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New York, New England and PJM New York, New England and PJM Electricity Markets OverviewElectricity Markets Overview

Prepared for:Prepared for:

Regional Regional Greenhouse Gas Greenhouse Gas Initiative Initiative WorkshopWorkshopNovember 30, 2004November 30, 2004

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Goals of This Presentation Goals of This Presentation

Provide an overview of the various wholesale electricity market elements that relate to RGGI design issues

Identify reliability requirements and operational issues pertinent to the RGGI process

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* = Peak Load in Megawatts

IMO25,414 MW*

Hydro Quebec35,137 MW*

ISO - New England25,348 MW*

NYISO30,983 MW*

PJM / PJM West107,820 MW*

1325 MW1325 MW

1500 MW1500 MW

1500 MW1500 MW1000 MW1000 MW

1050 MW1050 MW

975 MW975 MW

2375 MW2375 MW

2625 MW2625 MW

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New York State

(230 kV and above)

Legend:

Niagara

Oswego

Oakdale

Fraser

Marcy

Massena

Moses

Chateauguay

Plattsburgh

GilboaAlps

Clay

Lafayette

Watercure

Stolle Rd.

EdicPorter

Rotterdam

PleasantValley

Coopers Corners

Rock Tavern

Roseton

Buchanan

RamapoSprainbrook

Dunwoodie

765 kV

345 kV230 kV Goethals

Complex

Homer City

Shore Rd.E.Garden City

Huntley

Pannell

Sta.80

Transmission System

Somerset

500 kV

Adirondack

Dunkirk

Meyer

Willis

NewScotland

Leeds

Hillside

Millwood

Farragut

W49St/Rainey

New York’s Electrical SystemNew York’s Electrical System

10,775 miles of High Voltage Transmission

360+ individual generating units.

Installed Capacity 35,000+ MW

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PJM - Backbone Transmission Systems ( with expansions)

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New England’s Electric Power New England’s Electric Power SystemSystem 350+ Generators 8,000+ miles of

transmission lines 4 Satellite Control

Centers Peak load: 25,348 MW

on August 14, 2002 Capacity – 31,000 MW

ISO

an

d S

ate

llite

Fac

iliti

es

320 mi.520 km

400 mi.650 km

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New York’s Energy Supply Mix - 2003New York’s Energy Supply Mix - 2003

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53% 9%

34%2% 2%

Coal Gas Nuclear Oil Renewables

PJM’s Energy Supply Mix - 2003PJM’s Energy Supply Mix - 2003

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Comparison of NE, NY, & PJM Comparison of NE, NY, & PJM Electric Power SystemElectric Power System

ISO-NE PJM NYISO

Peak Demand 25,348 MW 107,820 MW 30,983 MW

Generation Capacity 31,000 MW 134,250 MW 36,500

High Voltage Transmission Lines 8,000 + miles 49,300 miles 11,000 miles

Population 14 million 44 million + 19 million+

Locational Marginal Pricing YES YES YES

Financial Transmission Rights YES YES YES

Responsibility for System Planning

YES YES YES

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Market Overview Market Overview

Two Settlement System Day-Ahead Market Real-Time Market

Locational Marginal Pricing Nodal congestion management pricing system Includes marginal losses Locational pricing for Energy and Reserves

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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%

Buying Power in New YorkBuying Power in New York

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NYISO Market Overview NYISO Market Overview Bid- and Offer-Based Markets

Co-optimized Energy, Regulation and Reserves Multi-part supplier offers Load bids, including firm and price-sensitive

components Hourly variation in offers Voluntary – bilaterals & self-supply

accommodated

Other Markets Installed Capacity Transmission Congestion Contracts

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Generation BidsGeneration Bids

Generator Modes Minimum Run Time & Minimum Down Time Maximum Stops per - Day Start-up Notification Time Curve Start-up Cost Curve Minimum Generation $ Incremental Operating $ Operating Limits

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Day-Ahead Energy MarketDay-Ahead Energy Market

Security Constrained Unit Commitment (SCUC) scheduling software simultaneously co-optimizes energyand ancillary services for least cost solution

Hourly Locational Marginal Prices (LMP)

Issues binding forward contracts to Suppliers and Loads

Bilateral transaction scheduling accommodated concurrently with supply and load bids

Deviations settled against Real-Time Market

Installed capacity suppliers required to bid in

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LMP ExampleLMP Example

Generator MW LBMP Paid A 80 $35 $2800 B 100 $35 $3500 C 50 $75 $3750 D 50 $75 $3750 $13800

Load MW LBMP Pays RED 30 $35 $1050 BLUE 250 $75 $18750

$19800

= $6000 paid to congestion contract holders= $6000 paid to congestion contract holders

