INTRODUCTION TO ANCILLARY SERVICES

Transcription

1 INTRODUCTION TO ANCILLARY SERVICES NEW YORK MARKET ORIENTATION COURSE JACK VALENTINE NYISO MARKET TRAINING

2 ANCILLARY SERVICES MANUAL anuals/pdf/oper_manuals/ancserv.pdf Revised 04/06/04 Manual does not reflect SMD market changes

3 What are Ancillary Services? G Unbundled services to facilitate market operations Voltage Support Regulation Reserves Help to maintain reliable operation Black Start GT Consists of both physical equipment and human resources LOAD LOAD Reserves

4 What are Ancillary Services? G Unbundled services to facilitate market operations Regulation Reserves Energy Imbalance Help to maintain reliable operation Scheduling Voltage Support Black Start Voltage Support Regulation Reserves Black Start GT LOAD LOAD Reserves

5 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

6 Ancillary Services Embedded, Cost Based Services

7 Cost Based Ancillary Services Scheduling, System Control & Dispatch (Schedule 1) Voltage Control (Schedule 2) Black Start (Schedule 6)

8 Scheduling, System Control & Dispatch (Schedule 1) NYISO Transmission System Operations for Reliability NYISO Facilitating the New York Wholesale Electric Market

9 Scheduling, System Control & Dispatch Service Recovers the costs of operating the NYISO Mechanism 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

10 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

11 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

12 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

13 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

14 Market Residuals Transmission Customers share in the costs/revenues from market residuals Based on Transmission Customers ratio share of NYISO megawatt-hour withdrawals

15 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 TUC Change 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 neighbors Emergency Transactions Costs or revenues from emergency transactions with neighboring control areas

16 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 load Excess Energy Amount Excess energy supplied to the system by generators that are off schedule Load 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

17 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.

18 Voltage Support Services (Cont.) The ability to produce or absorb VArs during a Contingency is valued as much or more than during steadystate conditions

19 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

20 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 MVAr capability testing Synchronous Condensers

21 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

22 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)

23 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

24 Provision for Lost Opportunity $ Cost P RT Real Time LBMP (P RT ) B 1 LOC Bid Cost Curve B 2 D 2 D 1 MW

25 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

26 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

27 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

28 Black Start Capability Service Represents 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

29 New York ISO Transmission System (230 kv and above) St. Lawrence Moses Chateauguay Willis Massena Plattsburgh Adirondack Niagara Somerset Oswego Complex Marcy Rotterdam Huntley Sta.80 Pannell Stolle Rd. Meyer Clay Lafayette Edic Porter Gilboa New Scotland Alps Leeds Dunkirk Hillside Watercure Oakdale Fraser Coopers Corners Pleasant Valley Roseton Millwood Legend: Homer City Ramapo 765 kv Sprainbrook 500 kv Dunwoodie W49St/Rainey 345 kv Farragut 230 kv Goethals Rock Tavern Buchanan Shore Rd. E.Garden City

30 Source & Scheduling of Service NYISO 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

31 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 start LSEs 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

32 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

33 Market Based Ancillary Services Operating Reserve Regulation & Frequency Response Energy Imbalance

34 Ancillary Services Operating Reserve Service (Rate Schedule 5)

35 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

36 Generation Reserves INSTALLED Installed Capability Two Separate Worlds OPERATING Operating Capability Peak Load Loading Seasonal % Real-Time Mw

37 NYISO Operating Reserve Requirements 10 MIN SYNC 600 MW min 30 MIN 600 MW 10 MIN NON-SYNC What is needed in addition to 10 min SYNC (600) to total 1200 MW 10 MINUTE TOTAL 1,200 MW SINGLE LARGEST CONTINGENCY 1,200 MW RESERVE REQUIREMENT: 1,800MW

38 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 cooptimization of energy, reserves and regulation DAM Schedules are financially binding

39 Suppliers of Ancillary Services NYCA generating units supplying ancillary services as indicated in the table below. Status Startup 10 Min Spin 10 Min Non-Synch 30 Min Spin 30 Min Non-Synch Regulation ISO Committed -Flexible ISO Committed -Fixed Self Committed -Flexible Self Committed -Fixed Off-line 10 Min 30 Min

40 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.

