Transcript Fast Start Pricing Improvements – Revised Edition

MARCH 11, 2015 | NEPOOL MARKETS COMMITTEE
Fast Start Pricing
Improving Price Formation When Fast Start
Resources Are Committed and Dispatched
Jonathan Lowell
PRINCIPAL ANALYST | MARKET DEVELOPMENT
Today’s Presentation
• Quick Review of Key Fast Start Pricing Concepts
• Deep-dive into Lost Opportunity Cost
• Detailed Walk-through of several examples
– Example 1 – Illustration of the Four FS Pricing Design Changes
– Example 2 – A “not economically useful” Fast Start Will Not Set Price
– Example 3 – Illustration of Reserve Pricing during Fast Start Pricing
• Additional information and detailed examples are provided in
an expanded memo accompanying this presentation:
– “Fast Start Pricing Improvements – Revised Edition”
•
Presentation of the results of a simulation of 2014 using Fast Start Pricing was
originally planned for March MC meeting, but due to software issues has been
rescheduled for the April meeting.
2
Quick Review - Objectives of the Fast Start
Pricing Design
• Improve price formation by reflecting the cost of fast-start
deployments through transparent market price signals.
• Improve performance incentives for all resources during tight
system conditions when reliability risk is heightened.
• Address shortcomings of the current Fast Start Pricing
methodology
– Shortcoming #1 - Fast Start assets are generally unable to set price
after the first dispatch interval, even though committed and
dispatched economically
– Shortcoming #2 - Relaxing EcoMin values in the dispatch solution
distorts the system energy balance
3
Quick Review – Fast Start Pricing Design
• “Lumpiness” is the Primary Source of Fast Start Pricing
Problems
– No pricing solution will fully satisfy the three pricing design principles:
• Efficiency
• Transparency
• Simplicity
• The new design has four components:
1.
Unit dispatch solution will respect FS offer minimum MW in all
intervals
2. EcoMin values for any committed Fast Start assets are “relaxed” to 0
MW in the pricing solution
3. Fast-Start commitment cost amortization in the pricing solution
•
•
4.
Startup Fee amortized over EcoMax during Min Run Time
No Load Fee amortized over EcoMax during and after Min Run Time
Compensation for Lost Opportunity Costs (LOC)
4
LOST OPPORTUNITY COSTS
Why Are LOC Payments Necessary?
• LOC payment ensures willingness to follow real-time dispatch instructions,
by eliminating financial incentives to deviate from instructions.
• All assets receive DDPs from the dispatch solution. While honoring
resource offer parameters, these DDPs:
– minimize total production cost
– respect reliability constraints
– maintaining the system energy balance
• Dispatch DDPs are consistent with each asset’s economic offer
– Note that exceptions may occur for specific reliability needs (e.g. posturing)
• However, prices that result from Fast Start Pricing may create
opportunities for some assets to increase profit by increasing output
above the dispatch DDP.
• The LOC payment solves this problem.
6
How Does LOC Occur – A Graphical Example
• Assumptions
Fast Start Unit
Non-Fast Start Unit
EcoMin
50 MW
100 MW
EcoMax
50 MW
500 MW
Startup Cost
$400/start
n/a
No Load Cost
