Future Market Implementation Requirements - way forward

2. Future Market ImplementationRequirements - way forward MWG – May 19th, 2009 - Decision Session #4

3. Requirements Gathering Process Review MISO BPMs Pull decision points Research RTOs Info Session #1 Info Session #2 Info Session #3 MWG Decision Session Review Protocol Language from previous Decisions

4. Process • Fourth Design Session – You are pros now!! • Review each of the decision points from Information Sessions • Dialogue • Decide which RTO designs best fits the SPP footprint • Staff will then develop protocol language for next MWG Face to Face

5. Topic Schedule March 30th Canceled due to CHTF April 6th Modeling Pseudo ties and JOU Virtuals Demand Response April 13th BA Functions April 27th Resource Adequacy May 4th Emergency Condition Load Forecast May 11th Settlements I May 26th Settlements II June 1st Reserve Sharing June 8th Credit June 22nd Market to Market June 29th Formulations July 6 Losses July 13th Technical Business Continuity Other Feb 2nd Market Structure Product to be Offered Resources Feb 9th Registration Resource Qualification Market Timeline Feb 23rd Market Functions I March 2nd Market Functions II March 9th Energy Transactions March 23rd Make Whole Payments Market Mitigation

6. April 27th • Resource Adequacy • How do we ensure that there is enough short term capacity for the new markets to select from. • How do we compensate – or incent to insure compliance • Where are the A/S obligations • Look at problem from three angles Capacity, Compliance and Deliverability • Must offer requirements • Order 719 implications

7. Short Term Resource Adequacy Need to ensure there is adequate capacity: • Capacity • Energy • Regulation • Spinning and Supplemental Reserves • Ramp • Dispatchable Range In order to clear both Day Ahead and Real Time Balancing markets without utilizing scarcity pricing and emergency operating procedures

8. Network Resource Must Offer Requirement • MPs with NRs designated for compliance purposes must submit a Self-Schedule, an Offer or Interchange Schedule in the Day-Ahead Energy and Operating Reserve Market and the Post Day-Ahead Reliability Assessment Commitment (RUC) process for the full operable capacity of the unit up to the DNR amount except to the extent that the NR is unavailable due to a full or partial forced or scheduled outage and that the outage is reported in the Midwest ISO Outage Scheduler. • MPs serving Load in the Midwest ISO footprint with NRs affiliated with a non-MP must submit an Interchange Schedule in the Day-Ahead Energy and Operating Reserve Market. “Must offer” requirements will reflect Resource operational limitations including those related to fuel limited, energy output limited or Intermittent Resources. • At its sole discretion, the Midwest ISO may curtail exports sourced at an NR or from the Real-Time Energy and Operating Reserve Market during a declared Emergency. • The Midwest ISO may not curtail exports associated with Generation Resources responding to reserve activation in accordance with the terms and conditions of a Regional Reserve Sharing Agreement during the time that such activation is effective.

9. Market Design – What is adequate? What is going to be the SPP definition of adequate? • To cover short term adequacy: • Require all Designated Resources as must offer • Alternatively – have must offer requirement to cover Load plus A/S? • How do we ensure ramp and dispatchable range as well as capacity • Does obligation come with estimate of LRS or after the fact

10. Other Markets Under Review PJM, NY and NE all have ICAP markets. Resources that are selected in the ICAP market have a Must Offer requirement Any unit that is cleared in the ICAP market has a must offer requirement

11. Who has a A/S Obligation • There have been a lot of water cooler conversations about who should be responsible for Regulation Obligations • In MISO the obligation is on the LSE. They get an obligation equal to their load ratio share (LRS) on the full MISO load • They can estimate their obligation by taking the forecast LRS * A/S Obligation • If Load and self scheduled generation are in same zone then they are hedged (more on this later) • The other way to go about this would be a hybrid approach with would split the obligation between LSEs and cost causers (Generators off set point)

12. Self Schedule of A/S • It has been mentioned in previous information and decision session, but probably worth repeating. • Because of the design of the Reserve Zones it is possible that if a vertically integrated utilities generation and load were in different zones it may be difficult to hedge out the Ancillary Service obligation with your own units. • If your Generation and Load are in the same zone you can self schedule your units to match the A/S obligation and to the extent that you forcast the obligation correctly there would be a complete hedge • However if you load was in a different zone than your generation, and there was a price split between the zones for a A/S it is possible to not be completely hedged

