“Rethinking” Ancillary Services in ERCOT and E fforts to Incorporate “Loads In SCED” ERCOT Staff

1. “Rethinking” Ancillary Services in ERCOT and Efforts to Incorporate “Loads In SCED” ERCOT Staff Operator Training Seminar Spring 2014

2. Introduction This presentation an overview of the current effort to “rethink” the Ancillary Services in ERCOT and an overview of the efforts to incorporate “Loads in SCED”.

3. Objectives (part 1) At the completion of this course of instruction you will: • Identify drivers for rethinking the Ancillary Services in ERCOT. • Identify the AS products being discussed for a new AS framework.

4. Objectives (part 2) • Identify Load Resources that can participate in Security Constrained Economic Dispatch (per NPRR 555). • Identify Real-Time Market Energy Bid Characteristics for Load Resources participating in SCED.

5. Drivers for new AS Framework • Current AS Framework has performed well but has issues • Resources could provide some services more efficiently if the requirements were decoupled (PFR/ FFR/ Contingency Reserve) • New service needed to ensure technical requirements are met that used to be provided, inherently, by generators (e.g. inertia) • Awkward to fit capabilities of new technologies (e.g. CCGTs with duct firing, wind turbines) that could provide services efficiently • Changes in market design and control systems(e.g. 5 minute dispatch, HRUC) have reduced the need for other services • New regulatory requirements (BAL-003) • Need for changes has been highlighted in discussion of Fast Responding Regulation Service (FRRS), NPRR 524(Resource Limits in Providing Ancillary Service), etc.

6. Goal • Future AS Framework • Technology neutral • Market-based • Based on fundamental needs of the system, not resource characteristics • Unbundled services • Flexible for new technologies • Pay for performance, where practical • Co-optimized procurement • Will evolve over time • Current AS Framework • Based on capabilities of conventional steam generating units • Unique services bundled together due to inherent capabilities of conventional units • Mix of compensated and uncompensated services • New technologies are cobbled on, with difficulty Transition Plan TBD Now 5+ Years

7. Scope of Proposed AS Framework • Long-term Ancillary Services (AS) framework intended to guide: • Decisions on near-term changes to current AS • Requirements for changes to ERCOT systems (EMMS, etc.) • Investment in new resources and new resource types by the mkt. • Framework will be developed in phases, due to complexity of issues • Current Phase will only address frequency control services • Future Phases may address Voltage Support and other services • Framework should eventually include roadmap for transition from current AS to future framework • Prioritization of services to be transitioned • Inter-relationship of services that must transition concurrently • High-level consideration of ERCOT systems and market impacts

8. Proposed AS Products ERCOT proposes the transition to the following five AS products: • Synchronous Inertial Response Service (SIR), • Fast Frequency Response Service (FFR), • Primary Frequency Response Service (PFR), • Regulating Reserve Up (RRU) and Regulating Reserve Down (RRD) Service, and • Contingency Reserve Service (CR).

9. ERCOT Proposal • This revised AS set adds and/or redefines specific AS products currently used by the ERCOT System and • Subsumes different elements within the current Responsive Reserve Service into several of the newly defined services. • Recognizesduring the transition period from today’s AS to the future AS set, there may be the need for a Supplemental Reserve Service that would be similar to today’s 30-minute Non-Spin Service.

10. Proposed Framework Current Framework • 400-600 MW Regulation Regulation Fast Frequency Response Primary Frequency Response • 2800 MW Responsive Contingency Reserve Supplemental Reserve • Max 1500 (incl. • 500 to RRS) Non-Spin Synchronous Inertial Response

11. Synchronous InertiaL Response (SIR) service

12. Synchronous Inertial Response (SIR) Service • SIR is stored kinetic energy that is extracted from the rotating mass of a synchronous machine following a disturbance in a power system • Maintain minimum Rate of Change of Frequency (RoCoF) • Provide sufficient time from Point A to Point C, for Fast Frequency Response and Primary Frequency Response • No triggering RoCoF protection of synchronous generators (generally 0.5 Hz/s)

13. Synchronous Inertial Response Service • SIR has significant implications on the RoCoF during power imbalances; • With increasing use of non-synchronous generation, changing load characteristics (less motor loads), increase in Combined Cycle units (lower inertia), the system SIR response is reduced: • RoCoF increases, leaving insufficient time for PFR to deploy and arrest the system frequency excursion. • High RoCoF may trigger generation RoCoF protection, tripping additional synchronous generators.

