCP Inter-Control Center Communications Protocol

ICT Independent Coordinator of Transmission

IMM Independent Market Monitor

LBA Local Balancing Authority

LMR Load Modifying Resource

LOLE Loss Of Load Expectation

LRZ Local Resource Zones

LSA Local Security Administrator

LSE Load Serving Entity

MDMA Meter Data Management Agent

MECT Module E Capacity Tracking

MP Market Participant

MTDT Market Transition Deliverability Test

NRIS Network Resource Interconnection Services

ORP Operating Reserve Provider

PMO Project Management Office

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Acronym DescriptionPRM Planning Reserve Margin

PSS Physical Scheduling System

PY Planning Year

QF Qualifying Facility

RC Reliability Coordination

SA Scheduling Agent

SE State Estimator

SPP Southwest Power Pool

TO Transmission Owner

TSR Transmission Service Request

UCAP Unforced Capacity

WAN Wide Area Network

XEFORd Equivalent Demand Forced Outage Rate

XML Extensible Markup Language

ZRC Zonal Resource Credit

Appendix:List of Acronyms (Contd)

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Appendix:Independent Market Monitor

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Independent Market MonitoringData Request

For Reference

MISO South Integration Workshop

Michael Chiasson

April 18, 2013

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Objectives

Market Monitoring Activities To understand how market power abuse is detected and the

actions taken to mitigate it

Data Requirements To understand the data needed to establish cost based

reference levels

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The Role of Market Monitoring

Deregulation is premised on the benefits of replacing regulation with competition to guide generation and transmission usage, and investment.

Under the Federal Power Act, wholesale prices must be just and reasonable.

FERC relies on competition to ensure just and reasonable prices.

In centralized markets, market monitoring and mitigation measures address potential market power concerns.

In the Energy Policy Act of 2005, FERC acquired significant authority to sanction participants for market manipulation.

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Market Power

Market power is the ability of a firm to profitably raise prices above competitive levels (SMD NOPR).

In general, it is far more costly to eliminate all market power than to allow some market power to exit.

Markets for electricity vary with market conditions due to the lack of storage and reliance on the physical transmission network.

Market power in electric markets is generally transitory, related to transmission constraints that isolate narrow market areas. All RTOs have some form of mitigation to address market power

associated with transmission constraints.

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Mitigating Market Power

The first and best form of mitigation is to address the structural characteristics of the market: Promoting transmission investments to reduce congestion and

associated locational market power; Remove barriers to investment in new generation; Facilitating demand-side participation in the market; and Divestiture: reducing concentration of supply ownership.

Even with the structural mitigation, market power concerns may still justify behavioral mitigation.

Behavior mitigation includes measures that restricts a supplier from exercising market power.

Market efficiency and market power generally receive equal monitoring attention contrary to the assumption of most that market power is the primary focus.

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Market Monitoring Functions

The monitoring function includes: Real-time screening and analysis to identify circumstances that

require further investigation we receive data continuously from the MISO;

Investigations of market operations or conduct identified through the daily screening or complaint processes; and

Periodic analysis and reporting. The IMM is also primarily responsible for developing the systems to

ensure that the market power mitigation measures are triggered in accordance with the MISO tariff.

This requires an interdisciplinary team of experts and the development of extensive market monitoring software.

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Market Mitigation Activities

Consistent with the definition of market power, mitigation is only applied when a conduct and market impact test are satisfied: Conduct test: supplier is withholding service or producing

uneconomically Impact test: Identified conduct is raising prices significantly

Criteria used to implement mitigation Area impacted by transmission constraints Conduct (Broad Constrained Area)

Economic withholding (energy) Energy offer greater than reference level by $100 per MWhr

hour or 300% increase Offers less than or equal to $25 per MWhr are acceptable Other limits apply to other parameters

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Market Mitigation Activities (Continued)

Conduct Uneconomic Production

Continued operation while LMPs are significantly below reference levels

Tariff does not provide a meaningful threshold for negative reference levels

Impact (Broad Constrained Area) Market Clearing Price increase of $100 per MW per hour

More stringent conduct and impact tests apply to Narrow Constrained Areas

Conduct and impact tests are also conducted for Physical Withholding

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Market Mitigation Activities (Continued)

Mitigation measures Constraining offer from rising above reference levels (non-punitive) Refer conduct to MISO for potential penalties (sanctions)

Physical withholding Self-scheduled overproduction

Market Mitigation Example

Assume: MP for a resource with a reference level of $50 per MWhr offers at $200

per MWhr. A transmission constraint impacted by the resource binds, creating a

Broad Constrained Area. Conduct Test: IMM identifies the $200 offer as failing the

conduct test because it exceeds the $50 reference level by more than the $100 per MWhr conduct test threshold.

Impact Test: IMM performs the impact test by resolving the market with the offer at the reference level and determining if LMPs changed by more than the $100 per MWhr impact test threshold.