$0/hour
n/a
Min Run Time
1 hour
n/a
Marginal Cost
(Offer Price)
$30 MWH
50 MW
$20/MWH
$60/MWH
100 – 400 MW
400 – 500 MW
• Demand = 430 MW
• FS offer, adjusted for amortized startup cost
= $30/MWH + ($400 / 50 MW/hour) = $38/MWH
7
LOC Illustration - Dispatch Solution
Dispatch Solution
Fast Start Unit
$/MWH
60
Non-Fast Start Unit
$/MWH
60
FS Offer Price $30/MWH
for the 50 MW block
30
$60/MWH offer
price for the top
100 MW
30
Offer Price $20/MWH
for 400 MW
20
20
50
MW
Dispatch Quantity
380
Dispatch Quantity
400
500
MW
8
LOC Illustration – Pricing Solution
Pricing Solution
Fast Start Unit
Non-Fast Start Unit
$/MWH
60
$/MWH
60
FS Offer Price
(adjusted for amortized
Startup Fee) is $38/MWH
for 0-50 MW
38
Next MW from the
Non-FS unit would
cost $60/MWH, so the
FS units sets the price
$60/MWH
for the top
100 MW
38
LMP = $38/MWH
FS unit would supply the
next MW at $38/MWH
20
20
30
Pricing
Quantity
50
MW
380
400
Pricing
Quantity
500
MW
9
LOC Illustration – Non-FS Unit DDP is Held Back
Relative to the Pricing Solution
Changes Between Dispatch & Pricing Solutions
Fast Start Unit
Non-Fast Start Unit
$/MWH
60
$/MWH
60
At a price of $38/MWH
the Non-FS would like to
operate at 400 MW
38
38
LMP = $38/MWH
LOC
20
20
30
Pricing
Quantity
50
MW
Dispatch
Quantity
380
Dispatch
Quantity
Operating at 380 MW
results in lost profit of
(400 - 380) x ($38 - $20)
= $360
400
Pricing
Quantity
500
MW
10
EXAMPLE 1
Illustrating the Four Fast Start Pricing Design Changes
Example 1 - Assumptions
• Two units, already committed for the interval: FS and non-FS
Fast Start Unit
Non-Fast Start Unit
EcoMin
50 MW
100 MW
EcoMax
50 MW
500 MW
Startup Cost
$150/start
n/a
No Load Cost
$100/hour
n/a
Min Run Time
30 min
n/a
Marginal Cost
(Offer Price)
$30 MWH
50 – 50 MW
$20/MWH
$60/MWH
100 – 400 MW
400 – 500 MW
• Demand = 430 MW
• Example study period is 1 hour
12
Example 1 – FS Unit Amortization of
Commitment Costs Within the MRT Period
Amortized Cost = $150/(50 MW×0.5 hr) + ($100/h)/50MW = $8/MWh
Startup Cost
No Load Cost
Fast Start Unit
Non-Fast Start Unit
EcoMin
50 0 MW
100 MW
EcoMax
50 MW
500 MW
Startup Cost
$150/start
n/a
No Load Cost
$100/hour
n/a
Min Run Time
30 min
n/a
Marginal Cost
(Offer Price)
$30 38 MWH
50 0 – 50 MW
$20/MWH
$60/MWH
100 – 400 MW
400 – 500 MW
13
Example 1 – FS Unit Amortization of
Commitment Costs After the MRT Period
Amortized Cost =
$0/MWH
Startup Cost
+ ($100/h)/50MW = $2/MWh
No Load Cost
Fast Start Unit
Non-Fast Start Unit
EcoMin
50 0 MW
100 MW
EcoMax
50 MW
500 MW
Startup Cost
$150/start
n/a
No Load Cost
$100/hour
n/a
Min Run Time
30 min
n/a
Marginal Cost
(Offer Price)
$30 32 MWH
50 0 – 50 MW
$20/MWH
$60/MWH
100 – 400 MW
400 – 500 MW
14
Example 1 – Dispatch & Pricing Solution
Dispatch Solution
Fast Start Unit
Non-Fast Start Unit
50 MW @ $30/MWH
380 MW @ $20/MWH
Pricing Solution Within MRT
Fast Start Unit
Non-Fast Start Unit
30 MW @ $38/MWH
400 MW @ $20/MWH
Next MWH would come from the FS unit @ $38/MWH
LMP = $38/MWH
Pricing Solution After MRT
Fast Start Unit
Non-Fast Start Unit
30 MW @ $32/MWH
400 MW @ $20/MWH
Next MWH would come from the FS unit @ $32/MWH
LMP = $32/MWH
Note that MW output levels from the Pricing Solution are not used for
dispatch and are not telemetered to assets.
