Two Examples of Reserve Market Design Under Consideration in New England

DRAFT – for illustrative purposes only

Two Examples of Reserve Market Design Under Consideration

in New England

- 9/16-9/17 Meeting of the

NEPOOL Markets Committee

John Farr (for ISO-NE)


2

Illustrative Example 1: Constrained Sub-Area and Two Reserve Products

Aspect of Reserve Markets Included in Example?

Multiple Reserve Products Yes (Spinning and Non-Spinning)

Multiple Locations Yes (Control Area with Constrained Sub-Area)

Multiple Settlements No (Separate Day-Ahead and Real Time

Examples)

Demand Bidding No

Co-optimization with Energy No


3

Control Area Requirements (Additional):Spinning = 200 MW (125 MW)

Total = 400 MW (125 MW)

Illustrative Example 1: Reserve Requirements

Control Area Boundary

Import ConstrainedArea Boundary

Import Constrained Area Requirements:Spinning = 75 MW

Total = 150 MW (75 MW)

• Control area has 400 MW total reserve requirement (spinning plus non-spinning), 200 MW of which must be spinning.

• 150 MW of 400 MW total requirement must be in import constrained area, 75 MW of which must be spinning


4

Ability of Different Types of Resources to Serve Operating Requirements

Operating Requirement

Type of Resource Con

trol

Are

a T

otal

Con

trol

Are

a S

pinn

ing

Impo

rt C

onst

rain

ed

Are

a T

otal

Impo

rt C

onst

rain

ed

Are

a S

pinn

ing

Control Area Non-Spinning XControl Area Synchronized X XImport Constrained Area Non-Spinning X XImport Constrained Area Synchronized X X X X

• Table shows ability of different types of resources to meet multiple requirements.

• Resources will be able to serve whatever markets for which they are able to meet operating requirement.


5

Illustrative Example 1: Day-Ahead Market Clearing

• Four units capable of providing reserves available in constrained area and ten total units available with bidding and cost characteristics shown above.

• Example assumes co-optimization has already taken place. Only reserve capabilities are shown.

Reserve Capacity* Bidding into Day-Ahead Market

Resource Location Synch Capacity Non-S Capacity Total Reserve Availability Bid Other Costs** Total Bid(MW) (MW) (MW) ($/MWH) ($/MWH) ($/MWH)

Red Control Area 60 80 140 0 0 0Blue Control Area 30 50 80 2 0 2Green Control Area 50 0 50 2 1 3Orange Control Area 0 150 150 4 0 4Purple Control Area 25 50 75 6 0 6Yellow Control Area 50 75 125 10 0 10

Black Constrained 50 0 50 0 0 0Grey Constrained 30 40 70 8 0 8White Constrained 0 50 50 2 10 12Brown Constrained 40 60 100 20 0 20Total: 335 555 890

* - Assumes Co-optization with Energy Bidding** - Lost opportunity and other costs resulting from co-optimization with energy.


6

Illustrative Example1: Day-Ahead Market Clearing

• Market clearing methodology– Each requirement is met based on lowest cost available

resources– Spinning resources and resources in import constrained areas

allowed to meet requirements for non-spinning reserves and for control area (i.e., “cascading”)

– Prices for spinning reserves and reserves in import constrained area must be at least as high as non spinning reserves and prices for control area.

• Following slides show bid stack for each product/location

• Slides are for illustration purposes. Actual market could be cleared using linear programming or other method.


7

Illustrative Example 1: Constrained Area Requirements

Designated Resources for Constrained Area Spinning Requirement

Resource Location Synch Capacity Total Bid Designated Capacity(MW) ($/MWH) (MW)

Black Constrained 50 0 50Grey Constrained 30 8 25Brown Constrained 40 20 0

Total: 75Marginal Bid Needed to Meet Requirement = 8

Additional Designated Resources for Constrained Area Total Requirement

Resource Location Total Reserve* Total Bid Designated Capacity(MW) ($/MWH) (MW)

Black Constrained 0 0 0Grey Constrained 45 8 45White Constrained 50 12 30Brown Constrained 100 20 0


* - Excludes MW already designated as meeting sych requirement


8

Illustrative Example 1: Control Area RequirementsAdditional Designated Resources for Control Area Spinning Requirement

