April 8, 2014 | Markets Committee

APRIL 8, 2014 | MARKETS COMMITTEE

Catherine McDonough [email protected] | 413-535-4027

Strengthen Incentive for Load to participate in the Day-Ahead Energy Market (‘DAEM’)

NCPC Cost Allocation: Phase 1

mailto:[email protected]

Outline

• Summary of Proposal/Key Driver

• Reallocate Charges Based on ‘Beneficiary Pays Principle’

• Proposal is Narrowly focused on Load Participants

• Response to Participant Questions/Concerns

• Proposed Tariff Language

• Next Steps

• Appendix : Material Posted at Prior MC Meetings

Summary of Proposal/Key Driver

• Exclude positive load deviations (DA>RT) from NCPC charges to strengthen the incentive for load (exports, load, decrements) to participate in DAEM so that more units will be committed Day-Ahead

• Driver: Committing more units Day-Ahead improves reliability– Improves the ability and willingness for cleared generation to

acquire/schedule fuel – Ensures operational readiness of units to meet their expected

schedule

• Narrow scope can be implemented before winter (2014/15) and provides better signals to market than existing cost allocation

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Reallocate Charges Based on ‘Beneficiary Pays’

• Allocate excluded RT 1st Contingency NCPC charges to load based their pro-rata share of Real-time Load Obligation(‘RTLO’)

• Why? – All load benefits from having resources scheduled to

ensure the reliable operation of the system regardless of whether load is cleared DAEM. Allocating a portion of the real time NCPC costs to RTLO is based on the ‘beneficiary pays principle’

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Proposal is Narrowly Focused on Load Participants

• Narrow scope of this solution can be implemented prior to next winter and will incrementally improve the reliability of the system relative to the current cost allocation method.

• Phase 1 proposes no change in how NCPC costs are allocated to any other NCPC deviations (negative load, generation, increments or import deviations)

• The ISO continues to work through a more comprehensive cost causation analysis related to real time NCPC and is expected to begin discussions with stakeholders late 2014/ early 2015

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RESPONSE TO PARTICIPANT QUESTIONS/CONCERNS

Response to Participant Question/Concern: #1

• How does the Phase 1 proposal improve the incentives for a participant who is currently bidding its RTLO with 100% accuracy in the DAEM? A: With Phase 1 in place, this participant will be charged for a portion

of RT 1st Contingency NCPC credits based on the ‘beneficiary pays principle.’ The participant still has an incentive to bid their RTLO in the DAEM; otherwise they will assume an added NCPC charge for negative load deviations.

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• Would a participant that currently clears its expected RTLO in the DAEM be worse off with this proposal?

A: As shown in the following examples, participants who bid their expected RTLO into the DAEM (equal number of positive and negative load deviations) can lower their NCPC charges under the Phase 1 proposal.

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Example: Participants who bid expected RTLO in the DAEM can benefit from Phase 1

•Assumptions: Same as Base Case (See Slide 31) except Participant A has the same number of positive (7) and negative load deviations (-7)

•Implication: RT 1st Contingency NCPC charges to Participant A are lower when their pro-rata share of positive load deviations is greater than their pro-rata share of RTLO .

Case 5 Participant A B C D Total Proposed*- Current Method (7)$ 7$ -$ -$ -$

% Change PROPOSED vs. CURRENT -21% 21% 0% 0% 0%*Assumes no change in behavior

NCPC deviations (participant) /NCPC deviations (all participants) 23% 23% 23% 32% 100%Impact Driver (+) load devs. (participant)/ (+) load devs. (all participants) 58% 8% 33% 100%

RTLO (participant) / RTLO (all participants) 33% 33% 33% 100%

Control (+) load devs. (participant)/load devs (participant) 50% 7% 29%

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Example: Participants who bid expected RTLO in the DAEM can benefit from Phase 1

•Assumptions: Same as Base Case (See Slide 31) except that Participant A has a lower RTLO (60 MW), lower total NCPC deviations (6) with an equal number of positive and negative load deviations. We also further that Participant B has an equal number of positive (7) and negative load deviations (-7).

•Implication: RT 1st Contingency NCPC charges to Participant A and B are lower when their pro-rata share of positive load deviations is greater than their pro-rata share of RTLO .

