Building the Energy Markets of Tomorrow... Today New York State Electricity Markets Federal Energy Regulatory Commission Market Design Technical Conference

Building the Energy Markets of Tomorrow . . . Today

New York StateNew York StateElectricity MarketsElectricity Markets

Federal Energy Regulatory CommissionFederal Energy Regulatory CommissionMarket Design Technical ConferenceMarket Design Technical Conference

January 22, 2002

Charles A. King - Vice President, Market ServicesCharles A. King - Vice President, Market Services


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Outline of Today’s PresentationI. Overview of New York’s Market Structure

II. Day-Ahead Market

III. Real-Time Market

IV. Transmission Service Markets

V. Financial Transmission Rights

VI. Ancillary Services Markets

VII. Long-Term Capacity Markets

VIII. Market Monitoring and Mitigation

Appendix – Statistics and Examples


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New 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 ISO30,983 MW*

PJM54,176 MW*

I. NYISO Overview


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I. NYISO OverviewNew York Electric Industry Restructuring

New York Transmission Owners entered into settlement agreements with New York Public Service Commission in mid 1990s which required divesture of generating units

Established phased schedule for retail access

Wholesale markets launched and NYISO began operation on December 1, 1999


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I. NYISO OverviewNYISO Governance

O PERATING CO M M ITTEE5 Sectors

58% Vote to Pass

BUSINESS ISSUES CO M M ITTEE5 Sectors

58% Vote to Pass

M ANAG EM ENT CO M M ITTEE5 Sectors

58% Vote to Pass

BO ARD O F DIRECTO RS10 M em ber Unaffiliated

6 Votes to Pass


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I. NYISO OverviewUnique System Characteristics

Transmission prone to thermal, voltage and stability limitations which can bifurcate NYISO system (east vs. west)

Much higher degree of transmission congestion

FERC 12/19/01 Electric Transmission Constraint Study

High degree of generation divestiture

Investor-owned utility divesture currently at 91 percent


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Legend:

KintighNiagara

Oswego

OakdaleFraser

Marcy

Massena

MosesChateauguay

Plattsburgh

Gilboa Leeds

NewScotland

Clay

Lafayette

Watercure

Stolle Rd.Edic

Porter Rotterdam

PleasantValley

Coopers Corners

Rock Tavern

Roseton

Bowline

RamapoSprainbrookDunwoodie765 kV

345 kV230 kV Farragut

Goethals

Complex

Homer City

Shore Rd.E.Garden City

Dunkirk

Pannell

Sta.80

New York Independent System OperatorHigh Voltage Transmission System - 230 kV and above Transmission

I. NYISO Overview


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I. NYISO OverviewMarkets

Bid-Based Markets Energy Regulation Spinning and Non-Spinning Reserves Three-part bids Self-scheduling

Other Markets Installed Capacity Transmission Congestion Contracts

Two Settlement System Day-Ahead Market Real-Time Market


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I. NYISO OverviewMarkets (continued)

Locational Based Marginal Pricing Nodal congestion management pricing system Marginal losses

Financial Hedging Instruments Transmission Congestion Contracts Contract For Differences Virtual Trading

Demand Response Program Day-Ahead Emergency


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I. NYISO OverviewMarkets (continued)

Flexible market structure accommodates: Bilateral Transactions

Existing Transmission Agreements

Scheduling of Energy Limited Resources

Municipal Customers

Power Marketers

Price responsive load customers


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Day-AheadMarket

(HourlyProcess)

Gen

Real-TimeMarket

SCUC

ForwardContracts

BME

SCD

Bids by 5 a.m.Day before

Schedules

RealConditions

Bids by 90 minbefore hour

DAM = Day-Ahead MarketSCUC = Security Constrained Unit CommitmentBME = Balancing Market EvaluationRT = Real-Time MarketSCD = Security Constrained Dispatch

BasepointsSupplementalResourceEvaluation

I. NYISO OverviewNew York's Two-Settlement Process


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II. Day-Ahead MarketHighlights

Bids submitted by 5:00 am previous day Suppliers submit MW quantity and price bids for each

hour including any ancillary services bids Loads submit MW requirement bids for each hour

including any price cap load bids Includes bids for virtual supply and virtual load

