Upload
lylien
View
214
Download
0
Embed Size (px)
Citation preview
SPP.org 11
MOPC Workshop Series on
Future Markets: Session I
August 24, 2010
SPP.org 2
Agenda
Introduction
The Day Ahead Market
Reliability Unit Commitment (RUC)
The Real-Time Balancing Market
Financial Schedules
Virtual Transactions
Co-optimization
Scarcity Pricing
SPP.org 3
Objectives
Describe high level overview of the relationships between the DA
Market, RUC, and RTBM.
Define Demand Bids and Resource Offers in the Day-Ahead Market
Provide examples for Demand Bids and Resource Offers cleared in
the DA Market.
Define virtual transactions and financial schedules
Explain examples for virtuals transactions and financial schedules.
Define co-optimization of Energy and Operating Reserves
Understand example of a co-optimized, least-cost solution.
Define scarcity pricing of Operating Reserves
Identify examples of scarcity pricing in the Future Market design
SPP.org 4
INTRODUCTION
SPP.org 5
Future Markets Motivation
• Increase Market Participant savings by moving from self-
commitment to centralized unit commitment
• Create a Day-Ahead Market so members can get price
assurance capability prior to real-time
• Market-based Operating Reserves to support the
Consolidated Balancing Authority (CBA)
SPP.org 6
Future Market Products
Energy
Operating Reserve
Regulation
o Regulation Up
o Regulation Down
Spinning
Supplemental
SPP.org 7
SPP Regulation Reserve Definition
Regulation Deployment
The utilization of Regulation-Up and Regulation-Down through Automatic
Generation Control (“AGC”) equipment to automatically and continuously
adjust Resource output to balance the SPP Balancing Authority Area in
accordance with NERC control performance criteria.
Regulation-Down
Resource capacity that is available for the purpose of providing Regulation
Deployment between zero Regulation Deployment and the down direction.
Regulation-Up
Resource capacity held in reserve for the purpose of providing Regulation
Deployment between zero Regulation Deployment and the up direction.
SPP.org 8
SPP Spinning Reserve Definition
“The portion of Contingency Reserve consisting of
Resources synchronized to the system and fully available to
serve load within the Contingency Reserve Deployment
Period following a contingency event.”
SPP defines contingency deployment period as 10 minute
interval
SPP.org 9
SPP Supplemental Reserve Definition
“The portion of Operating Reserve consisting of on-line or
off-line Resources capable of being synchronized to the
system that is fully available to serve load within the
Contingency Reserve Deployment Period following a
contingency event.”
SPP defines contingency deployment period as 10 minute
interval
SPP.org 10
Future Energy and Operating Reserve Market Functions
Day -Ahead Market
(DA Market)
Real -Time Balancing
Market(RTBM)
Reliability Unit Commitment
(RUC)
DA Market & Net RTBM Settlements
DA Market Offers (Energy and Operating Reserve), Bids, Operating Reserve
Requirements
DA Market Commitment, Cleared Energy and Operating
Reserve (MW and Price) (hourly)
Resource and Load
Meter Data
Dispatch Instruction, cleared Operating Reserve
(MW) (5 minute)
DA Market Commitment
RUC Commitment
EMS
RTBM Offers, Load Forecast, Operating
Reserve Requirements
TCR Markets
RTBM Offers, Load Forecast, Operating
Reserve Requirements
Dispatch Instruction, cleared Operating Reserve
(MW and Price) (5 minute)
Day -Ahead Market
(DA Market)
Real -Time Balancing
Market(RTBM)
Reliability Unit Commitment
(RUC)
DA Market & Net RTBM Settlements
DA Market Offers (Energy and Operating Bids, Operating Reserve
Requirements
DA Market Commitment, Cleared Energy and Operating
Reserve (MW and Price) (hourly)
Resource and Load
Meter Data
Dispatch Instruction, cleared Operating Reserve
(MW) (5 minute)
rCommitm
RUC Commitment
EMS
RTBM Offers, Load Forecast, Operating
Reserve Requirements
TCR Markets
RTBM Offers, Load Forecast, Operating
Reserve Requirements
Dispatch
Operating R(MW and Price)
(5 minute)
SPP.org 11
Example Conventions
To stay consistent with SPP Settlements, all the examples
throughout the presentation that involve settlement
calculations follow the convention below:
l)(Withdrawa Actual
)(Injection Actual (RT)Amount Actual Settlement
l)(Withdrawa Award
)(Injection Award (DA)Amount Cleared Settlement
SPP
SPP
SPP.org 12
THE DAY-AHEAD MARKET
(DA Market)
SPP.org 13
Understanding The Day Ahead Market
The Day Ahead Market provides Market Participants with
the ability to submit offers to sell Energy, Regulation-Up,
Regulation-Down, Spinning Reserve and Supplemental
Reserve and/or to submit bids to purchase Energy
SPP goal is to create a financially-binding day-ahead schedule for Energy and Operating Reserves
SPP will use a “Security-Constrained Unit Commitment” software to derive the day-ahead schedule, based on resource offers and bids submitted by Market Participant at 11 am on the day prior to Operating Day
SPP.org 14
Understanding The Day Ahead Market
Generation committed through the Day-Ahead Market is
selected by SPP in a way that results in the lowest total
production cost to serve bid in load and to meet Operating
Reserve requirements in the Day-Ahead Market.
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Me
ga
wa
tts Generation cleared in DA Market
Bid in Load and Operating Reserves
cleared in DA Market
Hour
Self Committed Resources
(Day Ahead Input)
SPP.org 15
Highlights
Market Participants submit Offers and Bids by 11:00 am
previous day to Operating Day
Suppliers submit MW quantity and price offers for each hour of Operating Day including any Operating Reserve Offers
Loads submit MW requirement bids for each hour of Operating Day including any price sensitive load bids
Includes offers / bids for virtual supply and virtual load
Security Constrained Unit Commitment (SCUC) scheduling
software co-optimizes Energy and Operating Reserves for
least cost solution
SPP.org 16
Highlights
Locational Marginal Prices (LMPs) and Operating Reserve
Market Clearing Prices (MCPs) posted by 4:00 PM previous
day to Operating Day
Cleared Energy supply paid at Settlement Location LMP
Cleared Energy demand charged at Settlement Location LMP
Cleared Operating Reserves paid at the Reserve Zone MCPs
SPP guarantees revenue sufficiency of committed resource
Offers
Supply-Demand deviations settled in Real-Time Market
SPP.org 17
Cleared Energy &
OR Offers
Cleared Energy
Bids: Virtuals &
Demand
Cleared Import,
Export &
Interchange
Transactions
RTBM Resource
Offers
DA Resource
Commit
Schedules
SPP Operating
Reserve
Requirements
RTBM Resource
Offers
DA Resource
Commit
Schedules
SPP Operating
Reserve
Requirements
[SCUC]
RTBM Resource
Offers
DA Resource
Commit
Schedules
DA Confirmed
Import, Export &
Interchange
Transactions
Resource
Outage
Notifications
SPP Operating
Reserve
Requirements
SPP Forecasts
(Load & Wind)
DA Market
Demand Bids
DA Market
Resource Offers:
Energy and OR
DA Market
Import, Export &
Interchange
Transactions
Resource
Outage
Notifications
SPP Operating
Reserve
Requirements
Virtual Energy
Offers and Bids
SPP.org 18
DA Market Timeline
- SPP Publishes Load and Wind Forecast
- SPP publishes Operating Reserve requirements
- Submit DA Demand Bids, Unit Offers (Energy & OR), Virtual bids & offers and physical transactions to SPP
- SPP runs SCUC in the day-ahead mode
- Submit revised offers and/or self schedules for units that were not selected in DA run
- SPP runs SCUC in RUC mode
- SPP reports DA RUC results to affected market participants
0600 19001100 1600 1700 2000
Day Prior to Operating Day
SPP.org 19
What Data Will Market Participants Need to
Submit to SPP for Resources?
