INTRODUCTION TO ANCILLARY SERVICES - NYISO … · New York ISO (230 kV and above) Legend: Oswego...

Copyright © 2004 NYISO

INTRODUCTION TO ANCILLARY SERVICES

NEW YORK MARKET ORIENTATION COURSE

JACK VALENTINENYISO MARKET TRAINING


ANCILLARY SERVICES MANUAL

• WWW.NYISO.COM/services/documents/manuals/pdf/oper_manuals/ancserv.pdf• Revised 04/06/04

• Manual does not reflect SMD market changes


What are Ancillary Services?

• Unbundled services to facilitate market operations

• Help to maintain reliable operation

• Consists of both physical equipment and human resources

GG

Voltage SupportRegulation

Reserves

GTGT

Black Start

LOAD LOAD

Reserves


What are Ancillary Services?Unbundled services

to facilitate market operations• Regulation• Reserves• Energy Imbalance

Help to maintain reliable operation• Scheduling• Voltage Support• Black Start

GG

Voltage SupportRegulation

Reserves

GTGT

Black Start

LOAD LOAD

Reserves


Six Ancillary Services

• Rate Schedule 1

• Rate Schedule 2• Rate Schedule 3

• Rate Schedule 4• Rate Schedule 5• Rate Schedule 6

• Scheduling, System Control & Dispatch

• Voltage Support• Regulation &

Frequency Response

• Energy Imbalance• Operating Reserve• Black Start


Ancillary ServicesEmbedded, Cost Based Services


Cost Based Ancillary Services

• Scheduling, System Control & Dispatch (Schedule 1)

• Voltage Control (Schedule 2)• Black Start (Schedule 6)


Scheduling, System Control & Dispatch (Schedule 1)

• NYISO Transmission System Operations for Reliability

• NYISO Facilitating the New York Wholesale Electric Market


Recovers the costs of operating the NYISOMechanism to recover NYISO startup costs

• Amortized over 5 years• Last Monthly Charge: December, 2004

Uplift Cost Recovery• Bid Production Cost Guarantee Payments

Cost paid by all transmission customers• 15% of fixed costs billed to Generators and other injections

Cost applies to all transactions

Scheduling, System Control & Dispatch Service


Scheduling, System Control & Dispatch Service (2)

ISO costs recovered through one of the two tariffs• ISO OATT• ISO Market Services Tariff

Provides for NYISO clearing account adjustment


Schedule 1 Cost Recovery-Market Services Tariff

• LBMP Market Administration• Administration of ICAP Market• Control Area Services Administration• Market Monitoring Program• 50% amortized NYISO start-up costs


Schedule 1 Cost Recovery-Open Access Transmission Tariff• Transmission Service Market Administration• Transmission System Engineering & Planning• Transmission Service Billing & Accounting• NYISO General & Administrative expense• System Scheduling, Control, & Dispatch costs• NYCA Transmission System Studies• 50% NYISO Start-up Costs• Residual Adjustments• FERC fees


Payment for Service

Billing• ISO embedded costs billed monthly based on

costs & expenses from previous month• Current Service Rate: $0.73 /MWH (combined

OATT & Mkt. Serv. Tariffs)• Uplift Charges and Residual Adjustments

billed/credited hourly to ALL in-month load• Bid Production Cost Guarantee charges are calculated

daily and billed hourly.• Average cost for 2003: $1.22/MWH

• Charges billed to all energy withdrawals including wheel-throughs and exports

• Suppliers are charged for 15% of ISO embedded costs and FERC fees


Market Residuals

Transmission Customers share in the costs/revenues from market residualsBased on Transmission Customers’ ratio share of NYISO megawatt-hour withdrawals


Residual Adjustment Components Defined

Marginal Losses• revenue collected from Transmission Customers in excess of payments to

Power Suppliers as a component of the LBMP or TUCChange in Transfer Capability

• Costs or savings associated with re-dispatch of generators due to changes in Transfer Capability between Forward Market schedules & Real-Time dispatch

Inadvertent Interchange• Costs or savings resulting from inadvertent interchanges between NYCA and

neighborsEmergency Transactions

• Costs or revenues from emergency transactions with neighboring control areas


Residual Adjustment Components Defined (2)

Metering Adjustment• Revenue excess/deficiency from metering errors

Forecast VS Actual System Load• Deviations between actual system load & the 5 minute load forecasts used by

RTD, resulting in either more or less Energy needed to meet system loadExcess Energy Amount

• Excess energy supplied to the system by generators that are off scheduleLoad to Bus Distribution

• Revenue excess/deficiency from Transmission Customers due to differences between their actual load and the sub-zonal load allocation used to compute their real-time settlements


Voltage Support Services(Rate Schedule 2)

• Generation Reactive Power Resources in the New York Control Area which must be operated to maintain voltages within acceptable limits

• Proper Voltage Support (pressure) is prerequisite for delivery of electrical energy through the transmission grid and is dynamic.


