The Future of Price Responsive Demand in New England

The Future of Price The Future of Price Responsive Demand Responsive Demand

in New Englandin New England

On Behalf of the Consumer Demand Response Initiative

May 13, 2009Consumer Demand Response

Initiative 2

GENERAL PURPOSE*

Maximize Consumer Surplus= Safe and Reliable Service at Just and Reasonable Rates

DESIGN PRINCIPLES*

•SAVINGS PRINCIPLE

•COMPETITIVE PRINCIPLE

*As fully described in “Defining the Product”


Initiative 3

1. Product Description

2. Dispatch Algorithm

3. Settlement Algorithm

4. Baseline Proposal

FOUR PARTS


Initiative 4

PRODUCT

Changes in consumption that increase consumer surplus.

Generation-Changes in production that increase consumer surplus

Comparability:


Initiative 5

KWhrs or KWs of deviation from consumption that would occur without compensation.

BILLING UNITS

Long Term-Short Term/negative clearing prices/generators allowed to collect payments without “but for” test.

Generation-KWhrs or KWs of deviation from production that would occur w/o compensation.

Comparability:

Discussion:


Initiative 6

Any load that can provide a consumption deviation that increases consumer surplus.

ELIGIBILITY

Comparability:

Any generation that can provide a production deviation that increases consumer surplus.

The Difference from ISO Theory: ISO theory worse than their actual practice. Market rules for generation designed to

increase consumer surplus.


Initiative 7

The price that will maximize consumer surplus

PRICE PER UNIT

By law: The price that will maximize consumer surplus.

In practice: The price that most closely resembles the result of a perfectly competitive market; i.e. the price that maximizes consumer surplus.

Discussion: Market Monitoring/market bid rules/RMR.

Comparability:


Initiative 8

When bids clear, ISO dispatches through Lead Market Participant.

EVENT ACTIVATION-NOTIFICATION

When bids clear ISO dispatches through Lead Market Participant.

Comparability:


Initiative 9

MEASUREMENT AND VERIFICATION

Deviation from consumption that would have occurred absent compensation (Customer Baselines): Interval Meter/Load profiling.

Comparability:

Deviation from Production that would have occurred absent compensation (generator baseline assumed usually to be 0).


Initiative 10

COST ALLOCATION: WHO PAYS?

Consumers in the Day Ahead or Real Time Market who receive the benefit of the change in consumption.

Comparability:

Consumers in the Day Ahead or Real Time Market who receive the benefit of the change in production.


Initiative 11

1. Allow non-LSE mediated supply-side bids for DR to be integrated into Day Ahead market.

2. To incorporate all costs and savings from Day Ahead dispatch of DR into Day Ahead Settlements.

3. To allow all Day Ahead Generation Resources to be dispatched in merit order.

4. To allow all Day Ahead DR to be dispatched in merit order.

5. To dispatch the lowest overall cost mix of resources to satisfy Day Ahead demand.

6. To eliminate the “missing money” problem identified by ISO in Real Time settlements.

STRATEGIC GOALSSTRATEGIC GOALS


Initiative 12

DISPATCH AND PRICING ALGORITHM BASIC APPROACH

1. Day Ahead dispatched DR is paid on an “as bid” basis.

2. Incremental cost of DR resources are spread over Day Ahead load to determine Day Ahead price paid by load.

3. Generation is paid based on clearing price without incremental adder.

4. Generation paid on basis of last cleared bid from either DR or generation resource.


Initiative 13

ADVANTAGES

1. Incorporates all costs of Day Ahead supply and all benefits into Day Ahead price.

2. Provides cost (to ratepayers) based screen to DR resources bidding in low load hours or in “flat” portions of supply curve.

3. Eliminates need for “floor bids” established by ISO and reduces exposure of all loads to payments in potential “gaming” situations.

4. Allows non-LSE mediated participation.

5. Permits participation of DR on supply side.


Initiative 14

THE QUESTION OF COMPARABILITY

• “As Bid” payment for DR is not “the same” as the payment regime for generation. How can it be comparable?

• Comparability (like efficiency) must be judged in terms of the objective to be achieved.

Our objective is to set the price to Maximize Consumer Surplus.

The price regime that Maximizes Consumer Surplus for DR may be different from the price regime that Maximizes Consumer Surplus for generation.

Thus, the pricing regimes may be different and yet be comparable in terms of providing the desired service.