41 Spinning Reserve Bid MW 10 Min Spinning Reserve Award Upper Operating Limit SCUC/RTD Scheduling Range for 10 min.spinning Reserve Generators KEY SCUC = Security Constrained Unit Commitment RTD = Real-Time Dispatch 0 Minimum Generation Energy Block Off-Line Note: Reserve Pick-up has not been initiated

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43 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)

44 New York ISO Transmission System (230 kv and above) St. Lawrence Moses Chateauguay Willis Massena Plattsburgh Adirondack Niagara Somerset Oswego Complex Marcy Rotterdam Huntley Sta.80 Pannell Stolle Rd. Meyer Clay Lafayette Edic Porter Gilboa New Scotland Alps Leeds Dunkirk Hillside Watercure Oakdale Fraser Coopers Corners Pleasant Valley Roseton Millwood Legend: Homer City Ramapo 765 kv Sprainbrook 500 kv Dunwoodie W49St/Rainey 345 kv Farragut 230 kv Goethals Rock Tavern Buchanan Shore Rd. E.Garden City

45 Reserve Locational Requirements 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

46 Reserve Locational Requirements New York CA Eastern New York Long Island 10 Minute Spinning Reserve 600 MW 300 MW 60MW 10 Minute Total Reserve 1200MW 1000MW 120MW 30 Minute Reserve 1800MW 1,000MW MW

47 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

48 Shadow Pricing of Reserve The shadow price of each locational reserve product is equal to the sum of the relevant shadow prices. WEST EAST LONG ISLAND 10 minute Spinning Reserve SP3 SP6 SP9 10 minute Total Reserve SP2 SP5 SP8 Total 30 Minute Reserve SP1 SP4 SP7 MCP for West 30 Min = SP1 MCP for West 10 Min Total Reserve = SP1 + SP2 MCP for West10 Min Total Reserve = SP1 +SP2+ SP3 MCP for East 30 Minute = SP1 + SP4 MCP for East 10 Min Non-Synch = SP1 +SP2 +SP4 +SP5 MCP for East 10 Min Spin = SP1 +SP2 + SP3 +SP4 + SP5 + SP6

49 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.

50 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 realtime.

51 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)

52 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 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

53 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

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55 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 quickstarts

56 Reserve Day-Ahead Example The table below shows the day-ahead schedules for energy and reserves upon which two scenarios are based. Day-Ahead Position Fully Disp Held back for Res Econ Min Gen 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) Min Gen (MW) Unit Unit Unit Unit Load (MW) 590 Reserve Requirement (MW) 25 LBMP ($/MWh $45 Reserve Clearing Price ($/MW) $12 In the DAM, Unit 3 sets the energy $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 = 12.

57 Reserve Settlement Scenario 1 The following scenario illustrates the Day-Ahead Market and Real-time Market settlements when an additional generator (#5) self-commits-flexible in realtime. 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?

58 RT Reserve Settlement Scenario 1 RT Base Case Fully Disp Fully Disp Econ Min Min Gen Incremental Energy (MW) Maximum Capacity (MW) Spinning Reserve (MW) Incremental RT Spinning Energy Offer Reserve Price Availability ($/MW) Offer ($/MW) Energy Schedule (MW) Reserve Schedule (MW) Min Gen (MW) Unit Unit Unit Unit Unit Load (MW) 590 Reserve Requirement (MW) 25 LBMP ($/MWh $45 Reserve Clearing Price ($/MW) $0 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 ( =0).

59 Reserve RT Scenario 1 $45 (RT LBMP) X 5 MW $35 (offer) X 5MW $45(RT LBMP) X 55 MW Net Energy Schedule (MW) Net Reserve Schedule (MW) RT Energy Payment ($) RT Reserve Payment ($) Additional Cost ($) Profit ($) Unit $ - $ - $ - $ - Unit $ 225 $ - $ 175 $ 50 Unit $ (2,475) $ - $ (2,475) $ - Unit $ - $ - $ - $ - Unit $ 2,250 $ - $ - $ 2, $ - $ - Load 0 0 $ - $ - $45 (RT LBMP) X 50 MW 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.