Case 6 Participant A B C D Total Proposed*- Current Method (1)$ (4)$ 5$ -$ -$

% Change PROPOSED vs. CURRENT -6% -9% 12% 0% 0%*Assumes no change in behavior





• Several participants expressed concern that the Phase 1 proposal will cause RTLO to consistently over clear in the DAEM.

A: Market forces will prevent this outcome. Phase 1 creates an incentive for participants clear their expected load in the DAEM. The proposed allocation of NCPC costs creates an incentive for individual participants to err on the side of over-clearing load in the DAEM. But the downward real-time price impact from any systematic over-clearing will curb the incentive for participants to systematically over clear load in the DAEM. The participation of virtual transactions will also prevent load from consistently over-clearing in the DAEM.

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• Some participants expressed concern that strengthening the incentive for load to bid in the DAEM will offset part of the expected financial gain from their strategy to purchase a portion of their RTLO in real-time – A: This is exactly the point. By strengthening the

incentive to clear load in the DAEM, the Phase 1 proposal will help to improve reliability by reducing the fuel-procurement and operational challenges.

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PROPOSED TARIFF LANGUAGE

Proposed Tariff Language

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III.F.3.1.2 * (g) All remaining NCPC costs for the Real-Time Energy Market are allocated and charged to Market Participants based on their pro rata daily share of the sum of the absolute values of a Market Participant’s (i) Real-Time Load Obligation Deviations in MWhs during that Operating Day, subject to the additional charge requirement specified in (h) below; (ii) generation deviations for Pool-Scheduled Resources not following Dispatch Instructions, Self-Scheduled Resources with dispatch able increments above their Self-Scheduled amounts not following Dispatch Instructions, and Self-Scheduled Resources not following their Day-Ahead Self-Scheduled amounts other than those Self-Scheduled Resources that are following Dispatch Instructions, including External Resources, in MWhs during the Operating Day; and (iii) deviations from the Day-Ahead Energy Market for External Transaction purchases in MWhs during the Operating Day. The Real-Time deviations calculation is specified in greater detail in Section III.F.3.2.

* Proposed changes to implement Phase 1 shown in blue on top of the revised tariff language that clarifies the existing method to allocate NCPC Costs

Proposed Tariff Language (continued)

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* Proposed changes based on discussion at last MC meeting are shown in red

Proposal Summary and Next Steps

• Exclude positive load deviations from NCPC charges to strengthen the incentive for load to participate in the day-ahead energy market

• Proposed changes targeted for implementation with Offer Flexibility Changes in Q4 2014

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Date Committee ActionDecember 2013 Markets Committee Introduce Proposal

February 2014 Markets Committee Discuss Proposal

March 2014 Markets Committee Discuss Proposal; Review Rules

April 2014 Markets Committee Discuss Proposal; Review Rules

May 2014 Markets Committee Vote Proposal

APPENDIX A Materials Presented at Previous MC Meetings

BACKGROUND

Current Allocation Approach for RT NCPC Costs

Reason NCPC Credits Paid Allocation Metric Allocation Interval

1st Contingency System-wide RT NCPC Deviations Daily Local Second Contingency Protection Resource (‘LSCPR’)

Locational Real Time Load (‘RTLO’) Daily

Voltage, Ampere, Reactive (‘VAR’) System-wide Network Load* MonthlySpecial Constraint Resources (‘SCR’) Transmission Owner Daily

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* For more detailed description of how these costs are allocated reference Schedule 2 of the OATT

NCPC credits are paid when real time energy market revenue is not sufficient to recover the cost associated with an accepted supply offer

Historical Allocation of Real-Time NCPC Costs

Reason NCPC Credits Paid 2010 2011 2012 2013* Total

1st Contingency $73.4 $50.3 $48.5 $55.4 $227.7 LSCPR $3.8 $5.7 $8.2 $30.4 $48.1 VAR $3.6 $0.9 $2.7 $1.4 $8.6 SCR $1.6 $3.4 $3.7 $5.2 $13.9 Totals $82.5 $60.3 $63.1 $92.5 $298.3

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* Includes data from January through October 2013

All values in Millions $

Real-time NCPC Deviations Used to Allocate real-time 1st Contingency NCPC Costs

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Historical Allocation of Real-time 1st Contingency NCPC costs