Resource Location Synch Capacity* Total Bid Designated Capacity(MW) ($/MWH) (MW)

Red Control Area 60 0 60Black Constrained 0 0 0Blue Control Area 30 2 30Green Control Area 50 3 35Purple Control Area 25 6 0Grey Constrained 0 8 0Yellow Control Area 50 10 0White Constrained 0 12 0Brown Constrained 40 20 0


* - Excludes MW already designated as meeting constrained area requirements

Additional Designated Resources for Control Area Total Requirement

Resource Location Total Reserve* Total Bid Designated Capacity(MW) ($/MWH) (MW)

Red Control Area 80 0 80Black Constrained 0 0 0Blue Control Area 50 2 45Green Control Area 15 3 0Orange Control Area 150 4 0Purple Control Area 75 6 0Grey Constrained 0 8 0Yellow Control Area 125 10 0White Constrained 20 12 0Brown Constrained 100 20 0


* - Excludes MW already designated as meeting other 3 requirements


9

Illustrative Example1: Summary of All Resources Meeting Operating Requirements

Resources Designated for all Requirements

Resource Location Area: Control Control Constrained ConstrainedType: Total Sych Total Sych

Red Control Area 140 60 0 0Black Constrained 50 50 50 50Blue Control Area 75 30 0 0Green Control Area 35 35 0 0Orange Control Area 0 0 0 0Purple Control Area 0 0 0 0Grey Constrained 70 25 70 25Yellow Control Area 0 0 0 0White Constrained 30 0 30 0Brown Constrained 0 0 0 0

Total: 400 200 150 75


10

Determining Clearing Prices Reserve Service• Value of reserve service equals the maximum marginal bid of resources designated as meeting requirements that are capable of providing that reserve service.

• In this example, all resources needed to meeting spinning reserve requirement in the constrained area would have been used to meet the total reserve requirement. Spin requirement is not “binding” and should not be relevant to price. Marginal Designated Bid for

Operating Requirement

Type of Resource Con

trol

Are

a T

otal

Con

trol

Are

a S

pinn

ing

Impo

rt C

onst

rain

ed

Are

a T

otal

Impo

rt C

onst

rain

ed

Are

a S

pinn

ing

Pric

e of

Res

erve

S

erfv

ice

Control Area Non-Spinning 2 2Control Area Synchronized 2 3 3Import Constrained Area Non-Spinning 2 12 12Import Constrained Area Synchronized 2 3 12 8 12


11

Real-Time Market

• ISO-NE proposes to price real-time reserves using “demand curves”

• Demand curves would indicate the value of various reserve services as a function of the amount of reserve capacity available

• Values based on “shadow value” of service implicit in ISO operational practices

• Explicitly values violations of each operating constraint• ISO to ensure greatest possible consistency between

pricing mechanism and operational practice.


12

Illustrative Demand Curve for Reserves

Reserve Capacity Available to Meet Single Operating Constraint

Demand

Supply1

Reserve Price

Q1

P1

Supply2

P2

Q2


13

Demand Curve for Reserves

• Provides means of pricing reserves in real-time. • Two conditions under which prices are set

– Scarcity conditions (Supply Curve 1 from previous slide)• ISO unable to its reserve criteria either because reserves are

unavailable or too expensive

• Demand curve provides maximum value ISO would be willing to pay for reserves in order to protect reliability/load

– At criterion conditions (Supply Curve 2 from previous slide)• ISO able to meet criteria but must incur redispatch or other cost in

order to do so (e.g., resource is “postured” to provide reserves even though its energy bid is in-merit in the energy market

• Reserves priced at cost of procurement (e.g., lost opportunity cost for resources “postured” to provide reserves


14

“Shadow Value” of Reserve Service

• “Shadow Value” of reserves is the value of making available an increment of capacity that is capable of serving one or more operating reserve requirements

• Is the sum of the values associated with individual operating requirements that the increment of reserve capacity can serve

• Positive when reserve capacity is scarce (i.e., operating requirement is not fully met) or when economic capacity must be withheld from the energy market to provide reserves.