Initiative 15

CONSIDERATIONS FOR DETERMINING COMPARABILITY IN THIS CASE

• Billing Unit effects of DR.

Need for workable dispatch algorithm.

Optimizing amount of DR, particularly in high priced hours to Maximize Consumer Surplus.


Initiative 16

THE NEED FOR A WORKABLE DISPATCH ALGORITHM

• Will a mathematically unique and stable solution emerge if clearing price is used?

Iterative effects of the billing unit adder.

Could a change in clearing price potentially “undispatch” previously in merit DR?

• Will the optimal amount of DR be dispatched in high cost hours?

Cost curves of DR resources; opportunity cost.

Cumulative effect of adder as more DR is dispatched.


Initiative 17

WE DO NOT HAVE DEFINITIVE ANSWERS TO THESE QUESTIONS YET

Therefore, for the purpose of illustration and to encourage further

discussion, we adopt the “As Bid” approach in the following examples.


Initiative 18

THE DAY AHEAD PRICING AND DISPATCH ALGORITHM

The Savings Principle:The Savings Principle:

Customers should pay for Demand Response up until the point that the incremental payment for DR exceeds the incremental benefit of the next unit of such services

Under the Day Ahead pricing algorithm, DR is paid on an “as bid” basis. The incremental cost of DR resources is spread over Day Ahead load adjusted for the billing unit effects of DR implementation. The pricing algorithm works by comparing possible Day Ahead bid stacks to determine which dispatch results in the cheapest Day Ahead Price. The lowest Day Ahead Price on a per billing unit basis maximizes consumer surplus, consistent with the Savings Principle. The algorithm generates a price, which we shall call the “Day Ahead Price” (to distinguish it from the “clearing price”), which is paid by all load cleared Day Ahead. Non-DR supply-side resources are paid based on the clearing price without this incremental, billing unit adjustment.


Initiative 19

THE “DAY AHEAD PRICE”

The price paid by load in any hour for each MW of load cleared Day Ahead is called the “Day Ahead Price” and is calculated as follows:

Where

DARR=Day Ahead Revenue Requirement. The Day Ahead Revenue Requirement for a dispatch interval is the total cost of paying all dispatched generation the clearing price, plus paying all dispatched Demand Response resources their bid price.

DAL=Day Ahead Load, the full amount of load bid in Day Ahead that clears.

DADR=Day Ahead Demand Response, the Megawatt value of all Demand Response resources dispatched to serve the Day Ahead load.

DAP=The Day Ahead Price.

=DAPDARR

DAL-DADR


Initiative 20

LOW LOAD EXAMPLES

Gen 5-100MW $130

Gen 4-100MW $120

Gen 3-100MW $100

DR2-100MW $90

Gen2-100MW $80

DR1-100MW $50

Gen1-100MW $25

RESOURCE STACK

Resource Bid


Initiative 21

LOW LOAD EXAMPLE 1: 200 MW CLEARED DA

Revenue Requirement

Resources

Revenue Requirement

Resources

$5,000 100MW-$50 DR1 (as bid)

$8,000 100MW-$80 Gen 2

$5,000 100MW-$25 Gen1

$8,000 100MW-$25 Gen 1

DARR=$10,000DAL-DADR=100MW

Day Ahead Price=$10,000100MW =$100.00/MW

DARR=$16,000DAL-DADR=200 MW

Day Ahead Price=$16,000200MW=$80MW

DISPATCH 1 DISPATCH 2

In this very low load situation, although the total effect of dispatch of DR on Day Ahead revenue requirement results in overall savings, the burden on all other customers who do not interrupt as calculated by the Day Ahead Price is higher than if all customers had simply been served by dispatch of the next available generating unit. In this case, the algorithm identifies a lower Day Ahead Price for using all generation, rather than using DR in the mix.