15
Example 1 - Lost Opportunity Cost Credit
• LOC during Min Run Time
– LMP = $38/MWH
– The non-FS unit would maximize profit by operating at 400 MW
– Profit at 400 MW = 400 MW x ($38/MWH - $20/MWH) x 0.5 hr
= $3600
– As dispatched Profit = 380 MW x ($38/MWH - $20/MWH) x 0.5 hr
= $3420
– LOC credit during MRT = $ 3600 - $3420 = $180
• LOC after Min Run Time
– LMP = $32/MWH
– The non-FS unit would maximize profit by operating at 400 MW
– Profit at 400 MW = 400 MW x ($32/MWH - $20/MWH) x 0.5 hr
= $2400
– As dispatched Profit = 380 MW x ($32/MWH - $20/MWH) x 0.5 hr
= $2280
– LOC credit after MRT = $ 2400 - $ 2280 = $120
• Total LOC credit for the full hour = $180 + $120 = $300
16
EXAMPLE 2
Illustrating Startup Amortization Within and After Min Run
Time, and Pricing When a Fast Start Asset is not
“Economically Useful”
Example 2 - Assumptions
• Two units, already committed for the interval: FS and non-FS
• Demand = 430 MW for 15 min, then drops to 395 MW
Fast Start Unit
Non-Fast Start Unit
EcoMin
50 MW
100 MW
EcoMax
50 MW
500 MW
Startup Cost
$150/start
n/a
No Load Cost
$100/hour
n/a
Min Run Time
30 min
n/a
Marginal Cost
(Offer Price)
$30 MWH
50 – 50 MW
$20/MWH
$60/MWH
100 – 400 MW
400 – 500 MW
• Two study periods: 1st 15 minutes, and 2nd 15 minutes
18
Example 2 – FS Unit Amortization of Commitment
Costs Within the MRT Period
• No change from Example 1 assumptions
• Applies in both the 1st and 2nd 15 minute study periods
Amortized Cost = $150/(50 MW×0.5 hr) + ($100/h)/50MW = $8/MWh
Startup Cost
No Load Cost
Fast Start Unit
Non-Fast Start Unit
EcoMin
50 0 MW
100 MW
EcoMax
50 MW
500 MW
Startup Cost
$150/start
n/a
No Load Cost
$100/hour
n/a
Min Run Time
30 min
n/a
Marginal Cost
(Offer Price)
$30 38 MWH
50 0 – 50 MW
$20/MWH
$60/MWH
100 – 400 MW
400 – 500 MW
19
Example 2 – 1st 15 Minutes Dispatch & Pricing
• In the first 15 minutes, assumptions are consistent with
Example 1, and outcomes are unchanged.
– Demand = 430 MW
– Dispatch Solution
• Non-FS unit quantity 380 MW @ $20/MWH
• FS unit quantity 50 MW @ $30/MWH
– Pricing Solution (within MRT)
• Non-FS unit quantity 400 MW @ $20/MWH
• FS unit quantity 30 MW @ $38/MWH
• LMP = $38/MWH
20
Example 2 – 2nd 15 Minutes Dispatch & Pricing
• Demand = 395 MW
• Dispatch Solution
– FS unit quantity 50 MW
– Non-FS unit quantity 345 MW
• Pricing Solution (still within MRT)
– FS unit quantity is 0 MW @ $38/MWH
– Non-FS unit quantity is 395 MW @ $20/MWH
– LMP = $20/MWH
• The FS asset is not dispatched in the pricing solution (0 MW
pricing quantity), and is not “economically useful”
– Pricing solution would not change if the FS asset was excluded
– The FS asset does not set price
– The Non-FS unit is the marginal unit and sets the LMP
21
Example 2 – FS Asset Make-Whole Payment
• The FS unit earns net revenues of:
50MW × ($38/MWH – $30/MWH) × 0.25 hr run time
+ 50MW × ($20/MWH – $30/MWH) × 0.25 hr run time
– $150 Startup – ($100 / hr no-load cost × 0.5 hr run time) = $-225
• The FS unit requires a Make-Whole Payment of $225 for the
half-hour study period
• New FS pricing does not eliminate the need for make-whole
payments for FS units, just reduces it.
• FS units may be uneconomic and unneeded (in hindsight) if
load changes from expectations when committed.
22
Example 2 – Non-FS Lost Opportunity Cost
• During the first 15 minutes:
– At an LMP of $38/MWH, the unit would choose to operate profitably
at a quantity of 400 MW, but was dispatched to a 380 MW DDP
(400 MW – 380 MW) × ($38/MWH – $20/MWH offer) × .25 hour = $90 LOC
• During the second 15 minutes:
– The LMP of $20/MWH is equal to the Non-FS offer of $20/MWH
(400 MW – 395 MW) × ($20/MWH – $20/MWH offer) × .25 hour = $0 LOC
23
EXAMPLE 3
Determining Reserve Prices Under Fast Start Pricing
Example 3 - Assumptions
• Three units, already committed for the interval: a FS and two
non-FS units
• Study period of 1 hour
• Demand = 195 MW
• Online reserve requirement = 16 MW
• Reserve Constraint Penalty Factor = $1000/MWH
25
Example 3 - Assumptions
Fast Start Unit
Non-Fast Start
Unit A
Non-Fast Start
Unit B
EcoMin
20 MW
50 MW
50 MW
EcoMax
20 MW
100 MW
100 MW
No Load
Cost
$1000/hour
$0/hour
$0/hour
0 MW
15 MW
10 MW
Online
Reserve
Capability
Marginal
Cost
(Offer Price)
$100 MWH
20 – 20
MW
$20/MWH
50 – 100
MW
Adjusted
Offer Price
$150 MWH
0 – 20
MW
--
--
$15/MWH 50 – 100 MW
--
--
• The FS asset is block-loaded – provides no reserve when
online.
