Locational ICAP Design Details July 18-19, 2005

Locational ICAP Design DetailsJuly 18-19, 2005

2

LICAP Schedule

• Administrative Law Judge issued an Initial Decision on June 15, 2005

– Adopted the ISO’s market design for the most part– Did not adopt the ISO’s proposed “Shortage Hour” measure of

Availability and recommended an EFORd approach

• Filing of Exceptions by involved parties due July 15, 2005

• FERC Order is expected sometime in September– Can adopt the ALJ’s recommendations or can order other changes

• Implementation of the Locational ICAP Market is still expected on January 1, 2006

3

Market Configuration for LICAP

•Five ICAP Regions

•Up to five unique prices

•Four ICAP Interfaces

•ICAP Interfaces and Regions added and subtracted as needed based on yearly process

NEMA

ME

CT

WEMA NH

SEMA

VT

RI

SWCT

4

Elements of ISO New England’s Proposal

• Four Fundamental Characteristics:– Demand Curve for Each ICAP Region

• Solves “bipolar” pricing issues • Provides incentives to build capacity in the Regions where it is needed

most

– Availability • Metric to determine how much resources receive in LICAP payments

– Energy Revenue Offset• Deduct Peak Energy Rents earned by a “benchmark generator” from

LICAP payments

– Fully utilize all resources in clearing the Auctions• Use all installed capacity (including listed and de-listed resources, and

resources on inactive reserve), net of imports and exports, to determine supply curve

Regional ICAP Requirements

6

Control Area ICAP Requirement

• ISO-NE establishes the ICAP Requirement to meet the reliability needs of the Control Area

• ICAP Requirement = Forecasted Peak Load x (1 + Reserve Margin)

• Communicated to Participants as twelve monthly values three months prior to the Capability Year(June 1 – May 31)

7

Regional ICAP Requirements

• The ISO will translate the Control Area ICAP Requirement into Regional ICAP Requirements

• The Regional ICAP Requirement for each month and ICAP Region will equal the product of the Control Area ICAP Requirement and the fraction of contributions to the Control Area annual coincident peak load by load in that ICAP Region from the calendar year immediately prior to the Capability Year

• The sum of all Regional ICAP Requirements will equal the Control Area ICAP Requirement

• The ISO will also calculate the amount of capacity that must be purchased from within the ICAP Region based on the 1 day in 10 criteria defined as the Local Capacity Purchase Requirement

8

Regional ICAP Requirement Numerical Example

• Consider the following information: Control Area ICAP Requirement = 27,000 MW Control Area Coincident Peak Load (2005) = 25,000 MW Regional Contribution to Control Area Coincident Peak Load (2005)

= 5,000 MW

Regional ICAP Requirement = 27,000 x (5,000/25,000) = 5,400 MW

9

Capacity Transfers Between ICAP Regions

MaineICAP

Region

Maine ExportInterface

Rest of Pool ICAPRegion

(Includes NH, RI, SEMass, VT, and

WCMass Load Zones

Rest of CTICAP

Region

NEMass/Boston ICAP

Region

Connecticut ImportInterface

NEMass/Boston ImportInterface

Capacity Transfer Limits for each ICAP Interface will limit the amount of capacity that may be transferred across each interface in the direction shown

Capacity transfers in the opposite direction (e.g., from Connecticut to Rest of Pool) will not be restricted

SWCTICAP

Region

10

Capacity Transfer Limits

• Capacity Transfer Limits (“CTLS”) define the amount of capacity transfer for each ICAP Interface that will be permitted in the ICAP Spot Auctions

• CTLs are calculated by subtracting the Local Capacity Purchase Requirement from the Regional ICAP Requirement

• Example: Regional ICAP Requirement = 5,400 MW Local Capacity Purchase Requirement = 4,400 MW CTL for the ICAP Region = 1,000 MW

• CTLs can be adjusted during the course of the Capability Year to reflect transmission upgrades or other material changes in capacity transfer capability

Participant’s ICAP Obligation

12

ICAP Obligations

• Participants whose retail customers contribute to the Control Area peak load are allocated an ICAP Obligation in each ICAP Region