Voltage Support Services (Cont.)

The ability to produce or absorb VArs during a Contingency is valued as much or more than during steady-state conditions


Generator Reactive Power Capability

Generators submit reactive power info• capability curves with MW values and

associated high and low MVAr limits• Annual testing of capability is required

[see Ancillary Services Manual and Tech Bulletins #103 & #91]

Establishes Reactive Power production capability for unit


Responsibilities for Service

NYISO• Coordination of bus voltage profiles• Coordinates voltage and reactive set points

Suppliers• Generators with a functioning Automatic

Voltage Regulators (AVR) that have successfully performed annual MVArcapability testing

• Synchronous Condensers


Recipients of Service

LSEs and Transmission Customers serving load in NYCA

Transmission Customers serving load outside NYCA• wheel through transactions• export transactions

Must be purchased from the NYISO


Payment for Service

Payments made to Suppliers of service• Current Annual Rate: $3,919/MVAr

• Cost based rates eliminated

• Rate is a FERC approved rate based on previously filed OATTs by the original 8 member utilities of the NYPP.

• Payments made monthly (1/12)


Voltage Support Billing

Payments made for this service by• All Transmission customers; LSE’s,

Exports, and wheel-throughs• Rate for 2004: $0.34 /MWH• Under ISO OATT


Provision for Lost Opportunity Cost

Bid Cost Curve

D 2 D 1

B 2

B 1

P RT

Real Time LBMP (P RT)

LOC

MW

$


ICAP Provisions

• ICAP providers receive payments for voltage support at all times.

• Generators w/o ICAP contracts receive pro-rated payments based on when the unit is online

• Suppliers with Synchronous Condensers receive payments only when the unit is online


Failure to Perform By Suppliers

Generators should be aware that there are substantial penalties for failure to provide proper voltage support as requested

See the Ancillary Services Manual for details


Black Start Service(Rate Schedule 6)

• Generators capable of starting without an outside electric supply, following a system-wide blackout

• Available to participate in system restoration


Black Start Capability ServiceRepresents key selected Generators

• ability to start without availability of outside electric supply

• available to participate in NY power system or bulk power system restoration activities

Desirable operating characteristics• location in the grid• startup time• ramping capability

New York ISO

(230 kV and above)

Legend:

Oswego

OakdaleFraser

Marcy

Massena

Moses

Chateauguay

Plattsburgh

AlpsClay

Lafayette

Watercure

Stolle Rd.

EdicPorter

Rotterdam

PleasantValley

CoopersCorners

RockTavern

Roseton

Buchanan

RamapoSprainbrook

Dunwoodie

765 kV

345 kV230 kV Goethals

Complex

Homer City

Shore Rd.E.Garden City

HuntleyPannell

Sta.80

Transmission System

Somerset

500 kV

Adirondack

Dunkirk

Meyer

Willis

NewScotland

Leeds

Hillside

Millwood

Farragut

W49St/Rainey

Niagara

St. Lawrence

Gilboa


Source & Scheduling of ServiceNYISO Manages BS Capability

• identifies generating units in critical areas for NY bulk power system restoration

• has flexibility to seek new resources• develops and periodically reviews Black

Start Restoration Plan


Payment for Service(ISO OATT)

Payments made to Generators that are included in Restoration Plan covering• Embedded capital costs of equipment• O&M expenses• Training

Forfeiture of Payment for failure to startLSEs pay monthly black start charge on all

transactions to supply load in NYCA• $15,181 x load’s share of total NYCA load• includes in-state bilateral transactions• includes purchases of energy from LBMP market• includes import transactions


Local Black Start Service

Black Start Generators participating in Local Transmission Owner Restoration Plans• ISO makes payments to the participating

Generators• ISO is reimbursed by the LSE’s for Local

Black Start Capability in their area


Market Based Ancillary Services

• Operating Reserve• Regulation & Frequency Response• Energy Imbalance


Ancillary ServicesOperating Reserve Service

(Rate Schedule 5)


Operating Reserve

Backup Generation available in the event of:• Loss of any major Generating Unit• Loss of transmission • Significant “dragging”of the Pool Control Error

Three Markets• 10 Minute Spinning Reserve• 10 Minute Non-Synchronized Reserve• 30 Minute Reserve: non-sync & spinning


Generation Reserves

Peak Load Loading

Installed Capability Operating Capability

INSTALLEDINSTALLED OPERATINGOPERATINGTwo Separate Worlds

Real-TimeMw

Seasonal%


�600 MW min 600 MW

What is needed in addition to 10 min SYNC (600) to total

1200 MW

SINGLE LARGEST CONTINGENCY 1,200 MWRESERVE REQUIREMENT: 1,800MW

10 MIN SYNC

10 MINUTETOTAL

1,200 MW

30 MIN

10 MIN NON-SYNC

NYISO Operating Reserve Requirements


Reserve in the Day-Ahead Market (DAM)

• All dispatchable (flexible) resources will now participate in the reserve market.