Security Constrained Unit Commitment (SCUC) scheduling software simultaneously cooptimizes energy and ancillary services for least cost solution


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II. Day-Ahead MarketHighlights (continued)

Locational Based Marginal Prices (LBMP) posted by 11:00 am previous day

Accommodates bilateral transaction scheduling concurrently with supply and load bids

Any deviations in supply or demand settled in Real-Time Market


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II. Day-Ahead MarketBenefits

Provides price certainty while avoiding volatility of Real-Time Market

Simultaneous co-optimization process maximizes the use of the existing transmission system and provides for appropriate cost allocation

Highly automated system manages complex operating processes


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II. Day-Ahead MarketBenefits (continued)

Multi-pass Security Constrained Unit Commitment (SCUC) process accommodates Reliability requirements Market mitigation Cost assignment of uplift


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II. Day-Ahead MarketUnique Characteristics

Day-Ahead prices include effect of reliability commitments and all scheduled external transactions

Incorporates automated mitigation (in-city and automated mitigation procedures (AMP))

Ancillary Services secured and priced Fully unbundled Simultaneous co-optimization of individual availability bids


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III. Real-Time MarketHighlights

Balances system supply and demand every five minutes

Bids may be adjusted to address in-day operating conditions

Accommodates additional bilateral transactions and changes to fixed output generator schedules

Security Constrained Dispatch (SCD) software re-optimizes energy and ancillary service markets onsystem-wide basis

Provides for commitment of “quick start” resources Locational Based Marginal Prices (LBMP) posted every

five minutes


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III. Real-Time MarketBenefits

Simultaneous co-optimization process maximizes the use of the existing transmission system while maintaining reliability

Provides for least cost dispatch of Real-Time resources

Provides Real-Time price transparency


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III. Real-Time MarketUnique Characteristics

Ex-ante pricing based upon “scheduled” generator basepoint vs. ex-post pricing based upon generator actual output

NYISO uses unit-specific MW signal instead of dollar zonal price signal

Minimum energy bid is -$1000 vs. $0 in PJM. NYISO practice allows market to resolve min-gen scenarios instead of dumping energy


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III. Real-Time MarketUnique Characteristics (continued)

Variations on criteria used to determine which units are eligible to set Locational Marginal Pricing (LMP)

PJM only allows units that respond to $ zonal price signal to set LMP

NYISO used hybrid pricing method to allow inflexible units to set LMP. PJM does not allow inflexible units to set price


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IV. Transmission Service MarketsHighlights

Firm transmission service available to users willing to pay congestion costs Continuous redispatch to support firm transactions

Transmission Congestion Contracts (TCCs) provide financial hedge against congestion costs

Non-firm transmission service curtailed when congestion exists

Cost of transmission marginal losses included in clearing price


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IV. Transmission Service MarketsHighlights

Long-term prescheduling and ramp management will enhance ability to acquire explicit long-term transmission service across control area boundaries

Facilitation of “counter-flow” transactions in hourly scheduling process avoids need to curtail day-ahead transactions for transmission system security

Implementation of Open Scheduling System (OSS) for “One Stop Shopping”


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IV. Transmission Service MarketsBenefits

Loads pay non-pancaked license plate Transmission Service Charge

All parties pay the same rate at the same location

All parties have equal access to the transmission system, no physical reservations / rights to hoard

Day-Ahead transaction certainty enhanced through presence and utilization of counter-flow transactions


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IV. Transmission Service MarketsUnique Characteristics

NYISO utilizes an implicit bid-based transmission reservation scheduling process

NYISO planned implementation of explicit transmission pre-scheduling process provides physical long-term reservation and schedule at NYISO boundaries

Utilization of “counter-flow” transaction avoids curtailment of Day-ahead schedules

Open Scheduling System (OSS) facilitates transaction scheduling


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IV. Transmission Service MarketsUnique Characteristics

Blended (flow-based) export transmission service charge rate

Generation minimum interconnection criteria is “access-based” with no deliverability requirement

Special protection schemes fully addressed


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V. Financial Transmission RightsHighlights

Transmission Congestion Contracts (TCCs) sold through auction - serves as a congestion hedge, or as financial instrument available to the market

Auctions held on a semi-annual basis for TCCs for variable time periods (half-year to 5 years)