13. What Causes Regulation • Regulation deployment is triggered when ACE goes above (or below) certain levels. It is usually step deployed taking into account how often zero is crossed (not linearly deployed like energy which is one to one for load forecast) • ACE has three main components – Tie Line Error (NSI-NAI), Frequency, Meter Error • Tie Line Error components • Units that are running off of set point instruction • Short Term Load Forecast (STLF) error • Frequency error (if there is no tie line error) is caused by non SPP activity in the eastern interconnect. • This means that in increase in units off set point or STLF error will cause SPP to increase the required regulation to maintain CPS1 and Balancing Authority ACE Limit BAAL • With this in mind – how do the two options (LSE only or Hybrid obligation approach) work.

14. LSE only LSE only • Little Incentive for resources to follow set points – especially intermittent • Could augment his approach with a URD type calculation and allow intermittent to supply 5 min load forecast that the system would dispatch them to (instead of SE) Hybrid Approach • Would need to figure out a formula to calculate how much extra regulation was needed due to each unit (What would this formula look like) • If we could implement it would incent resources to follow set point • Could also implement intermittent forecast as in above LSE option

15. Decision Tree No Intermittent Forecast Obligation LSE Only No incentive Intermittent Provide 5 Min forecast URD type charge for being outside of forecast No Intermittent Forecast Obligation Shared Between LSE and Resources* No incentive Intermittent Provide 5 Min forecast URD type charge for being outside of forecast *Formula would have to translate MW off of dispatch with an increased regulation requirement. Large differences would likely require additional units to be committed, while small differences would require more often deployment of regulations procured.

16. ACE to Regulation

17. Other adequacy Issues • Ramp – this is what is most likely to be scarce • Dispatchable range What is the best way to incent in order to ensure Capacity, Ramp and Range are all available

18. Other adequacy Issues What is allowed to count toward adequacy for: • Interruptible Demand • Behind-the-Meter Generation • QFs • Intermittent Resources?

19. System Support Resources (RMR) • In order to assure reliability in the Midwest ISO Reliability Coordinator Area, the Midwest ISO may enter into System Support Resource (SSR) Agreements with Generation Resource owners that may otherwise cease operations due to uncertain future economic feasibility. A Resource owner that wishes to be considered for SSR eligibility must apply to the Midwest ISO to receive SSR designation. • If accepted, the Generation Resource owner will enter into an agreement with the Midwest ISO that specifies the Daily Capacity Payment (DCP), as well as other fixed and variable amounts for Start-Up (SU) and Production Costs (PC) used to calculate Revenue Sufficiency Guarantees (RSGs). SSR Agreements will be renewed yearly, but may contain special provisions for costs that vary monthly or seasonally within the year. They may even contain provisions for Fuel-Index (FI) based costs and distinct variable costs associated with peak and off-peak operating periods.

20. System Support Resources (RMR) Options for make-whole that have been considered at SPP in EIS: • Take the opposite of Transmission upgrade cost allocation approach, making the outage owner pay a %, and then spread the remainder to the loads affected (at risk).   • Similar option, but pull a certain percentage from the RNU bucket.  The logic being, if the RMR was not called (for ~4 hours during peak), the flowgate would initiate VRLs for the duration.  If there are little to no schedules, uplift is created anyway.   • Have the loads pay based on risk, calculated by the LDFs of the flowgate.  This would be similar to the IDC logic.  By squaring the LDFs, we capture and have the loads that are closer to the flowgate pay the generator providing counter-flow on that path.   • Overall, this can provide another benefit to the EIS market, as the make-whole payment will compensate the difference between the start-up/no load production costs and the payment received.  Comparing this to the general reduction in LIPs for the duration of the RMR should provide a better option, along with the added reliability and control of the system.  

21. Intermittent Units in DA and RUC • The RTOs are seeing a problem with Intermittent units that are not bidding into the DA market. • Since the RUC process starts with the DA commitment it does not see any intermittent output. It then commits enough other resources to meet hourly peak load. • When the intermittent shows up in real time there is over commitment and min gen issue are observed. • Participation in the DA market would solve this problem. How can we incent? • What assumptions in the DA and RUC can we make about intermittent (specifically wind).

