Competitive Wholesale Power Market New York Independent System Operator

History – New York Power Pool1965 Blackout New York Power Pool – Utilities dedicated to the reliability of the NY system

Facilitate communicationManage flow of electricity between utilities and surrounding control area

1970 Control CenterMinimum reserve marginsSufficient supply to meet demand

Federal Action – Evolution to MarketsPURPA – 1978 – Non-Utility Generators own generation, utilities must buy at avoided cost. Over 2000 MW’s developed in NYEPACT – 1992 – created competitive wholesale markets

Cross utility salesCross control area salesDelineated Federal and State authorities

Order 888 – 1996Open access to the transmission systemNondiscriminatory transmission service rate schedulesOpen Access Same-time Information System

Transmission capacityPrices

Federal Action – FERCOrder 2000 – Codifying the Northeast

Regional Transmission Organizations (RTO)Congestion managementMarket monitoringSystem planningIndependence from market participants

Standard Market Design (2002) (note - FERC abandoned this effort)RTO’s – all regions, “appropriate” size, operational authority for the gridRegional Planning – reliability and economicsEliminate rate pancaking between regionsMarket Monitor and mitigationFirm Transmission RightsReal Time Spot MarketsResource Adequacy

Competitive Wholesale MarketsSince 1998 competitive wholesale markets have expanded through out the United States. Over 60% of the U.S. population and 50% of the electricity demand are served in competitive markets.

New York ActionRegulatory Restructuring – FlexibilityDivesture of utility generation assets to eliminate vertical market power concernsCreation of the New York ISO Mid 1999 Resolution of Grandfathered Transmission Rights (TCC’s)

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New York State: 19,157,532 peoplePeak Load Forecast of 33,295 MW

38, 340 MW Native Generation

Over 335 generating units modeledRequired Installed Capacity 39,288 MW

The NYISO Control Area

1700 MW in Demand Response

10,775 miles of High Voltage Transmission

2006 Capacity by Fuel Type

17%

9%

35%

9%

15%

13%

1%

1%

Gas 6508

Oil 3659

Gas & Oil 13831

Coal 3505

Hydro 5700

Nuclear 5169

Other 341

Wind 245

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230 kV and above Transmission

Legend:

KintighNiagara

Oswego

Oakdale Fraser

Marcy

Massena

MosesChateauguay

Plattsburgh

Gilboa Leeds

NewScotland

Clay

Lafayette

Watercure

Stolle Rd.Edic

Porter Rotterdam

PleasantValley

CoopersCorners

RockTavern

Roseton

Bowline

Ramapo SprainbrookDunwoodie765 kV

345 kV230 kV Farragut

Goethals

Complex

Homer City

Shore Rd.E.Garden City

Dunkirk

Pannell

Sta.80

New York Independent System Operator

Central East Interface

Total East Interface

Upstate NY –Southeast NY (UPNY-SENY) Interface

Cable Interface

New York ISONew York ISONew York ISO"Hub of the Northeast"

* = Peak Load in Megawatts

IMO23,857 MW*

Hydro Quebec19,410 MW* ISO -

New England25,158 MW*

New York ISO31,983 MW*

PJM54,176 MW*

Area Covered by Northeast

Major Cities covered would include:• Montreal• Ottawa• Toronto• Augusta• Portland• Montpelier• Concord• Boston• Providence• Hartford• Albany• Syracuse• Buffalo• New York City• Philadelphia• Harrisburg• Baltimore• Washington, DC

• Serves a combined load on the order of 155,000 MW

• Involves over 50,000 miles of transmission lines

• Serve a population on the order of 70,000,000 people

• Includes a combined customer load greater than the entire Western Interconnection

• Includes major world political, financial and cultural centers

2400 MW

2500 MW

1000 MW

1500 MW

1600

MW

1500 MW

350 MW

- Washington D.C.

- New York City

- Ottawa

New York Market91% Merchant Generation

Regulated and Merchant Transmission

Regulated Monopoly Distribution

Competitive Retail Sales

New York Wholesale Markets Energy - Day-Ahead and Real Time MarketsInstalled Capacity MarketAncillary Services Markets

Market based:Reserves (10 min spinning, 10 min non-spin and 30 minute reserves)Regulation

Cost based:Voltage SupportBlackstartScheduling

Demand ResponseVirtual MarketsTransmission Congestion Contracts

Bilateral(forward)Contracts

50%

RealTime<5%

NYISODay-Ahead

Market45 – 50%

Bilateral Contracts outside the NYISO 50%NYISO Day-Ahead Market 45 - 50%NYISO Real-Time Market <5%