3-Part Energy Offers
Energy Offer Curve
($/MWh as a function of
MW)
Startup Offers ($/Start for
hot, warm, and cold
starts)
No-Load Offers ($/hr)
Operating Reserve Offers
Regulation Up ($/MW)
Regulation Down ($/MW)
Spin ($/MW)
Supplemental ($/MW)
SPP.org 20
What Data Will Market Participants Need to
Submit to SPP for Resources?
Operating Parameters and
Limits
Ramp rates
Hourly min and max operation
limits
Hourly min and max emergency
limits
Min and max run time,
Min down time
Etc.
Commit Status
Market
Reliability
Self
Outage
Energy Dispatch Status
Market
VER
Not Qualified
OR Dispatch Status
Market
Fixed
Not Qualified
SPP.org 21
Start-Up Offer
No-Load Offer
Energy Offer
The cost for operating a
synchronized Resource at
zero (0) MW output.
The cost that a Market Participant
incurs in starting up a generating unit
A set of price/quantity
pairs that represents the
offer to provide Energy
from a Resource
Energy 3-Part Offer
SPP.org 22
Energy 3-Part Offer Example
Resource Type 120 MW Gas Unit
Fuel Gas
Fuel Cost ($/MMBTU) 7
Incremental Heat Rate (MMBTU/MWh) 10
No-Load Heat (MMBTU/Hr) 100
Startup Fuel Requirement (MMBTU) Hot=1000;Warm=2000;Cold=2500
Min Econ. Capacity Limit (MW) 25
Max Econ. Capacity Limit (MW) 120
Consider the following Market Participant Resource:
Assuming the Market Participant decides to offer this
Resource at cost, formulate its 3-part offer
SPP.org 23
Energy 3-Part Offer Example
Resource Type 120 MW Gas Unit
Fuel Gas
Fuel Cost ($/MMBTU) 7
Incremental Heat Rate (MMBTU/MWh) 10
No-Load Heat (MMBTU/Hr) 100
Startup Fuel Requirement (MMBTU) Hot=1000;Warm=2000;Cold=2500
Min Econ. Capacity Limit (MW) 25
Max Econ. Capacity Limit (MW) 120
Consider the following Market Participant Resource:
Hot Warm Cold
7,000 14,000 17,500
MW $/MWh
25 70
120 70
700
Startup Offer ($) No Load Offer ($/h) Incremental Offer
SPP.org 24
Operating Reserve Offers
An Operating Reserve Offer is an offer to supply Reserve
Product capacity
Impact:
Financial
o Market Participants receive payment for cleared Offers
Reliability
o Additional capacity offered into the DA Market allows SPP to
cover all of its Operating Reserve Requirements
SPP.org 25
What Data Will Market Participants Need to
Submit to SPP for Loads?
Fixed Demand Bids
Market Participants specify a MW quantity, load location, and hours
and become price takers. The bid will be cleared regardless of the
price at the load settlement location.
Price-Sensitive Demand Bids
Market Participants specify a MW quantity/price pairs, load location,
and hours. A price sensitive demand bid is a bid to buy generation
as the price decreases.
SPP.org 26
|Example 1|
Day Ahead Market: Incremental Energy Offer
• MP1 submits the DA Incremental Offer Curve below for
resource Gen1 for hour 1100. Assuming Gen1 is online and
that DA Market LMP clears at $40/MWh, determine Gen1’s
expected:
•DA Energy award
•DA Energy credit / charge
DA Energy Award = 65 MWh
MW $/MWh
25 10
50 25
75 50
120 60
Gen1 DA Energy Offer Curve
MP1
Gen1 Load1
DA Energy Credit/Charge = - DA Award *
DA LMP = -65 x 40 = -$2600 (credit)
SPP.org 27
|Example 2|
Day Ahead Market: Price Sensitive Demand Bid
• Assume MP1 submits the DA Price Sensitive Demand Bid
Curve below for resource Load1 for hour 1100. If DA Market
LMP clears at $40/MW, determine Load1’s expected:
•DA Energy award
•DA Energy credit / charge
DA Energy Award = 65 MWh
MW $/MWh
25 80
50 55
75 30
100 25
Load1 DA Energy Bid Curve
MP1
Gen1 Load1
DA Energy Credit/Charge = DA Award * DA
LMP = 65 x 40 = $2,600 (charge)
SPP.org 28
|Example 3|
Day Ahead Market: Operating Reserve Offer
Gen 1Oper. Cap. Max(MW): 120Spin Cap. Max (MW): 15
• MP1 submits a $5/MW DA Spin Offer for resource Gen1 for
1100. Assume Spin clears the DA Market at a 12 $/MW MCP
and that Gen1 cleared 65 MW of Energy. Determine Gen1’s
expected:
•DA Spin award
•DA Spin credit/charge
DA Spin Award = Min [15, 120 – 65] = 15 MW
DA Spin Credit/Charge = - DA Award * DA
MCP = - 15 x 12 = -$180 (credit)
MP1
Gen1 Load1
Max Spin
Cap.(MW)
$/MW
15 5
Gen1 DA Spin Offer
SPP.org 29
Understanding Make Whole Payments
SPP Market offers the
Make-Whole Payment
guarantee: all units that
are started by the RTO
receive enough DA
revenues to cover their 3-
part offers (Energy, No-
Load, and Startup Offers)
and Operating Reserve
Offers
Energy Offer
No-Load Offer
Startup Offer
Market
Revenues
Make-Whole
Payment
OR Reserve
Offer
SPP.org 30
|Example 4|
Day Ahead Market: Understanding Make Whole Payments
Assume that:
• Gen1 is initially on-line
• SPP Commits Gen1 unit for all 24 hours
• DA LMP = 40 $/MWh for all 24 hours
• DA Schedule = 65 MWh for all 24 hours
Let’s determine:
a. DA Revenues
b. DA Costs
c. DA Make-whole Payment
MP1
Gen1 Load1
MW $/MWh
25 10
50 25
75 50
120 60
Gen1 DA Energy Offer Curve
Gen 1Oper. Cap. Max(MW): 120Startup Offer ($/start) 17,500
No-Load ($/hr) 700
SPP.org 31
Assume that:
• Gen1 is initially on-line
• ISO Commits Gen1 unit (cold start) for all 24 hours
• DA Schedule = 65 MWh for all 24 hours
• DA LMP = 40 $/MWh for all 24 hours
Answers:
DA Revenues = DA LMP x DA Energy Award x 24
(40 x 65 ) x 24 = $62,400
DA Costs = (DA Energy Cost + DA No-Load Cost) x 24
= (1,175 + 700) x 24 =$45,000
DA Make-Whole Payment = Min{0;DA Rev-DA Cost)
= $0
MP1
Gen1 Load1
MW $/MWh
25 10
50 25
75 50
120 60
Gen1 DA Energy Offer Curve
Gen 1Oper. Cap. Max(MW): 120Startup Offer ($/start) 17,500
No-Load ($/hr) 700
|Example 4|
Day Ahead Market: Understanding Make-Whole Payments
SPP.org 32
Assume that:
• Gen1 is initially off-line
• SPP Commits Gen1 unit (cold start) for all 24
hours
• DA Schedule = 65 MWh for all 24 hours
• DA LMP = 40 $/MWh for all 24 hours
Let’s determine:
a. DA Revenues
b. DA Costs
c. DA Make-Whole Payment
MP1
Gen1 Load1
MW $/MWh
25 10
50 25
75 50
120 60
Gen1 DA Energy Offer Curve
Gen 1Oper. Cap. Max(MW): 120Startup Offer ($/start) 17,500
No-Load ($/hr) 700
|Example 5|
Day Ahead Market: Understanding Make-Whole Payments
SPP.org 33
Assume that:
• Gen1 is initially off-line
• SPP Commits Gen1 unit (cold start) for all 24
hours
• DA Schedule = 65 MWh for all 24 hours