Initiative 22

LOW LOAD EXAMPLE 2: 400 MW CLEARED DA

DISPATCH 1 DISPATCH 2 DISPATCH 3

Revenue Requirement

Resources Revenue Requirement


Resources

$9,000 100MW-$90 DR 2 (as bid)

$10,000 100MW-$100 Gen 3

$12,000 100MW-$120 Gen 4

$9,000 100MW-$80Gen2 $10,000 100MW-$80 Gen2

$12,000 100MW-$100Gen 3

$5,000 100MW-$50DR1 (as bid)

$5,000 100MW-$50 DR 1 (as bid)

$12,000 100MW-$80Gen 2

$9,000 100MW-$25Gen 1

$10,000 100MW-$25 Gen1

$12,000 100MW-$25 Gen1

DARR=$32,000 DAL-DADR=200MW

DAP=$32,000200MW=$160.00MW


DAP=$35,000300 MW=$116.50


DAP= $18,000400MW=$120.00

In this instance, even with the incremental effect on prices to other customers caused by the dispatch of DR in Dispatch 2, it is still a cheaper solution in terms of the Day Ahead Price than dispatching only generation as illustrated by comparison of Dispatch 2 and Dispatch 3. It is also cheaper in terms of overall revenue requirements.


Initiative 23

HIGH LOAD EXAMPLES

Gen 5-100MW $130

Gen 4-100MW $120

Gen 3-100MW $100

DR 2-100MW $90

Gen 2-100MW $80

DR 1-100MW $50

Gen 1-100MW $25

Gen 0-1,000MW $24

RESOURCE STACK

Resource Bid


Initiative 24

HIGH LOAD EXAMPLE 1: 1,300 MW LOAD CLEARED DA

Revenue Requirement


Resources

$8,000 100MW-$80 Gen2 $10,000 100MW-$100 Gen 3

$5,000 100MW-$50 DR 1(as bid)

$10,000 100MW-$80 Gen 2

$8,000 100MW-$25 Gen 1 $10,000 100MW-$25 Gen 1

$80,000 1000MW-$24 Gen 0

$100,000 1,000MW-$24 Gen 0

DARR=$101,000DAL-DADR=1,200/MW

Day Ahead Price=$101,0001200MW =$84.17/MW

DARR=$130,000DAL-DADR=13,000/MW

Day Ahead Price=$130,00013,000=$100.00/MW

In this example, the Day Ahead Price[1] is $84.17 per MW under Dispatch 1 (which includes DR) and $100.00 per MW under Dispatch 2 (which includes only generation). All Day Ahead load is clearly better off under Dispatch 1.

[1] Calculated by dividing the Day Ahead Revenue Requirement (DARR) by the Day Ahead load minus Demand Response Resources (DAL-DADR).

DISPATCH 1 DISPATCH 2


Initiative 25

HIGH LOAD EXAMPLE 2: 1,400 MW LOAD CLEARED DA

Revenue Requirement

Resources

Revenue Requirement

Resources

Revenue Requirement

Resources

$9,000 100MW-$90 DR 2( as bid)

$10,000 100MW-$100 Gen 3

$12,000 100MW-$120 Gen 4

$9,000 100MW-$80 Gen 2

$10,000 100MW-$80 Gen 2

$12,000 100MW-$100 Gen 3

$5,000 100MW-$50 DR 1 (as bid)

$5,000 100MW-$50 DR 1 (as bid)

$12,000 100MW-$80 Gen 2

$9,000 100MW-$25 Gen 1

$10,000 100MW-$25 Gen 1

$12,000 100MW-$25 Gen 1

$90,000 100MW-$24 Gen 0

$100,000 1000MW-$24 Gen 0

$120,000 1000MW-$24 Gen 0


DAP=$122,0001200MW=$101.67/ MW


DAP=$135,0001300 MW=$103.85


DAP=$168,0001400MW=$120.00/MW

DISPATCH 1 DISPATCH 2 DISPATCH 3

In this example, Dispatch 1 yields the lowest Day Ahead Price. Comparing Dispatch 1 to Dispatch 2, we see the dispatch of additional DR, rather than generation, is

cheaper on a per MW basis even after the billing unit adjustment is made.


Initiative 26

WHERE ARE WE?

• Day Ahead price is lower in absolute terms than any other price per MW for all Day Ahead Load.

• Any LSE load cleared Day Ahead is receiving a lower price per MW even if DR does not occur in its footprint.

• Thus, even if every LSE wound up paying “full freight” for all its Day Ahead load, they are receiving lower cost Day Ahead service than otherwise.


Initiative 27

THE SETTLEMENT ALGORITHM AND THE “MISSING MONEY” PROBLEM

• The Missing Money problem is a billing unit problem.

• It is directly related to the billing unit effects of DR discussed in relation to the “Day Ahead Price” Algorithm.

Dispatch of DR reduces the billing units of load over which payment for resources is spread.