• ISO Committed Flexible• Self-Committed Flexible• Available, off-line, 10 & 30 minute startup units

• SCUC continues to commit generation and produce DAM schedules for the co-optimization of energy, reserves and regulation• DAM Schedules are financially binding


Suppliers of Ancillary Services• NYCA generating units supplying ancillary services

as indicated in the table below.

30 Min

Regulation

10 MinOff-line

Self Committed

- Fixed

Self Committed- Flexible

ISO Committed

- Fixed

ISO Committed

-Flexible

30 Min Non-Synch

30 Min Spin10 Min Non-Synch

10 Min SpinStartupStatus


Reserve in the DAM (2)

• In the DAM, Generator Availability Bids are required • Bids will not be accepted without data

entered in this field (May enter “0”) Generators will no longer bid the amount of reserve offered

• Limited by Emergency ramp rate* and by the applicable Upper Operating Limit (UOL)

*No less than capacity weighted average of normal response rates.


Spinning Reserve BidMW

0

Minimum Generation Energy Block

Off-Line

Upper Operating Limit10 Min Spinning Reserve Award

Note: Reserve Pick-up has not been initiated

SCUC/RTD SchedulingRange for 10 min.Spinning

Reserve Generators

KEY

SCUC = Security Constrained UnitCommitment

RTD = Real-Time Dispatch


Reserve Requirements are Locational

Hourly Payments for Reserve Providers• Locational Pricing

Three Reserve Locations• West of Total East (Zones A-E)• East of Total East (Zones F-J)• Long Island (Zone K)

New York ISO

(230 kV and above)

Legend:

Oswego

OakdaleFraser

Marcy

Massena

Moses

Chateauguay

Plattsburgh

AlpsClay

Lafayette

Watercure

Stolle Rd.

EdicPorter

Rotterdam

PleasantValley

CoopersCorners

RockTavern

Roseton

Buchanan

RamapoSprainbrook

Dunwoodie

765 kV

345 kV230 kV Goethals

Complex

Homer City

Shore Rd.E.Garden City

HuntleyPannell

Sta.80

Transmission System

Somerset

500 kV

Adirondack

Dunkirk

Meyer

Willis

NewScotland

Leeds

Hillside

Millwood

Farragut

W49St/Rainey

Niagara

St. Lawrence

Gilboa


Reserve LocationalRequirements

• Locational requirements for reserve remain in effect

• With Total East constrained, separate clearing prices for NYCA (West) and East (East of total East)

• Long Island prices may not exceed East reserve clearing prices when reserve constraint is binding


Reserve LocationalRequirements

270-540MW

1,000MW

1800MW

30 Minute Reserve

120MW 1000MW

1200MW

10 Minute Total Reserve

60MW

300 MW

600 MW

10 Minute Spinning Reserve

Long Island Eastern New York New York CA


DAM Reserve Clearing Price• Locational Reserve Clearing Prices =

the sum of the shadow prices* of the applicable nested reserve constraints. • Shadow Price = The Lost Opportunity Cost

(LOC) plus the availability bid of the marginal reserve provider selected to meet a given reserve constaint.

• LOC= the margin on the sale of energy or regulation that the unit foregoes to provide reserve (difference between the units energy bid (offer) and LBMP)

• Demand Curves set reserve clearing prices when activated by capacity shortages

*The actual cost to provide the next available MW of reserve


Shadow Pricing of Reserve

SP7SP4SP1Total 30 Minute Reserve

SP8SP5SP210 minute Total Reserve

SP9SP6SP310 minute Spinning Reserve

LONG ISLANDEASTWEST

MCP for West 30 Min = SP1MCP for West 10 Min Total Reserve = SP1 + SP2MCP for West10 Min Total Reserve = SP1 +SP2+ SP3MCP for East 30 Minute = SP1 + SP4MCP for East 10 Min Non-Synch = SP1 +SP2 +SP4 +SP5MCP for East 10 Min Spin = SP1 +SP2 + SP3 +SP4 + SP5 + SP6

The shadow price of each locational reserve product is equal to thesum of the relevant shadow prices.