Monthly “Re-configuration Auctions” conducted

Auction results posted

TCCs settled in Day-Ahead market

May be specified between generators, zones, external proxy buses, NYISO reference bus


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V. Financial Transmission RightsBenefits

All Transmission Congestion Contracts (TCCs) auctioned except those associated with Grandfathered Transmission Wheeling Agreements

Fully funded TCCs provide hedging certainty

Multiple round auction enhances price discovery


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V. Financial Transmission RightsBenefits (continued)

“Alternating Current (AC) Power flow” solution provides for improved accuracy

Simultaneous feasibility is assured to avoid “over selling” of Transmission Congestion Contracts (TCCs)

TCCs are “unbundled” - for more liquid market

Moving towards a simultaneous, multi-period TCC auction process by Summer 2003


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V. Financial Transmission RightsUnique Characteristics

NYISO fully funds TCCs and balances over/under collection with Transmission Owners PJM passes revenue shortfalls to FTR holder and

over-collection is refunded to loads

High degree of capability offered for sale in the auction

TCCs may be purchased up to 5 years vs. monthly in PJM


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VI. Ancillary Services MarketHighlights

Market-Based Services Regulation

Spinning Reserve

10-Minute Non-Spinning Reserve

30-Minute Non-Spinning Reserve

Simultaneously co-optimized with energy markets both Day-Ahead and Real-Time

Incorporates locational reserve requirements

Cost-Based Services Scheduling, Control and Dispatch

Voltage Support

Black Start


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VI. Ancillary Services MarketBenefits

Separate but simultaneously co-optimized markets provide an efficient mechanism for obtaining the least-cost solution

Lost opportunity cost payments ensure availability of sufficient resources

Markets can satisfy locational needs

Allows for a more precise ability to control and dispatch resources to maximize use of the transmission system


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VI. Ancillary Services MarketUnique Characteristics

Fully unbundled regulation and reserve services

Four markets vs. single regulation market in PJM

Explicit availability bids for each Ancillary Service Market

Specific locational requirements met

Ancillary services are fully scheduled in the Day-Ahead Market, with in-day adjustments made through hourly and supplemental processes

Energy and ancillary services simultaneously co-optimized


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VII. Long Term Capacity MarketsHighlights

Installed Capacity (ICAP) requirements for Load Serving Entities (LSE’s) based on annual peak load

Long-term ICAP requirement

Monthly ICAP auctions accommodate load-shifting and latest generator performance

Supply can be via Bilateral Transaction, self supply, or auction


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VII. Long Term Capacity MarketsHighlights (continued)

Locational requirements apply (in-city and Long Island)

Deficiency charges applied to Load Serving Entities (LSEs), if requirements are not met

Market power mitigation measures apply in New York City


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VII. Long Term Capacity MarketsBenefits

NYISO market similar to neighbors for product consistency

Ensures resource adequacy to meet reliability requirements

Installed Capacity (ICAP) reflects experienced availability: Unforced Capacity (UCAP)

Intermittent resources (windmills, etc…) eligible

Demand-side resources allowed to participate


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VII. Long Term Capacity MarketsUnique Characteristics

4 hour qualification test vs. 2 hour test in PJM

Full credit for ICAP / UCAP for interruptible loads and intermittent generators

Monthly certification

Deficiency penalty applied monthly


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VIII. Market Monitoring & MitigationHighlights

NYISO market monitoring procedures …

foster transition to a fully competitive market

seek to maintain a competitive supply demand relationship under all conditions

minimize unnecessary market intervention

insure delivery of market based products from suppliers

Mitigation based upon Conduct and Impact standard

Multiple mitigation needs addressed through variable thresholds, margins, and reference offers/bids


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Market Monitoring accountable to NYISO Board of Directors

Independent Market Advisor provides oversight

NYISO applying comprehensive mitigation approach to address all mitigation needs based upon conduct / impact standard

Day-Ahead Market (DAM) In-City with structural component

Real-Time (RT) In-City with structural component

Statewide Automated DAM


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Market monitoring of: Physical Withholding / physical audits Economic Withholding Uneconomic production Submission of false information Failure to follow dispatch instruction Under-scheduling load Transmission congestion contracts Transmission service / transactions Installed Capacity Markets Market participant financial positions against collateral


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VIII. Market Monitoring & MitigationBenefits