Initiative 28

10

Approach 3: PRD Integrated thru Supply OffersDemand (Bids) Supply (Offers)

Day-Ahead Energy MarketDemand - LSE A (MW) 10,000 Demand - LSE B (MW) 10,000 Generation (MW) 18,000 Demand Resources (MW) 2,000 Total 20,000 20,000 Clearing Price ($/MWh) 100.00$ Day-Ahead Payments/Charges 2,000,000$ 2,000,000$ Real-Time Energy MarketDemand - LSE A (MW) 8,000 Demand - LSE B (MW) 10,500 Generation (MW) 18,500 Demand Resources (MW) 2,000 Total 18,500 20,500 Real-Time DeviationsDemand - LSE A (MW) (2,000) Demand - LSE B (MW) 500 Generation (MW) 500 Demand Resources (MW) - Total Deviations (1,500) 500 Clearing Price ($/MWh) 100.00$ Real-Time Payments/Charges (150,000)$ 50,000$ Total Payment/Charges 1,850,000$ 2,050,000$ Variance 200,000$ "Missing Money"

Payments / Charges by ParticipantLSE A 800,000$ LSE B 1,050,000$ Generation 1,850,000$ Demand Resources 200,000$ Total 1,850,000$ 2,050,000$

© 2008 ISO New England Inc.

LSE RT Deviation = RT Load -DA Bid

LSE A RT Deviation = 8,000 MW – 10,000 MW = (2,000) MW

LSE B RT Deviation = 10,500 MW – 10,000 MW = 500 MW

Generation RT Deviation = 500 MW = additional generation needed to serve RT Demand.

*ISO New England presentation by Henry Yoshimura and Robert Laurita, January 7, 2009 Markets Committee Meeting, Slide No. 10.


Initiative 29

THE SOLUTION

• Price algorithm establishes a Day Ahead Revenue Requirement (DARR)

• The Day Ahead Price equals the price needed to collect the DARR from load cleared Day Ahead (DAL) minus the MW of DR cleared (DADR).

• Day Ahead Price =DARR

DAL-DADR


Initiative 30

THE SOLUTION (cont.)

1. Charge all load cleared Day Ahead (DAL) the Day Ahead Price (DAP).

This results in an overcollection of money (i.e. more than needed to pay the DARR).

The overcollection = DADR x DAP.

We will call this amount the “Reconciliation Account” (RA).


Initiative 31

THE SOLUTION (cont.)Remember:

The Day Ahead Price is absolutely lower than any other price per unit for all load cleared Day Ahead.

Therefore, even if we never returned this “overcollection” (the RA). All Day Ahead Load would still be receiving a lower price than otherwise.

However, we intend to return the RA to Day Ahead loads.

Because the RA is not needed in order to pay for all resources dispatched Day Ahead, we will return the RA to Day Ahead loads based on the following Settlement Algorithm


Initiative 32

THE SETTLEMENT ALGORITHM1. Total all negative Real Time load deviations for all LSEs who cleared in the Day

Ahead Market.

2. If total negative deviations for all LSEs who cleared in the Day Ahead market are equal to or less than the total Demand Response resources cleared Day Ahead, then:

i. Each LSE with a negative deviation receives the Day Ahead Price times its negative deviation from the RA and;

ii. Any money remaining in the RA is distributed pro rata to all Day Ahead load in proportion to the amount of load cleared Day Ahead by LSEs, i.e.;

3. If total negative Real Time deviations for all LSEs are greater than the total Demand Response resources cleared Day Ahead, then each LSE with a deviation receives a share from the RA based upon:

LSE Day Ahead Load

Total Day Ahead Load

LSE Negative Deviation

Total Negative Deviation


Initiative 33

THE PURPOSE OF THE SETTLEMENT ALGORITHM

To permit every LSE with load cleared Day Ahead that has a negative real time deviation to;

1.Be held harmless by a payment from the RA for that deviation or;

2.To have that deviation backed by a generation supply resource that can be settled in Real Time.


Initiative 34

THE SETTLEMENT ALGORITHM-EXAMPLES

For the sake of simplicity, all of these examples assume the following Day Ahead scenario:

1. Four LSEs each of whom have cleared 100MW of load Day Ahead.

2. The Day Ahead supply side resources cleared are:

a. 10MW of Demand Response and;

b. 390 MW of Generation.

