MOPC Workshop Series on Future Markets: Session I
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MOPC Workshop Series on Future Markets: Session I August 24, 2010. 1. Agenda. Introduction The Day Ahead Market Reliability Unit Commitment (RUC) The Real-Time Balancing Market Financial Schedules Virtual Transactions Co-optimization Scarcity Pricing. Objectives.

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Mopc workshop series on future markets session i august 24 2010

MOPC Workshop Series on Future Markets: Session I

August 24, 2010

1


Agenda

Agenda

  • Introduction

  • The Day Ahead Market

  • Reliability Unit Commitment (RUC)

  • The Real-Time Balancing Market

  • Financial Schedules

  • Virtual Transactions

  • Co-optimization

  • Scarcity Pricing


Objectives

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


Introduction

INTRODUCTION


Future markets motivation

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)


Future market products

Future Market Products

  • Energy

  • Operating Reserve

    • Regulation

      • Regulation Up

      • Regulation Down

    • Spinning

    • Supplemental


Spp regulation reserve definition

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 spinning reserve definition

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 supplemental reserve definition

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


Future energy and operating reserve market functions

DA Market Offers (Energy

DA Market Offers (Energy

RTBM Offers, Load

RTBM Offers, Load

RTBM Offers, Load

RTBM Offers, Load

and Operating Reserve),

and Operating

Forecast, Operating

Forecast, Operating

Forecast, Operating

Forecast, Operating

Bids, Operating Reserve

Bids, Operating Reserve

Reserve Requirements

Reserve Requirements

Reserve Requirements

Reserve Requirements

Requirements

Requirements

Real

Real

-

-

Time

Time

Dispatch

Dispatch

Day

Day

-

-

Ahead

Ahead

Reliability Unit

Reliability Unit

Instruction, cleared

Instruction, cleared

Balancing

Balancing

Market

Market

Commitment

Commitment

DA Market

r

RUC

RUC

O

Operating Reserve

perating Reserve

Market

Market

Commitm

Commitment

Commitment

Commitment

(DA Market)

(DA Market)

(RUC)

(RUC)

(MW)

(MW)

(RTBM)

(RTBM)

(5 minute)

(5 minute)

DA Market

DA Market

Dispatch

Dispatch

Commitment, Cleared

Commitment, Cleared

Instruction, clea

red

Energy and Operating

Energy and Operating

Operating Reserve

Operating R

Reserve (MW and

Reserve (MW and

(MW and Price)

(MW and Price)

DA Market &

DA Market &

Price) (hourly)

Price) (hourly)

(5 minute)

(5 minute)

Net RTBM

Net RTBM

EMS

EMS

Settlements

Settlements

Resource

Resource

TCR Markets

TCR Markets

and Load

and Load

Meter Data

Meter Data

Future Energy and Operating Reserve Market Functions


Example conventions

Example Conventions

  • To stay consistent with SPP Settlements, all the examples throughout the presentation that involve settlement calculations follow the convention below:


The day ahead market da market

THE DAY-AHEAD MARKET(DA Market)


Understanding the day ahead market

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


Understanding the day ahead market1

Understanding The Day Ahead Market

Bid in Load and Operating Reserves cleared in DA 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.

Generation cleared in DA Market

Megawatts

Self Committed Resources

(Day Ahead Input)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

Hour


Highlights

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


Highlights1

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


Mopc workshop series on future markets session i august 24 2010

Cleared Energy & OR Offers

DA Market Resource Offers: Energy and OR

RTBM Resource Offers

RTBM Resource Offers

RTBM Resource Offers

DA

Market

DA Confirmed Import, Export & Interchange Transactions

DA Market Demand Bids

Cleared Energy Bids: Virtuals &

Demand

DA Resource Commit Schedules

DA Resource Commit Schedules

DA Resource Commit Schedules

DA Market Import, Export & Interchange Transactions

Resource Outage Notifications

Resource Outage Notifications

Cleared Import,

Export &

Interchange Transactions

SPP Operating Reserve Requirements

SPP Operating Reserve Requirements

SPP Operating Reserve Requirements

SPP Operating Reserve Requirements

[SCUC]

SPP Forecasts (Load & Wind)

Virtual Energy Offers and Bids


Da market timeline

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

1100

1600

1700

1900

2000

Day Prior to Operating Day


What data will market participants need to submit to spp for resources

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)


What data will market participants need to submit to spp for resources1

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


Energy 3 part offer

IMPACTS

Energy 3-Part Offer

The cost that a Market Participant incurs in starting up a generating unit

Drive commitMENT decisions in SCUC

The cost for operating a synchronized Resource at zero (0) MW output.