14. Synchronous Inertial Response Service • So far, the RoCoF during high wind/low load condition was less than 0.2 Hz/s and the average time to reach frequency nadir during frequency events is 4 to 6 seconds. • The system inertia available in the real time operations under current conditions is still sufficient. • Studies based on 2012 system conditions indicated RoCoF as high as 0.4 Hz/s for two largest unit trip (2750 MW as per recently approved NERC BAL-003 standard).

15. SIR, Future work • Monitor and project the trend of ERCOT system inertial response and RoCoF • Identify the minimum needs of system inertia and duration between points A and C • Gather data to determine each generator’s RoCoF tolerance • Investigate capability and value of synthetic inertial response from renewable energy resources to contribute to system’s SIR

16. Fast frequency response (ffr) service

17. Fast Frequency Response (FFR) Service Need • To changing frequency to supplement the inherent inertial response from synchronous machines • To provide sufficient time for PFR to deploy and arrest fast frequency excursion in the event of sudden power imbalance Deployment and Performance • Self deployment • Provide full response within 30 cycles (0.5 secs.) at a specified frequency thresholds and sustained for at least 10 minutes • FFR service will require a high resolution measurement

18. Fast Frequency Response (FFR) Service Discussion • Presently there is no separate FFR Service in ERCOT, however up to 1400 MW of Responsive Reserve Service (RRS) procured from Load Resources (LR) satisfy FFR characteristics • In the proposed AS framework FFR and PFR are highly interdependent and the required quantity of each service can vary based on the system conditions • FFR and PFR work together to produce the desired system response • FFR service cannot completely replace the PFR service • A performance requirement needs to developed

19. Primary frequency response (Pfr) service

20. Definition of PFR Service Primary Frequency Response (PFR) is defined as the instantaneous proportional increase or decrease in real power output provided by a Resource in response to system frequency deviations. • This response is in the direction that stabilizes frequency. • Primary Frequency Response is attained due to Governor or Governor-like action • PFR is instantaneous response relative to the frequency deviation, • PFR is generally delivered completely within 12 to 14 seconds.

21. Primary Frequency Response (PFR) Service- Need ERCOT as a single Balancing Authority Interconnection with only limited interconnection to the other Interconnects is solely responsible for maintaining frequency to maintain reliability and meet NERC standard requirements. • All of ERCOT’s frequency response can only come from Resources within the ERCOT Interconnection. • The BAL-003 NERC Frequency Response Standard • BAL-003 sets a Frequency Response Obligation (FRO) for each BA based on loss of two largest single units. • The minimum FRO for ERCOT is 413 MW/0.1 Hz

22. Determination of the Amount of FFR and PFR Reserves • The objective of Fast Frequency Response (FFR) and Primary Frequency Response (PFR) Reserves should be to ensure Frequency is arrested above UFLS threshold of 59.30 Hz and to meet NERC FRO Standard (BAL-003). • Frequency Response Obligation (FRO) for ERCOT is determined based on instantaneous loss of two largest units (2750 MW). • ERCOT must develop methodologies for the regular assessment of the needed concurrent amounts of both FFR and PFR.

23. Determination of the Amount of FFR and PFR Reserves • How much PFR is needed will be based on minimum requirement for FFR while maintaining minimum PFR capability within Generators (for example, in the current RRS, Load Resources can provide up to 50% of 2800 MW RRS).