• A Participant’s ICAP Obligation is based on their pro-rata share of the sum of all Participant ICAP Peak Contributions in the ICAP Region from the previous calendar year

• The allocation factor is the contribution of each individual customer to the prior year’s Control Area coincident peak, divided by the sum of the contributions of all Control Area retail customers in the ICAP Region to the prior year’s NEPOOL coincident peak

• Prior to the start of the power year, ISO identifies the day and hour of the peak to be used by the meter readers

13

ICAP Obligations (cont’d)

• All Participants will receive their monthly ICAP Obligation by ICAP Region by the 8th day of the month prior to the Obligation Month

• ICAP Obligations will be updated each month to account for load shifting

• Host Participants submit Daily ICAP Peak Contribution value for each Load Asset (via SMD Applications page)

14

ICAP Obligation Numerical Example for a Load Asset

• Assume the following information for a Load Asset: Regional ICAP Requirement determined previously = 5,400 MW Participant’s Load Asset ICAP Peak Cont Value to the Control

Area coincident peak = 50 MW Region’s Load Asset ICAP Peak Cont Value to the Control Area

coincident peak = 5,000 MW Participant Ownership = 100%

• Participant’s ICAP Obligation = (50 / 5,000)* 5,400 = 54 MW

15

Satisfaction of Monthly ICAP Obligation

• During the month, Participants can meet their Regional ICAP Obligation under several options

• ICAP Obligations can be met through: Self-supply by clearing their ICAP Resource in the Spot Auction Bilateral transactions Load Response Resource Credits HQ Interconnection Capability Credits Purchases and Sales through the Regional ICAP Auctions

16

Bilateral Contract Example

Bilateral Sale Part B to Part A of 20 MW

REGION 1

Participant A:

ICAP Oblig: -50 MWICAP Supply: 75 MW

REGION 2

Participant B:

ICAP Oblig: -100 MWICAP Supply: 30 MW

17

Bilateral Contract Example

Participant A: Participant A:

ICAP Oblig: -50 MWICAP Oblig: -50 MWICAP Supply: 75 MWICAP Supply: 75 MW

Participant B:Participant B:

ICAP Oblig: -100 MWICAP Oblig: -100 MWICAP Supply: 30 MWICAP Supply: 30 MW

Bilateral Sale Part B to Part A of 20 MW

If applied in Region 1:REGION 1 SupplyPart A 75 MWPart B 0 MW

REGION 2 SupplyPart A 0 MWPart B 30 MW

If applied in Region 2:REGION 1 SupplyPart A 75 MWPart B 0 MW

REGION 2 SupplyPart A 0 MWPart B 30 MW

Original ICAP Oblig Adjusted ICAP Oblig

Original ICAP Oblig Adjusted ICAP Oblig

0 MW 0 MW-50 MW -50 MW

0 MW 0 MW-100 MW -100 MW

0 MW -20 MW

Original ICAP Oblig Adjusted ICAP Oblig

Original ICAP Oblig Adjusted ICAP Oblig-50 MW -30 MW

0 MW +20 MW-100 MW -120 MW

REGION 1 REGION 2

18

Use of Capacity Transfer Rights

• At the beginning of each Capability Year, the ISO will create Capacity Transfer Rights (“CTRs”) for each ICAP Interface equal to the CTLs specified for each ICAP Interface

• CTRs will allow Participants receiving CTR allocations to trade capacity in regions other than the region in which their load or resource is located

• CTRs are a financial instrument - Ownership of CTRs does not actually transfer capacity obligations (or resources) across ICAP Interfaces

• A CTR entitles its owner to collect a payment equal to the price difference between the sink and source ICAP Regions defined for the CTR

• Payments made to CTR owners will be based on prices in the ICAP Spot Auction in each ICAP Region

• CTR allocation recommended by the ALJ gives a preferential allocation to MMWEC in NEMA and Duke in Maine

Participant’s Supply Portfolio

20

Components of a Supply Portfolio

• Generating ResourcesQualifying FacilitiesLimited Energy Resources Intermittent Power ResourcesSettlement Only Generators

• Load Response Resources• External Purchases and Sales• ICAP credits such as HQICCs and NYPA