Energy Offer

Start-Up Offer

No-Load Offer

A set of price/quantity pairs that represents the offer to provide Energy from a Resource

Drive DISPATCH decisions IN SCED


Energy 3 part offer example

Energy 3-Part Offer Example

Consider the following Market Participant Resource:

Assuming the Market Participant decides to offer this Resource at cost, formulate its 3-part offer


Energy 3 part offer example1

Energy 3-Part Offer Example

Consider the following Market Participant Resource:

Startup Offer ($)

No Load Offer ($/h)

Incremental Offer


Operating reserve offers

Operating Reserve Offers

  • An Operating Reserve Offer is an offer to supply Reserve Product capacity

  • Impact:

    • Financial

      • Market Participants receive payment for cleared Offers

    • Reliability

      • Additional capacity offered into the DA Market allows SPP to cover all of its Operating Reserve Requirements


What data will market participants need to submit to spp for loads

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.


Example 1 day ahead market incremental energy offer

|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

MP1

Load1

Gen1

Gen1 DA Energy Offer Curve

DA Energy Award = 65 MWh

DA Energy Credit/Charge = - DA Award * DA LMP = -65 x 40 = -$2600 (credit)


Example 2 day ahead market price sensitive demand bid

|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

MP1

Load1

Gen1

Load1 DA Energy Bid Curve

DA Energy Award = 65 MWh

DA Energy Credit/Charge = DA Award * DA LMP = 65 x 40 = $2,600 (charge)


Example 3 day ahead market operating reserve offer

|Example 3|Day Ahead Market: Operating Reserve Offer

  • 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

MP1

Load1

Gen1

DA Spin Award = Min [15, 120 – 65] = 15 MW

DA Spin Credit/Charge = - DA Award * DA MCP = - 15 x 12 = -$110 (credit)

Gen1 DA Spin Offer


Understanding make whole payments

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

OR Reserve Offer

Make-Whole Payment

Energy Offer

No-Load Offer

Market Revenues

Startup Offer


Example 4 day ahead market understanding make whole payments

|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:

  • DA Revenues

  • DA Costs

  • DA Make-whole Payment

MP1

Load1

Gen1

Gen1 DA Energy Offer Curve


Example 4 day ahead market understanding make whole payments1

|Example 4|Day Ahead Market: Understanding Make-Whole Payments

  • 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

Load1

Gen1

Gen1 DA Energy Offer Curve


Example 5 day ahead market understanding make whole payments

|Example 5|Day Ahead Market: Understanding Make-Whole Payments

  • 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:

  • DA Revenues

  • DA Costs

  • DA Make-Whole Payment

MP1

Load1

Gen1

Gen1 DA Energy Offer Curve


Example 5 day ahead market understanding make whole payments1

|Example 5|Day Ahead Market: Understanding Make-Whole Payments

  • 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

Load1

Gen1

Gen1 DA Energy Offer Curve


Reliability unit commitment ruc

RELIABILITY UNIT COMMITMENT (RUC)


Understanding ruc

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


Understanding ruc1

Understanding RUC

Bid in Load and Operating Reserve cleared in DA Market

Generation committed in RUC

Generation cleared in DA Market

SPP Load Forecast and Operating Reserve Requirements (RUC Input)

Megawatts

Generation de-committed in RUC

Self Committed Resources

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

Hour


Highlights2

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


Highlights3

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)


Mopc workshop series on future markets session i august 24 2010

Resource Commit / De-commit Schedules

RTBM Resource Offers

RTBM Resource Offers

RTBM Resource Offers

RTBM Resource Offers

R

U

C

Process

DA Confirmed Import, Export & Interchange Transactions

DA Confirmed Import, Export & Interchange Transactions

Resource Dispatch and AGC

Notifications

DA Resource Commit Schedules

DA Resource Commit Schedules

DA Resource Commit Schedules

DA Resource Commit Schedules

Resource Outage Notifications

Resource Outage Notifications

Fixed Interchange Transaction Curtailment Notification

SPP Operating Reserve Requirements

SPP Operating Reserve Requirements

SPP Operating Reserve Requirements

SPP Operating Reserve Requirements

[SCUC]