22. Energy Limited Resources • NOx limited resource only handled for 24 hour period not optimized over a year • Just wanted to clarify that for the unit commitment process it is a daily process. It will not track something like a yearly NOx limit and optimize over the year • The reason for this point, is how do you handle a unit that is a unit called on for reliability and it has will incur a penalty for NOx usage (or other penalty) because it has operated though the year (either Market Picked or as a RMR)

23. Decision session talking points • How best to ensure Adequacy – Energy Capacity, A/S Capacity, Ramp and dispatchable range • What is Adequate? Cover load+A/S or all DR? • Where does the obligation for Energy + A/S rest with. Does the load have an obligation to offer enough resources to cover LF + A/S? • How much do Interruptible, Behind the meter, QG and Intermittent resources count toward adequacy • How are Reliability Must Run selected and compensated • What is the best way to handle intermittent in the DA and RUC

24. Information Session - May 4th • Emergency Conditions • DA/RUC/RT Surplus • DA/RUC/RT Deficient • Load Forecast • Changes to process with SPP as BA • Demand response support • Separation of Non-Conforming loads in forecast process

25. Emergency Conditions • Emergency Conditions can refer to a number of things in RTO and BA operations. • As we talked about in the BA presentation it can refer to a number of conditions including loss of EMS and bomb threats. • However in this presentation we will use it to the logic in the market software (and possibly EMS) that is invoked when it cannot fine a solution of matching Resources with Load (plus A/S). Rules must be set up on how to dispatch in these infeasible solutions • Can be either Day Ahead or RT • The BA Abnormal and Emergency Procedures will obviously have to blend with the software design.

26. MISO – Day Ahead Shortage Condition If the sum of the fixed Demand Bids, Fixed Export Schedules, System Losses and Operating Reserve Requirements in the Day-Ahead Market cannot be satisfied by the maximum non-Emergency supply level of all available non-Emergency Resources, Import Schedules and Virtual Supply Offers, MISO clears the Day-Ahead Market pursuant to the following procedures. • Release Emergency Maximum • Utilize units that are Emergency only commitment • If the market remains short • Curtail Fixed Demand Bids • Curtail Fixed Export Schedules in proportion to the scheduled amounts. • Under this situation, all Energy and Operating Reserve will be priced at the VOLL.

27. MISO – Day Ahead Surplus Condition If the non-Emergency minimum supply from Offers and Fixed Import Schedules exceed cleared Demand Bids plus cleared Export Schedules plus cleared Virtual Demand Bids less the Market-Wide Regulating Reserve Requirement, the MISO will use the following procedures to clear the Day-Ahead Market. . • Release Emergency Minimum except for Resources selected to provide Regulating Reserve • If the market remains in surplus condition • Reduce supply, including Fixed Import Schedules, proportionately until Energy balance is achieved • Should Regulating Reserve Scarcity occur, Energy LMPs shall contain negative Regulating Reserve Scarcity Prices and Regulating Reserve MCPs shall include positive Regulating Reserve Scarcity Prices based upon the Market-Wide and/or Zonal Regulating Reserve Demand Curves.

28. MISO RAC (RUC) – Shortage Step One: The Midwest ISO issues an alert, warning or event and posts on its website: (1) the hours in the Operating Day during which an EEA Level 1 is anticipated; (2) the hours during the Operating Day in which Export Schedules are expected to be curtailed; (3) the hours during the Operating Day in which Resource Hourly Emergency Maximum Limits are expected to be utilized; and (4) the hours during the Operating Day in which Emergency only Resources are expected to be committed. Step Two: If the Midwest ISO projects that it cannot meet its Regulating Reserve requirement and all Contingency Reserve has been depleted, the Midwest ISO issues an alert or warning and posts on its website the anticipated hour in which an EEA Level 2 Emergency is expected to occur. If the Midwest ISO declares and EEA-2 event, the following actions may be initiated: (1) instruct the Local Balancing Authorities to issue public appeals, (2) begin Emergency Energy purchase procedures (3) issue EDR Dispatch Instructions to EDR Participants based on EDR Offers submitted; (4) direct LBAs to initiate voltage reduction procedures; and/or (5) directs LSEs to curtail appropriate amounts of Load Modifying Resources. At this point, the Midwest ISO has exhausted all measures at its disposal to alleviate the shortage condition prior to entering into the real-time Operating Hour.