In these examples, because all MW are priced at the Day Ahead Price, we do not attribute a particular price to the MW. We will assume the following five scenarios:


Initiative 35

ILLUSTRATIVE REAL TIME SETTLEMENT SCENARIOS CONSIDERED

Scenario 1: All of the Demand Response load reduction occurs in a single LSE and all of the other LSE’s have no deviation in Real Time from their Day Ahead share.Scenario 2: None of the Demand Response Load Reduction occurs in loads of one of the four LSEs who cleared Day Ahead. Rather, the reductions occur in an LSE that did not clear Day Ahead.

Scenario 3: The Demand Response load reduction occurs only partially in an LSE that cleared in the Day Ahead market.

Scenario 4: No one knows whose load Day Ahead demand response reduced in Real Time, but LSEs loads deviate from Day Ahead in a somewhat random fashion.

Scenario 5: No one knows whose load Day Ahead demand response reduced in Real Time, but all Day Ahead LSE loads go down and the total negative deviation is greater than the total Demand Resources bid in Day Ahead.


Initiative 36

SCENARIO 1All of the Demand Response load reduction occurs in a single LSE and all of the other LSEs have no deviation in Real Time from their Day Ahead share.

Day Ahead Load

Real Time Load

Deviation

LSE 1 100 MW 90 MW -10 MW

LSE 2 100 MW 100 MW 0 MW

LSE 3 100 MW 100 MW 0 MW

LSE 4 100 MW 100 MW 0 MW

TOTAL 400 390 -10 MW

Result:LSE 1 is paid 10 MW x Day Ahead Price from the RA. There is no Real Time Settlement beyond this.


Initiative 37

Scenario 1 Rationale: By charging the Day Ahead Price to all load bid in Day Ahead more money is collected than needed to pay for the resources dispatched. Because of the billing unit adjustment to the Day Ahead Price, only 390 MW of Day Ahead load needs to be charged the Day Ahead Price in order to fully recover the cost of all supply resources dispatched. We do not need to know, Day Ahead, which LSE or which combination of LSEs will actually see a load reduction caused by DR. Under the Algorithm, all LSEs hedge their full load at the Day Ahead Price. LSE1 is held harmless for the deviation in real time by settling its deviation at the Day Ahead Price, essentially refunding the extra money paid.


Initiative 38

SCENARIO 2None of the Demand Response Load Reduction occurs in loads of one of the four LSEs who bid in Day Ahead. Rather, the reductions occur in an LSE that did not clear Day Ahead.

Day Ahead Share

Real Time Load

Deviation

LSE 1 100 MW 100 MW 0 MW

LSE 2 100 MW 100 MW 0 MW

LSE 3 100 MW 100 MW 0 MW

LSE 4 100 MW 100 MW 0 MW

TOTAL 400 MW 400 MW 0 MW

Result:Each LSE is credited with 2.5 MW x Day Ahead Price from the RA. Real Time loads pay 10 MW uplift at Real Time price.


Initiative 39

Scenario 2 Rationale: Under the Day Ahead pricing algorithm Day Ahead loads have paid in full for 400MW of supply resources with 390 MW of billing units. The resources purchased include the Demand Response resource (which for purposes of this example we presume is performing as expected and reducing load). That Demand Resource did not happen to show up in their real time loads, but it is still “out there” performing and, per hypothesis, reducing real time load that would otherwise have occurred and have to be paid for by some combination of real time loads at the real time price. LSE 1, 2, 3 and 4 have each contributed equally to pay for the Demand Response resource that is “out there” reducing real time load for Real Time LSEs. Thus, a pro rata return of the over-collection based upon Day Ahead load share is appropriate for returning the over-collection.

*For more detailed rationale, see “Integration of Demand Response Into Day Ahead Markets-Supply Side Approach”


Initiative 40

SCENARIO 3

The Demand Response load reduction occurs only partially in an LSE that cleared in the Day Ahead market .

Day Ahead Share

Real Time Load

Deviation

LSE 1 100 MW 95 MW -5 MW

LSE 2 100 MW 100 MW 0 MW

LSE 3 100 MW 100 MW 0 MW

LSE 4 100 MW 100 MW 0 MW

TOTAL 400 MW 395 MW -5 MW

Result: LSE 1 receives 6-1/4 MW x Day Ahead Price from RA. LSE 2, 3 and 4 each receive 5/4 MW x Day Ahead Price from RA. Real Time load pays 5 MW uplift at Real Time price.