• Zero when no scarcity exists (i.e., operating requirements fully met without redispatch costs)


15

Demand Curves and Operational Practice

• ISO actions taken to restore or create reserves may come at significant cost, for example:– Posturing of resources– Commitment of otherwise out-of-merit resources– Scheduling of imports

• ISO should not take actions to restore reserves at costs that exceed prices indicated on curves.– Perfect consistency not possible

• “Lumpiness” of resources

• Uncertainty resulting from time-delay between action and real time (e.g., unit commitment decisions due to start-up times)

– ISO to seek to ensure greatest possible consistency


16

“Shadow Value” of Reserve Service

Shadow Value of Value of Meeting Reserve Service Operating Constraint(s) CA-NS = CA-Ttl

CA-Synch = CA-Ttl + CA-Spin

IC-NS = CA-Ttl + IC-Ttl

IC-Synch = CA-Ttl + CA-Spin + IC-Ttl

+ IC-Spin

• Value of meeting individual operating constraints may be zero or positive

• By definition, reserve values reflect relative value of service (e.g., CA-NS can not be greater than CA-Synch)


17

Illustrative Example 1: Real-Time Market Clearing

• Four separate demand curves used to provide values for CA-Ttl, CA-Spin, IC-Ttl, and IC-Spin

• Based on real-time levels of capacity available to meet these operating constraints, assume curve indicates values*:

CA-Ttl = $5/MWH CA-Spin = $0/MWH

IC-Ttl = $0/MWH IC-Spin = $60/MWH

• Solving for prices:

CA-NS = $5 = $5/MWH

CA-Synch = $5 + $0 = $5/MWH

IC-NS = $5 + $0 = $5/MWH

IC-Synch = $5 + $0 + $0 + $60 = $65/MWH

* - For example, assume $5/MWH redispatch cost exists to meet control area total reserve requirement and the demand curve indicates a value of $60/MWH for synchronized in the constrained area due to scarcity.


18

Illustrative Example 2: Interactions Between Forward, Day-Ahead, and Real-Time

Reserve Market

Aspect of Reserve Markets Included in Example?

Multiple Reserve Products No

Multiple Locations No

Multiple Settlements Yes, Forward, Day-Ahead, and Real-Time

with Multiple Participants

Demand Bidding Yes

Co-optimization with Energy No


19

Relationship Between Forward Market and Day-Ahead and Real-Time Markets

• Upon implementation of the day-ahead and real-time market, the forward market will provide a longer-term mechanism for trading and hedging real-time reserve obligations. – Supply selling into forward market has obligation to provide reserves in

real-time, or to purchase them (i.e., “financially binding”)

– Optional participation by those with obligation

– Optional participation by those with assets

– Supply not limited to physical assets

– Supply selling into forward market has no additional obligations to bid in any particular manner (unlike the current forward reserve market)


20

Relationship Between Day-Ahead, and Real-Time Markets (Questions Bolded, Ex. 2 Assumptions in Bolded Italics)

• Like the day-ahead energy market, the day-ahead reserve market will identify expected reserve resources, create a financial obligation for those resources to provide reserves, and provide a means through which most participants with real-time reserve obligations are likely to cover that obligation.

– Will purchase/bidding be optional or obligatory for those with obligation? Will those with obligation bid willingness to pay? Example 2 assumes participation is optional w/ resource adequacy guaranteed by RAA process (as with energy)

– Will sale/bidding be optional or obligatory for those with physical assets? Example 2 assumes that ICAP resources be obligated to bid in manner parallel to energy market.

• The real-time reserve market will identify the resources that physically provided reserves and ensure that all participants meet their physical and financial obligations.

– Will real-time market also determine final reserve obligation? Example assumes that final reserve obligation should depend on real-time requirements and real-time supply conditions (e.g., will be reduced in OP4 conditions)

– Obligatory purchase by those with obligation

– Supply determined by those actually providing service

– No bidding by supply or demand

– Prices determined using demand curves and lost opportunity cost


21

Illustrative Example 2: Resources and Obligations

Participants:

Expected Physical Ability to Supply

Reserves

Expected Reserve Obligation (Before

Trading) Expected Position

Mary 75 0 75Joe 0 100 -100John 200 100 100Fred 0 100 -100Betsy 175 0 175Mike 0 0 0Total: 450 300 150

• Six participants have the these expected positions.• Supply positions are expected, based on characteristics of their

assets and expected use in the energy market• Obligations are expected based on a fixed, but yet undefined

method for allocating reserve obligations• Like energy, final supply and obligations will be based on real-time

conditions.