26
Example 3 – Dispatch Solution
Fast Start Unit
Non-Fast Start
Unit A
Non-Fast Start
Unit B
Dispatch
DDP
20 MW
76 MW
99 MW
Reserve
Designation
0 MW
15 MW
1 MW
•
The FS is block loaded at 20 MW
•
Unit B is the less expensive non-FS, and provides most of the remaining energy
and 1 MW of reserve
•
Unit A provides most of the reserve, because it is the more expensive non-FS unit
27
Example 3 – Pricing Solution
Fast Start Unit
Non-Fast Start
Unit A
Non-Fast Start
Unit B
Pricing Run
Quantity
11 MW
85 MW
99 MW
Reserve
Designation
0 MW
15 MW
1 MW
•
Unit A, being less expensive than the FS unit, provides additional energy in the
pricing solution, when the FS unit’s EcoMin is relaxed.
•
With EcoMin relaxed, the FS quantity decreases from 20 MW to 11 MW
•
In this example, reserve designations in the pricing solution do not change.
•
An additional MWH of energy would be provided by the FS unit at a cost of
$150/MWH. Therefore, LMP = $150/MWH.
•
An additional MW of reserve requires the redispatch of the FS unit and Unit B, at a
cost reflecting the relative difference in offer prices. Reserve price is $135/MWH:
$150/MWH - $15/MWH = $135/MWH
28
Example 3 – Reserve Co-optimization Logic
• FS pricing preserves the proper pricing relationships between energy and
reserves under RT co-optimization
• In Example 3, the FS unit sets LMP at $150 / MWH
• Unit B is the marginal supplier of reserves (i.e., provides next reserve MW
if reqm’t increases by 1 MW).
• For dispatch-following incentives in a co-optimized market, all prices must
make the marginal reserve supplier (Unit B) indifferent between supplying
more energy v. reserves
• Therefore, the correct energy-reserve price difference must equal B’s offer
cost, which is $15:
$150 LMP – $135 RMCP = Unit B’s $15/MWH offer price
• Thus the correct co-optimized reserve price must be $135
29
Example 3 – Lost Opportunity Cost
• Given the clearing prices (LMP = $150/MWH and RMCP = $135/MWH) the
LOC for each unit is the difference between the maximum feasible profit
and the actual profit, but not less than $0.
Non-Fast Start
Unit A
Non-Fast Start
Unit B
Max Feasible
Profit
85 MW x (150 – 20 $/MWH)
+ 15 MW x $135/MWH
= $13,075
99 MW x (150 – 15 $/MWH)
+ 1 MW x $135/MWH
= $13,500
Actual Profit in
Dispatch Solution
76 MW x (150 – 20 $/MWH)
+ 15 MW x $135/MWH
= $11,905
99 MW x (150 – 15 $/MWH)
+ 1 MW x $135/MWH
= $13,500
LOC
$13,075 - $11,905 = $1,170
$13,500 - $13,500 = $0
Observations:
Reserves are more valuable than
energy for Unit A
Unit B is indifferent between
reserves and energy
30
Example 3 – Pricing Solution Reserve Capability
• In the pricing solution, reserve capability is limited to the
reserve a FS unit can provide above its original offered EcoMin
– In this example, the reserve capability is 0 MW because the unit is
block loaded.
• If the FS asset had a dispatchable range in the dispatch
solution, it would have been able to provide online reserve in
the pricing solution between offered EcoMin and EcoMax
(subject to ramp rate limitations)
– The online reserve designated in the pricing solution must be no
greater than the unit’s reserve capability in the dispatch solution
31
Anticipated Schedule
• February MC meeting – conceptual overview
• March MC meeting
– Design review and detailed examples
• April MC meeting
– Historical simulation of fast start pricing design impacts
– Tariff language review
• May MC meeting – request MC vote
• June PC meeting – request PC vote
• FERC filing – summer 2015
• Implementation - sometime in 2016
32
APPENDIX A
Fast Start Pricing Presentation at the February 10, 2015
Markets Committee Meeting
FEBRUARY 10, 2015 | NEPOOL MARKETS COMMITTEE
Fast Start Pricing
Improving Price Formation When Fast Start
Resources Are Committed and Dispatched
Jonathan Lowell
PRINCIPAL ANALYST | MARKET DEVELOPMENT
Real-Time Price Formation – Reflecting the Cost
of Deploying Fast Start Resources
• Today, operating characteristics of most fast-start resources prevent them
from setting the energy price
• RT Fast Start Pricing changes will improve price formation by enabling faststart resources to set price more frequently and reflecting the cost of faststart deployments through transparent market price signals.