• DA LMP = 40 $/MWh for all 24 hours
Answers:
DA Revenues = DA LMP x Energy Award x 24
(40 x 65 ) x 24 = $62,400
DA Costs = (Energy Cost + No-Load Cost) x 24
+ Startup Cost
= (1,175 + 700)x24 + 17,500 = $62,500
DA Make-Whole Payment = Min{0;DA Rev-DA Cost)
= -$100 (credit)
MP1
Gen1 Load1
MW $/MWh
25 10
50 25
75 50
120 60
Gen1 DA Energy Offer Curve
Gen 1Oper. Cap. Max(MW): 120Startup Offer ($/start) 17,500
No-Load ($/hr) 700
|Example 5|
Day Ahead Market: Understanding Make-Whole Payments
SPP.org 34
RELIABILITY UNIT COMMITMENT
(RUC)
SPP.org 35
Understanding RUC
RUC is required to ensure reliable operating plan during the
operating day
Day-Ahead RUC performed following Day-Ahead Market clearing
Intra-Day RUC performed throughout the operating day as needed,
at least every 4 hours
RUC process ensures that Market physical commitment produces
adequate capacity to meet SPP Load Forecast and Operating
Reserve requirements in real-time
Uses SCUC algorithm to commit / de-commit additional resources
as needed
SPP.org 36
Understanding RUC
Hour
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Me
ga
wa
tts
Generation
cleared in DA
Market
Bid in Load and Operating
Reserve cleared in DA
Market
Self Committed Resources
Generation committed
in RUC
Generation
de-committed
in RUC
SPP Load Forecast and Operating
Reserve Requirements (RUC Input)
SPP.org 37
Highlights
Reliability Unit Commitment (RUC) ensures enough capacity, in addition
to Operating Reserve capacity, is committed to reliably serve the SPP
forecasted load for the next operating day
All Market Participants need to submit offers for all their registered
resources that are not on a planned, forced or otherwise approved
outage (Real-Time Balancing Market Resource Offers)
RUC will take into consideration the cleared resource commitment
schedules from the DA Market or previous RUC clearing process
(dependent upon market timeline)
Same as in the Day-Ahead Market, Resources committed by the RUC
processes are subject to make-whole payments given that they meet
the eligibility criteria
SPP.org 38
Highlights
A Security Constrained Unit Commitment (SCUC) program
is used in order to commit (decommit) and dispatch
committed resources based on submitted 3-Part Energy
Offers and Operating Reserve Offers in order to meet SPP
Load Forecast and Operating Reserve Requirements,
respecting transmission system operating constraints
RUC clearing is performed for Energy and Operating
Reserve products on a least cost, co-optimized basis
accounting for Resource marginal impacts on the
transmission network (marginal system losses and
congestion)
SPP.org 39
Resource
Commit /
De-commit
Schedules
Resource
Dispatch and
AGC
Notifications
Fixed Interchange
Transaction
Curtailment
Notification
RTBM Resource
Offers
DA Resource
Commit
Schedules
SPP Operating
Reserve
Requirements
RTBM Resource
Offers
DA Resource
Commit
Schedules
SPP Operating
Reserve
Requirements
[SCUC]
RTBM Resource
Offers
DA Resource
Commit
Schedules
DA Confirmed
Import, Export &
Interchange
Transactions
Resource
Outage
Notifications
SPP Operating
Reserve
Requirements
SPP Forecasts
(Load & Wind)
DA Confirmed
Import, Export &
Interchange
Transactions
RTBM Resource
Offers
DA Resource
Commit
Schedules
Resource
Outage
Notifications
SPP Operating
Reserve
Requirements
SPP Forecasts
(Load & Wind)
SPP.org 40
Day-Ahead RUC vs. Intra-Day RUC
Both RUC processes share the same purpose: ensure a
reliable operating plan during the operating day
Both processes use similar input data:
Day-Ahead RUC uses outputs from Day-Ahead Market
clearing process and the SPP available forecasts in the
Day-Ahead period.
Intra-day RUC uses outputs from the Day-Ahead
Market, Day-Ahead RUC and previously run Intra-day
RUC processes within the operating day
Intra-day RUC uses more up to date forecast data and
state estimator data closer to the operating hour
SPP.org 41
Day-Ahead RUC Timeline
- SPP runs SCUC in RUC mode
- SPP reports DA RUC results to affected Market Participants
- Submit revised offers and/or self schedules for units that were not selected in DA run
1900 2000
Day Prior to Operating Day
1700
SPP.org 42
Intra-Day RUC Timeline
0800Operating Day
04000000 1200 1600 2000 2400
- SPP runs SCUC in RUC mode
- SPP reports RUC results to affected Market Participants
- Submit revised offers and/or self schedules for units that were not selected in previous DA, DA RUC, Intra-Day RUC
Intra-Day RUC
Process =
Intra-Day RUC
Process
Intra-Day RUC
Process
Intra-Day RUC
Process
Intra-Day RUC
Process
Intra-Day RUC
Process
Intra-Day RUC
Process
SPP.org 43
THE REAL-TIME BALANCING MARKET
(RTBM)
SPP.org 44
Understanding the Real-Time Balancing Market
The Real-Time Balancing
Market (RTBM) serves as the
mechanism through which SPP
balances real-time load and
generation.
Resources are selected to be
increased (incremented) or
decreased (decremented) in
order to maintain system
balance
Generation Load
SPP.org 45
Highlights
Uses Security Constrained Economic Dispatch (SCED) to
ensure results are physically feasible.
Operates on a continuous 5-minute basis; calculates
Dispatch Instructions for Energy and clears Operating
Reserve by resource.
Energy and Operating Reserve are co-optimized.
Settlements are based on the difference between the
results of the RTBM process and the DA Market clearing.
Charges are imposed on Market Participants for failure to
deploy Energy and Operating Reserve as instructed.
SPP.org 46
Highlights
1-part offer: Energy Offer Curve
Operating Reserve Offers
Regulation-up and Regulation-down
Spinning Reserve and Supplemental Reserves
Accommodates participation of supply and demand external
to SPP
Imports, exports and through transactions and external
resources
SPP.org 47
|Example 6|
Real-Time Balancing Market Energy Offer Curve
• MP1 clears DA as shown in Example 1 and then submits the
following Incremental Offer Curve for Resource Gen1 for hour
1100 in Real-Time. Assuming Gen1 is online and that RT
Market LMP is $40/MWh, Gen1’s dispatch instruction is
60MW for each interval of the hour.
•What will be settlement for this scenario?