29. MISO RAC (RUC) – Surplus Step One: The Midwest ISO issues an appropriate Emergency alert, in accordance with Emergency Operating Procedure – 003 (EOP-003),and includes Resource Hourly Emergency Minimum Limits for both Generation Resources and DRR-Type II as part of the RAC process. Step Two: If use of Hourly Emergency Minimum Limits is not sufficient to relieve the anticipated surplus condition, the Midwest ISO may de-commit non-Must Run Resources on an economic basis that were committed as part of the Day-Ahead Energy and Operating Reserve Market clearing to relieve the anticipated surplus condition.

30. MISO – RT Surplus Within the real-time operating Hour, the SCED algorithm will utilize Market Participant Offers for all Resource Capacity used in the RAC process immediately preceding the real-time operating Hour, including selected Hourly Emergency Minimum Limit segments, in clearing the Real-Time Energy and Operating Reserve Market for each Dispatch Interval. If use of Hourly Emergency Minimum Limits creates a Regulating Reserve shortage during any Dispatch Interval, the Ex-Ante MCPs for Regulating Reserve will reflect Scarcity Prices and LMPs will reflect negative Scarcity Prices as set by the Regulating Reserve Demand Curve.

31. MISO – RT Shortage Within the real-time operating Hour, the SCED algorithm will utilize MP Offers for all Resource Capacity used in the RAC process immediately preceding the real-time operating Hour, including selected Hourly Emergency Maximum Limit segments, Emergency-only Resources and Emergency Energy purchases, in clearing the Real-Time Energy and Operating Reserve Market for each Dispatch Interval. If there is an actual Operating Reserve shortage during any Dispatch Interval, the Ex-Ante MCPs for Operating Reserve will reflect Scarcity Prices set by the Demand Curves based upon the level of the shortage. As a last resort, if there is a shortage of available Capacity to meet demand requirements within the Operating Hour, the Midwest ISO will issue an EEA Level 3 and begin Load Shedding procedures as described in Attachment Q of the Tariff and all Ex-Ante LMPs and MCPs will be set at the VOLL.

32. MISO - Emergency Energy Purchases Following the declaration of an EEA Level 2, the Midwest ISO may contact external Balancing Authorities through the applicable Midwest ISO to external Balancing Authority Agreements (BA-to-BA Agreements) and indicate that Emergency Energy may be needed. Payment for such purchases, if scheduled will be in accordance with the payment terms specified in the applicable BA-to BA Agreement. Emergency Energy purchases shall be implemented in the form of a schedule in the PSS between the Midwest ISO and the selected adjacent external Balancing Authority. Note that Transmission Service on external non-Midwest ISO transmission facilities provided may be needed to effectuate the schedule. The Midwest ISO will implement and curtail these schedules with as much notice as practical to allow for a reasonable transition into and out of the shortage condition.

33. PJM – Day Ahead Shortage Condition If the day-ahead demand bid MW cannot be satisfied with all available generation at its economic maximum MW limit, the program shall issue a Warning message. The program shall then perform the following steps to achieve power balance: • Increase all on-line generation up to its maximum emergency MW limit. (MW proportionately by ratio of eco max). Set LMP values equal to the highest offer price of all on-line generation. • Load off-line generation that is designated as available only for maximum generation emergency conditions, as required based on economic offer data. Set LMP values equal to the highest offer price of all on-line generation. • If power balance is not achieved after Step 2, drop any remaining price-sensitive demand to zero MW. Set LMP values equal to the highest price-sensitive demand bid that was cut in this step. If no price-sensitive demand was reduced in this step, the LMP values are set equal to highest offer price of all on-line generation (resulting from Step 2). • If power balance is not achieved after step 3, reduce all load proportionately (by ratio of load MW) until balance is achieved. Set LMP values equal to the highest offer price of all on-line generation, the price from Step 3, or the bid cap (presently $1000/ MWh), whichever is higher.