• Fast Start Pricing can improve performance incentives for all resources
during tight system conditions when reliability risk is heightened.
• ISO-NE’s External Market Monitor recommended Fast Start Pricing
improvements in “2013 Assessment of the ISO New England Electricity
Markets”, pp. 22 & 87-95.
• Stakeholders have identified price formation as a key concern.
35
ISO-NE’s Existing Fast Start Pricing - Background
• ISO-NE’s existing fast-start pricing logic was designed 15 years
ago to work within the software/hardware limitations that
existed at the time
• Current fast start pricing is neither transparent nor efficient
• In practice, fast-start units, even when deployed in economic
merit order, often do not set RT LMP
– Fast starts generally operate few hours during which inframarginal
rents provide an opportunity to recover commitment costs
– Must rely on NCPC payments to recoup commitment costs
– External Market Monitor: “In 2013, 60 percent of the fast-start
capacity that was started in the real-time market did not recoup its
offer.” (EMM Assessment, p. 22).
36
Today’s Presentation
• Summary of current Fast Start Pricing and the existing
shortcomings to be addressed
• High-level description of proposed Fast Start Pricing design
– How does it work?
– How does it address the existing shortcomings
• Additional information and detailed examples are provided in
the accompanying memo:
– “Fast Start Pricing Improvements”
37
Future Presentations
• Additional discussion of Fast Start pricing details
– Examples
• Quantitative estimates of FS Pricing impacts, based on
simulations applying the new methodology to a year of
historical data
–
–
–
–
RT LMPs and RT reserve prices
Lost Opportunity Cost payments
RT NCPC (for Fast Start assets, and total system)
Planned for the March MC meeting
• Discussion of tariff changes
– Planned for April-May MC meetings.
38
ISO-NE’s Current FS Pricing Methodology
• In the first 5-minute dispatch interval when a Fast Start is
dispatched:
– The Fast Start’s EcoMin is “relaxed” to zero
– Amortized Startup and No Load costs are added to energy offer price
– Fast-starts frequently set price during this initial 5-min interval
• In subsequent dispatch intervals
– EcoMin is not relaxed to zero (offered EcoMin used for dispatch)
– Commitment costs are not added to the energy offer price
– Fast-starts generally do not set price after their first dispatch interval,
even when they are:
• Economically committed and dispatched; and
• Highest-priced resource operating at the time
39
Shortcomings of Current FS Pricing
• Shortcoming #1 - Fast Start assets are generally unable to set
price after the first dispatch interval, even though committed
and dispatched economically
– Costs of deploying Fast Starts are not reflected in RT LMPs, even when
deployed efficiently to meet demand
– “Side payments” (NCPC) required to recover full cost of deployment
• Shortcoming #2 - Relaxing EcoMin values in the dispatch
solution distorts the system energy balance
– Leads to inefficiencies in system dispatch (during first interval)
– The distortions must be managed by regulation reserves at potentially
higher cost than a balanced energy dispatch.
40
Pricing is Intimately Related to Real-Time
Commitment & Dispatch
• Commitment – determine resources to commit (start) and decommit (shut-down)
• Dispatch – determine the “Desired Dispatch Point” (DDP) for
each asset
• Pricing – determine market prices for energy and reserves
41
“Lumpiness” is the Primary Source of Fast Start
Pricing Problems
• “Lumpiness” – caused by minimum output levels and
commitment costs
– Many Fast Start assets are “block loaded”: EcoMin = EcoMax
– Most others have EcoMin close to EcoMax (‘almost’ block loaded)
• There is no perfect solution for lumpy problems – no pricing
solution will fully satisfy three pricing design principles:
– Efficiency
– Transparency
– Simplicity
• Any solution reflects compromises
• ISO’s proposal is better than its
current practice on these three elements.
42
Four Related Changes are Proposed to Address
the Identified Existing Shortcomings
1.
Unit dispatch solution will respect FS offer minimum MW in all intervals
–
–
–
–
2.