RT Energy Actual= 60MWh
MW $/MWh
25 10
50 25
75 60
120 65
Gen1 RT Energy Offer Curve
MP1
Gen1 Load1
RT Energy Settlement = (RT Actual -DA Award)
x RT LMP = (-60 + 65) x 40 = $200.00 (charge)
SPP.org 48
• MP1 clears DA as shown in Example 1. Assuming Gen1 is
metered at 70 MWh at hour 1100 and that RT Market LMP
clears at $40/MWh, determine Gen1’s:
•RT Energy award
•RT Energy settlement
RT Energy Award = 70MWh
MW $/MWh
25 10
50 25
75 50
120 60
Gen1 RT Energy Offer Curve
MP1
Gen1 Load1
RT Energy Settlement = (RT Actual -DA Award)
x RT LMP = (-70+65) x 40 = -$200 (credit)
|Example 7|
Real Time Balancing Market Incremental Energy Offer
SPP.org 49
FINANCIAL SCHEDULES
SPP.org 50
Understanding Financial Schedules
Bilateral Transactions that transfer financial responsibility within the
SPP Market Footprint
Energy
Operating Reserve
May be entered up to 4 days after Operating Day
SPP.org 51
Understanding Financial Schedules
Energy Financial Schedules
Must specify
o Settlement Location
o MW amount
o Buyer
o Seller
o Pricing (Day-Ahead or Real-Time Balancing Market)
o Seller and Buyer confirmation of the transaction
SPP.org 52
Understanding Financial Schedules
Operating Reserve Financial Schedules
Must specify
o Reserve Zone
o Operating Reserve Product
o MW amount
o Buyer
o Seller
o Pricing
o Seller and Buyer confirmation of the transaction
SPP.org 53
MP1 MP2
Gen1 Load2
|Example 8|
Understanding Financial Schedules: Energy Bilateral
DA Market Clearing (Supply)
Energy Award(MW): 100
DA LMP ($/MWH): 40
DA Market Clearing (Load)
Energy Award (MW): 100
DA LMP ($/MWH): 50
Assume DA Market clears as shown above. MP2 purchases 100 MW from MP1 @ 45 $/MWH
by entering into a bilateral transaction. The parties agree to submit an 100 MW Financial
Schedule that is settled at MP1 Settlement Location. Determine MP1 and MP2 DA impacts if:
a) One of the Market Participants fails to confirm the above financial schedule with SPP
b) Both Market Participants confirm the financial schedule with SPP
SPP.org 54
|Example 8|
Understanding Financial Schedules: Energy Bilateral
a) Financial Schedule not confirmed by Market Participants with SPP
MP1 MP2
Gen1 Load2
DA Market Clearing (Supply)
Energy Award (MW): 100
DA LMP ($/MWH): 40
DA Market Clearing (Load)
Energy Award (MW): 100
DA LMP ($/MWH): 50
MP1 SPP Settlement
DA Market Settlement = - DA Award x DA LMP = 100 x 40 = -$4,000 (credit)
MP1 Books (this bilateral transaction occurs outside SPP)
MP1 gets paid by MP2 an amount equal to $4,500 (=100 x 45)
In total, the impact on MP1 is a total credit of $8,500 since the Financial Schedule was not
confirmed with SPP
SPP.org 55
|Example 8|
Understanding Financial Schedules: Energy Bilateral
a) Financial Schedule not confirmed by Market Participants with SPP
MP1 MP2
Gen1 Load2
DA Market Clearing (Supply)
Energy Award (MW): 100
DA LMP ($/MWH): 40
DA Market Clearing (Load)
Energy Award (MW): 100
DA LMP ($/MWH): 50
MP2 SPP Settlement
DA Market Settlement = DA Award x DA LMP = 100 x 50= $5,000 (charge)
MP2 Books (this bilateral transaction occurs outside SPP)
MP2 pays MP1 an amount equal to $4,500 (= 100 x 45)
In total, the impact on MP2 is a total charge of $9,500 since the Financial Schedule was not
confirmed with SPP
SPP.org 56
|Example 8|
Understanding Financial Schedules: Energy Bilateral
MP1 SPP Settlement
Gen1 DA Settlement = -DA Award x DA LMP = -100 x 40 = -$4,000 (credit)
DA Financial Schedule Settlement = Fin Sched x DA LMP = 100 x 40 = $4,000 (charge)
DA Net Settlement =- 4,000 + 4,000 = $0
MP1 Books (this bilateral transaction occurs outside SPP)
MP1 gets paid by MP2 an amount equal to $4,500 (=100 x 45)
In total, the impact on MP1 is a total credit of $4,500 since the Financial Schedule was
confirmed with SPP
b) Financial Schedule confirmed by Market Participants to SPP
MP1 MP2
Gen1 Load2
DA Market Clearing (Supply)
Energy Award (MW): 100
DA LMP ($/MWH): 40
DA Market Clearing (Load)
Energy Award (MW): 100
DA LMP ($/MWH): 50
SPP.org 57
|Example 8|
Understanding Financial Schedules: Energy Bilateral
MP2 SPP Settlement
Load2 DA Settlement = DA Award x DA LMP = 100 x 50 = $5,000 (charge)
DA Financial Schedule Settlement = -Fin Sched x DA LMP = -100 x 40 = $4,000 (credit)
DA Net Settlement = 5,000 – 4,000 = $1,000 (charge)
MP2 Books (this bilateral transaction occurs outside SPP)
MP2 pays MP1 an amount equal to $4,500 ( = 100 x 45)
In total, the impact on MP2 is a total charge of $5,500 since the Financial Schedule was
confirmed with SPP
b) Financial Schedule confirmed by Market Participants to SPP
MP1 MP2
Gen1 Load2
DA Market Clearing (Supply)
Energy Award (MW): 100
DA LMP ($/MWH): 40
DA Market Clearing (Load)
Energy Award (MW): 100
DA LMP ($/MWH): 50
SPP.org 58
MP1 MP2
Gen1 Load2
|Example 9|
Understanding Financial Schedules: Energy Bilateral
DA Market Clearing (Supply)
Energy Award (MW): 100
DA LMP ($/MWH): 40
DA Market Clearing (Load)
Energy Award (MW): 100
DA LMP ($/MWH): 50
Assume DA Market clears as shown above. MP2 purchases 100 MW from MP1 @ 45 $/MWH
by entering into a bilateral transaction. The parties agree to submit an 100 MW Financial
Schedule that is settled at MP2 Settlement Location.
Determine MP1 and MP2 DA impacts if both Market Participants confirm the financial
schedule with SPP
SPP.org 59
|Example 9|
Understanding Financial Schedules: Energy Bilateral
MP1 SPP Settlement
Gen1 DA Settlement = -DA Award x DA LMP = -100 x 40 = -$4,000 (credit)
DA Financial Schedule Settlement = Fin Sched x DA LMP =100 x 50 = $5,000 (charge)
DA Net Settlement = - 4,000 + 5,000= $1,000 (charge)
MP1 Books (this bilateral transaction occurs outside SPP)
MP1 gets paid by MP2 an amount equal to $4,500 ( = 100 x 45)
In total, the impact on MP1 is a total credit of $3500 since the Financial Schedule was
confirmed with SPP
b) Financial Schedule confirmed by Market Participants to SPP
MP1 MP2
Gen1 Load2
DA Market Clearing (Supply)
Energy Award (MW): 100
DA LMP ($/MWH): 40
DA Market Clearing (Load)
Energy Award (MW): 100
DA LMP ($/MWH): 50
SPP.org 60
|Example 9|
Understanding Financial Schedules: Energy Bilateral
MP2 SPP Settlement
Load 2 DA Settlement = DA Award x DA LMP = 100 x 50 = $5,000 (charge)
DA Financial Schedule Settlement = - Fin Sched x DA LMP = 100 x 50 = -$5,000 (credit)
DA Net Settlement = 5,000 – 5,000 = $0
MP2 Books (this bilateral transaction occurs outside SPP)
MP2 pays MP1 an amount equal to $4,500 ( = 100 x 45)
In total, the impact on MP2 is a total charge of $4500 since the Financial Schedule was
confirmed with SPP
b) Financial Schedule confirmed by Market Participants to SPP
MP1 MP2
Gen1 Load2
DA Market Clearing (Supply)
Energy Award (MW): 100
DA LMP ($/MWH): 40
DA Market Clearing (Load)
Energy Award (MW): 100
DA LMP ($/MWH): 50
SPP.org 61
VIRTUAL TRANSACTIONS
SPP.org 62
Understanding Virtual Transactions
What is a Virtual Transaction?