Mitigation parameters (triggers, thresholds, reference prices, etc) may be tailored to address specific needs

Reference prices reflect historical accepted competitive offers whenever possible

Process provides for consultation with market participants prior to mitigation

Procedures automated to prevent “lost day”

Mitigation parameters can be reviewed and adjusted over time, allows Market Participants to “build out “ of a congested pocket


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VIII. Market Monitoring & MitigationUnique Characteristics

NYISO relies on a conduct / impact standard to determine exercise of market power (except for New York City pocket mitigation; plan under development to add conduct / impact plus structural component)

PJM assumes market is un-competitive when transmission congestion exists (except for East/Central/West voltage constraints)

NYISO mitigates to a competitively set reference bid

PJM mitigates via cost-capping (cost + 10 percent)


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GeneratorReference

Prices

TRIGGERS

VIII. Market Monitoring & Mitigation

THRESHOLD

MARGINS

CONSULTATION

MARKET IMPACT TEST

CONDUCT TEST

Historical 90 day Competitive

Negotiated

Default

Universal Market Mitigation Framework

Mitigation Occurs Only During Non-competitive Times


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APPENDIX

Statistics and Examples


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II. Day-Ahead MarketPerformance Statistics

High degree of price certainty Load zones A, G, and J used as trading

indices by power marketers 95% of New York’s energy transactions

settled Day-Ahead Includes both Day-Ahead Market and Bilateral

Transactions

All Transmission Congestion Contracts (TCCs) settled Day-Ahead


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Bilaterals50%

RealTime <5%

NYISODay-Ahead

Market45 – 50%

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

100%

II. Day-Ahead MarketNew York Market Share


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III. Real-Time MarketPerformance Statistics

Represents less than 5 percent of New York energy market transactions

Less than .05 percent of price intervals corrected in 2001

Improved NERC control performance


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III. Real-Time MarketPerformance Statistics

NYCA Daily Control PerformanceDecember 2001

708090

100110120130140150160170180190200210

DayCPS1 for Dec.=179.67 % Compliance Threshold=100%

CPS1 measures how well a Control Area meets its demand requirement

CP

S%

CPS1 CPS1 Target


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IV. Transmission Service MarketsOpen Scheduling System (OSS)

What is OSS? OSS is comprised of an industry leading set of tools

for Market Participants and Scheduling Coordinators to interact, trade and communicate within and across control areas

Initially, OSS will provide the ability to: Enter bilateral transaction bids across Scheduling

Coordinator borders with a single data entry interface View status from each Scheduling Coordinator View schedules from each Scheduling Coordinator Request transmission and ramp reservations


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What is OSS? OSS is comprised of an industry leading set of tools

for Market Participants and Scheduling Coordinators to interact, trade and communicate within and across control areas

Initially, OSS will provide the ability to: Enter bilateral transaction bids across Scheduling

Coordinator borders with a single data entry interface View status from each Scheduling Coordinator View schedules from each Scheduling Coordinator Request transmission and ramp reservations


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Kickoff Phase 1

Test Start

Phase 2 and beyond

Internal and external bilateral transactions (hourly)

Pre-scheduling

Integration with PJM

Ability to review and manage schedule status

Ability to edit NERC tags

Bid entry up to 18 months in future

Support EST only

Integration with e-Tag agents

Integration w/ WebCoordinate

Consistent with ESC and OASIS II

Automated Checkout

Inter-regional congestion commitments

Integration with more scheduling coordinators

Support of sub-hourly transactions

User defined time zone

2/11/02

Agreement on OSS end-vision

Validation of pilot concepts

Open nodal architecture

Design/Development

6/05/01 8/27/01

Phase 1

Live

3/11/02

OSS Project Timeline


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OSS Summary Open, platform independent design that is

consistent with Order 2000 OSS is an application that can be easily

adopted by other Scheduling Coordinators with minimal change to existing systems

Addresses critical Inter-Control Area transaction seams issues with minimal impact on current MP processes


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Based on requirements gathered from MPs with input from Scheduling Coordinators

Defines a communication protocol between Scheduling Coordinators

The OSS application will be deployed in phases with the first scheduled for Q1 2002

OSS Summary


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V. Financial Transmission RightsPerformance Statistics