100%

New York Wholesale Markets- EnergyCentral Dispatch System

Energy MarketsLocational-Based Marginal Pricing

LBMP is the incremental or marginal cost to supply load at a specific location in the gridLocational energy price differentials represent the opportunity cost for transmission, between specific locations in the gridSystem is bid-based; bids are confidential; market clearing prices are published Generators are paid the LBMP at their bus; loads pay on a zonal basis; zonal LBMP is the load weighted average of the LBMPs of the generators in the zone

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Energy MarketsTwo settlement scheduling system

First settlement - Day-Ahead scheduleschedules for load and generation day-ahead are based on day-ahead forecasts and bids; bids have to be in by 5 am for 24 hrs the next day; results are posted by NYISO by11amscheduled load and generation become forward sales and purchase contracts; with financial obligations to provide or consume actual energy

Second settlement - Real-Time Dispatchdispatched by NYISO to meet actual requirmentsreal time LBMP is determined from the actual dispatch based on bidsgenerators that operate as scheduled are paid consistent with their forward contracts; loads that consume as scheduled make payments consistent with their forward contractsany deviations by generators or loads from their day-ahead schedules are settled at Real-Time LBMP.

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Energy Markets

Security Constrained Unit Commitmentselects most economic mix of generation and transaction resources to meet the scheduled requirements - based on bidsSCUC commits generation and produces DAM schedules for the cooptimization of energy, reserves and regulationrecognizes transmission and several other constraintsestablishes day-ahead forward contracts for generation, load and transactionspublishes 24 hourly dispatch prices and schedules

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Energy Markets

Real Time markets consist of Real Time Commitment (RTC) and RealTime Dispatch (RTD)RTC is the real-time analysis that results in economic schedules of generators for each hour of the day. Every fifteen minutes, RTC studies ten future points in time, separated by 15 minute intervals and produces schedules for each 15-minute interval, for possible commitment of 10 minute and 30 minute start up unitsRTD is a multi-period security constrained dispatch model that co-optimizes to solve simultaneously for Load, Operating Reserves, and Regulation Service on a least-as-bid production cost basis over a fifty, fifty-five or sixty-minute period (depending on when each RTD run occurs within an hour); RTD executes nominally every 5 minutes

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Installed Capacity MarketReliability rules require utilities and other load serving entities to purchase capacity to meet forecast peak load plus 18% reserve marginICAP revenues to generators contribute towards the recovery of fixed cost of units; they provide more predictable revenue streamThree Capacity Markets in NY

New York CityLong IslandRest Of State

Six month strip auctions, monthly auctions and spot auctions are conducted by the NYISO

Original ICAP Market DesignLoads must purchase Minimum RequirementDeficiencies charged a high penaltyMarket proved dysfunctional

Erratic ICAP pricesWhen capacity is tight, ICAP prices spikeWhen capacity levels exceed the minimum requirement, however, ICAP prices plungeLoads had no incentive to purchase ICAP above minimumExcess capacity beyond minimum not valued although it may help reliability

Susceptible to market power abuseSuppliers had incentive to withhold to create deficiency

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ICAP Demand Curve

Original design used “vertical” demand curveFixed minimum requirementFixed deficiency charge

New design uses “sloped” demand curvePrice decreases gradually as supply increasesLoads buy excess supply cleared in the auction

Market function improvedPrices less erraticPrices vary predictably with ICAP supply

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Demand Curve

IC A P D e fic ie n c y C h a rg e v s . D e m a n d C u rv e

0

5

1 0

1 5

2 0

2 5

9 6 9 8 1 0 0 1 0 2 1 0 4 1 0 6 1 0 8 1 1 0 1 1 2

% o f M in im u m R e q u ire m e n t

$ pe

r kW

-mon

th

D e fic ie n c yC h a rg e

D e m a n dC u rve

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Ancillary Services Market

Regulationcontinuous balancing of resources with load within NYCAassist in maintaining scheduled frequency at 60Hzregulation service bid into market by individual units that have AGC capability; payments to suppliers; loads to paygenerators not obligated to participate

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Ancillary Services Market

Operating Reservesbackup generation available in the event of loss of any major generating unit, loss of transmission10 min spinning reserve: >=50% of single largest system contingency total 10 min reserve (spin and non synch):>=100% of single largest system contingencytotal operating reserve: sum of 10 min +30 min reserve:150% of single largest capacity contingency available in 30 minutes or lessreserve requirements are locational: west of total east, east of total east and LIIn Real time, “Reserve Demand Curves” are applied during scarcity conditions and determine the reserve clearing prices and impact LBMPs

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Ancillary Services Market

Voltage SupportReactive Power Resources in the New York Control Area which must be operated to maintain voltages within acceptable limitsProper Voltage Support is a prerequisite for delivery of electrical energy through the transmission grid and is dynamic.Current Annual Rate: $3,919/ MVArRate is a FERC approved cost based rate

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Ancillary Services MarketBlackstart Service