60 Reserve Settlement Scenario 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?

61 Reserve Day-Ahead Example The table below shows the day-ahead schedules for energy and reserves upon which three scenarios are based. Day-Ahead Position Fully Disp Held back for Res Econ Min Gen 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) Min Gen (MW) Unit Unit Unit Unit Load (MW) 590 Reserve Requirement (MW) 25 LBMP ($/MWh $45 Reserve Clearing Price ($/MW) $12 In the DAM, Unit 3 sets the energy $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 = 12.

62 Reserve RT Higher Load Scenario 2 RT Higher Load Fully Disp Fully Disp Held back for Res Held back for Res Econ Disp Incremental Energy (MW) Maximum Capacity (MW) Spinning Reserve (MW) Incremental Energy Offer Price ($/MW) RT Spinning Reserve Availability Offer ($/MW) Energy Schedule (MW) 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 = 20. Reserve Schedule (MW) Min Gen (MW) Unit Unit Unit Unit Unit Load (MW) 950 Reserve Requirement (MW) 25 LBMP ($/MWh $65 Reserve Clearing Price ($/MW) $20

63 Reserve RT Higher Load $65 (RT LBMP)X 5 MW RT High Load Settlement Scenario 2 Net Energy Schedule (MW) Net Reserve Schedule (MW) RT Energy Payment ($) RT Reserve Payment ($) Additional Cost ($) Profit ($) Unit $ - $ - $ - $ - Unit $ 325 $ (100) $ 175 $ 50 Unit $ 3,250 $ (100) $ 2,250 $ 900 Unit $ 9,100 $ - $ 7,700 $ 1,400 Unit $ 10,725 $ 200 $ 7,475 $ 3, $ 23,400 $ - $ 17,600 $ 5,800 Load $ 23,400 $ - $20 (RT RCP) X 5 MW $35 (offer) X 5 MW 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

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65 Average Clearing Prices for 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)

66 Performance Tracking for Removed under 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% SMD2

67 Failure to Provide Operating Reserve Removed under SMD2 ACT GEN MW Upper Operating Limit SCD Shortfall Penalty = (SCD - Act Gen) * LBMP Lower Operating Limit 0 Off-Line

68 NYISO Response to Failure to Removed under SMD2 Perform Penalties No payment for the shortfall in energy Charged for the shortfall in energy provided, at real-time LBMP Reductions 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

69 Reserve Shortage (Scarcity) Removed under SMD2 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

70 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 $ 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

71 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.

72 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

73 Reserve Price ($) Demand Curve for Reserves- Normal (curve is for demonstration purposes only) 1,000 Demand Supply Reserve Quantity (MW)

74 Reserve Price ($) Demand Curve for Reserves- Short of 30-Minute (curve is for demonstration purposes only) 1,000 Demand Reserve Quantity (MW) Supply

75 Reserve Price ($) Demand Curve for Reserves- Short of 10-Minute (curve is for demonstration purposes only) 1,000 Demand Supply Reserve Quantity (MW)

76 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

77 Reserve Demand Curve Values ($/MW) With reserve shortages these values establish reserve clearing prices and are added to the LBMP of energy. NYCA EAST LI 10 Min Spin 10 Min Total 30 Min Total 500* 150* $ $ * * *Higher values reflect reserve requirements that must be maintained per reliability rules.

78 Additive Impact on LBMP Demand Curve values are cascading - the value for each constraint violated is added to the LBMP NYCA EAST LI 10 Min Spin 10 Min Total NYCA 500* 150* EAST * LI Min Spin 10 Min Total $850 $350 $1,400 $875 $1,750 $1, Min Total $ $ * 30 Min Total $200 $225 $525

79 Reserve Demand Curve Activation LBMP = Energy bid of last MW converted to energy + (plus) Applicable Demand Curve Values $649 Unit 1 dispatched to meet next MW of load: Sets LBMP. $649 $150 Unit 2 held for reserves but must be dispatched to meet load. $150 Unit 1 Unit 2 With reserve shortage DC is activated and applied. Unit 1 Unit 2 Post-shortage RTD Pre-shortage RTD LBMP = $649 RCP = $499 ($649 - $150) LBMP = $650 ($150 + $500) RCP = $500 (Demand Curve)