Full Two Settlement System for Reserve

• Loads purchase full reserve requirement in the DAM

• Real-time balancing obligation lies with suppliers with a day-ahead schedule• Reserve selected in the DAM must buy back what

is not scheduled in RT, at the RT clearing price• The Day Ahead Margin Assurance Payment is modified

due to the addition of the 2nd settlement for reserve and regulation services to ensure suppliers are “held harmless” when following ISO direction results in financial harm through no fault of their own.


Full Two Settlement System for Reserve

• Eliminates additional costs in today’s market due to re-optimization or procurement of replacement services in RT

• Creates additional incentive for suppliers to be available in RT and to perform when called upon in a reserve activation.

• 10-minute reserve shortages are less likely under RTS• 10-minute latent reserves will be available in real-

time.


Reserve in Real Time Dispatch(RTD)

• All availability bids are at $0 • All dispatchable capacity is visible

and available for scheduling reserve• Available 10 & 30 minute Spinning reserve• Available 10 & 30 Non Synch• Capability determined by ramp rate and the

applicable Upper Operating Limit (UOL)


Reserve Clearing Price in RTD

• RT reserve is scheduled and settled nominally every 5 minutes• Based on RTD’s co-optimization of energy,

reserves and regulation over the next 50-60 minutes

• Like the DAM, the reserve clearing prices are set using shadow pricing• Sum of the shadow prices of the applicable nested

reserve constraints• No availability bids in R-T• Shadow price is the LOC of the marginal units providing

reserve


Reserves in Real Time Dispatch Corrective Action Mode

(RTD-CAM)• Operator initiated version of RTD• Used to initiate

• Reserve Pickups• Large event & Small event

• Small event RPU permits basepoints to be lowered to reduce transmission line loading

• Produces 10 minute basepoints• May be followed with additional 5 minute intervals

• Maximum Generation Pickups• Basepoints ASAP


Reserves in RTD-CAM (Cont.)

• Continues to solve for reserve requirements• Maintained during reserve pickups

• Continues to calculate and set energy & reserve prices• More accurately reflects true condition and prices

become more realistic• Capability to commit 10 minute quick-

starts


Reserve – Day-Ahead Example

• In the DAM, Unit 3 sets the energy price @ $45 b/c Unit 4 is at min gen. Unit 2 is backed down for reserves, so the reserve price is this unit’s lost opportunity cost (difference between LBMP and their energy bid) plus the availability bid or 45-35+2 = 12.

Day-Ahead PositionMin Gen

(MW)

Incremental Energy (MW)

Maximum Capacity

(MW)

Spinning Reserve

(MW)

Incremental Energy Offer

Price ($/MW)

DA Spinning Reserve

Availability Offer ($/MW)

Energy Schedule

(MW)

Reserve Schedule

(MW)Unit 1 50 150 200 10 25 1 200 0Unit 2 50 150 200 10 35 2 195 5Unit 3 50 150 200 10 45 3 145 10Unit 4 50 150 200 10 55 4 50 10

590 25

Load (MW) 590LBMP ($/MWh $45

Reserve Requirement (MW) 25

Reserve Clearing Price ($/MW) $12

Fully DispHeld back for Res

Econ Disp@ Min Gen

The table below shows the day-ahead schedules for energy and reserves upon which two scenarios are based.


Reserve SettlementScenario 1

The following scenario illustrates the Day-Ahead Market and Real-time Market settlements when an additional generator (#5) self-commits-flexible in real-time. Reserves are moved to generator 5, and unit 2 is fully dispatched for energy.

What is the marginal unit for energy?

What is the marginal unit for reserve?


RT Base CaseMin Gen

(MW)


Maximum Capacity

(MW)

Spinning Reserve

(MW)


Price ($/MW)

RT Spinning Reserve


Energy Schedule

(MW)

Reserve Schedule

(MW)Unit 1 50 150 200 10 25 0 200 0Unit 2 50 150 200 10 35 0 200 0Unit 3 50 150 200 10 45 0 90 5Unit 4 50 150 200 10 55 0 50 10Unit 5 50 150 200 10 65 0 50 10

590 25




RT Reserve SettlementScenario 1

• In day, Unit 5 self-commits as a flexible unit so it is also available for reserve scheduling.

• Unit 2 can be fully dispatched, there is no lost opportunity and availability bids are restricted to 0 in RT.

• Reserve clearing price is now $0 (45-45+0=0).

Fully DispFully DispEcon Disp

@ Min Gen@ Min Gen


Reserve – RT Scenario 1

• RT Base Case Settlement• RT load has not changed from day-ahead so there is no RT

settlement on load for either reserves or energy. All additional revenues required to pay generators not scheduled day-ahead is recovered from other generators who were scheduled day-ahead and were not in RT.