Generators capable of starting without an outside electric supply, following a system-wide blackoutAvailable to participate in system restoration

NYISO Manages Black Start Capabilityidentifies generating units in critical areas for NY bulk power system restorationhas flexibility to seek new resourcesdevelops and periodically reviews Black Start Restoration Plan

Payments made to Generators that are included in Restoration Plan covering embedded capital costs of equipment, O& M expenses, and TrainingLSEs pay monthly black start charge

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Virtual Markets

Virtual Bidding is the submission of bids for the financial purchase or sale of energy, rather than the physical delivery or purchase of energy in the NYISO-administered energy markets. Virtual Bidding enables qualified NYISO Customers to:

buy energy (Virtual Load) in the Day-Ahead Market (DAM) at day-ahead prices and sell it in the Real-Time (RT) Market at real-time prices and;sell energy (Virtual Supply) in the DAM at day-ahead prices and buy energy to cover the sale in the RT market at real-time prices.

Virtual Load and Virtual Supply transactions are financial transactions only and have no effect on real time physical energy consumption

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Transmission Congestion Contracts

A TCC is a financial contract which hedges congestion prices between locations in the gridTCCs normally purchased via NYISO auction or through “grandfathered” provisionOnly applies to the day ahead marketFacilitates bilateral transactionsAllows the holder to collect the congestion rent associated with transmitting energy

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NYISO’s Demand Response Programs

NYISO’s Demand Response Programs are aimed at wholesale electricity Market Participants, Aggregators and NYISO Direct CustomersTwo Reliability Programs – Controlled by NYISO

Emergency Demand Response ProgramICAP Special Case Resources Program

One Economic Program – Controlled by CustomerDay-Ahead Demand Response Program

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Demand Response

Wholesale Competition: Role of Demand Side Response(MW Enrollment as of May, 2006)

1,090

570

386

-

200

400

600

800

1,000

1,200

Demand Side Response Program

MW

Special Case Resources Emergency Demand Response Day Ahead Demand Response Program

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DR:Who Can Participate?

Interruptible load can participate in:The Emergency Demand Response (EDRP) programICAP Special Case Resources (SCR) programThe Day-Ahead Demand Response (DADRP) program

Standby generators can participate in:The EDRP programThe SCR program

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Emergency Demand Response ProgramReliability Program Minimum Resource Size: 100 kW, may aggregate within Zones to reach thresholdActivated in Response to forecast or actual Operating Reserve Deficiency Payment for Energy (kWh) ReductionProvider notified of activation 2 hours ahead, if possible

Paid the greater of real-time marginal price or $500/MWh & guaranteed 4 hour minimumMay set real-time market price at $500

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The Emergency Demand Response Program (cont’d)

Available to curtailable load & emergency backup generation (including generation in excess of host load)Open to Load Serving Entities (LSEs), Direct Customers, and Aggregators (Curtailment Service Providers - CSPs) Activated after ICAP SCR resources if deemed necessary by OperationsVoluntary Response – No Penalties for Non-PerformanceCredit Requirements: NoneFee to become CSP: None

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The ICAP Special Case Resources Program

Reliability ProgramMinimum Resource Size: 100 kW, may aggregate within Zones to reach thresholdActivated in response to a forecast or actual Operating Reserve DeficiencyPayment for Capacity (kW) Reduction plus Payment for Energy (kWh)Provider advised with day-ahead advisory and a 2-hour in-day notification

Paid for energy reduction: real-time market price or Strike Price (maximum $500/MWh), whichever is greater & guaranteed 4 hour minimumMay set real time market price under scarcity pricing rules

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The ICAP Special Case Resources Program (cont’d)

Available to curtailable load & emergency backup generation (including generation in excess of host load)Open to Load Serving Entities (LSEs), Direct Customers, and Aggregators (Responsible Interface Providers – RIPs)Activated prior to Emergency Demand Response resourcesMandatory Response – Subject to penalties and derated for non-complianceCredit Requirements: NoneFee to become RIP: None

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ICAP/SCR Penalties

Deficiency Penalty: Retroactive penalty assessed if customer unable to verify contracted demand reduction during contract period

Contracted demand reduction during any single hour of an event or verification audit nullifies any exposure to a “Deficiency Penalty”

Derating: Performance over previous Capability Periods is used to calculate UCAP value. Less than full performance limits amount of capacity that can be sold in future capability periods.