B

A C

D

30 MW

100 MW @ $35

100 MW @ $25

100 MW @ $75

50 MW @ $30

250 MW

REDBLUE

150 MW limit

LMP = $35 LMP = $75

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Day-AheadMarket

(15-minuteProcess)

Gen

Real-TimeMarket

SCUC

ForwardContracts

RTC

RTD

Bids by 5 a.m.Day before

Schedules

ActualConditions

Bids by 75 minbefore hour

SCUC = Security Constrained Unit CommitmentRTC = Real-Time CommitmentRTD = Real-Time Dispatch

BasepointsSupplemental

ResourceEvaluation

New York's Two-Settlement ProcessNew York's Two-Settlement Process

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Bid Production Cost Guarantee (BPCG)

Bid “Costs”...• Start• Min Gen• Energy•less penalties

LMP

Generator Offer

Must be retrievedthrough...

… or gen’s made whole

All based on entire day!

^

6 2312HB: 8

$25

$40

$20

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Ancillary Service MarketsAncillary Service Markets

Market-Based ServicesRegulation10-Minute Spinning ReserveTotal 10-Minute Reserve30-Minute Reserve

Cost-Based ServicesScheduling, Control and DispatchVoltage SupportBlack Start

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Operating ReserveOperating 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

Locational Requirements: Long Island East of Central East Entire Control Area

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≧600 MW min 600 MW

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

1200 MW

SINGLE LARGEST CONTINGENCY 1,200 MW

RESERVE REQUIREMENT: 1,800MW

10 MIN SYNC

10 MINUTETOTAL

1,200 MW

30 MIN

10 MIN NON-SYNC

NYISO Operating Reserve Requirements

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Regulation ServiceRegulation Service

Necessary for continuous balancing of load and generation – maintain 60 Hz frequency

Performed on a 6-second basis through automatic generation control (AGC)

North American Electric Reliability Council (NERC) reliability requirement – tracked via CPS2 index

Full two-settlement for regulation Regulation service will be scheduled and settled,

nominally on a 5-minute basis Single, statewide price

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Long Term Capacity MarketsLong Term Capacity Markets

Installed Capacity (ICAP) Requirements are set in advance for the upcoming Capability Year by the New York State Reliability Council.

Load-serving entities (LSEs) meet their ICAP requirements by: Self-Supply

Bilateral Transactions with Suppliers

Capability Period Auctions (6-month strip)

Monthly Auctions (for balance of Capability Period)

Deficiency/Spot Market Auction (1-month)

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Clarifying Questions?Clarifying Questions?

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NYISO Services

NYISO ClearingAccount

BilateralContractors

Load ServingEntities

Power SuppliersTransmission

OwnersTCC Holders

Auction Payments

Rent

CongestionAdjustment

NTACAuction Revenues

Ancillary ServicesTUC (Congestion)

TUC (Losses)ICAPDeficiency

LossAdjustment

NTAC, Energy,Ancillary Services

Penalties

AncillaryServices,Energy

ICAP & BilateralsNYCA Internal Bilaterals,

Transmission Service Charge

Exports & WheelsTSC

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Market Monitoring and Market Monitoring and Performance Performance

Daily Monitoring Mitigation (Economic

Withholding) Reference prices Mitigation reporting ICAP bidding compliance Daily market analysis/reports Price validation Physical withholding screening Load bidding

Economic and Long Range Analysis Tool development/maintenance and daily

processing (e.g. SCUC, PROBE) Special reports (FERC, PSC, NYISO, etc) Transactions Monitoring VT monitoring Portfolio analysis/tracking Price validation audit Weekly Report ICAP auction monitoring TCC auction monitoring Market design/requirements Performance tracking

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Market Experience - Market Experience - Sample DaySample Day

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New York Electricity Market ExpensesJune to August, 2001 to 2004

0

100

200

300

400

500

600

700

800

900

June July August June July August June July August June July August

2001 2002 2003 2004

$ in

Mil

lion

s

Ancillary Services & OtherUpliftCongestionMarginal LossesEnergy Expenses

Source: Summer 2004 Review of the New York Electricity Markets – David B. Patton, Ph.D., Independent Market AdvisorSource: Summer 2004 Review of the New York Electricity Markets – David B. Patton, Ph.D., Independent Market Advisor

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Current Key Issues - Regional Market InitiativesCurrent Key Issues - Regional Market Initiatives

Energy Markets

Elimination of pancaked through and out charges throughout the Northeast region

Improve the efficiency of inter-market energy trading – Coordinate energy dispatches between ISOs and move toward single area LMP dispatch efficiency and financial versus physical transactions (VRD-like concept)

Reduce risks for inter-market energy trading – Cross-border congestion hedges

Establish greater consistency of bidding protocols – Single point regional transaction entry