Net Energy

Schedule (MW)

Net Reserve Schedule

(MW)RT Energy

Payment ($)

RT Reserve Payment

($)Additional Cost ($) Profit ($)

Unit 1 0 0 -$ -$ -$ -$ Unit 2 5 -5 225$ -$ 175$ 50$ Unit 3 -55 -5 (2,475)$ -$ (2,475)$ -$ Unit 4 0 0 -$ -$ -$ -$ Unit 5 50 10 2,250$ -$ -$ 2,250$

0 0 -$ -$

Load 0 0 -$ -$

$45 (RT LBMP) X 5 MW

$35 (offer) X 5MW

$45(RT LBMP) X –55 MW

$45 (RT LBMP) X 50 MW


Reserve SettlementScenario 2

This scenario uses the same DAM schedule and settlement as scenario 1. Generator 5 self-committed flexible however, this time the load has increased by 360 MW.

What is the marginal unit for energy?

What is the marginal unit for reserve?


Reserve – Day-Ahead Example

• In the DAM, Unit 3 sets the energy price @ $45 b/c Unit 4 is at min gen. Unit 2 is backed down for reserves, so the reserve price is this unit’s lost opportunity cost (difference between LBMP and their energy bid) plus the availability bid or 45-35+2 = 12.

Day-Ahead PositionMin Gen

(MW)


Maximum Capacity

(MW)

Spinning Reserve

(MW)


Price ($/MW)

DA Spinning Reserve


Energy Schedule

(MW)

Reserve Schedule

(MW)Unit 1 50 150 200 10 25 1 200 0Unit 2 50 150 200 10 35 2 195 5Unit 3 50 150 200 10 45 3 145 10Unit 4 50 150 200 10 55 4 50 10

590 25




Fully DispHeld back for Res

Econ Disp@ Min Gen

The table below shows the day-ahead schedules for energy and reserves upon which three scenarios are based.


Reserve – RT Higher Load Scenario 2

• Again, Unit 5 has self-committed as a flexible unit so it is also available for reserve scheduling.

• Load has come in 360 MWs higher. • Here units 3 & 4 are backed down to maintain the reserve

requirement.• The reserve price is set by Unit 3 and they both get paid the

marginal LOC of Unit 3 which is 65-45+0 = 20.

RT Higher LoadMin Gen

(MW)


Maximum Capacity

(MW)

Spinning Reserve

(MW)


Price ($/MW)

RT Spinning Reserve


Energy Schedule

(MW)

Reserve Schedule

(MW)Unit 1 50 150 200 10 25 0 200 0Unit 2 50 150 200 10 35 0 200 0Unit 3 50 150 200 10 45 0 195 5Unit 4 50 150 200 10 55 0 190 10Unit 5 50 150 200 10 65 0 165 10

950 25




Fully DispFully Disp

Held back for ResHeld back for Res

Econ Disp


Reserve – RT Higher Load Scenario 2

• RT High Load Settlement• Net Real Time load must cover its shortfall in the energy

market. However the load bought sufficient operating reserves day-ahead, so any increases in a generators reserve schedule is offset by another generators reduction

Net Energy

Schedule (MW)

Net Reserve Schedule

(MW)RT Energy

Payment ($)

RT Reserve Payment

($)Additional Cost ($) Profit ($)

Unit 1 0 0 -$ -$ -$ -$ Unit 2 5 -5 325$ (100)$ 175$ 50$ Unit 3 50 -5 3,250$ (100)$ 2,250$ 900$ Unit 4 140 0 9,100$ -$ 7,700$ 1,400$ Unit 5 165 10 10,725$ 200$ 7,475$ 3,450$

360 0 23,400$ -$ 17,600$ 5,800$

Load 360 0 23,400$ -$

$65 (RT LBMP)X 5 MW

$20 (RT RCP) X –5 MW

$35 (offer) X 5 MW


Average Clearing Pricesfor Reserve:2003 (through

Sept., 2004) 10 Minute Spin

• East: $4.27 ($2.27)• West: $4.16 ($2.24)

10 Minute Non Synch• East: $1.03 ($0.31)• West: $0.99 ($0.30)

30 Minute Reserve: $0.96 ($0.26)


Performance Tracking for Reserve Generation

Units response will be measured for full 10 min. reserve pickups only

PTS compares unit’s actual generation with reserve pickup dispatch point.