RT NCPC Deviations 2010 2011 2012 2013* Total ($) Total (%)

Positive Load (RT<DA) $18.8

$11.5 $9.2 $7.4 $46.9 21%

Negative Load (RT>DA) $33.9 $ 20.8 $23.2 $ 27.0 $ 104.9 46%

Generation $6.5 $6.3 $6.3 $9.8 $28.9 13%

Import $6.1 $5.2 $5.7 $7.5 $24.5 11%

Increment $8.1 $6.5 $4.1 $3.8 $22.5 10%

Totals $73.4 $50.3 $48.5 $55.4 $227.7 100%

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All values in Millions $

* Includes data from January through October 2013

PROBLEM/CONCERN

Summary of Problem/Concern

• Real-time Load Obligation (‘RTLO’) is generally greater than the amount of load cleared in the DAEM – 91% of peak-hour real-time load generally clears in the DAEM – About 70% of DA/RT load deviations are negative (RT>DA)– Virtual transactions--especially Decrements – down since 2010/2011

• ISO frequently needs to commit more units in Resource Adequacy Analysis (‘RAA’) or in Real Time to meet load that does not clear in the DAEM – Reduces efficiency of the unit commitment and dispatch process– Later notice can make it more challenging for generators to start and

to procure fuel-especially during winter months—which reduces the time available for ISO System Operators to devise alternative plan

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Participants tend to under-clear load in DAEM

Historical Daily Averages (2012-2013)

Percent of RTLO (peak-hour) Cleared Day Ahead* 91%*Includes Load Bids + DECs -INCs

NCPC load deviations (MW) 40,732

Positive NCPC load deviations (DA>RT) (MW) 12,586 Positive NCPC load deviations /NCPC load deviations 31%

Negative NCPC load deviations (RT>DA) MW 28,146 Negative NCPC load deviations / NCPC load deviations 69%

RTLO (MW) 367,856

Negative NCPC load deviations/RTLO 8%Positive NCPC load deviations /RTLO 3%NCPC load deviations/RTLO 11%

Real Time Load Exceeds Load Cleared in DAEM

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70%

75%

80%

85%

90%

95%

100%

105%

110%

115%

1-Jan-10 1-May-10 1-Sep-10 1-Jan-11 1-May-11 1-Sep-11 1-Jan-12 1-May-12 1-Sep-12 1-Jan-13 1-May-13 1-Sep-13

Percent of RTLO (peak hour) cleared in DAEM*

60 day Moving Average

* Includes Cleared DA Load Bids (Fixed and Price Sensitive) + DECs - INCs

PROPOSED SOLUTION

Proposed Solution: Modify NCPC Cost Allocation Phase 1

• Allocate RT 1st Contingency NCPC charges associated with positive real-time load deviations to participants based on their real-time load obligation (‘RTLO’)* – No change in how we allocate RT 1st Contingency NCPC charges to negative

load deviations or other NCPC deviations – No change in how we calculate NCPC deviations– RTLO excludes DARD pumping load & load from non-pumping DARDs that

follow dispatch

• Expected Benefits – Stronger incentive for load (exports, load, decrements) to participate in DAEM

– Addresses concerns regarding the reduction in virtual transactions – Complements other changes the ISO has proposed– Can be in place for Winter (2014/15)

• Comprehensive review of the current method used to allocate NCPC costs may result in broader set of changes in Phase 2 (discussions to begin in 2015)

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RT 1st Contingency NCPC Cost Allocation Current Method

1. NCPC deviation charge rate (daily) = RT 1st Contingency NCPC charges (daily) / Total NCPC deviations (daily)

2. RT 1st Contingency NCPC charges (participant, daily) = NCPC deviation charge rate (daily) x NCPC deviations (participant, daily)

Note: All NCPC deviations are charged the same ($/MW) rate

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Example : Current MethodBase Case *

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*Base Case assumes that all Load Participants have the same load deviations and RTLO MWs. We relax these assumptions in the examples shown in the Appendix A.

