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.
Slide #5

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
This is key slide
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. ERCOT proposes the transition to the following five AS products:
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.
Recognizes during 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. Fast Frequency Response
Current Framework
Proposed Framework 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 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).
System Load
FFR
PFR(5% Droop)
<=35000 MW
840 MW(30% 0f 2800)
1960 MW
0 MW
4480 MW

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 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. Qualification Deployment Performance
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. Targeted to be implemented by Summer 2014
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) }
BasePointgen is instruction on how much to produce
BasePointLR is 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 $50/MWh
G2 Offer to Sell: 2,000 $300/MWh
LR Bid to Buy: 1,000 $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 t
t+5
t+10
t+15
t+20
t+25
LMP 50
200
300
Inelastic Demand
58,500
59,700
60,050
60,125
59,075
NPF_LR
1,000
925
GTBD
59,500
60,700
60,350
59,425
BP_G1
60,000
BP_G2
125
BP_LR

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
RRS
NSpin
180 MW
Total Demand
Response Capability

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
$/MWh
RTM Energy Bid MW
Total Demand
Response Capability
Proxy Bid extension
$/MWh
SWCAP
SWCAP
Right shifted
RTM Energy Bid MW
LPC
MPC

47. (No Non-spin responsibility)
Scenario 1
ALR CLR
(No Non-spin responsibility)
RTM Bid to Buy (up to):
Load Zone
LMP
SCED Base Point
MPC →
5 MW DR-capable ► ► ►
$1,000
$50
MPC
LPC →
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)
10 MW Firm

48. (No Non-spin responsibility)
Scenario 2
ALR CLR
(No Non-spin responsibility)
RTM Bid to Buy (up to):
Load Zone
LMP
SCED Base Point
MPC →
5 MW DR-capable ► ► ►
$1,000
$1,500
LPC
LPC →
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)
10 MW Firm

49. (No Non-spin responsibility)
Scenario 3
ALR CLR
(No Non-spin responsibility)
RTM Bid to Buy (up to):
Load Zone
LMP
SCED Base Point
MPC →
5 MW DR-capable ► ► ►
$1,000
$1,000
LPC≤ BasePoint ≤ MPC
LPC →
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
10 MW Firm

50. (5 MW Non-spin responsibility; 5 MW additional DR capability)
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’l DR-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

51. (5 MW Non-spin responsibility; 5 MW additional DR capability)
Scenario 4b
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’l DR-capable ►
$1,000
LPC≤ BasePoint ≤ LPC+5
subject to ramp rate limitations from its current consumption level (NPF) ► ►
$5,000
5 MW Non-spin ►
$5,000
LPC →
5 MW Firm

53. Drivers for moving to a new Ancillary Services Framework includes the following:
The Generation mix in ERCOT is changing new regulatory requirements
A new framework should allow better use of the capabilities of existing and new Resources
Better specifications and performance based pay would likely lead to a more efficient way to acquire and deploy AS
All of the above

54. The proposed AS products (currently in discussion) within the new AS framework does NOT include:
(SIR) Synchronous Inertial Service
(FFR) Fast Frequency Response
(PFR) Primary Frequency Response ERS
(QFR) Quick and Flexible Ramping

55. The objective of Fast Frequency Response (FFR) and Primary Frequency Response (PFR) Reserves should be to ensure Frequency is arrested above UFLS _________ __ _____ __ and to meet NERC FRO Standard (BAL-003).
threshold of Hz
threshold of Hz
threshold of Hz
threshold of Hz

56. The following are eligible to participate as a Load Resource in SCED (per NPRR 555).
Existing or new single-site Controllable Load Resources
Aggregate Load Resources (ALRs) composed of multiple sites within single ERCOT Load Zone
Load Resources with temporal constraints or block energy bids
Both a and b

57. Which of the following are true about Load Resources participating in SCED:
QSEs with LRs in SCED will submit Bids to buy (not Offers to sell)
Bids will reflect a LR’s willingness to consume “up to” a specified five-minute Load Zone LMP
Base Point instructions could require a LR to move up or down incrementally every 5 minutes to any level between its LPC and MPC (subject to ramp rate limitations)
All of the above

58. Questions? ON
OFF