Virtual Energy Bids and Offers allow any Market Participant to bid or
offer at any Settlement Location in the SPP Day-Ahead Market.
If a virtual transaction is cleared, the Market Participant will settle
the Bid or Offer at the difference between the Day-Ahead Market
LMP and the Real-Time Balancing Market (RTBM) LMP for the full
amount of the Day-Ahead award.
The net effect of Virtual Energy Bids and Offers is to cause the Day-
Ahead LMP and RTBM LMP to converge.
o If there is a location that is expected to be more expensive in the DA
Market than in the RTBM, participants may be incented to submit
Virtual Energy Offers until, over time, the two markets equalize in price.
SPP.org 63
Understanding Virtual Transactions: Settlement
Virtual Offer
Offer Quantity (MW) into DA Market at an Offer Price ($/MWh)
If DA LMP > Offer Price, Offer is cleared in Day-Ahead for Offer Quantity
If cleared, Market Participant must buy back Energy awarded from SPP at the Real-
Time price
If DA LMP > RT LMP Market Participant realizes a profit
If DA LMP < RT LMP Market Participant incurs losses
Virtual Bid
Bid Quantity (MW) into DA Market at Bid Price ($/MWh)
If DA LMP < Bid Price, bid is cleared in day-ahead for Bid Quantity
If cleared, Market Participant must sell back Energy awarded to SPP at the Real-
Time price
If DA LMP < RT LMP Market Participant realizes a profit
If DA LMP > RT LMP Market Participant incurs losses
SPP.org 64
|Example 10|
Understanding Virtual Transactions: Virtual Offer
• MP1 submits a Virtual Energy Offer Curve for hour 1100 in
Day-Ahead. Assuming the DA LMP clears at $40/MWh and
the RT LMP clears at $35/MWh, determine the virtual’s:
•DA Energy award
•Net Energy Settlement of the Virtual financial position
MW $/MWh
5 25
10 35
15 45
MP1 DA Virtual Offer Curve
MP1
Gen1 Load1
DA Energy Award = 12.5 MWh
Net Energy Settlement = - DA Award x (DA LMP
– RT LMP) = -12.5 x (40-35) = - $62.5 (credit)
SPP.org 65
|Example 11|
Understanding Virtual Transactions: Virtual Offer
• MP1 submits a Virtual Energy Offer Curve for hour 1100 in
Day-Ahead. Assuming the DA LMP clears at $40/MWh and
the RT LMP clears at $45/MWh, determine the virtual’s:
•DA Energy award
•Net Energy Settlement of the Virtual financial position
MW $/MWh
5 25
10 35
15 45
MP1 DA Virtual Offer Curve
MP1
Gen1 Load1
DA Energy Award = 12.5 MWh
Net Energy Settlement = - DA Award x (DA LMP
– RT LMP) = -12.5 x (40-45) = $62.5 (charge)
SPP.org 66
|Example 12|
Understanding Virtual Transactions: Virtual Bid
• MP1 submits a Virtual Energy Bid Curve for hour 1100 in
Day-Ahead. Assuming that the DA LMP clears at $40/MWh
and the RT LMP clears at $35/MWh, determine the virtual’s:
•DA Energy award
•Net Energy Settlement of the Virtual financial position
MW $/MWh
5 45
10 20
15 5
MP1 DA Virtual Bid Curve
MP1
Gen1 Load1
DA Energy Award = 6 MWh
Net Energy Settlement = DA Award x (DA LMP –
RT LMP) = 6 x (40-35) = $30 (charge)
SPP.org 67
|Example 13|
Understanding Virtual Transactions: Virtual Bid
• MP1 submits a Virtual Energy Bid Curve for hour 1100 in
Day-Ahead. Assuming that the DA LMP clears at $40/MWh
and the RT LMP clears at $45/MWh, determine the virtual’s:
•DA Energy award
•Net Energy Settlement of the Virtual financial position
MW $/MWh
5 45
10 20
15 5
MP1 DA Virtual Bid Curve
MP1
Gen1 Load1
DA Energy Award = 6 MWh
Net Energy Settlement = DA Award x (DA LMP –
RT LMP) = 6 x (40-45) = - $30 (credit)
SPP.org 68
CO-OPTIMIZATION
SPP.org 69
Understanding Co-optimization
Why co-optimize?
There is a strong interaction between the supply of Energy
and the provision of Operating Reserve
Energy and Operating Reserve compete for same resource
capacity
Co-optimization evaluates the lost opportunity costs trade-offs
when allocating products (Energy, Operating Reserve)
SPP.org 70
Understanding Co-optimization
When clearing the market (Day-Ahead and Real-Time), SPP must
determine an operating schedule that:
Minimizes the SPP total production costs, based on Offers and
Bids of Market Participants and ,
Maximizes Market Participants benefits for all the market products
that they have submitted Bids and Offers on,
Ensures that all reliability and transmission constraints are met.
The market clearing optimization engine proposed by SPP is a co-
optimization engine, which takes Bids and Offers of all market products
(Energy, Spinning Reserve, Regulation-Up, Regulation-Down,
Supplemental Reserve) for all Market Participants and simultaneously
determine the market products allocation amongst Market Participants
that achieves the above mentioned objectives.
SPP.org 71
Understanding Co-optimization
Does co-optimization produce a schedule that minimizes the total
production cost for SPP?
Does co-optimization produce a schedule that maximizes operating
profits for Market Participants?
Can we explain Operating Reserve prices calculated by the
optimization engine?
SPP.org 72
MP2
Gen 1
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 8
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 2
Load 1
Energy Forecast (MW): 100
End User Rate ($/MWH): 40
Spin Requirement (MW): 10
Gen 2
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 10
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 3
Load 2
Energy Forecast (MW): 100
End User Rate ($/MWH): 45
Spin Requirement (MW): 10
Understanding Co-optimization: Examples
Consider 2 Market Participants MP1 and MP2 as above, each with generation resources
and load to serve with a reliability requirement in the form of Spinning Reserve.
How can these Market Participants benefit most from SPP future market operations?
Balancing Authority 1 Balancing Authority 2
MP1
SPP.org 73
MP2
Gen 1
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 8
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 2
Load 1
Energy Forecast (MW): 100
End User Rate ($/MWH): 40
Gen 2
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 10
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 3
Load 2
Energy Forecast (MW): 100
End User Rate ($/MWH): 45
Understanding Co-optimization: Examples
In SPP future market operations, there will be only one Consolidated Balancing Authority,
responsible for establishing reliability requirements throughout SPP network footprint.