Units not meeting their reserve obligation within 10 minutes will be penalized• receive proportionally less for availability for all

hours selected during that day• i.e., unit selected to provide 50 MW of Op Res

actually delivers 40 MW –availability payments for day paid at 80%

Removed under

SMD2


Failure to Provide Operating Reserve MW

0

Upper Operating Limit

Off-Line

Lower Operating Limit

SCDShortfall Penalty = (SCD - Act Gen) * LBMP

ACT GEN

Removed under

SMD2


NYISO Response to Failure to Perform…Penalties

No payment for the shortfall in energy Charged for the shortfall in energy provided,

at real-time LBMPReductions in Availability and Lost

Opportunity Cost payments• Based on Reserve Response

Persistent poor performance may result in• removal from the reserve market• Pass a re-qualification test

Removed under

SMD2


Reserve Shortage (Scarcity) Pricing (T.B. #108)

With a NYISO declared reserve shortage, LBMPs are calculated such that the LBMP in NYC (Zone J) is $1,000.• Zonal LBMPs will be the greater of the calculated

value or SCD (dispatch) LBMP• When shortage is only in the East, rule will only

apply to Eastern Zones (F-K)• Does not apply to transitional shortages

• End of Reserve Pickup• Emergency Sales to neighboring control areas• Top-of-the-hour schedule changes

Removed under SMD2


Reserve Demand Curve• To implement in our software, a more

robust and tightly integrated method of pricing reserves and energy during scarcity conditions• Replaces manual activation of scarcity pricing

rules• Consistent with our $500 value for EDRP and the

existing $1000 10-minute reserve shortage costs • Reserve Demand curve values set reserve

clearing prices and impacts LBMP when the NYCA is capacity constrained

• When serving the next MW of load creates or increases the shortage of reserve.

• Locational or statewide

• Will be applied in SCUC, RTC and RTD


Reserve Demand Curve• Price of Reserves is defined even if not

enough reserves are available at any price to meet the ISO’s reserve target.• In shortage (Capacity Constrained) situations, the

price of reserves is set by the Demand Curve.• Allows the market to clear and set rational prices• Only MWs scheduled as reserves are paid the

reserve clearing price • Demand Curve creates a risk on the supplier of

pricing themselves out of the market.


Reserve Demand Curve (Cont.)

• DC values were set high enough to capture with a high degree of certainty, all available reserve

• Implementation of the DC will not impede operator ability to manually procure reserves necessary to meet requirements


Demand Curve for Reserves-Normal

600 18001200Reserve Quantity (MW)

Res

erve

Pri

ce ($

)

1,000Demand

Supply

(curve is for demonstration purposes only)


Demand Curve for Reserves-Short of 30-Minute


Res

erve

Pri

ce ($

)

1,000Demand

Supply



Demand Curve for Reserves-Short of 10-Minute


Res

erve

Pri

ce ($

)

1,000Demand

Supply



Reserve Demand Curve

• 9 Demand Curves• One for each category and location of

reserve• Categories: 10 Minute Spin, 10 Minute Total and 30

Minute Total• Locations; NYCA, Eastern (East of Total East), and

Long Island

• Curves will be applied for each reserve constraint


Reserve Demand Curve Values ($/MW)

With reserve shortages these values establish reserve clearing prices and are added to the LBMP of energy.

300*25200MW @$50 200MW @ $100

200 MW @ $200

30 Min Total

25500*150*10 Min Total

2525500*10 Min Spin

LIEASTNYCA

*Higher values reflect reserve requirements that must be maintained per reliability rules.


Additive Impact on LBMPDemand Curve values are cascading - the value for each

constraint violated is added to the LBMP

$525$225$20030 Min Total

$1,200$875$35010 Min Total

$1,750$1,400$85010 Min Spin

LIEASTNYCA

300*25200MW @$50

200MW @ $100

200 MW @ $200

30 Min Total

25500*150*10 Min Total

2525500*10 Min Spin

LIEASTNYCA


Reserve Demand Curve Activation

LBMP = Energy bid of last MW converted to energy + (plus) Applicable Demand Curve Values

$649

$150

Unit 1 Unit 2

Pre-shortage RTDLBMP = $649RCP = $499 ($649 - $150)

Unit 2Unit 1

$150

$649

Post-shortage RTD

LBMP = $650 ($150 + $500)

RCP = $500 (Demand Curve)

• Unit 1 dispatched to meet nextMW of load: Sets LBMP.• Unit 2 held for reserves but mustbe dispatched to meet load.• With reserve shortage DC is activated and applied.