Net Revenues to Transmission Owners- Year 2000: ~ $260 million

- Year 2001: ~ $65 million

Outstanding Transmission Congestion Contracts (TCCs)- Grandfathered: ~ 40 percent (~ 11,800 MW)

- NYISO Auction: ~ 60 percent (~ 18,800 MW)


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V. Financial Transmission RightsPerformance Statistics

Alleviating Contract Path Confusion Parties do not need to optimally pair their

supply and load up as bilateral transactions to minimize transmission charges

TUC paid by aggregator does not depend on how it bids its supply and load

TUC is point-to-point Does not depend on contract path

An Example

Source Sink


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V. Financial Transmission RightsExample – Configuration A

Sink

FraserChat East

LeedsNiagara 345

SprainbrookRamapo

Goethals

Source


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Example 6.1.1: Billing for Aggregation

Delivered EnergyPoint of

Injection LBMP

Point of Withdrawal

LBMP for Load Zone Total TUC*

(MWh) ($/MWh) ($/MWh) ($)

RAMAPO SPRBROOK 200 34.88 37.00 424.00 GOETHALS SPRBROOK 200 35.59 37.00 282.47 CHATEAST LEEDS 3 200 22.44 38.19 3,150.49 NIAG 345 FRASER 200 15.70 29.88 2,835.01

Total TUC Charge 6,691.97

Aggregator TUC for Bilateral Set 1

Point of Withdrawal Bus

Point of Injection Bus

Configuration A - Billing

V. Financial Transmission RightsExample – Configuration A


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V. Financial Transmission RightsExample – Configuration B

FraserChat East

LeedsNiagara 345

SprainbrookRamapo

Goethals

Source Sink

Config BConfig A


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V. Financial Transmission RightsExample – Configuration B

Configuration B - Billing


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V. Financial Transmission RightsExample

The Aggregator Net Charge


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VI. Ancillary Services MarketExample: Summer 2001

29435

30509

30665

30983

29568

28500

29000

29500

30000

30500

31000

MW

Mon Tues Wed Thurs Fri

NYISO Loads Peak Week August 6 - 10, 2001Daily Peak Loads (MW)


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VI. Ancillary Services Market Example: Summer 2001

Overview of Northeast Peak

Load Situation on Aug. 9 - New NYISO Peak Load - 30,983 MW

(Hour Beginning:14:00, August 9)

New Peaks in Neighboring Control Areas IMO - 25,269 MW ISO-NE - 25,158 MW PJM - 54,176 MW


64


Situations Observed – NYISO Operating at Reserve Requirements Neighboring Control Areas Operating at

Margins NYISO Able to Maintain Energy Exports Depressed Voltage Levels Observed in PJM

and New York


65


Load Relief Measures Total - 1,580 MW

EDRP & SCR - 580 MW Voltage Reduction - 350 MW Public Appeals - 270 MW NYS Government - 220 MW TO Programs - 130 MW


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System Performance Equipment Performance

Market Information System was reliable The Transmission System was secure and reliable Generation performed consistently Load was served throughout the period


67


System Performance Impact of Transactions on Voltages

NYISO exports and wheels to PJM PJM experienced severe voltage problems in the East NYISO experienced depressed SENY voltages Some transactions cut by NYISO to increase voltages PJM requested NYISO voltage reduction to avoid

system voltage collapse NYISO implemented 5 percent voltage reduction to

assist PJM


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NYISO Reserve RequirementOperating Reserve

August 9, 2001

0

500

1000

1500

2000

2500

3000

3500

4000

4500

11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00

Time

MW

s

30 Min Act 30 Min Req Reserve + ICAP Sales

Counting ICAP Sales towards reserve

Level of Exports Maintained during Peak Day

NYISO Reserve RequirementOperating Reserve

August 9, 2001


69


Benefits of NYISO “Best Practices” August 9, 2001

Best Practice: Simultaneous co-optimization of energy and ancillary service markets;

Best Practice: Hourly evaluation (Balancing Market Evaluation – BME) which optimizes in-day resource adjustments;

Best Practice: Emergency Demand Response Program


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Benefits of NYISO “Best Practices” August 9, 2001 (continued)

NYISO Best Practices provided the ability to track and augment system energy and reserves in real time despite adverse conditions.

NYISO Best Practices provided the ability to make full utilization of limited transmission capability in real-time to maintain reliability in NY and support neighboring control areas.