In the following case studies, we assume that:
Both Market Participants belong to the same Reserve Zone and offer their
generation at cost,
The network has no congestion and no losses.
Reserve Zone
Spin Requirement (MW): 20
Consolidated Balancing Authority
MP1
SPP.org 74
MP2
Gen 1
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 8
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 2
Load 1
Energy Forecast (MW): 100
End User Rate ($/MWH): 40
Gen 2
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 10
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 3
Load 2
Energy Forecast (MW): 100
End User Rate ($/MWH): 45
Let’s determine:
Each Market Participant awards (Energy and Spin), operational cost and LMP,
The Reserve Zone Spin MCP,
SPP total production cost,
Each Market Participant profit margin.
Reserve Zone
Spin Requirement (MW): 20
MP1
|Example 14|
Understanding Co-optimization: Non-Co-optimized case
Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin
each)
SPP.org 75
MP2
Gen 1
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 8
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 2
Load 1
Energy Forecast (MW): 100
End User Rate ($/MWH): 40
Gen 2
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 10
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 3
Load 2
Energy Forecast (MW): 100
End User Rate ($/MWH): 45
Let’s determine:
Each Market Participant awards (Energy and Spin), operational cost and LMP,
The Reserve Zone Spin MCP,
SPP total production cost,
Each Market Participant profit margin.
Reserve Zone
Spin Requirement (MW): 20
MP1
|Example 14|
Understanding Co-optimization: Non-Co-optimized case
Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin
each)
SPP.org 76
MP2
Gen 1
Energy Award (MW): 100
Spin Award (MW): 10
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 100
Spin Award (MW): 10
Load 2
Energy Forecast (MW): 100
|Example 14|
Understanding Co-optimization: Non-Co-optimized case
MP1 Gen. Schedule
(MW)
Operational
Cost ($)
Energy 100 800
Spin 10 20
Total - 820
MP2 Gen. Schedule
(MW)
Operational
Cost ($)
Energy 100 1,000
Spin 10 30
Total - 1,030
LMP = 8 $/MWH LMP = 8 $/MWH
Total System Operational Cost = $ 1,850
Spin Market Clearing Price = 2 $/MW
Reserve Zone
Spin Requirement (MW): 20
Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin
each)
MP10 MW >>
SPP.org 77
MP2
Gen 1
Energy Award (MW): 100
Spin Award (MW): 10
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 100
Spin Award (MW): 10
Load 2
Energy Forecast (MW): 100
LMP = 8 $/MWH LMP = 8 $/MWH
Explaining LMPs: Why is LMP = 8 $/MWH at MP1’s price node?
Answer: if we increase the load at MP1’s price node by 1 MW, that increase would be most
economically met by:
- increasing Gen 1’s energy schedule by 1 MW → production cost impact = (101-100) x 8 = $ 8
Spin Market Clearing Price = 2 $/MW
|Example 14|
Understanding Co-optimization: Non-Co-optimized case
Reserve Zone
Spin Requirement (MW): 20
Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin
each)
MP10 MW >>
SPP.org 78
MP2
Gen 1
Energy Award (MW): 100
Spin Award (MW): 10
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 100
Spin Award (MW): 10
Load 2
Energy Forecast (MW): 100
LMP = 8 $/MWH LMP = 8 $/MWH
Spin Market Clearing Price = 2 $/MW
|Example 14|
Understanding Co-optimization: Non-Co-optimized case
Reserve Zone
Spin Requirement (MW): 20
Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin
each)
MP10 MW >>
Explaining MCPs : Why is Spin Clearing Price = 2 $/MW?
Answer: if we increase the Spinning Reserve system requirement by 1 MW, that need would be most
economically met by:
- increasing Gen 1’s Spinning Reserve schedule by 1 MW → production cost impact = (11-10) x 2 = $ 2
SPP.org 79
MP2
Gen 1
Energy Award (MW): 100
Spin Award (MW): 10
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 100
Spin Award (MW): 10
Load 2
Energy Forecast (MW): 100
LMP = 8 $/MWH LMP = 8 $/MWH
Operating Profit
Revenues ($) Costs ($) Net Profit ($)
Generation MP1: 820.00 820.00 0.00
Charges ($) Revenues ($) Net Profit ($)
Demand MP1: 820.00 4,000.00 3,180.00
Operating Profit
Revenues ($) Costs ($) Net Profit ($)
Generation MP2: 820.00 1,030.00 -210.00
Charges ($) Revenues ($) Net Profit ($)
Demand MP2: 820.00 4,500.00 3,680.00
MP1 Profit = $ 3,180 MP2 Profit = $ 3,470
Spin Market Clearing Price = 2 $/MW
|Example 14|
Understanding Co-optimization: Non-Co-optimized case
Reserve Zone
Spin Requirement (MW): 20
Market Participants self-schedule their participation in the market (100 MW Energy and 10 MW Spin
each)
MP10 MW >>
SPP.org 80
MP2
Gen 1
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 8
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 2
Load 1
Energy Forecast (MW): 100
End User Rate ($/MWH): 40
Gen 2
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 10
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 3
Load 2
Energy Forecast (MW): 100
End User Rate ($/MWH): 45
Let’s determine:
Each Market Participant awards (Energy and Spin), operational cost and LMP,
The Reserve Zone Spin MCP,
SPP total production cost,
Each Market Participant profit margin.
Reserve Zone
Spin Requirement (MW): 20
Consolidated Balancing Authority
MP1
|Example 15|
Understanding Co-optimization: Co-optimized case
Market Participants offer their true economic limits and let SPP co-optimize the market
SPP.org 81
MP2
Gen 1
Energy Award (MW): 115
Spin Award (MW): 5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 85
Spin Award (MW): 15
Load 2
Energy Forecast (MW): 100
MP1 Gen. Schedule
(MW)
Operational
Cost ($)
Energy 115 920
Spin 5 10
Total - 930
MP2 Gen. Schedule
(MW)
Operational
Cost ($)
Energy 85 850
Spin 15 45
Total - 895
LMP = 10 $/MWH LMP = 10 $/MWH
Total System Operational Cost = $ 1,825
15 MW >>
Spin Market Clearing Price = 4 $/MW
(vs. $ 1,850 in Example 14)
|Example 15|
Understanding Co-optimization: Co-optimized case
Market Participants offer their true economic limits and let SPP co-optimize the market
Reserve Zone
Spin Requirement (MW): 20
MP1
SPP.org 82
MP2
Gen 1
Energy Award (MW): 115
Spin Award (MW): 5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 85
Spin Award (MW): 15
Load 2
Energy Forecast (MW): 100
LMP = 10 $/MWH LMP = 10 $/MWH
15 MW >>
Explaining LMPs : Why is LMP = 10 $/MWH at MP1’s price node?
Answer: if we increase the load at MP1’s price node by 1 MW, that increase would be most
economically met by:
- increasing Gen 2’s energy schedule by 1 MW → production cost impact = (86-85) x10 = $ 10
Spin Market Clearing Price = 4 $/MW
|Example 15|
Understanding Co-optimization: Co-optimized case
Reserve Zone
Spin Requirement (MW): 20
Market Participants offer their true economic limits and let SPP co-optimize the market
MP1
SPP.org 83
MP2
Gen 1
Energy Award (MW): 115
Spin Award (MW): 5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 85
Spin Award (MW): 15
Load 2
Energy Forecast (MW): 100
LMP = 10 $/MWH LMP = 10 $/MWH
15 MW >>
Explaining LMPs : Why is LMP = 10 $/MWH at MP1’s price node?