Means: The dispatch solution honors all offered values and parameters
(differs from current treatment in first dispatch interval)
Ensures the dispatch instruction is feasible for the FS unit
Directly solves Existing Shortcoming #2
EcoMin values for Fast Start assets are “relaxed” to 0 MW in the pricing
solution that calculates RT prices for any committed FS unit
–
Makes committed FS units more likely to set LMP
–
Specifically: Will enable a Fast Start to set its LMP whenever it is
•
Committed by the ISO (i.e., starting up or while running thereafter), and
•
“Economically useful” for meeting demand in the least-cost dispatch
–
“Economically useful” = Total system costs would be strictly greater absent
the FS unit (requiring a higher cost unit to be dispatched instead)
–
Directly addresses Existing Shortcoming #1 (along with Change 3, next).
43
Four Related Changes, Continued
3.
Fast-Start commitment cost amortization in the pricing solution
–
–
Two minor modifications from current amortization rules for FS units
Start-Up Fee amortized over EcoMax and Min Run Time (MRT)
•
•
–
No Load Fee amortized over EcoMax & included in energy offer price
•
•
4.
Added to incremental energy offer price until the Fast Start’s MRT has expired
Change from current amortization over 1 hour: some FS units have MRT < 1 hour.
Same treatment as current practice during first dispatch interval
Added to incremental energy offer price until the Fast Start is de-committed
Compensation for Lost Opportunity Costs (LOC)
–
–
–
In some circumstances, one (or a few) generators may be “postured” down
below their economic dispatch point to maintain the system energy balance
Occurs when a Fast-Start sets price above the offer price of another unit that
must be dispatched down ‘against’ price, but Fast-Start is at its minimum.
Necessary to ensure willingness to follow dispatch instructions ‘down’ against
price (aka, being postured down).
44
When Does Fast Start Pricing Apply?
• Fast Start Pricing methodology is applied in any dispatch
interval in which a Rapid Response Pricing Asset (RRPA) is
committed
– Keep in mind, dispatch is performed with a 15 minute lookahead
– FS Pricing will therefore reflect the assets committed for the upcoming
interval at time T+15.
– Uncommitted assets do not factor into FS Pricing
• What is a Rapid Response Pricing Asset? Generators and
DARDs that have the same characteristics as currently
required for Fast Start Generators:
•
•
•
•
•
•
dispatchable within the hour through electronic dispatch
minimum run time <= 60 minutes
cold Notification Time plus cold Start-Up Time <= 30 minutes
available for dispatch and manned or remote dispatch capability
receive & acknowledge start-up/shut-down instructions electronically
satisfied any minimum down time constraint
45
Lost Opportunity Cost (LOC) Calculation
• To provide real-time dispatch-following incentives, LOC is calculated for
every 5 minute interval, using 5-min energy output and 5-min RT LMPs:
LOC = Max Feasible Profit – Actual Profit, but not less than $0
• Few MW will incur a LOC, in general
– Affects, at most, MW equal to the EcoMin of the “relaxed” RRPA that sets price
• Hourly “rolled-up” LOC credits are included in NCPC credit calculations as
additional revenue
• “Profits” consider both energy and reserves
– “Max Feasible Profit” considers only feasible outcomes, as constrained by
ramp rates, EcoMin, EcoMax, etc. Does not consider offline scenarios.
• Any LOC not used to offset other NCPC credits would be allocated as RT
posturing costs are allocated
– RTLO (excluding postured pumps)
46
Lost Opportunity Cost Credit Eligibility
• Who is eligible?
– Assets that are committed in the associated dispatch solution
– Self-scheduled/self-committed assets, unless otherwise excluded
• LOC is $0 for ineligible assets
• Who is not eligible?
– Non-dispatchable and Settlement Only assets
– Demand Response assets, at this time.
• Will be evaluated as part of PRD Full Implementation
– DNE Dispatchable Generators
• These assets are not dispatched to a DDP (not ‘postured’)
– Assets postured for other reasons (limited energy) during the interval
• The Posturing NCPC credit already covers lost opportunity costs
– Assets providing regulation during the interval
• Regulation compensation already includes opportunity costs
47
Anticipated Schedule
• February MC meeting – conceptual overview
• March - April MC meetings
–
–
–
–
Design discussion
Examples
Historical simulation of fast start pricing design impacts
Tariff language review
• May MC meeting – request MC vote
• June PC meeting – request PC vote
• FERC filing – summer 2015
• Implementation - sometime in 2016
48