(a) (b) (c) (d) (e)

(1) RT 1st Contingency NCPC charges for Dec 31st 154$ Participant

A B C D Total Load Load Load Other

(2) NCPC deviations 14 14 14 20 62 (3) = (1a)/(2e) NCPC deviation charge rate 2.48$

(4)=(2)x(3e) RT 1st Contingency NCPC charges (CURRENT METHOD) 35$ 35$ 35$ 50$ 154$

RT 1st Contingency NCPC Cost Allocation Proposed Method (Phase 1)

1. RT 1st Contingency NCPC charges (participant, daily) = NCPC deviation charge rate (daily) x NCPC deviations (participant, daily)

except positive NCPC load deviations (DA>RT)

2. Total RT 1st Contingency NCPC charges for RTLO =NCPC deviation charge rate (daily) x positive NCPC load deviations (daily)

3. NCPC load charge rate (daily) =Total RT 1st Contingency NCPC charges for RTLO/ Total RTLO

4. RT 1st Contingency NCPC load charge (participant, daily) = NCPC load charge rate (daily) x RTLO (participant, daily)

*Parts of the allocation method that change with the Phase 1 proposal shown in blue

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Example: Proposed Method (Phase 1)Base Case

NCPC deviation charge rate is the same as w/ current method: See Slide 8

(a) (b) (c) (d) (e) (1) RT 1st Contingency NCPC Credits for Dec 31st 154$

Participant A B C D Total

Load Load Load Other (5) Negative NCPC load deviations (MWs) 6 13 10 NA (6) NCPC Non-load deviations (MWs) 20

(7)=(5)+(6) NCPC deviations (MWs) 6 13 10 20 49(3) RT 1st Contingency NCPC charge rate 2.48$

(8)=(6)*(3e) RT 1st Contingency NCPC deviation charges 15$ 32$ 25$ 50$ 122$

(9) Positive NCPC load deviations (MWs) 8 1 4 NA 13(10)= (9)*(3e) Total RT 1st Contingency NCPC charges for RTLO 32$

(11) RTLO (MWs) 130 130 130 NA 390(12)=(10e)/(11e) NCPC load charge rate 0.08$ (13)=(11)*(12e) RT 1st Contingency Load Charges* 11$ 11$ 11$ -$ 32$

(14)=(8)+(13) Total RT 1st Contingency NCPC charges (PROPOSED METHOD) 26$ 43$ 36$ 50$ 154$ *Total displayed is off by 1 due to rounding

Example: Proposed vs. Current Method

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Participants whose pro-rata share of positive load deviations > pro-rata share of RTLO allocated less RT 1st Contingency NCPC charges Participants whose pro-rata share of

positive load deviations < pro-rata share of RTLO allocated more RT 1st Contingency NCPC charges Impact of Phase 1 change is smaller when

the difference between pro-rata shares of (+) load deviations and RTLO is smaller

Base Case Participant A B C D Total Proposed*- Current Method (9)$ 8$ 1$ -$ -$





Summary: What does the Phase 1 Proposal change?

• No change in the way Generators, Imports, Increments and Negative NCPC load deviations are charged for NCPC

• Reallocates ~20% of RT 1st Contingency NCPC charges to RTLO instead of positive NCPC load deviations (DA>RT)

• NCPC charges will be lower for participants whose pro-rata share of positive NCPC load deviations is greater than their share of RTLO

• NCPC charges will be higher for participants whose pro-rata share of positive NCPC load deviations is less than their share of RTLO

• NCPC charges for Decrements (‘DECs’) will be zero

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SCENARIO ANALYSIS

Case 1*: Neutral impact on Participants whose pro-rata share of (+) load deviations = pro-rata share of RTLO

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*Assumptions: Same as Base Case except Participant 3 has lower RTLO (115 vs. 130 MW )

Implication: Pro-rata share of positive load deviations = pro-rata share of RTLO for participant C; Phase 1 has no impact on RT 1st Contingency Charges for Participant C

Case 1 Participant A B C D Total Proposed*- Current Method (9)$ 9$ (0)$ -$ -$





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Case 2*: Decrements will have zero NCPC charges

*Assumptions: Same as Base Case except Participant 3 is a cleared virtual demand bid (DEC) for 1 MW; positive load deviation = 1 MW and RTLO = 0

Implication: Participant 3 has no RT 1st Contingency NCPC charges

Case 2 Participant A B C D Total Proposed*- Current Method (9)$ 13$ (3)$ -$ -$

% Change PROPOSED vs. CURRENT -21% 29% -100% 0% 0%*Assumes no change in behavior




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Case 3*: Share of NCPC charges allocated to RTLO rises w/share of positive load deviations