Answer: if we increase the load at MP1’s price node by 1 MW, that increase would be most
economically met by:
- increasing Gen 2’s energy schedule by 1 MW → production cost impact = (86-85) x10 = $ 10
Spin Market Clearing Price = 4 $/MW
|Example 15|
Understanding Co-optimization: Co-optimized case
Reserve Zone
Spin Requirement (MW): 20
Market Participants offer their true economic limits and let SPP co-optimize the market
MP1
SPP.org 84
MP2
Gen 1
Energy Award (MW): 115
Spin Award (MW): 5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 85
Spin Award (MW): 15
Load 2
Energy Forecast (MW): 100
LMP = 10 $/MWH LMP = 10 $/MWH
15 MW >>
Explaining MCPs: Why is Spin Clearing Price = 4 $/MW?
Answer: if we increase the Spinning Reserve system requirement by 1 MW, that need would be most
economically met by:
- decreasing Gen 1’s energy schedule by 1 MW → production cost impact = (114 – 115) x 8 = - $ 8
- increasing Gen 2’s energy schedule by 1 MW → production cost impact = (86-85) x 10 = $ 10
- increasing Gen 1’s Spinning Reserve schedule by 1 MW → production cost impact = (6-5) x 2 = $ 2
Spin Market Clearing Price = 4 $/MW
|Example 15|
Understanding Co-optimization: Co-optimized case
Reserve Zone
Spin Requirement (MW): 20
Market Participants offer their true economic limits and let SPP co-optimize the market
MP1
SPP.org 85
MP2
Gen 1
Energy Award (MW): 115
Spin Award (MW): 5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 85
Spin Award (MW): 15
Load 2
Energy Forecast (MW): 100
LMP = 10 $/MWH LMP = 10 $/MWH
Operating Profit
Revenues ($) Costs ($) Net Profit ($)
Generation MP1: 1,170.00 930.00 240.00
Charges ($) Revenues ($) Net Profit ($)
Demand MP1: 1,040.00 4,000.00 2,960.00
Operating Profit
Revenues ($) Costs ($) Net Profit ($)
Generation MP2: 910.00 895.00 15.00
Charges ($) Revenues ($) Net Profit ($)
Demand MP2: 1,040.00 4,500.00 3,460.00
MP1 Profit = $ 3,200 MP2 Profit = $ 3,475
15 MW >>
(vs. $ 3,180 in Example 14) (vs. $ 3,470 in Example 14)
Spin Market Clearing Price = 4 $/MW
|Example 15|
Understanding Co-optimization: Co-optimized case
Reserve Zone
Spin Requirement (MW): 20
Market Participants offer their true economic limits and let SPP co-optimize the market
MP1
SPP.org 86
MP1 MP2
Gen 1
Energy Award (MW): 115
Spin Award (MW): 5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 85
Spin Award (MW): 15
Load 2
Energy Forecast (MW): 100
LMP = 10 $/MWH LMP = 10 $/MWH
15 MW >>
Explaining Profit Maximization: Is MP2 Profit maximized?
Answer: Yes, since MP2 is being awarded as much spinning reserve (its most profitable product) first
followed by energy next (less profitable product).
Offer
($/MW)
Market Price
($/MW)
Profit Margin
($/MW)
Energy: 10 10 10 – 10 = 0
Spin: 3 4 4 – 3 = 1
Spin Market Clearing Price = 4 $/MW
|Example 15|
Understanding Co-optimization: Co-optimized case
Reserve Zone
Spin Requirement (MW): 20
Market Participants offer their true economic limits and let SPP co-optimize the market
SPP.org 87
MP2
Gen 1
Energy Award (MW): 115
Spin Award (MW): 5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 85
Spin Award (MW): 15
Load 2
Energy Forecast (MW): 100
LMP = 10 $/MWH LMP = 10 $/MWH
15 MW >>
Explaining Profit Maximization: Is MP1 Profit maximized?
Answer: Yes, since MP1 is being awarded as much energy first, followed by Spinning Reserve. Note
that both products are equally profitable for this Market Participant.
Offer
($/MW)
Market Price
($/MW)
Profit Margin
($/MW)
Energy: 8 10 10 – 8 = 2
Spin: 2 4 4 – 2 = 2
Spin Market Clearing Price = 4 $/MW
|Example 15|
Understanding Co-optimization: Co-optimized case
Reserve Zone
Spin Requirement (MW): 20
Market Participants offer their true economic limits and let SPP co-optimize the market
MP1
SPP.org 88
Understanding Co-optimization: Conclusion
Does co-optimization produce a schedule that minimizes the total
production cost for SPP?
Answer: YES
Does co-optimization produce a schedule that maximizes
operating profits for Market Participants?
Answer: YES
No Co-
optimization
With Co-
optimization
System Cost ($): 1,850 1,825
No Co-
optimization
With Co-
optimization
MP1 Profit ($): 3,180 3,200
MP2 Profit ($): 3,470 3,475
Total MPs Profits ($): 6,650 6,675
SPP.org 89
Can we explain Operating Reserve prices calculated by the
optimization engine?
Answer: YES
Operating Reserve Clearing Price = Lost Opportunity Cost +
Operating Reserve Offer Price for marginal unit (which
provides the next MW for the Operating Reserve product)
Decreasing Gen 1’s energy schedule by 1 MW:
production cost impact = (114 – 115) x 8 = - $ 8
Lost Opportunity Cost = 2 $
Marginal Unit Offer Price = 2 $Increasing Gen1’s Spinning Reserve schedule by 1 MW:
production cost impact = (6-5) x 2 = $ 2
Increasing Gen 2’s energy schedule by 1 MW:
production cost impact = (86 – 85) x 10 = $ 10
Co-optimized Scenario (Example 9): MCP for Spinning Reserve
+
Understanding Co-optimization: Conclusion
SPP.org 90
SCARCITY PRICING
SPP.org 91
Understanding Scarcity Pricing
Scarcity Pricing is a market mechanism that allows prices to
rise automatically when there is a shortage of supply in the
market
Prices set by scarcity pricing should reflect the level of
shortage in supply
Scarcity prices enhance market efficiency and reliability
o May stimulate demand response
o Draw supply from outside the SPP Balancing Authority
o Incentivizes generation availability during peak loads
o Promotes long-term contracting
SPP.org 92
Understanding Scarcity Pricing
SPP has implemented Scarcity Pricing in its Future Market
Protocols through a set of Demand Curves for Operating
Reserve
Demand Curves: Set pre-determined prices at different
levels of shortages for each of the reserve products:
o Operating Reserve
o Regulation – Up
o Regulation - Down
SPP.org 93
MP1 MP2
Gen 1
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 8
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 2
RegUp Cap. Max (MW): 4.5
RegUp Offer Cost ($/MW): 6
Load 1
Energy Forecast (MW): 100
End User Rate ($/MW) 40
Gen 2
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 10
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 3
RegUp Cap. Max (MW): 4.5
RegUp Offer Cost (MW): 4
Load 2
Energy Forecast (MW): 100
End User Rate ($/MW) 45
Understanding Scarcity Pricing: Examples
In the following case studies, we assume that:
Both Market Participants belong to the same Reserve Zone and offer their
generation at cost as well as their true economic limits,
Reliability requirements are in the form of Regulation-Up and Spinning Reserve,
with demand curves set to $200/MW and $75/MW respectively,
The network has no congestion and no losses.