Operating Reserve ChargesLSE’sTransmission customers exporting

energyCharges calculated hourly by NYISO

• according to ratio of the LSE load to the sum of ALL load (plus exports) for that hour

• Not locational

Billed monthly under the ISO OATT• Average cost for 2002: $0.26/MWH• Average cost for 2003: $0.28/MWH• Average cost through Sept., 2004: $0.13/MWH


Ancillary ServicesRegulation

(Rate Schedule 3)


Regulation & Frequency Response

• Balancing Generation with ever-changing electric load

• Generator response to six second signals produced by the NYISO


The Need for Regulation & Frequency Response Service

• Assist in maintaining scheduled frequency at 60 Hz

• Compliance with NYSRC, NERC, and NPCC Reliability Requirements

DNIDNI&&

GenGen LoadLoad


NYISONYISO

TO TO Control Control CenterCenter



Control Signals to Satellite Control Centers (TOs)

AGC control errors• every 6 seconds• for units providing Regulation

RTD (SCD) Dispatch basepoint signals• nominally every 5 minutes• signal for each unit from RTD (SCD)• ramped at 6 sec. intervals


Control Signals to the Generators

• AGC signals are created by NYISO, passed through the TO and on to Regulating Units.• Effectiveness and timeliness may vary from unit to

unit• AGC/RTD (SCD) signals are created by

NYISO and available for direct pass to Generators• See Communications Interface Manual

(nyiso.com/services/documents/manuals/pdf/admin_manuals/communications.pdf)

• Flexible units are dispatched every 5 minutes


Regulation Providers

• Market open to generators that have AGC capability WITHIN NYCA...• not obligated to participate

• Suppliers may bid in the Day-Ahead Mkt., Real-Time Mkt., or both

• A single statewide clearing price.


Regulation Market

• Bidding and Scheduling• Suppliers must bid as ISO-committed

flexible or self-scheduled flexible in order to be eligible to provide regulation.

• Regulation suppliers must specify both the maximum amount of regulation capacity offered (MW) and an availability offer ($/MW).

• Regulation Capacity = Reg. response rate x 5 minutes


Generating Unit Operating CharacteristicsMW


AGC Desired Generation

RTD Base Point Signal (5 minutes)

Lower Operating Limit = Minimum Generation Point

Off-Line0

RegulationCapacity

RegulationCapacity

RTDBase PointRange


Two Settlement System• Full two-settlement for regulation (SCUC &

RTD).• Day Ahead schedules are financially

binding• Day ahead obligations balanced against

real time schedules.• Suppliers with net real time regulation schedules

will be settled at real time prices.• Suppliers selected Day-Ahead but not scheduled in R-T

will buy back the service at the R-T price• Suppliers scheduled R-T for additional regulation will

receive the R-T clearing price for additional regulation provided.


Changes in Regulation• Pricing

• Regulation market clearing prices will be set based on the shadow prices in both DAM and R-T.

• Shadow price= Marginal availability bid + marginal Lost Opportunity Costs (LOC) .

• Real-time regulation service will be scheduled and settled, nominally on a 5-minute basis (RTD).

• Regulation prices impact LBMP ONLY when the NYCA is capacity constrained

• when serving the next MW of load creates or increases the shortage of regulation.


Regulation Revenue Adjustment Payment/Charge

• Ensures regulation providers are properly compensated for regulating relative to the LBMP and their economic RTD basepoint

• RRAP-made to ensure full compensation for energy produced

• RRAC-avoids ISO overpayment for energy reserved and paid for in the Regulation Market

• Regulation Clearing Price incorporates the LOC of the marginal unit

• Calculated for each interval



• Regulating units settle energy in real-time at the lesser of their actual output or AGC basepoint


Average Clearing Prices for Regulation 2003 (Through Sept., 2004)

Regulation (DAM) – $28.32 ($19.92)



• When AGC is greater than the RTD• RRA Payment for units with energy bids greater

than R-T LMBP• RRP Charge for units with energy bids less than

R-T LBMP• When AGC is less than the RTD

• RRA Charge for units with energy bids greater than R-T LBMP

• RRA Payment for units with energy bids less than R-T LBMP


Regulation PerformanceActual

KEY

RTD = Real-Time Dispatch

MCP = Market Clearing Price for Regulation

MW

0

RegulationBandwidth


Off-Line

Lower Operating Limit

Max. AGC Basepoint

RTDMin. AGC BasepointPresent AGC Basepoint

Actual Generation{Unit Control Error


Incentive BasedRegulation Service

Availability Payment based on Performance Index (PI)

• PIreg= [(Reg Capacity-AAUCE) / (Reg. Capacity)] + 0.10

• AAUCE = Average Absolute Unit Control Error; derived from a unit’s deviation of the actual gen from the 30 second min & max of the desired generation of the unit (see next slide)

• Better Performance = Greater Availability Payments

• Availability Payment= [(PI-PSF) / (1-PSF)] X [MCP$ x Reg Cap]

• PSF= Payment Scaling Factor; initially set at 0


REGULATION AVAILABILITY EXERCISE

• A generator bids 10 MWs of Regulation Capacity at $4/MW into the New York market. The clearing price for that hour is $16/MW and the unit is selected to provide regulation.