Contracts

21

ICAP Ratings

• Defined as the amount of ICAP that a Resource is qualified to supply in the Spot Auction

• Generating Resources = equal to SCC• Load Response Resources = based on their performance

in the most recently called “event” in accordance with the Load Response Program

• External Purchases = equal to the MW value of the contract

• Miscellaneous Resources NYPA = contract amount times one plus the Control Area

Reserve Margin HQICC = contract amount for the applicable month

22

Establishing a Participant’s ICAP Supply

• Each Participant with ownership in ICAP Resources will be assigned a total ICAP Supply at the beginning of the Auction Month

• All ICAP Supply will be bid into the Spot Auction• Total ICAP Supply will be based on the ICAP Rating of

the following components: Generating Resources Load Response Resources External ICAP Contract Purchases HQICC NYPA Misc ISO Adjustment

23

Calculation of Availability Ratings

• Each Resource in a Participant’s ICAP Supply will receive an Availability Rating updated at the end of each Obligation Month based on the Resource’s rolling twelve month EFORd Availability Rating = (1 – EFORd)

• Load Response Resource will have an Availability Rating of 1.0 since their ICAP Rating is updated for each “event” called

• NYPA/HQICCs will have an Availability Rating of 1.0• The gross auction payment received for cleared ICAP Supply will be

adjusted by the Rating for each Resource– For example, if a 100 MW Resource with an Availability Rating of .90 (EFORd

of .10) clears the ICAP Spot Auction at $3/kW-mo, the Gross Auction Payment will equal 100,000kW x $3/kW-mo = $300,000

– The Gross Auction payment will be adjusted by an Availability Adjustment equal to $300,000 x .10 = $30,000

• External Contract Purchases will have a separate availability penalty calculated

ICAP Supply Auction

25

Supply Auctions Overview

• ICAP Supply Auctions will be conducted in each ICAP Region

• Auctions allow Participants to sell or purchase Installed Capacity based on submitted offers and bids

• Improves market liquidity and facilitates trading

26

How the Supply Auction Works

• Regional Supply Auctions occur around the middle of month prior to Obligation month

• The Supply Auction allows Participants to sell or buy Installed Capacity by making an offer or bid into the respective region

• No obligation by Load to bid in Auction; No obligation by Generation to Offer into Auction

• Bids and offers can be virtual

• Bids and offers can be submitted in up to 10 bid blocks

• All bids and offers are in $/MW and must be in whole dollar amounts

27

Setting the Supply Auction Clearing Price by Region

Clearing Price ($)

Cleared Qty (MW)

Supply Offers

Demand Bids

28

Settlement of Supply Auction

• Participants provide supply offers and demand bids up to 17:00 hours on day of ICAP Supply Auction

• All purchases and sales will be applied to the Participant’s ICAP Obligation in the applicable ICAP Region

• The five regional ICAP Supply Auction clearing prices will be made available to Participants within two business days of the ICAP Supply Auction

• Settlement Calculations: ICAP sales and purchases Supply Auction payments and charges based on the clearing prices

ICAP Spot Auction

30

ICAP Spot Auction Participation

• All Participants with ownership shares in listed ICAP resources must bid those resources into the Spot Auction regardless of Bilateral or Supply Auction Sales

• Bids are asset based – represents a change to current ICAP market

• Bids and offers can be submitted in up to 10 bid blocks

• All bids are in $/MW and must be in whole dollar amounts

• If the Participant does not submit a bid, the ISO will not submit a bid on their behalf and the Participant will not be paid for that portion of its ICAP Supply

31

How Does the Spot Auction Work?