34. PJM – Day Ahead Surplus Condition If the day-ahead demand bid MW is less than the total generation MW with all possible generation off and with all remaining generation at their economic minimum MW limit, the program shall issue a Minimum Generation Warning message due to an excess of economic generation in the Day-Ahead Market. The program shall then perform the following steps to achieve power balance. • Reduce all on-line generation down to its minimum emergency MW limit. (Reduce generator MW proportionately, by ratio of economic minimum. If power balance is achieved prior to reaching minimum limits). Set LMP values equal to the lowest offer price of all on-line generation. • Set LMP values to zero. Reduce all on-line generation below emergency minimum proportionately (by ratio of emergency minimum) to achieve power balance.

35. Consolidated BA impacts – Load Forecast • The footprint will be SPP RTO as opposed to individual BAs • Still need load forecast by LSE so that obligations for A/S can be estimated (if based on load ratio share) • What input will the former BAs have on the forecast process (mid term and short term)

36. Separation of Non-Conforming load • One difference from SPP current methodology that MISO uses is to allow the option of RTO forecasting the conforming component and let the LSE send in the non-conforming portion which is added in during real time. • SPP has implemented this with one MP also

37. Other RTOs • Information on the other’s LF process are hard to come by. Most keep the details of this process internal • NY used to have a process by which the MPs and the RTO both forecasted and then the best one was picked. They have since gone to a process where only the RTO calculates

38. MISO Dispatchable DRR • MP must establish Demand Forecast Cap during registration process • Based on historical consumption levels • Establishes reasonable baseline and limits potential gaming • MP then submits Dispatch Interval Demand Forecast 5 minutes prior to the applicable Dispatch Interval, subject to the Cap • MISO receives telemetered demand consumption data • Dispatchable DRR has same telemetering requirements as any other generation resource • MISO then calculates the DRR output as follows: Calculated DRR-Type II Output (Dispatch Interval) = Dispatch Interval Demand Forecast - (5 minute integration of telemetered demand consumption data)

39. Gaming Example – No Demand Forecast Cap • Registration: • Host Load Zone with 100 MW of load: 50 MW of fixed demand and 50 MW of block load curtailable demand • MP registers 50 MW DRR-Type I associated with this Host Load Zone • Operations: • MP is cleared for 50 MW of Supplemental Reserve • MP submits Dispatch Interval Demand Forecast of 150 MW • MP is deployed for Supplemental Reserve for the entire Operating Hour • MP submits one-minute interval demand consumption data that integrates to 100 MW for each Dispatch Interval • DRR-Type I output = 150 MW – 100 MW = 50 MW. • Observations: • DRR-Type I appears to be in compliance with deployment instruction • In reality, NO load reduction occurred. Compliance created solely though submittal of high demand forecast. • Demand Forecast Cap is needed

40. Example - Co Gen Facility Full Load with no co-generation can draw 100MW 50 MW Generator Would Cap the Forecast at 100MW – this would limit the gaming opportunities to 50MW Forecast 100MW and actual output 50MW would be credited with 50MW of demand reduction

41. PJM • PJM requires the demand response aggregator to submit the demand reduction. The RTO and the LSE then have 10 days to validate and reject the settlement

42. Decision session talking points • What is the order of emergency logic (ORWG?) • How do we incent intermittent resources to participate in the DA Market • Do we want to Implement DRR Forecast Cap • Allow RTO and LSE to reject DRR settlement?

43. May 11th • New Market Settlement - Session 1 • Settlement Charges • Energy Settlement • Physical Transactions • Financial Transactions • Ancillary Services • Settlement Statements • Day Light Savings Time