•Assumptions: Same as Base Case except Participant C has lower RTLO (115 vs. 130 MW ) and NCPC load deviations for all participants are positive

•Implication: RT 1st Contingency NCPC Charges allocated based entirely on RTLO; Participants A and B pay more and Participant C pays less

Case 3 Participant A B C D Total Proposed*- Current Method 1$ 1$ (3)$ -$ -$

% Change PROPOSED vs. CURRENT 4% 4% -8% 0% 0%*Assumes no change in behavior




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Case 4*: Reducing negative load deviations alone may not reduce RT 1st Contingency NCPC charges

•Assumptions: Same as Base Case except Participant C has no negative load deviations ; Participant C’s load deviations = 4 instead of 14.

•Implication: RT 1st Contingency NCPC charges to Participant C are higher because the pro-rata share of positive load deviations is less than their pro-rata share of RTLO .

Case 4 Participant A B C D Total Proposed*- Current Method (11)$ 10$ 1$ -$ -$





MARKET ANALYSIS

Summary of Impacts

• No change in RT 1st Contingency NCPC deviation charge rate; generators, Imports, Increments and negative NCPC load deviations will be charged the same as today

• Phase 1 reallocates ~20% of RT 1st Contingency NCPC charges to RTLO instead of to positive load deviations; If positive load deviations rise over time, the share of RT 1st Contingency NCPC charges allocated to RTLO will also rise

• RT 1st Contingency NCPC charges will be lower for participants whose pro-rata share of positive load deviations is greater than their pro-rata share of RTLO

• RT 1st Contingency charges for Decrements (‘DECs’) will be zero because DECs create only positive load deviations and have no associated RTLO

• Participants may be able to reduce RT 1st Contingency NCPC charges by bidding their expected load in the DAEM; i.e. increase the share of positive load deviations

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RT 1st Contingency NCPC charge rates

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RT 1st Contingency NCPC deviation charge rate ($/MW of NCPC deviation)

Year Average Minimum Median Maximum St.Dev. 2010 2.06 0.00125 0.62 17.94 3.202011 1.64 0.00032 0.45 22.78 3.182012 1.75 0.00033 0.58 18.84 2.872013 2.47 0.00074 0.41 44.33 5.54

2010-2013 1.98 0.00032 0.49 44.33 3.86

Proposed* RT 1st Contingency NCPC load charge rate ($/MW RTLO)

Year Average Minimum Median Maximum St.Dev. 2010 0.12 0.00014 0.04 1.34 0.202011 0.08 0.00002 0.02 3.08 0.242012 0.07 0.00001 0.02 1.88 0.152013 0.06 0.00004 0.01 2.06 0.15

2010-2013 0.08 0.00001 0.02 3.08 0.19

* Based on the historical level of positive NCPC load deviations and RTLO

Historical Daily Averages 2012-2013

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RT 1st Contingency Charges 154,675$

NCPC deviations (MW) 61,887 NCPC load deviations (MW) 40,732 NCPC load deviations (MW)/ NCPC deviations (MW) 66%

Positive NCPC load deviations (DA>RT) (MW) 12586Positive/NCPC load deviations 31%Positive NCPC load deviations /NCPC Deviations 20%

Negative NCPC load deviations (RT>DA) MW 49,301 Negative NCPC load deviations / NCPC load deviations 69%

RTLO (MW) 367,856

Negative NCPC load deviations/RTLO 8%

Positive NCPC load deviations /RTLO 3%

NCPC load deviations/RTLO 11%

RESPONSE TO PARTICIPANT QUESTIONS

Response to Participant Questions

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Response to Participant Questions (continued)

• Could the under-bidding of RTLO in the DAEM be due to the ISO’s load forecast? A: The ISO’s daily peak load forecast posted prior to close of the DAEM

bidding window is slightly above 100% on average,

• Is it optional for participants to bid load in the DAEM ? A: Yes. The ISO simply wants to strengthen the incentive for participants

to exercise this option because it helps to lower system costs and improve reliability with the new energy mix that characterizes the current generation fleet.

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April 8, 2014 | Markets Committee

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