24. Regulating Reserve (rr) service

25. Regulating Reserve (RR) Service – Up & Down • An amount of reserve responsive to Load Frequency Control, which is sufficient to provide normal regulating margin. • ERCOT generation is dispatched through Security Constrained Economic Dispatch (SCED) every five minutes to balance the generation and demand. The power imbalance between each SCED interval will cause frequency deviation that requires Regulating Reserve to compensate. This action will be provided by RR service.

26. Regulating Reserve (RR) Service – Up & Down While not substantially changing from todays Regulation Service ERCOT is proposing to implement the following: • LFC signals will be delivered by ERCOT to the QSE specifically for the Resource providing this service • The deployment instructions should be determined by taking into consideration ramp rates, HSLs etc. of each of the individual Resources. • Resources providing RR should be limited to min(NURR,NDRR)*5*0.70, where NURR and NDRR are Normal-Up Ramp Rate and Normal-Down Ramp Rate • The pay for performance approach should reward those Resources that closely follow the ERCOT LFC signal • ERCOT will re-visit its LFC and RLC to avoid deploying RR for more than 10 continuous minutes in one direction during normal operation.

27. Contingency reserve (cr) service

28. Contingency Reserve (CR) Service – Need & Purpose • CR is to ensure that the Balancing Authority is able to restore Interconnection frequency within defined limits following a DCS event or large net load forecast error within 15 minutes and restore its Primary Frequency and Regulating Reserve. • According to NERC BAL-002-1 Disturbance Control Standard (DCS), The minimum amount of CR required is equivalent to “Most Severe Single Largest Contingency”, in ERCOT’s case this is currently 1375 MW. • ERCOT may additionally procure CR reserve to cover for large net load forecast errors. • To ensure ERCOT can meet the standard, the CR must be fully deliverable within 10 minutes so that frequency can be restored to the pre-disturbance level within 15 minutes

29. Contingency Reserve Qualification • Resources providing CR should be qualified up to the MW value to which they are able to ramp within 10 minutes from the time of deployment. Deployment • ERCOT will deploy CR for a sizable generation trip. • Resources providing CR must telemeter their ramp-rates such that SCED can dispatch the full Resource CR responsibility within 10 minutes. Performance • Resources providing CR must be able to deliver and sustain the reserve deployments for the full hour it is carrying that obligation.

30. Supplemental reserve (Sr) service

31. Supplemental Reserve (CR) Service • SR service is needed to compensate for net load forecast error and/or forecast uncertainty on days in which large amounts of reserve are not available online • Generation Resources capable of being ramped to a specified output level within thirty (30) minutes or Load Resources that are capable of being interrupted within thirty (30) minutes and that are capable of running (or being interrupted) at a specified output level for at least one (1) hour • Supplemental Reserve Service would be similar to today’s 30-minute Non-Spin Service

32. Review of “Future Ancillary Services” ERCOT proposes the transition to the following five AS products: • Synchronous Inertial Response Service (SIR), • Fast Frequency Response Service (FFR), • Primary Frequency Response Service (PFR), • Regulating Reserve Up (RRU) and Regulating Reserve Down (RRD) Service, and • Contingency Reserve Service (CR).

33. NPRR 555 LOADS IN sced

34. NPRR 555: Loads in SCED 1.0 • NPRR 555 provides a mechanism for demand response to contribute to price formation • Targeted to be implemented by Summer 2014 • Discussion about Loads in SCED version 2.0 in progress

35. High-level summary • Eligibility to participate: LSE QSEs representing Load Resources capable of following 5-minute SCED base point instructions • Existing or new single-site Controllable Load Resources (CLRs) • SCED qualification will be a new attribute for redefined CLR • Aggregate Load Resources (ALRs) composed of multiple sites within single ERCOT Load Zone (subset of CLR) • New interface will allow QSEs to maintain ALR populations • Will not support direct participation by third-party DR QSEs • Will not support DR with temporal constraints or block energy bids • If LR’s bid is on the margin, base point instructions could require LR to move up or down incrementally every 5 minutes to any level between its LPC and MPC • SCED will honor LR’s telemetered ramp rates