Initiative 41

Scenario 3 Rationale: This case combines principles from the previous two. LSE 1 has a negative deviation. He is held harmless by receiving 5MW times the Day Ahead Price. This still leaves 5MW times the Day Ahead Price left in the Reconciliation Account (RA). Each LSE, including LSE 1, receives 1 and ¼ MW times the Day Ahead Price from the account based on the same principles discussed above. Real time loads who did not clear in the Day Ahead market are receiving 5MW of benefit in terms of reduced real time load that they would have had to pay for at real time prices absent the investment by Day Ahead loads in the purchase of the DR resource. Without the performance of this DR resource, real time loads would have been 5MW higher and that difference would have to be purchased at the real time price. Further, that real time price would likely have been higher both for those 5MW’s and for every other MW of real time load absent investment in DR by the Day Ahead loads. It is therefore appropriate for there to be 5MW of uplift to real time loads that did not clear Day Ahead, but who are receiving the benefit of a 5MW load reduction paid for by Day Ahead loads.


Initiative 42

SCENARIO 4

No one knows whose load Day Ahead demand response reduced in Real Time, but LSEs loads deviate from Day Ahead in a somewhat random fashion.

Day Ahead Share

Real Time Load

Deviation

LSE 1 100 MW 110 MW +10 MW

LSE 2 100 MW 90 MW -10 MW

LSE 3 100 MW 101 MW +1 MW

LSE 4 100 MW 100 MW 0 MW

TOTAL 400 MW 401 MW +1 MW

Result: 1. LSE 1 pays for 10 MW at Real Time price.2. LSE 2 is paid 10 MW at Day Ahead price from the RA.3. LSE 3 buys 1 MW at Real Time price.4. LSE 4 stands pat.


Initiative 43

Scenario 4 Rationale: At this point we drop the didactic pretext that we need to ascertain whose load is reduced by DR in order to solve the missing money problem equitably. Under the Settlement Algorithm, settlement for positive deviations from the Day Ahead load are no different than now. Each LSE hedged only 100MW Day Ahead, so LSE1 pays for 10MW at the real time price, and LSE3 buys 1MW at the real time price. The only LSE with a negative deviation in this case is LSE2. That negative deviation is paid for at the Day Ahead Price out of the RA’s money.


Initiative 44

SCENARIO 5

No one knows whose load Day Ahead demand response reduced in Real Time, but all Day Ahead LSE loads go down and the total reduction is greater than the total Demand Resources bid in Day Ahead.

Day Ahead Share

Real Time Load

Deviation

LSE 1 100 MW 90 MW -10 MW

LSE 2 100 MW 90 MW -10 MW

LSE 3 100 MW 90 MW -10 MW

LSE 4 100 MW 90 MW -10 MW

TOTAL 400 MW 360 MW -40 MW

Result:All LSEs are credited 2.5 MW at Day Ahead price from RA. Each LSE has 7.5 MW backed by generation to resell or settle at Real Time price.


Initiative 45

Scenario 5 Rationale: Under the Settlement Algorithm, each LSE is either held harmless for DR purchased Day Ahead, or is provided with an opportunity to resettle amounts at real time. Each LSE has a deviation of 10MW. RA monies are distributed in proportion to each LSE’s negative deviation to the total negative deviations of all LSE’s. This results in a fraction of ¼ for each LSE that cleared Day Ahead. Each LSE, therefore, receives (10MW ÷ 4) 2.5MW times the Day Ahead Price from the RA. Thus, they have been held harmless for the full amount of DR dispatched Day Ahead. They are each left with 7.5MW that they can settle at real time (7.5 x 4=30 MW). 30MW added to the 360MW that showed up in real time is equal to 390MW. 390MW is exactly the amount of generation that was cleared Day Ahead


Initiative 46

CUSTOMER BASELINES

• The Enernoc Proposal 45 Day window.

At least 15 days.

Weighting.


Initiative 47

BASELINE RELATED ISSUES

• “Problem” with symmetric weather adjustments.

• “Problem” with one size fits all.

• “Problem” with perfection.

• Maintenance, shutdowns, vacations.


Initiative 48

BIDDING RELATED ISSUES

• Conditional Bids.

• Blocks/Run times.

• Shoulder periods.

• Should generators have more bid flexibility?

Documents

The Future of Price Responsive Demand in New England