ISO New England

Presentation Transcript

Carol Chessmore

Feiran Huang

University of Texas at Arlington

EE 5379: Fundamentals of Power and Energy Trading

Dr. Ricson Chai

Fall 2008

Introduction

Market Description

Service Area
Statistics and History
Market Type
LMP, FTRs, and ARRs
Pricing
Seams

Operations

Operations Structure
Action During Capacity Deficiency
Transmission Outage Plans
Emergency Plan
Regulatory Agencies

Service Area

300 market participants
8 pricing zones and a hub
Summer peaking system

Typical Peak Summer Demand: 19,000 MW to 24,000 MW
Typical Peak Winter Demand: 18,000 MW to 20,000 MW
Typical Fall and Spring Demand: 15,000 MW to 18,000 MW
Record Demand: 28,130 MW

13 interconnections to New York and Canada
Part of the Eastern Interconnection

Generation Types in New England ISO

2007 Generation in the ISO-NE 2007 Generation in ERCOT

Source: ISO-NE Source: ERCOT

Generation by State

Source: ISO-NE

Size Comparison of ERCOT and ISO-NE

Brief History of New England Market

1999 - Single energy clearing price market
March 2000 - Congestion Management (CMS) and Multi-Settlement Systems (MSS) added

CMS: Locational prices of electricity
MSS: Day Ahead and Real Time markets

March 2001 - Began use of Standard Market Design (SMD)

Used a PJM model
Worked with New York to standardize rules

Comparison of Original System with SMD

Available Trading Markets

Bilateral Transactions

Between wholesale buyers and sellers
Long term contract for set time frame
Set prices
75% of transactions

Day Ahead Market (DAM)

Short term forward market
Used to manage risk of increases in real time prices

Real Time Market (RTM)

Spot market
Used for transactions not covered by bilateral transactions or DAM
Most risk since prices can change rapidly

Forward Capacity Market

Started in February 2008

Forward Capacity Market

Economic incentive for investment in new and existing capacity resources

Demand Resources
Generation Resources

Auction

Forecasted requirements for 3 years in advance
Qualification process to prove they have their proposed capacity

Pay-for-Performance

Reduces payments to units not available during high demand

Peak Energy Rent

Reduces capacity costs for everyone when they reach a certain peak level
Theory: capacity market compensates for fixed costs while energy market compensates for variable costs
Prevents over-collection between the energy market and the capacity market during high demand

Locational Marginal Price

LMP is “cost of congestion”

Value of locating new generation
Value of upgrading transmission
Value of reducing consumption

3 costs

Energy (from least expensive unit)
Congestion (from more expensive unit)
Loss

Price calculated at 3 locations

Node (900 nodes)
Zone (8 zones)
Hub (1 hub)

Node

Not all Physical nodes have Pricing Nodes
Some Pricing Nodes are public and some are private

Zones

Load weighted average of the nodes in the zone
Zone LMP is public

Hub

Located in an area with low congestion
Price is average of the zone prices
Provides a stable reflection of the overall price

Eventually transition to full nodal market

Uses of LMPs

LMPs used to calculate Charges or Credits for market services

Energy Market Energy

Energy Component

Transmission

Congestion Component

Transmission Losses

Loss Component

Net Commitment Period Compensation (NCPC)
Emergency Energy
Forward Reserves
Data Reconciliation
Inadvertent Energy Accounting

Pricing using LMP

Calculated hourly for the Day Ahead Market
Calculated every 5 minutes for the Real Time Market
Real-Time Market

Participants with Generators are paid with Generator Node LMP
Participants with Asset Related Demands are charged based on the Load Node LMP
Participants with load other than Asset Related Demands are charged based on Zonal LMP

Day Ahead Market

Generators paid with Generator Node LMP
Participants with Increment Offers are paid with LMP at which the location cleared
Participants with Decrement Offers or Demand Bids are paid with LMP at which the location cleared

Rule of Thumb

If you are being paid, then use Node LMP
If you are being charged, then use Zonal LMP

FTRs

“Congestion Revenue”

Zonal LMP (loads charged) > Nodal LMP (generators paid)
Congestion revenue = Zonal LMP – Nodal LMP

Financial Transmission Rights (FTR)

Sold at auction to participants
Gives owner the right to receive part of congestion revenue
Helps market participants manage their congestion risks

Obtained in 3 ways

Auction
Secondary market
Unregistered trades

ARRs

Auction Revenue Rights (ARR)

NE ISO collects revenues from auction of FTRs

How are ARRs used?

Given out as Qualified Upgrade Awards (QUA) to pay for transmission upgrades that increase transfer capacity
Given to entities that pay congestion costs

Four stage process
Based on load served in the area
Allows them to recoup some of the congestion costs and some of the costs from acquiring FTRs

Demand Response

General Features

Internet Based Communication System (IBCS)
Pre-planned actions to reduce load
Pre-determined rate paid per kWh
Monthly Capacity Payment based on ICAP or Market Price

Real-Time Demand Response Program

During emergency
2 categories

Within 30 min
Within 2 hours

Real-Time Profiled Response

Without interval metering, but with directly controllable loads
Reduce load within 30 minutes

Real-Time Price Response Program

Reduce load when wholesale price forecast exceeds 10 ¢/kWh

Day-Ahead Program

Started in 2005
Supplement to the Real-Time Program
Participants in either Real-Time Program
Offer electricity reduction bids based on day-ahead wholesale energy market