• The ISO will utilize a downward sloping demand curve in each ICAP Region • The ISO will clear each ICAP Spot Auction in a two step process

Step 1: The ISO will determine the clearing price by constructing a supply curve that includes all listed and delisted capacity, as well as units on inactive reserve. An import/export test will be conducted - all valid imports will be included in the supply curve while all valid exports will be excluded from the supply curve

Step 2: The ISO will determine the cleared ICAP amount by reviewing all bids and clearing those bids that are at or below the clearing price determined above

• A Participant’s ICAP Obligation will vary as a function of the demand curve If the cleared amount is greater than the ICAP Region’s Requirement, each

Participant’s ICAP Obligation will be scaled up by their pro-rata share of the additional ICAP purchased

If the cleared amount is less than the ICAP Region’s Requirement, each Participant’s ICAP Obligation will be scaled down by their pro-rata share of the ICAP below the Requirement

32

How Does the Spot Auction Work? (cont’d)

• All ICAP Regions are cleared simultaneously in order to most efficiently meet the ICAP Requirement in each region

• If Interfaces are not constrained, then clearing prices are the same• CTRs will be allocated to Participants to allow them to utilize

resources in other regions to meet ICAP Obligations• The Settlement for each Participant in each ICAP Region will be

based on: Resources cleared in the Spot Auction Bilateral transactions Capacity traded through the ICAP Supply Auction Final capacity obligation as determined through the use of regional

demand curves CTRs    

33

Demand Curve

$0.00

$7.70

$15.40

100% 105% 110% 115%

% of Capacity Requirement

2X Cost of New Entry

Cost of New Entry

100% (min. requirement)

gets $7.70

Capacity beyond this point, less than $7.70

Surplus capacity valued at $0

34

Demand Curve (cont’d)

– Sloped Demand Curve Determines the Amount of Capacity Needed to Ensure Reliability

– Demand Curve is Scaled for Each ICAP Region based on the Region’s ICAP Requirement

– Price Paid for Capacity is Based on the Cost of New Entry for a Generating Facility in each ICAP Region

• Based on a simple cycle frame unit

• Accounts for differing siting costs in the five regions

• When capacity levels become too low, assumes that consumers are willing to pay at least the cost of building a new power plant as a capacity payment

• Prices automatically decrease as capacity levels increase

35

Regional Spot Auction Clearing Example One

Cleared ICAP Supply/ICAP Requirement in Region

0

2

4

6

8

10

12

14

0.90 0.95 1.00 1.05 1.10 1.15 1.20

$/K

w-M

on

th

P1

Q1

36

Regional Market Clearing Example Two

0

2

4

6

8

10

12

14

0.90 0.95 1.00 1.05 1.10 1.15 1.20

$/K

w-M

on

th

P2

Q2

Cleared ICAP Supply/ICAP Requirement in Region

Settlement of the Auctions

38

LICAP Settlement Guiding Principles

• No ‘Participant Position’ in the Spot Auction

• Supply Auction – Regional / Virtual

• Bilateral Transactions – Increase or Decrease Obligation

• All supply must participate in the Spot Auction

• Payments for ICAP Supply will be adjusted for Availability and Peak Energy Rents

• Charges for ICAP Obligations will be adjusted by CTRs and the Demand Curve Adjustments

39

Settlement of Spot Auction

• Spot Auction bid deadline “locks down”: External Transactions Spot Auction Supply Offers Generation Ownership % changes

• Still available after Spot Auction bid deadline: Internal Bilateral Transactions Load Ownership % changes

2 business days required

• Participants are required to offer all Resources in their ICAP Supply into the Spot Auction

• Participants without a Supply portfolio will not bid into the Auction– IBTs and Supply Auction activity affect obligation – not supply – Participants in excess of their ICAP obligation will receive payment

based on the Spot Auction clearing price

40

Settlement of Spot Auction (cont’d)

• Demand curve may either increase or decrease capacity obligations

• Forward transactions (Bilaterals and Supply Auction activity) may be used to meet obligations, including those that result from the application of the Demand Curve

• Participants may wish to consider the impact of the use of demand curves on their expected final capacity obligation when determining future purchases of capacity

41

Settlement of Spot Auction (cont’d)

• Payments/Charges related to Participant’s ICAP Supply: Credit equal to the product of the Participant’s MW quantity of cleared supply and

the applicable ICAP Region clearing price Charge to Participants with cleared ICAP supply equal to the average Peak Energy

Rent earned by a benchmark generator in the ICAP Region for the most recent twelve months. PER is reported to Participant’s at the beginning of the Auction month

Charge to Participant’s with cleared ICAP Supply equal to the product of the Availability Rating of the Resource times the cleared MW amount times the ICAP Region’s clearing price. Availability Ratings will be known to Participants since they are based on each Resources rolling 12 month average at the beginning of the Auction month