22

Illustrative Example 2: Forward Reserve Market After Implementation of Spot Reserve Markets

Participants:


Reserves Supply Offer(s)


Trading) Demand Bid(s)Mary 75 75 @ 5 0Joe 0 100 100 @ 5John 200 200 @ 3 100 75 @ 3Fred 0 100 120 @ 10Betsy 175 175 @ 8 0 50 @ 2Mike 0 50 @ 4 0

0

2

4

6

8

10

12

0 100 200 300 400 500

Supply

Pri

ce

Supply

Demand

220 MW's Clear @ $4


23

Illustrative Example 2: Forward Reserve Market After Implementation of Spot Reserve Markets

Participants:


Reserves Forward Sales

Supply Position (Resources less

Sales)


Trading) Forward Purchases

Expected Obligation (Initial less Purchases)

Expected Position

Mary 75 0 75 0 0 0 75Joe 0 0 0 100 100 0 0John 200 200 0 100 0 100 -100Fred 0 0 0 100 120 -20 20Betsy 175 0 175 0 0 0 175Mike 0 20 -20 0 0 0 -20Total: 450 220 230 300 220 80 150

• 220 MWs of forward reserves clear at a price of $4/MWH• Table shows how each participants position is changed by forward

auction. A few things to note:– 220 of 300 MWs of expected obligation purchased in forward

auction– An excess of 150 MW of reserves are expected to exist– Mike has sold forward without any physical asset to back up

his sale– Fred has more than covered his expected obligation


24

Illustrative Example 2: Day-Ahead Reserve Market

Participants:


Sales) Supply Offer(s)

Expected Obligation (Initial less Purchases) Demand Bid(s)

Mary 75 75 @ 2 0Joe 0 0John 0 100 100 @ 3Fred 0 10 @ 1 -20Betsy 175 175 @ 6 0Mike -20 0 20 @ 2

0

1

2

3

4

5

6

7

0 50 100 150 200 250

Supply

Pri

ce Demand

Supply

85 MW's Clear @ $3


25

Illustrative Example 2: Day-Ahead Reserve Market

Participants:


ReservesForward and Day-

Ahead Sales


Sales)


Trading)Forward and Day-Ahead Purchases

Expected Obligation (Initial less Purchases)

Expected Position

Mary 75 75 0 0 0 0 0Joe 0 0 0 100 100 0 0John 200 200 0 100 85 15 -15Fred 0 10 -10 100 120 -20 10Betsy 175 0 175 0 0 0 175Mike 0 20 -20 0 0 0 -20Total: 450 305 145 300 305 -5 150

• 85 MWs of day-ahead reserves clear at a price of $3/MWH• Table shows how each participants position is changed by day-

ahead auction. A few things to note:– John is only participant with remaining obligation– Mike still has to buy back the 20 MW he sold forward as he

has no physical assets to fill his position– Betsy still has all her capacity (has not sold anything)


26

Illustrative Example 2: Real-Time Reserve Market

Participants:Actual Reserves

SuppliedForward and Day-

Ahead SalesSupply Position

Supplied less Sales)

Actual Reserve Obligation (Before

Trading)Forward and Day-Ahead Purchases

Obligation (Actual less Purchases)

Real-Time Position

Mary 75 75 0 0 0 0 0Joe 0 0 0 90 100 -10 10John 20 200 -180 90 85 5 -185Fred 0 10 -10 90 120 -30 20Betsy 175 0 175 0 0 0 175Mike 0 20 -20 0 0 0 -20Total: 270 305 -35 270 305 -35 0

Notes: John Supplies 180 MW less than expected due to unit outageActual obligations of 270 MW's is 30 MW's less than expected due to shortage of supply

0

50

100

150

200

250

0 50 100 150 200 250 300 350

Supply

Pri

ce

Demand Curve Supply

270 MW's Clear @ $15


27

Illustrative Example 2: Real-Time Reserve Market

• In real-time John is only able to supply 20 MW’s of reserves. 180 MWs less reserves is available than expected

• Scarcity condition exists as ISO is unable to meet its real-time criterion. Reserve price is $15 based on the 270 MW of reserves actually available in real-time.