Reserves

Operations Reserve

Can recover from the loss of 2 biggest sources with no interruption
Reserve margin of about 1,800 MW
Reserve Adequacy Analysis
Locational Forward Reserve Market

Twice a year auction for reserves
Online unused capacity or offline fast start generators

Pricing for Reserves

Day Ahead Market

Operating reserves charges proportionate to DAM load obligations

Real Time Market

Charges are levied upon participants whose real time load deviates from the day ahead schedule
Charges for those whose generators deviate from day ahead schedules and who do not follow real time dispatch instructions

Forward Reserve Clearing Prices
Real Time Reserve Clearing Price

Set to zero unless need to redispatch
If need to redispatch, then equal to RCPF

Real Time Reserve Penalty Constraints

If reserve cannot be met

Local TMOR RCPF = $50/MWh
System TMOR RCPF = $100/MWh
System TMNSR RCPF = $850/MWh
System TMSR RCPF = $50/MWh

Seams

Seams - Barriers that inhibit the economic trade of capacity and energy between neighboring wholesale electricity markets

ISO New England
New York ISO
PJM
Ontario
Hydro-Quebec
New Brunswick Power

Result of differences in

Market rules
Operating and scheduling protocols

In July 2002, FERC issued a Notice of Proposed Rulemaking for Standardized Market Design
In 2002, Northeastern Independent Market Operators Coordinating Committee was formed

Coordination of market design and system planning protocols
Sharing of regulation services
Sharing of reserves during short-term interruptions
Ensure that energy exporting procedures are similar so that trading across borders is easier

Operations Structure

Departments

System Operations
Market Operations
System Planning

Committees

Participants Committee & Working Groups
Markets Committee & Working Groups
Reliability Committee & Working Groups
Transmission Committee & Working Groups
Other Committees
Inactive Committees

Procedures and Manual

Operating Procedures (OP)

The procedures inform generators of operating and reliability requirements.
Total 21 OP

Summary of the Procedures and Manuals

Transmission

OP2, 6, 7, 11, 12, 13, 16, 17, 19

Market

OP3, 4, 5, 8, 9, 14, 18, 21, M-06,-11,-35,-36

Installed Capacity

M-20

Accounting and Billing

M-27, -28, -29

ISO Administrative

OP1, 10

Action During a Capacity Deficiency

Operating Procedure 4
16 point plan

Action 1: Power caution
Action 2: All contracted 5MW generators come online
Action 3-5: Interrupt Real Time Demand with 2 hour or less notification
Action 6: Allow depletion of 30 minute reserve
Action 7-8: Continue to interrupt Real Time Demand
Action 9: Power Watch
Action 10: Request all generation contractually available

Action During a Capacity Deficiency

Action11: Purchase energy from neighboring markets
Action 12:

Allow 5% less of normal operating voltage
Interrupt demand with 30 minutes or less
Inform NY ISO that sharing may be necessary

Action 13: Voltage reduction of 5% in 10 minutes
Action 14: Request all generation not contractually secured
Action 15:

Radio and Television Address for voluntary load curtailment
Power Warning

Action 16: New England State Governors to reinforce appeals for voluntary load curtailment

Power Capacity Information

Normal
Power Caution

Issued to market participants
Prepare to implement OP 4
No need for public action

Power Watch

Public action: Reduce AC, shutting off lights, and doing laundry at night instead of peak hours

Power Warning

Public action: Shut off unnecessary lights, equipment, and appliances

Transmission Outages

Outages:

Scheduled Outages
Long-Term Planned Transmission Outages
Short-Term Transmission Outages
Unplanned Outage

Emergency Outage
Forced Outage
Overrun Outage
Opportunity Outage

Transmission Outages

Categories of Transmission Facilities

Category “A”– Highest voltages >= 115kV except 115kV radial circuits and most critical facilities
Category “B”– All 115kV radial circuits and all 69kV circuit
Local Area – Below 69kV

NOTE: Lists of Category A and B facilities are posted for the public

The outage treatment will be different from category to category

Operating Reserve

An additional resource to meet the actual New England control area load

Control Area (CA)

An electrical power system to which a common Automatic Generation Control (AGC) is applied in order to
Match generation and load
Maintain interchange with other CA
Maintain frequency

Operating Reserve

Ten-Minute Reserve

Ten-Minute Non-Spinning Reserve (TMNSR)
Ten-Minute Spinning Reserve (TMSR)

Thirty-Minute Operating Reserve (TMOR)

The same as Ten-Minute Non-Spinning Reserve
In 30 minutes

Replacement Reserve

Reserve other than TMSR, TMNSR, or TMOR

Operating Reserve

First Contingency Loss

The largest capacity outage (MW) that would result from the loss of a single element

Second Contingency Loss

The largest capacity outage (MW) that would result from a single element after allowing for the First Contingency Loss

Operating Reserve

Procedure

Real time Operating Reserve Requirement

Ten-Minute Reserve >= require to replace the First Contingency Loss
Thirty Minute Operating Reserve >= 50% of the Second Contingency Loss
Any excess of Ten Minute Reserve can be counted as Thirty Minute Reserve
Operating Reserve shall be sustainable for at least one hour from the time of activation
The output of the largest generating unit cannot be considered as Operating Reserve