80 Operating Reserve Charges LSE s Transmission customers exporting energy Charges 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

81 Ancillary Services Regulation (Rate Schedule 3)

82 Regulation & Frequency Response Balancing Generation with everchanging electric load Generator response to six second signals produced by the NYISO

83 The Need for Regulation & Frequency Response Service Assist in maintaining scheduled frequency at 60 Hz Compliance with NYSRC, NERC, and NPCC Reliability Requirements DNI & Gen Load

84 Control Signals to Satellite Control Centers (TOs) AGC control errors every 6 seconds for units providing Regulation TO Control Center NYISO TO Control Center TO Control Center RTD (SCD) Dispatch basepoint signals nominally every 5 minutes signal for each unit from RTD (SCD) ramped at 6 sec. intervals

85 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

86 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.

87 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

88 Generating Unit Operating Characteristics Regulation Capacity MW Upper Operating Limit RTD Base Point Range AGC Desired Generation RTD Base Point Signal (5 minutes) Regulation Capacity Lower Operating Limit = Minimum Generation Point 0 Off-Line

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91 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.

92 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.

93 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

94 Regulation Revenue Adjustment Payment/Charge Regulating units settle energy in realtime at the lesser of their actual output or AGC basepoint

95 Average Clearing Prices for Regulation 2003 (Through Sept., 2004) Regulation (DAM) $28.32 ($19.92)

96 Regulation Revenue Adjustment Payment/Charge 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

97 Regulation Performance Actual MW Upper Operating Limit Regulation Bandwidth Unit Control Error { Actual Generation Max. AGC Basepoint Present AGC Basepoint Min. AGC Basepoint RTD Lower Operating Limit KEY RTD = Real-Time Dispatch 0 Off-Line MCP = Market Clearing Price for Regulation

98 Incentive Based Regulation Service Availability Payment based on Performance Index (PI) PIreg= [(Reg Capacity-AAUCE) / (Reg. Capacity)] 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

99 REGULATION AVAILABILITY EXERCISE 1. 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?

100 Regulation Demand Curve There are no locational requirements for regulation Price of regulation set by curve when shortages occur and will impact LBMP Regulation NYCA 25 and $300/MW

101 Charges for Regulation Service 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)

102 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

103 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.

104 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

105 Ancillary Services Lesson 3 1/2 Energy Imbalance (Rate Schedule 4)

106 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

107 Energy Imbalance Internal Energy Imbalance addressed through real-time market and real-time settlements deviations between what was scheduled Dayahead and the Real time actual withdrawals (loads) and injections (generators) includes deviations from bilateral transaction schedules

108 Forward Contract for Generation Vs. Real Time Dispatch Forward Contracts RTD Calls for More RTD Calls for Less 500 MW 350 MW Forward Contract 400 MW Gen Paid for 350 Mw at fwd cont $ RTD Basepoints plus Day-ahead LBMP Gen Paid for 350 Mw at fwd cont $ minus 300 RTD Basepoints MW Day-ahead LBMP

109 Forward Contract for Covering Load Vs. Real Time Load Fwd Contract for 60 Mw 70 Mw Actual Load Exceeds Fwd Contract: Load Pays for 60 Mw at fwd cont $ Plus10 Actual Load Less than Fwd Contract: Load Pays for 60 Mw at fwd cont $ minus10 50 Mw

110 Internal Energy Imbalance Services Transmission Customers taking service under ISO OATT ONLY If actual energy withdrawal exceeds scheduled delivery additional 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.

111 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

112 Who Pays for Services? Ancillary Service Regulation & Frequency Response Operating Reserve Black Start Voltage Support Scheduling, System Control & Dispatch Energy Imbalance Internal Loads Exports Wheel Throughs

113 Ancillary Service Charges Ancillary Service Sched.,Sys Control & Dispatch Voltage Support Regulation Energy Imbalance Operating Reserve Black Start Cost $0.73/MWH (Embedded) ~$1.22/MW* ($1.46) (Uplift/Residuals) $0.36/MWH ~$0.34/MWH* ($0.20) ~$0.28/MWH* ($0.13) ~$0.001/MWH *Average for 2003 (Through Sept., 2004)