• John is unable to cover his forward and day-ahead sales with bilateral purchases because of the outage and must buy 185 MW of reserves at real-time prices.

• Betsy sells all of her reserves in real-time market.• All other participants settle their relatively small real-time positions

– e.g., Mary has sold forward and does not participate in real-time market

– e.g., Mike has to buy back 20 MW at loss


28

Illustrative Example 2: Participant Settlement for Forward, Day-Ahead, and Real-Time

Reserve Markets

Participant: Mary Quantity Price Revenue

(Expense)(MW) ($/MWH) ($)

Expected Ability to Supply Reserves 75 Expected Reserve Obligation (Before Trading) - Expected Position (Before Trading) 75

Actual Reserves Supplied 75 Actual Reserve Obligation (Before Trading) - Actual Position (Before Trading) 75

Reserves Sold (Purchased) Forward - 4 - Reserves Sold (Purchased) Day-Ahead 75 3 225 Reserves Sold (Purchased) Real-Time - 15 - Total Reserves Sold (Purchased) 75 3 225


29


Reserve Markets

Participant: Joe Quantity Price Revenue


Expected Ability to Supply Reserves - Expected Reserve Obligation (Before Trading) 100 Expected Position (Before Trading) (100)

Actual Reserves Supplied - Actual Reserve Obligation (Before Trading) 90 Actual Position (Before Trading) (90)

Reserves Sold (Purchased) Forward (100) 4 (400) Reserves Sold (Purchased) Day-Ahead - 3 - Reserves Sold (Purchased) Real-Time 10 15 150

Total Reserves Sold (Purchased) (90) 3 (250)


30


Reserve Markets

Participant: John Quantity Price Revenue


Expected Ability to Supply Reserves 200 Expected Reserve Obligation (Before Trading) 100 Expected Position (Before Trading) 100

Actual Reserves Supplied 20 Actual Reserve Obligation (Before Trading) 90 Actual Position (Before Trading) (70)

Reserves Sold (Purchased) Forward 200 4 800 Reserves Sold (Purchased) Day-Ahead (85) 3 (255) Reserves Sold (Purchased) Real-Time (185) 15 (2,775)

Total Reserves Sold (Purchased) (70) 32 (2,230)


31


Reserve Markets

Participant: Fred Quantity Price Revenue


Expected Ability to Supply Reserves - Expected Reserve Obligation (Before Trading) 100 Expected Position (Before Trading) (100)

Actual Reserves Supplied - Actual Reserve Obligation (Before Trading) 90 Actual Position (Before Trading) (90)

Reserves Sold (Purchased) Forward (120) 4 (480) Reserves Sold (Purchased) Day-Ahead 10 3 30 Reserves Sold (Purchased) Real-Time 20 15 300

Total Reserves Sold (Purchased) (90) 2 (150)


32


Reserve Markets

Participant: Betsy Quantity Price Revenue


Expected Ability to Supply Reserves 175 Expected Reserve Obligation (Before Trading) - Expected Position (Before Trading) 175

Actual Reserves Supplied 175 Actual Reserve Obligation (Before Trading) - Actual Position (Before Trading) 175

Reserves Sold (Purchased) Forward - 4 - Reserves Sold (Purchased) Day-Ahead - 3 - Reserves Sold (Purchased) Real-Time 175 15 2,625 Total Reserves Sold (Purchased) 175 15 2,625


33


Reserve Markets

Participant: Mike Quantity Price Revenue


Expected Ability to Supply Reserves - Expected Reserve Obligation (Before Trading) - Expected Position (Before Trading) -

Actual Reserves Supplied - Actual Reserve Obligation (Before Trading) - Actual Position (Before Trading) -

Reserves Sold (Purchased) Forward 20 4 80 Reserves Sold (Purchased) Day-Ahead - 3 - Reserves Sold (Purchased) Real-Time (20) 15 (300) Total Reserves Sold (Purchased) - N/A (220)

Documents

Two Examples of Reserve Market Design Under Consideration in New England