NYISO able to maintain exports critical to neighboring areas during peak load periods due to flexibility afforded by NYISO Best Practices.


71

VI. Ancillary Services MarketPerformance Statistics

NYISO Monthly Average Ancillary Service PricesDay Ahead Market 2001

$0

$5

$10

$15

$20

$25

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

10 Min Spin Res Avg - 2001 10 Min Non-Synch Avg - 2001 30 Min Op Res Avg - 2001 Regulation Average - 200110 Min Spin Res Avg East - 2001 10 Min Non-Synch Avg East - 2001 30 Min Op Res Avg East - 2001 Regulation Average East - 200110 Min Spin Res Avg West - 2001 10 Min Non-Synch Avg West - 2001 30 Min Op Res Avg West - 2001 Regulation Average West - 200110 Min Spin Res Avg - 2000 10 Min Non-Synch Avg - 2000 30 Min Op Res Avg - 2000 Regulation Average - 2000

East West

East West

EastEast

West


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*10 minute reserves includes only capability in Eastern New York due to locational reserve requirements.

VI. Ancillary Services MarketPerformance Statistics

Ancillary Services Capability and Offers

0

500

1000

1500

2000

2500

Exc

l.P

UR

PA

All

Un

its

Exc

l.P

UR

PA

All

Un

its

Exc

l.P

UR

PA

All

Un

its

Exc

l.P

UR

PA

All

Un

its

10 Min Spin* 10 Min Nspin* Regulation 30 Min Reserves

Reg

ula

tion

an

d 1

0 M

inu

te R

eser

ves

(MW

)

0

3000

6000

9000

12000

15000

30 M

inu

te R

eser

ves

(MW

)

AverageCapability

AverageOffer

ApproximateDemand


73

VII. Long Term Capacity MarketsPerformance Statistics

Installed Capacity (ICAP) Requirements Statewide: 36,132 MW Locational:

New York City:8,428 MW Long Island: 4,639 MW

Procurement 75 percent Bilateral Transactions 25 percent NYISO Auctions


74

VII. Long Term Capacity MarketsPerformance Statistics

Statistics on ICAP prices Winter - UCAP

Strip Auction

– $9.40/kW/month NYC (3970 MW)

– $2.00/kW/month Rest of State (ROS) (2290 MW)

Monthly – thorough 1/2002

– $7.30/kW/month NYC (550 MW)

– $0.20/kW/month ROS (550 MW)


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VIII. Market Monitoring & MitigationFundamentals of Operation

Market Power Mitigation: Two Criteria Conduct inconsistent with workable competition Actions have a substantial impact on LBMPs or other

revenues


76


Conduct inconsistent with workable competition Economic Withholding of an Electric Facility Physical Withholding by an Electric Facility Uneconomic Over-production from an Electric Facility


77


Actions have a substantial impact on LBMPs or other Revenues

Criterion The lower of a tripling of prices or $100 in an energy or

ancillary services market A tripling of guarantee payments to a market

participant


78


Does Conduct Exceed Thresholds? Thresholds for Economic Withholding

The lower of a quadrupling of prices or $100 / MW in the energy markets and for most reserves.

The lower of a quadrupling of prices or $50 / MW for real-time 10-minute spinning reserves.

A tripling of startup cost offer prices

Reference concept Accepted, unmitigated offers during periods of workable

competition


79


Does Conduct Exceed Thresholds? Thresholds for Physical Withholding: Day-

Ahead The lower of 10% or 100 MW of a unit’s capability. The lower of 5% or 200 MW of an organization’s capability

Thresholds for Physical Withholding: Real-Time Operation of a unit at less than 90% of the NYISO’s dispatch

rate


80


Does Conduct Exceed Thresholds?

Thresholds for Uneconomic Over-production Schedule and production of energy at an LBMP less than 20% of a

unit’s reference price.

Real-time output exceeding 110% of the NYISO’s dispatch level.

The conduct must cause or contribute to congestion


81


Screening Reports “5 AM” Generator, Startup, and Zone Reports “11AM” Generator and Energy Exception Reports

Identify DAM conduct through reports and data screens

Identify impact through SCUC and offer-curve analysis

Conduct and impact together trigger prospective mitigation

Documents

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