36. High-level summary (cont.) • QSEs with LRs in SCED will submit Bids to buy (not Offers to sell) • Bids will reflect LR’s willingness to consume “up to” a specified five-minute Load Zone LMP • May be a curve or a MW bid at single strike price • Bid curve option could allow the QSE to submit bids with different strike prices for separate loads within the LR • Bid will modify the SCED demand curve and have ability to set price • SCED Generation to be Dispatched (GTBD) will be adjusted to accommodate LR participation • This will ensure proper price formation and reduce the likelihood of oscillating dispatch instructions • Bids from LRs capped at the System Wide Offer Cap • This is to avoid stranded AS and PRC • ‘Bid to buy’ creates settlement outcomes equivalent to the “volumetric flow” LMP minus G methodology endorsed by TAC, while avoiding need for ERCOT to “send back” the DR value to the LSE

37. High-level summary (cont.) • LR benefits and opportunity: • Avoided cost of consumption above specified price • Price certainty due to ERCOT dispatch • Eligibility to provide Non-spin • Treated similarly to Offline Generation providing Non-spin • Energy Bids ≥$180 will need to be released to SCED within 20 minutes following dispatch • NPRR 555 also proposes that any CLR providing RRS also must be dispatched by SCED • Market impacts: • LR Bids may set price in the RTM • No make-whole payments • No load ratio share uplifts to market for DR value • SCED will dispatch LRs for power balance and congestion management using the applicable Load Zone Shift Factor

38. LRs in Ancillary Services & SCED • RRS and Non-Spin from CLR will be deployed via economic dispatch of DR capacity via SCED • CLR will have RTM Energy Bid that covers the RRS and/or Non-Spin capacity released to SCED • Also can optionally bid additional DR capacity for SCED dispatch • SCED will only consider CLR for dispatch if its telemetered Resource status is ONCLR or ONRGL • Cannot be OUTL if carrying AS responsibility unless QSE moves responsibility to a different Resource • No change to existing participation in RRS by UFR-type Load Resources • UFR-LR-RRS may still be deployed manually in EEA 2 • Prices will be at SWCAP any time this happens because Gen-RRS is deployed first • No change to existing ERS

39. CLR with Bid to Buy: SCED Objective & Power Balance • SCED optimization will minimize cost of dispatch of supply and maximize revenue from demand while meeting Power Balance Minimize { Sum(OfferPricegen * BasePointgen) – Sum(BidPriceLR * BasePointLR) } • BasePointgenis instruction on how much to produce • BasePointLRis instruction on how much to consume • NPFLR is current telemetered real power consumption • All Resources can follow 5 minute SCED Base Points • Power Balance Constraint: Supply=Demand Supply = Sum (BasePointgen) Demand = GTBD = Inelastic Demand + Elastic Demand Inelastic Demand = GTBD - Sum(NPFLR) Elastic Demand = Sum (BasePointLR) Sum (BasePointgen) = GTBD - Sum(NPFLR) + Sum (BasePointLR)

40. Example of SCED outcome: CLR with Bid to Buy • G1 Offer to Sell: 60,000 MW @ $50/MWh • G2 Offer to Sell: 2,000 MW @ $300/MWh • LR Bid to Buy: 1,000 MW @ $200/MWh willingness to consume up to 1,000 MW if LMP at or below $200/MWh • No ramp rate limitations for any Resource • All Resources follow 5 minute SCED Base Points • LR Base Point is instruction on how much to consume

41. RTM Energy Bid Characteristics • The RTM Energy Bid is CLR specific • The RTM Energy Bid is used only in the Real-Time Market (SCED) • The RTM Energy Bid must be submitted before the end of the Adjustment Period for a given Operating Hour • Bid price cannot exceed SWCAP • Regulation Up & RRS capacity on bid curve shall be priced at SWCAP • Non-Spin capacity on bid curve shall be priced no lower than $180/MWh