44. There are 16 Day Ahead Charge Types in the MISO Market Day-Ahead Charge Types 1 Day-Ahead Asset Energy Amount Energy 2 Day-Ahead Non-Asset Energy Amount Energy 3 Day-Ahead Financial Schedule Congestion Amount Financial 4 Day-Ahead Financial Schedule Loss Amount Financial 5 Day-Ahead Virtual Energy Amount Financial 6 Day-Ahead Revenue Sufficiency Guarantee Dist Amt Make Whole 7 Day-Ahead Revenue Sufficiency Guarantee Make Whole Pymt Amt Make Whole 8 Day-Ahead Regulation Amount Ancillary 9 Day-Ahead Spinning Reserve Amount Ancillary 10 Day-Ahead Supplemental Reserve Amount Ancillary 11 Day-Ahead Market Administration Amount Admin 12 Day-Ahead Schedule 24 Allocation Amount Admin 13* Day Ahead Congestion Rebate on Carved-Out Grandfathered Agreements GFA 14* Day Ahead Losses Rebate on Carved-Out Grandfathered Agreements GFA 15* Day Ahead Congestion Rebate on Option B Grandfathered Agreements GFA 16* Day Ahead Losses Rebate on Option B Grandfathered Agreements GFA *SIDE NOTE ON GRANDFATHERED AGREEMENTS: Grand Fathered Agreements are incorporated throughout the formulations for charges, but not discussed explicitly in this presentation. SPP will discuss in conjunction with Congestion Hedging.

45. There are 28 Real Time Charge Types in the MISO Market Real-Time Charge Type Names 1 Real-Time Asset Energy Amount Energy 2 Real-Time Non-Asset Energy Amount Energy 3 Non-Excessive Energy Amount Energy 4 Excessive Energy Amount Energy 5 Real-Time Financial Schedule Congestion Amount Financial 6 Real-Time Financial Schedule Loss Amount Financial 7 Real-Time Virtual Energy Amount Financial 8 Real-Time Regulation Amount Ancillary 9 Real-Time Spinning Reserve Amount Ancillary 10 Real-Time Supplemental Reserve Amount Ancillary 11 Regulation Cost Distribution Amount Ancillary 12 Spinning Reserve Cost Distribution Amount Ancillary 13 Supplemental Reserve Cost Distribution Amount Ancillary 14 Real Time Excessive Deficient Energy Deployment Charge Amount Ancillary 15 Net Regulation Adjustment Amount Ancillary 16 Contingency Reserve Deployment Failure Charge Amount Ancillary 17 Real-Time Revenue Sufficiency Guarantee First Pass Distribution Amount Make Whole 18 Real-Time Revenue Sufficiency Guarantee Make Whole Payment Amount Make Whole 19 Real-Time Price Volatility Make Whole Payment Make Whole 20 Real-Time Distribution of Losses Amount Losses 21 Real-Time Net Inadvertent Distribution Amount Market 22 Real Time Revenue Neutrality Uplift Amount Market 23 Real-Time Market Administration Amount Admin 24 Real-Time Schedule 24 Allocation Amount Admin 25 Real-Time Schedule 24 Distribution Amount Admin 26 Real-Time Miscellaneous Amount Admin 27* Real Time Congestion Rebate on Carved-Out Grandfathered Agreements GFA 28* Real Time Losses Rebate on Carved-Out Grandfathered Agreements GFA

46. There are 12 Financial Transmission Rights Charge Types • Financial Transmission Rights Charge Type Names • 1 Financial Transmission Rights Hourly Allocation Amount • 2 Financial Transmission Rights Market Administration Amount • 3 Financial Transmission Rights Monthly Allocation Amount • 4 Financial Transmission Rights Transaction Amount • 5 Financial Transmission Rights Yearly Allocation Amount • 6 Financial Transmission Rights Monthly Transaction Amount • 7 Financial Transmission Rights Full Funding Guarantee Amount • 8 Financial Transmission Rights Guarantee Uplift Amount • 9 Financial Transmission Rights Annual Transaction Amount • 10 Auction Revenue Rights Transaction Amount • 11 Auction Revenue Rights Infeasible Uplift Amount • 12 Auction Revenue Rights Stage 2 Distribution Amount • TOTAL OF 56 CHARGES IN THE MISO MARKET • VERSUS ~6 CHARGES IN THE CURRENT SPP MARKET • The other markets have essentially the same charge components as MISO. but may distribute the calculations differently – combining or disaggregating calculations when compared to the MISO calculations. • Differences primarily arise from special situations – the Phase Angle Regulator in PJM, etc.

47. Energy Settlement Energy Settlement Example • Very basic example • Describe the two market settlement process to form a base for discussion of the remaining charges. • Establish a baseline of understanding for this audience