Credit to Participant’s with cleared ICAP Supply equal to the product of the total inversion dollars and the ratio of the Participant’s Performance Based Payment (“PBP”) to the total PBP in the ICAP Region. The PBP is defined as the cleared ICAP Supply times the clearing price minus the PER adjustment minus the Availability Adjustment

A charge to Participant’s based on the sale of capacity to external control areas equal to the product of the contract amount and the difference between the Net Regional Clearing Prices in the sink and source regions

42

Settlement of Spot Auction (cont’d)• Payments/Charges related to Participant’s ICAP Requirements:

Credit/charge equal to the product of the Participant’s Adjusted ICAP Requirement and the Adjusted Net Regional Clearing Price (“ANRCP”)

The Net Regional Clearing Price (“NRCP”) is equal to the Total PBPs in the ICAP Region divided by the total Cleared ICAP Supply in the ICAP Region

Since CTRs are settled on the NRCP and cannot become a charge, the NRCP in Import Constrained Regions must be compared to the NRCP in the adjacent ICAP Region from which transfer is limited. The ANRCP = MAX (NRCP for Import Constrained Region, NRCP in adjacent ICAP Region)

Credit to Participants with Load Assets in the ICAP Region equal to the total payments made by Generators in the ICAP Region who are exporting capacity to New York

Credit/Charge equal to the product of the Demand Curve Differential and the Adjusted Net Regional Clearing Price. The Demand Curve Differential is equal to the product of the Demand curve Scaling Factor minus one and the Participant’s ICAP Requirement in the ICAP Region

A credit equal to the product of the difference in the ANRCPs between the ICAP Regions for which the CTR is defined and the capacity value of the CTR

Projected Market Clearing Prices

44

Projected ICAP Spot Auction Clearing Prices ($/kW-mo)

  2005 2006 2007 2008 2009 2010Southwest Connecticut $6.78 $7.88 $7.83 $6.66 $5.49 $6.69

Rest of Connecticut $4.61 $5.70 $7.83 $6.66 $5.49 $6.69

NEMA/Boston $4.93 $6.04 $5.83 $5.75 $5.49 $6.69

Rest of Pool $3.26 $4.04 $5.83 $5.75 $5.49 $6.69

Maine $3.26 $4.04 $5.83 $5.75 $5.49 $6.69

Total $4.57 $5.54 $6.63 $6.11 $5.49 $6.69

45

Projected Clearing Prices - Assumptions

• Load Growth = 1.3% (RTEP 04)• OC = 30,092 MW (includes additional 200 MW tie benefit)• Transmission:

SWCT Phase 1: 550 MW in 2007 NEMA1: 900 MW in 2007 SWCT Phase 2: 850 MW in 2009 NEMA2: 200 MW in 2009 SNERP: 900 MW in 2010

• Generation Summary: Kendall Retirement (187 MW) in NEMA in 2007 New Boston Retirement (352 MW) in 2007 Kleen Power 620 MW in ROC in 2009 Peabody 140 MW in NEMA in 2009 New Entry in Year Following the Market Clearing at EBCC

46

Projected Clearing Prices – Assumptions (cont’d)

• Capacity Imports: Cross Sound Cable: Up to 150 MW when CT above $8.00 (This price is not reached in these scenarios) New York Interface: Up to 600 MW when ROP above $5.00 (Case results – 200MW-2007, 400MW-2008) Maine-New Brunswick: Up to 200 MW when Maine is above $3.00

(Case results 100MW-2007, 200MW-2008)

• DSM: At $5.00 DSM enters, 2% of peak in year following $5.00 (Case

results - SWCT & CT 80 MW each-2007)

• RMR Offset: In 2006 RMR Offset Equals Current/Proposed Contracts Over 2007-2009 RMR Grows Based on Contracts to all Combined

Cycles, CT's, and Jets

Load Shifting

48

Load Shifting by Region

• In areas where retail choice is an option, load shifting may occur

• As customers shift from one supplier to another, the peak load with the customer shifts with them