Coordination and compatibility of billing and settlements for regional trading

Capacity Markets Regional ICAP trading improvements - greater market rules compatibility

Renewable resource valuation methods

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RGGI Reliability ConsiderationsRGGI Reliability Considerations

Supplemental commitments are often required to meet NOx requirements in NYC

Certain units on 115, 138 and 230 kV networks provide voltage support on underlying network (Western NY, Long Island)

11 of 66 Transmission Owner Applications of New York State Reliability Council Reliability Rules directly address the need for specific thermal units to meet reactive power support and local power system requirements

Dual-fuel units (gas/oil) are important during peak winter demand periods

Operating range flexibility is important

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Note: August 2003 blackout hours excluded.

0

100

200

300

400

500

600

700

800

Ave

rage

Cap

acit

y C

omm

itte

d (

MW

)

2001 2002 2003 2004 2001 2002 2003 2004 2001 2002 2003 2004

New York City Long Island Up-State New York

Supplemental Resource Evaluation CommitmentSummer 2001 to 2004

Average Capacity Committed

Average Output Quantity

Source: Summer 2004 Review of the New York Electricity Markets – David B. Patton, Ph.D., Independent Market AdvisorSource: Summer 2004 Review of the New York Electricity Markets – David B. Patton, Ph.D., Independent Market Advisor

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Wind Power Reliability ConsiderationsWind Power Reliability Considerations

Operational Issues: Reactive power

demands increase with increasing MW output (acts as an induction generator)

Dynamic response to power system faults

Potential regulation impact

Mitigation Strategies: Voltage regulation at the

Point-of-Interconnection, with a guaranteed power factor range.

Low voltage ride-through.

A specified level of monitoring, metering, and event recording.

Power curtailment capability.

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Current Market Rules for IntermittentsIn New York, intermittents existing as of 11/19/1999 and 500 MW of new

resources are: paid for all energy produced regardless of their Day-Ahead schedule (Imbalance

Charges) excused from paying penalties for generating at less than their basepoints

(Under-Generation Penalties)

Wind and solar resources are paid for their capacity in a valuation based on historic capacity factors, adjusted for maintenance

Rule Changes Contemplated: Adjust the manner in which intermittents are balanced against their Day-Ahead

Schedules, Including Real-Time Payments for Delivered Energy

Adjust the Method Used to Measure the Capacity Value of All Generation Including correlation of resource availability with system peak hours

Adjust the exemption from Regulation Penalties

How will the 500 MW “Exemptions” be applied?

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RGGI Design and Electricity Market RGGI Design and Electricity Market IntersectionIntersection

Allocation of allowances If allowances must be purchased by suppliers, will

the total cost be reflected in energy market offers? If so, will the clearing price be such that the units

are committed? If allowance costs are not fully reflected in energy

offers, will capacity prices increase?What if costs are not recovered? Will we be faced

with retirements of baseload units otherwise needed for reliability?

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RGGI Design and Electricity Market RGGI Design and Electricity Market IntersectionIntersection

Cap size Regional, state-by-state allocations Possible impacts are similar to those associated with

handling of allowances, i.e., too tight a cap may result in units needed for reliability being uneconomic

Caps should be designed in a manner that shapes future performance without creating immediate financial problems for suppliers – this will have a ripple effect on new construction

Phased-in caps can signal new construction in a market-friendly manner

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RGGI Design and Electricity Market RGGI Design and Electricity Market IntersectionIntersection

Temporal FlexibilityBorrowing

• Would be necessary in situations where reliability may otherwise be jeopardized (similar arrangement for NOx in 6 NYCRR 237-6.5f)

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RGGI Design and Electricity Market RGGI Design and Electricity Market IntersectionIntersection

LeakageUncertainty of supply from Ontario (~5 years out)What is the impact on PJM commitment if only

portions of the control area are subject to RGGI?How will new coal facilities outside the RGGI

region impact the overall program effectiveness?

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RGGI Design and Electricity Market RGGI Design and Electricity Market IntersectionIntersection

Implementation Timing / Phase-In Consider predicted installed

reserve margin Need to keep in mind other

scheduled and proposed regulations, the timing and cost of which create significant supplier uncertainty:

• NY’s revised NOx (NYCRR 237) and SOx (NYCRR 238) rulemakings

• Potential mercury rules• Water permits (outages

for fish protection, etc.)

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Concluding thoughts on cap-and-trade systemNeeds to be flexibleShould be in a form that can be widely adopted in

other regions, countries, etc.Should, to the extent possible, adopt standard

approaches in use elsewhereDesign should drive market solutions

RGGI Design and Electricity RGGI Design and Electricity Market IntersectionMarket Intersection