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Day-Ahead Demand Response Program

Economic ProgramMinimum Resource Size: 1 MW, may aggregate within ZonesLoad Bids curtailment in Day-Ahead Market just like a generator - if chosen, can set marginal price. $75/MWh minimum bid.Payment for Energy (kWh) ReductionParties submitting accepted bids get:

Notified by 11:00 a.m. schedule commitment for the next day (midnight-midnight) incentive credit (fixed load bid reduced by amount of curtailment provided)paid greater of marginal price or bid for actual interruption

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Day-Ahead Demand Response Program (cont’d)

Available to interruptible load only (generation excluded)Open to Load Serving Entities (LSEs), Direct Customers, and Aggregators (Demand Reduction Providers – DRPs)Activated prior to Emergency Demand Response resourcesMandatory Response – Penalties Assessed for Non-Compliance

penalized for buy-through at Day-Ahead or Real-Time marginal price, whichever is greater

Credit Requirements: Relaxed from Generator LevelsFee to become DRP: None

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Metering RequirementsHourly interval billing meters requiredReduced accuracy metering (2% or better) allowed –takes advantage of Energy Management System opportunities Small customer aggregation program allows other validation methods (e.g., statistical sampling)NYISO uses an automated notification system to communicate emergency/reliability event notifications to program participants

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Small Customer Aggregation

Small Customer Aggregation (SCA) Currently Applies to EDRP, SCR, and DADRP Allows Participation without Interval MetersProposed Generic Rules Guide Specific ProposalsMinimum Aggregation is Program-Specific

DADRP – 1 MW/ZoneSCR/EDRP – 100 kW/Zone

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EDRP & SCR Growth

0200400600800

100012001400160018002000

Dat

e5/

23/2

001

6/7/

2001

7/5/

2001

7/26

/200

18/

20/2

001

9/6/

2001

12/1

8/20

015/

1/20

026/

6/20

026/

24/2

002

7/1/

2002

8/1/

2002

9/12

/200

26/

25/2

003

8/5/

2003

10/1

4/20

032/

6/20

042/

26/2

004

3/29

/200

45/

4/20

046/

24/2

004

7/15

/200

48/

15/2

004

9/15

/200

410

/26/

2004

11/9

/200

412

/7/2

004

1/18

/200

52/

9/20

058/

1/20

0510

/18/

2005

12/1

2/20

052/

6/20

064/

18/2

006

Date

MW

Reg

iste

re

0

500

1000

1500

2000

2500

3000

# C

usto

mer

MW Registered # Customers # Customers (Disaggregated)

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Resource PlanningISO Reliability Planning Process

Pre restructuring, vertically integrated utilities built (or contracted for) needed resources to ensure reliability of the system In a restructured market, it is envisioned the market will addressresource needs to ensure reliabilityPlanning process is primarily designed to provide information to the market participantsWhile market may still address resource needs, there could be instances of “market failure” and the market may not satisfy theresource needsIn that case, there is a need for a back-stop solution to procure adequate resources to ensure reliability

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Resource Planning

Comprehensive Reliability PlanProvides for market response (transmission, generation, demand response)NYISO certifies projects that would technically meet the identified need without identifying a preferred solutionProvides for regulated “backstop” process with TO obligations and optional developer participationCost Allocation based on beneficiaries-pay methodology

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Resource PlanningAllows Transmission, Generation and Demand Response Alternatives to Compete

Areas of system where transmission and generation are substitutesMaturing demand response market mechanisms should be allowed to compete

Preferred by DPS Because:Market process making the choice minimizes market disruptionLikely to produce solution with least customer impact

44

Resource Planning

“Economic” Planning process:Primarily intended to address congestionNYISO posts information on a historical basis on several quantitative metrics of congestion - to assist the market placeUnder what conditions should regulatory solutions be considered to alleviate congestion? Work in progress

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NYISO GovernanceOrganizational Independence

Role of Board of Directors (ten including NYISO CEO)

Market Participant RoleFive major sectors

Generation, End-use customers, Other Suppliers, Public Power and Environmental, Utilities

Balance of interests58% market participant vote needed to pass changes

FERC filings 205 vs 206

NYPSC RoleNYISO Board ObserverAdvisory RoleReliability RoleMarket MonitoringParticipate in the deliberations of working groups on various issues

Market PerformanceNew Entry

Generation has been proposed and completed in load areas where electric energy and capacity prices indicate a need for additional supply.More than 4,700 MW of new, efficient generating capacity has been put into service while slightly more than 600 MW has been retired, since the NYISO's markets opened. Some of the new capacity is "merchant" generation and some is facilitated by NYPA/LIPA or IOUs:

In contrast, the following amounts have been added in the following prior periods:Period Addition (MW)1985-1990 2,0041991-1995 4,7941996-2000 3032000-2005 4,200

Financing, Siting and Interconnection issues

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Market Performance

Competitive forces have resulted in New York's power plants being available on peak 90.3 percent of the time during the summer months versus 86.5 percent prior to NYISO operationThe duration of nuclear unit maintenance outages has been greatly reduced while their reliability has improved since the inception of NYISO market operations. Average capacity factor for nuclear units has increased from approximately 60 percent prior to 2000 to approximately 90 percent currently.

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