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Market Mitigation Example (Continued)

Mitigation: Assuming that the impact test threshold was exceeded, the $200 offer is replaced with the default offer based on the $50 reference level for the resource.

Note: Though the limit for the conduct test in this example is $150 per MWhr

(reference level plus conduct threshold), the default offer used in mitigation is at $50 (reference level without the threshold).

The reference level is used in the conduct test, impact test and the mitigation measure for this example.

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Reference Levels Review

Reference levels are the competitive benchmark used in conduct tests, impact tests and some mitigation measures

Reference levels are posted on the Midwest ISO Market Portal

Dart > Resource Information> Query Market Monitor Information>Type: Reference Price

Reference levels are set by prioritized methods

1. Cleared offer based: Min(mean, median) of previous 90 days of accepted offers adjusted for time and fuel

price

2. LMP based (for self scheduled):mean(LMP) lowest 25% of hours dispatched

3. Cost based from validated survey data

4. Consultation for adjustments and exceptions

Cost Based Reference Levels

Initial reference levels are cost based and are determined using data provided through the Operating Cost Survey.

The Operating Cost Survey data is request via the document Cost Survey for ASM Products Bulletin 20130222[1].pdf.

MPs have a tariff obligation to provide this data. The data is to reflect the physical capabilities of the generation

resources as apposed to preferred offer strategies. Data is collected through the web site

https://www.potomaceconomics.com/ocs/home.action as described in the bulletin.

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Operating Cost Survey Web Site

For access to the web site, have a management representative of the MP e-mail the IMM: NERC ID for the MP For each individual needing access and authorized to view MP

confidential information Name E-mail address Phone number

Access can be given immediately but data can not be uploaded or viewed until following the Commercial Model update in September.

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Reference Levels are an estimate of Marginal Cost (Incremental Costs)

The marginal cost of an additional unit of output is the cost of the additional inputs needed to produce that output.

More formally, the marginal cost is the derivative of total production costs with respect to the level of output.

Marginal cost and average cost can differ greatly.

For example, suppose it costs $1000 to produce 100 units and $1020 to produce 101 units.

The average cost per unit is $10, but the marginal cost of the 101st unit is $20

Marginal costs include opportunity cost, risks and other factors that can cause marginal costs to exceed incremental production costs.

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Average vs. Incremental Costs

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Opportunity Costs

Associated with limits to energy production Permits hours of operation per year Hydro feet of water behind the dam Fuel delivery

Limits are translated to N hours of operation for an operating range over a time span

Concept is to operating for the N most profitable hours, rather the first N hours that are above incremental operating costs

Offer price is the greater of the price duration curve at N for the affected period and the incremental operating costs

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Price Duration Curve1,000 hour run limit suggests $240/MWhr Opportunity Cost

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Risk Premium

Current operation is done at the risk of an outage that can affect future operation

Consequence of outage Direct cost labor and materials Business interruption expense

Probability of outages can be estimated using NERC GADS data Probability weighted costs is risk premium that is added to the

incremental operating costs Start failure gives start cost premium Run time failure gives energy cost premium

Operating Cost Survey Data Request

Instructions OCS instructions 20111219[1].pdf, templates and examples are provided on the Operating Cost Survey web site. The survey has the following sections: Contact Info is who the IMM should contact with questions about the

submittal, alerts regarding data validation, and investigations regarding conduct.

Peer Group is a categorization of the unit with similar units. Startup Costs are the startup costs defined for this resource. No-load Cost is the hourly no-load cost in $ per hour for the resource. Limits are the set of resource operational limits.

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Operating Cost Survey Data Request (Continued)

Runtimes specify the resources operational runtimes, total starts, and total energy delivered.

Energy Sources are the sources that provides the energy that is converted to electricity through chemical, mechanical, or other means. Energy sources include coal, petroleum and petroleum products, gas, water, uranium, wind, sunlight, geothermal, and other sources.

Applicable Emissions specify the emissions programs that are applicable to the unit.

Emissions specify the emissions allowance costs that are applicable to the unit.

Performance Indexes quantify the historic reliability of the unit.

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Operating Cost Survey Data Request (Continued)

Variable Op Expenses specify the fuel consumption and other variable operating costs at various resource output levels and seasons.

Energy Limitations specify the limits on energy production. These limitations can affect resource availability and the opportunity costs of operating the resource.

Fuel Blends specify blends of fuels used at the unit. A different fuel blend can be used for startup, no-load, and each level of operation.

ASM Values specify values that may be used in the calculation of cost based reference levels for ancillary services.

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Reference Level Validation

Up-Front Up-front validation rules that provide error messages immediately upon

submittal are implemented to help ensure submittals are consistent with instructions.

Up-front rules check for format, relative magnitude and completeness. Back-End

Back-end rules check for reasonableness of values based on the size and technology of the facility.

Failures of validation tests will be communicated to participants. Waivers may be provided based on additional documentation.

Closing Comments and Questions

For more information Tariff Module D BPM 009 Consultation per the Bulletin

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