42. RTM Energy Bid Characteristics • The RTM Energy Bid is submitted as a curve having up to 10 points (MW/price combinations) • The MW range on the bid curve goes from zero to total demand response capability • First bid MW point is at zero MW (left-most point on the bid curve) • Last bid MW point is the total demand response capability (right-most point on the bid curve) • The prices on the bid curve from 0 MW to last bid MW are monotonically non-increasing going from left to right • Price at 0 MW is highest • Price at last bid MW is equal to or lower than price at 0 MW • Price in between 0 MW and last bid MW are monotonically non-increasing

43. RTM Energy Bid Characteristics • The RTM Energy Bid can be submitted with a fixed not-to-exceed price for an “up to bid MW” • This is a submission of a bid curve with two (MW/price) points having the same price for both MW points. • The first MW point is at 0 MW (left-most point) • The last MW point is the total demand response capability (right-most point)

44. RTM Energy Bid Characteristics: Example Bid Curve $/MWh SWCAP SWCAP RTM Energy Bid RegUp NSpin RRS 180 0 MW Total Demand Response Capability 0

45. RTM Energy Bid Characteristics • There is no mitigation of the RTM Energy Bid in SCED Step 2 • For each SCED run, the RTM Energy Bid is right shifted so that the last MW on the bid curve coincides with the telemetered Maximum Power Consumption (MPC) • By this right shift of the bid curve, if the telemetered Low Power Consumption (LPC) is less than the first point of the right-shifted RTM Energy Bid, then ERCOT shall create a proxy bid extension from LPC to this right-shifted first point of the bid curve with a price of SWCAP

46. RTM Energy Bid: Example Bid Curve Right Shift for SCED Use RTM Energy Bid $/MWh 0 MW Total Demand Response Capability Proxy Bid extension $/MWh 0 SWCAP SWCAP Right shifted RTM Energy Bid 0 MW MPC LPC

47. Scenario 1 • For any SCED intervals that the LR’s bid to buy is greater than the five-minute Load Zone LMP, SCED Base Point will instruct the LR to consume at its telemetered Maximum Power Consumption, subject to ramp rate limitations from its current consumption level (NPF) RTM Bid to Buy(up to): ALR CLR (No Non-spin responsibility) Load Zone LMP SCED Base Point MPC → 5 MW DR-capable ► ► ► $50 MPC $1,000 LPC → 10 MW Firm

48. Scenario 2 • For any SCED intervals that the LR’s bid to buy is less than the five-minute Load Zone LMP, SCED Base Point will instruct the LR to consume at its telemetered Low Power Consumption, subject to ramp rate limitations from its current consumption level (NPF) RTM Bid to Buy(up to): ALR CLR (No Non-spin responsibility) Load Zone LMP SCED Base Point MPC → 5 MW DR-capable ► ► ► $1,500 LPC $1,000 LPC → 10 MW Firm

49. Scenario 3 • For any SCED intervals that the LR’s bid to buy is equal to the five-minute Load Zone LMP, SCED may dispatch the LR in either direction (up or down) in increments as small as 0.1 MW, within the bounds of the LR’s telemetered Maximum Power Consumption and Low Power Consumption, subject to its telemetered ramp rate limitations from its current consumption level (NPF) • In this scenario, the LR sets the Load Zone LMP RTM Bid to Buy(up to): ALR CLR (No Non-spin responsibility) Load Zone LMP SCED Base Point MPC → 5 MW DR-capable ► ► ► $1,000 $1,000 LPC≤ BasePoint ≤ MPC LPC → 10 MW Firm

50. Scenario 4a ALR CLR (5 MW Non-spin responsibility; 5 MW additional DR capability) RTM Bid to Buy(up to): Load Zone LMP SCED Base Point MPC → ► 5 MW add’lDR-capable $1,000 ► ► $1,500 LPC+5MW subject to ramp rate limitations from its current consumption level (NPF) 5 MW Non-spin ► $5,000 LPC → 5 MW Firm