• Assuming the AAUCE is 2 MW, what does the unit get paid in availability for this hour?

1.


Regulation Demand Curve

• There are no locational requirements for regulation

• Price of regulation set by curve when shortages occur and will impact LBMP

25 MW @$250/MW and Remainder @

$300/MW

RegulationNYCA


Charges for RegulationService

Billed for Service• LSEs• Payments made by generators not

providing regulation service in the form of Regulation Performance Penalty for persistent under-generation

• Assessed both fixed and flexible generation• Tracked by NYISO’s Performance Tracking System

(PTS)


Performance Tracking for Generation

5 minute RTD basepoints are ramped at 6 second intervals

Flexible generators are expected to respond, on average, within their deviation tolerance of the basepoint (RTD) intervals received• the deviation tolerance is 3% percent of the unit’s

Upper Operating Limit (UOL)• e.g.., 600 MW UOL unit and NYISO regulation

performance index at 1.0 * 3% deviation tolerance= 18 MW


Performance Tracking for Generation (Cont.)

Generation performance penalties are assessed generators only when they exceed their deviation tolerance* through under generation for more than 3 dispatch intervals• Deviation tolerance: lesser of 3% of unit’s upper operating

limit or 3 times the Response Rate (TB #78)• Regulation MCP (R.T.) x [SCD basepoint - actual generation

output]

Intermittent Renewables, selected NYC steam providers and some PURPA units are exempt.


Performance Tracking

Units are paid for over-generation within their deviation tolerance. • limited to 3% of Upper Op Limit bandwidth • Over-Generation in excess of deviation

tolerance is “given” to the market


Ancillary ServicesLesson 3 1/2

Energy Imbalance(Rate Schedule 4)


Energy Imbalance

• The mismatch between what was scheduled Day-ahead and Real-time actual withdrawals by load and injections from generators

• Inadvertent energy flow between the NY Control Area and External Systems


Energy Imbalance

Internal Energy Imbalance• addressed through real-time

market and real-time settlements• deviations between what was scheduled Day-

ahead and the Real time actual withdrawals (loads) and injections (generators)

• includes deviations from bilateral transaction schedules


350 MW

500 MW

Day-ahead LBMP

Day-ahead LBMP

400 MW

300 MW

plus 50mw @RTminus 50mw @RT

Forward Contracts

RTD Calls for More

RTD Basepoints

RTD Basepoints

RTD Calls for Less

Forward Contract for GenerationVs. Real Time Dispatch

Forward Contract

Gen Paidfor 350 Mw

at fwd cont $

Gen Paidfor 350 Mw

at fwd cont $


Actual Load Exceeds Fwd Contract:

Forward Contract for Covering LoadVs. Real Time Load

Actual Load Less than Fwd Contract:

Fwd Contractfor 60 Mw

Load Paysfor 60 Mw

at fwd cont $Plus10 Mw @RT

Load Paysfor 60 Mw

at fwd cont $

minus10 Mw @RT

70Mw

50Mw


Internal Energy Imbalance Services

Transmission Customers taking service under ISO OATT ONLY…• If actual energy withdrawal exceeds scheduled

deliveryadditional energy will be the greater of

• 150% of the real-time LBMP or• $100 / Mwh

• If actual withdrawal is less than scheduled, it will not be paid for the excess energy.


Energy Imbalance (External)

External Energy Imbalance• refers to mismatch between

scheduled and actual flows between NYCA and other control areas

• Inadvertent accounting using existing NERC guidelines

• addressed through in-kind energy payback


Who Pays for Services?

Ancillary Service InternalLoads

Exports WheelThroughs

Regulation & FrequencyResponseOperating ReserveBlack StartVoltage SupportScheduling, System Control& DispatchEnergy Imbalance


Ancillary Service Charges

~$0.001/MWHBlack Start~$0.28/MWH* ($0.13)Operating Reserve--------------Energy Imbalance~$0.34/MWH* ($0.20)Regulation$0.36/MWHVoltage Support

$0.73/MWH (Embedded)~$1.22/MW* ($1.46)(Uplift/Residuals)

Sched.,Sys Control& Dispatch

CostAncillary Service

*Average for 2003 (Through Sept., 2004)

INTRODUCTION TO ANCILLARY SERVICES - NYISO … · New York ISO (230 kV and above) Legend: Oswego...

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Transcript of INTRODUCTION TO ANCILLARY SERVICES - NYISO … · New York ISO (230 kV and above) Legend: Oswego...