• Load-Shifting adjustments will be made monthly Based on the data submission of Daily ICAP Peak Contribution

value by Host Utility Meter Readers

• ISO-NE will adjust the requirement for each Participant such that the total ICAP requirement in the ICAP Region remains constant and that an individual Participant's requirement reflects the same gains and losses

49

Financial Arrangements to Cover Load Shifting

• Financial accounting for Load Shifting will be performed on or about the 6th of the month following the Obligation month

• The process steps by ISO will include: Track the shifts in ICAP responsibility throughout the month

and determine the deviation in a Participant’s requirement Participants who, on net, see an increase in their ICAP

Requirement during the month are charged for that increase Participants who, on net, see a decrease in their ICAP

Requirement during the month will be paid for that decrease

50

Example: Accounting for Load Shifting

• Information determined from earlier calculations: Region 1 Spot Auction Clearing Price = $500/MW-mo Region 2 Spot Auction Clearing Price = $200/MW-mo

• Given the following Daily ICAP Peak Contribution Value for Participant A: Asset Name: Load L1 Ownership = 100% Day 1 to 10 = - 102.5 MW Day 11 to 30 = - 97 MW

51

Example: Table

DayDayDaily ICAP Peak Daily ICAP Peak

Contribution ValueContribution Value Actual ICAPActual ICAP Historical ICAPHistorical ICAP Daily DeviationDaily Deviation

1 -102.5 -100 -100 0.0

2 -102.5 -100 -100 0.0

10 -102.5 -100 -100 0.0

11 -97 -94.634 -100 5.366

12 -97 -94.634 -100 5.366

29 -97 -94.634 -100 5.366

30 -97 -94.634 -100 5.366

52

Example: Accounting for Load Shifting

• Step 1: Determine ICAP Deviation

• ICAP Deviation: Day 1 to 10 = 0 MW Day 11 to 30 = 5.36585 MW

• ICAP Deviation for the month = (10 x 0) + (20 x 5.36585) = 107.31707 MW

53

Blended Price for Load Shifting

• Step 2: Apply Blended Price

• Weighted average of the clearing prices in the source and sink locations: Source Locational Clearing Price * Transfer Limit / Sink ICAP Requirement Plus Sink Locational Clearing Price * (Sink ICAP Requirement – Transfer Limit) / Sink ICAP Requirement

• For Region I, the calculation is:= ($200 * -50/-200) + ($500 * [-200 - (-50)] / -200)= 50 + 375 = $425

54

Calculate Load Shift Payment/Charge

• Step 3: Calculate Load Shift Payment/Charge:

• Load Asset L1 is 100% owned by Participant A• Sum of Daily ICAP Deviations = 107.31707 MW• Number of Days in Month = 30• Daily Average Deviation = 107.31707 / 30 = 3.57733 MW

• Load Shift Payment / Charge = Daily Average Deviation * Blended Price * Demand Curve Scaling Factor

= 3.57733 x $ 425 x 98% = $ 1,489.92

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90-Day Resettlement

• Host Participants may resubmit Daily UCAP Peak Contribution Values within the 90-day period

External Contract Submittal (through 18th)

Accounting for June

Load Shifting

Internal Contract Submittal (through 25th)

JulJul

GADSData

submitted for March

AprApr

2020

Use first day of the month UCAP Peak

Contribution to calculate Monthly Requirement

for June

Annually on May 1: Submit UCAP Peak Contribution for the

crossover year

Monthly requirement MIS reports

published

Supply Auction results

published for June (supply

offers and demand

bids) Spot Auction Settlement MIS

reports published

De-listing for next Obligation Month due (2 business days prior to next Obligation Month)

Spot Market

MIS reports

published

Bid window for IBTs closes

Bid window closed for

Spot Auction (excluding

IBTs)

MM review & mitigation process begins

MayMay

11 1212 1717 1818 2525 2626 2727

BillJune

Supply Auction

and Spot Auction

JunJun

1717 77 1515

Note: Days shown are calendar days

Bill Accounting

for June Load

Shifting

AugAug SepSep OctOct NovNov

1414 1111

Last day to submit

changes to June UCAP

Peak Contribution

Bill 90-day Resettlement for June Load

Shifting (UCAP Peak Contributions

only)