Reserve Zone
Spin Requirement (MW): -
Reg Up Requirement (MW): -
Consolidated Balancing Authority
SPP.org 94
MP1 MP2
Gen 1
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 8
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 2
RegUp Cap. Max (MW): 4.5
RegUp Offer Cost ($/MW): 6
Gen 2
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 10
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 3
RegUp Cap. Max (MW): 4.5
RegUp Offer Cost (MW): 4
Let’s determine:
Each Market Participant awards (Energy, RegUp, Spin) and LMP,
Each Market Participant production cost,
The Reserve Zone RegUp and Spin MCPs,
SPP total production cost.
Reserve Zone
Spin Requirement (MW): 20
Reg Up Requirement (MW): 8
Consolidated Balancing Authority
|Example 16|
Understanding Scarcity Pricing: no Operating Reserve shortage
Load 1
Energy Forecast (MW): 100
End User Rate ($/MW) 40
Load 2
Energy Forecast (MW): 100
End User Rate ($/MW) 45
SPP.org 95
MP2
Gen 1
Energy Award (MW): 107
RegUp Award (MW): 3.5
Spin Award (MW): 9.5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 93
RegUp Award (MW): 4.5
Spin Award (MW): 10.5
Load 2
Energy Forecast (MW): 100
LMP = 10 $/MWH LMP = 10 $/MWH
7 MW >>
RegUp Market Clearing Price = 8 $/MW
Spin Market Clearing Price = 4 $/MW
Reserve Zone
Spin Requirement (MW): 20
RegUp Requirement (MW): 8
MP1
MP1 Gen. Schedule
(MW)
Operational
Cost ($)
Energy 107 856
RegUp 3.5 21
Spin 9.5 19
Total - 896
MP2 Gen. Schedule
(MW)
Operational
Cost ($)
Energy 93 930
RegUp 4.5 18
Spin 10.5 31.5
Total - 979.5
|Example 16|
Understanding Scarcity Pricing: no Operating Reserve shortage
Total System Operational Cost = $ 1,875.5
SPP.org 96
MP2
Gen 1
Energy Award (MW): 107
RegUp Award (MW): 3.5
Spin Award (MW): 9.5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 93
RegUp Award (MW): 4.5
Spin Award (MW): 10.5
Load 2
Energy Forecast (MW): 100
LMP = 10 $/MWH LMP = 10 $/MWH
7 MW >>
RegUp Market Clearing Price = 8 $/MW
Spin Market Clearing Price = 4 $/MW
Reserve Zone
Spin Requirement (MW): 20
RegUp Requirement (MW): 8
MP1
|Example 16|
Understanding Scarcity Pricing: no Operating Reserve shortage
Operating Profit
Revenues ($) Costs ($) Net Profit ($)
Generation MP1: 1,135.98 896.00 239.98
Charges ($) Revenues ($) Net Profit ($)
Demand MP1: 1,072.00 4,000.00 2,928.00
Operating Profit
Revenues ($) Costs ($) Net Profit ($)
Generation MP2: 1,008.00 979.50 28.50
Charges ($) Revenues ($) Net Profit ($)
Demand MP2: 1,072.00 4,500.00 3,428.00
MP1 Profit = $ 3,159.98 MP2 Profit = $ 3,448.50
SPP.org 97
MP1 MP2
Gen 1
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 8
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 2
RegUp Cap. Max (MW): 4.5
RegUp Offer Cost ($/MW): 6
Load 1
Energy Forecast (MW): 100
Gen 2
Econ. Oper. Cap. Min (MW): 50
Econ. Oper. Cap. Max (MW): 120
Energy Offer Cost ($/MWH): 10
Spin Cap. Max (MW): 15
Spin Offer Cost ($/MW): 3
RegUp Cap. Max (MW): 4.5
RegUp Offer Cost (MW): 4
Load 2
Energy Forecast (MW): 100
Let’s determine:
Each Market Participant awards (Energy, RegUp, Spin) and LMP,
Each Market Participant production cost,
The Reserve Zone RegUp and Spin MCPs,
SPP total production cost.
Reserve Zone
Spin Requirement (MW): 20
Reg Up Requirement (MW): 12
Consolidated Balancing Authority
|Example 17|
Understanding Scarcity Pricing: Operating Reserve shortage
SPP.org 98
MP2
Gen 1
Energy Award (MW): 106
RegUp Award (MW): 4.5
Spin Award (MW): 9.5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 94
RegUp Award (MW): 4.5
Spin Award (MW): 10.5
Load 2
Energy Forecast (MW): 100
LMP = 10 $/MWH LMP = 10 $/MWH
6 MW >>
RegUp Market Clearing Price = 200 $/MW
Spin Market Clearing Price = 4 $/MW
Reserve Zone
Spin Requirement (MW): 20
RegUp Requirement (MW): 12
MP1
MP1 Gen. Schedule
(MW)
Operational
Cost ($)
Energy 106 848
RegUp 4.5 27
Spin 9.5 19
Total - 894
MP2 Gen. Schedule
(MW)
Operational
Cost ($)
Energy 94 940
RegUp 4.5 18
Spin 10.5 31.5
Total - 989.5
|Example 17|
Understanding Scarcity Pricing: Operating Reserve shortage
Total System Operational Cost = $ 1,883.5
RegUp Shortage = 3 MW
SPP.org 99
MP2
Gen 1
Energy Award (MW): 106
RegUp Award (MW): 4.5
Spin Award (MW): 9.5
Load 1
Energy Forecast (MW): 100
Gen 2
Energy Award (MW): 94
RegUp Award (MW): 4.5
Spin Award (MW): 10.5
Load 2
Energy Forecast (MW): 100
LMP = 10 $/MWH LMP = 10 $/MWH
6 MW >>
RegUp Market Clearing Price = 200 $/MW
Spin Market Clearing Price = 4 $/MW
Reserve Zone
Spin Requirement (MW): 20
RegUp Requirement (MW): 12
MP1
|Example 17|
Understanding Scarcity Pricing: Operating Reserve shortage
RegUp Shortage = 3 MW
Operating Profit
Revenues ($) Costs ($) Net Profit ($)
Generation MP1: 1,998.00 894.00 1,104.00
Charges ($) Revenues ($) Net Profit ($)
Demand MP1: 2,240.00 4,000.00 1,760.00
Operating Profit
Revenues ($) Costs ($) Net Profit ($)
Generation MP2: 1,882.00 989.50 892.50
Charges ($) Revenues ($) Net Profit ($)
Demand MP2: 2,240.00 4,500.00 2,260.00
MP1 Profit = $ 2,864.00 MP2 Profit = $ 3,152.50
SPP.org 100
Understanding Scarcity Pricing: Conclusion
Operating Reserve Shortage will have an impact on
Operating Reserve clearing prices
Even in case of Operating Reserve shortage, co-
optimization based SCED provides the most economical
system total operational cost
SPP.org 101
Objectives
Describe high level overview of the relationships between the DA
Market, RUC, and RTBM.
Define Demand Bids and Resource Offers in the Day-Ahead Market
Provide examples for Demand Bids and Resource Offers cleared in
the DA Market.
Define virtual transactions and financial schedules
Explain examples for virtuals transactions and financial schedules.
Define co-optimization of Energy and Operating Reserve
Understand example of a co-optimized, lease-cost solution.
Define scarcity pricing of Operating Reserve
Identify examples of scarcity pricing in the Future Market design
SPP.org
Debbie James
Manager, Market Design
Carrie Simpson
Senior Market Analyst, Market Design