SPP Forecasts (Load & Wind)

SPP Forecasts (Load & Wind)


Day ahead ruc vs intra day ruc

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


Day ahead ruc timeline

Day-Ahead RUC Timeline

  • 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

1700

1900

2000

Day Prior to Operating Day


Intra day ruc timeline

Intra-Day RUC Timeline

=

  • Submit revised offers and/or self schedules for units that were not selected in previous DA, DA RUC, Intra-Day RUC

  • SPP runs SCUC in RUC mode

  • SPP reports RUC results to affected Market Participants

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

1600

2400

0800

1200

2000

0000

0400

Operating Day


The real time balancing market rtbm

THE REAL-TIME BALANCING MARKET(RTBM)


Understanding the real time balancing market

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


Highlights4

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.


Highlights5

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


Example 6 real time balancing market energy offer curve

|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?

MP1

Load1

Gen1

Gen1 RT Energy Offer Curve

RT Energy Actual= 60MWh

RT Energy Settlement = (RT Actual -DA Award) x RT LMP = (-60 + 65) x 40 = $200.00 (charge)


Example 7 real time balancing market incremental energy offer

|Example 7|Real Time Balancing Market Incremental Energy Offer

  • 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

MP1

Load1

Gen1

Gen1 RT Energy Offer Curve

RT Energy Award = 70MWh

RT Energy Settlement = (RT Actual -DA Award) x RT LMP = (-70+65) x 40 = -$200 (credit)


Financial schedules

FINANCIAL SCHEDULES


Understanding financial schedules

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


Understanding financial schedules1

Understanding Financial Schedules

  • Energy Financial Schedules

    • Must specify

      • Settlement Location

      • MW amount

      • Buyer

      • Seller

      • Pricing (Day-Ahead or Real-Time Balancing Market)

      • Seller and Buyer confirmation of the transaction


Understanding financial schedules2

Understanding Financial Schedules

  • Operating Reserve Financial Schedules

    • Must specify

      • Reserve Zone

      • Operating Reserve Product

      • MW amount

      • Buyer

      • Seller

      • Pricing

      • Seller and Buyer confirmation of the transaction


Example 8 understanding financial schedules energy bilateral

|Example 8|Understanding Financial Schedules: Energy Bilateral

MP1

MP2

Gen1

Load2

  • 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:

    • One of the Market Participants fails to confirm the above financial schedule with SPP

    • Both Market Participants confirm the financial schedule with SPP


Example 8 understanding financial schedules energy bilateral1

|Example 8|Understanding Financial Schedules: Energy Bilateral

a) Financial Schedule not confirmed by Market Participants with SPP

MP1

MP2

Gen1

Load2

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


Example 8 understanding financial schedules energy bilateral2

|Example 8|Understanding Financial Schedules: Energy Bilateral

a) Financial Schedule not confirmed by Market Participants with SPP

MP1

MP2

Gen1

Load2

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


Example 8 understanding financial schedules energy bilateral3

|Example 8|Understanding Financial Schedules: Energy Bilateral

b) Financial Schedule confirmed by Market Participants to SPP

MP1

MP2

Gen1

Load2

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


Example 8 understanding financial schedules energy bilateral4

|Example 8|Understanding Financial Schedules: Energy Bilateral

b) Financial Schedule confirmed by Market Participants to SPP

MP1

MP2

Gen1

Load2

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


Example 9 understanding financial schedules energy bilateral

|Example 9|Understanding Financial Schedules: Energy Bilateral

MP1

MP2

Gen1

Load2

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


Example 9 understanding financial schedules energy bilateral1

|Example 9|Understanding Financial Schedules: Energy Bilateral

b) Financial Schedule confirmed by Market Participants to SPP

MP1

MP2

Gen1

Load2

  • 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


Example 9 understanding financial schedules energy bilateral2

|Example 9|Understanding Financial Schedules: Energy Bilateral

b) Financial Schedule confirmed by Market Participants to SPP

MP1

MP2

Gen1

Load2

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


Virtual transactions

VIRTUAL TRANSACTIONS


Understanding virtual transactions

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.

      • 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.


Understanding virtual transactions settlement

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


Example 10 understanding virtual transactions virtual offer

|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

MP1

Load1

Gen1

MP1 DA Virtual Offer Curve

DA Energy Award = 12.5 MWh

Net Energy Settlement = - DA Award x (DA LMP – RT LMP) = -12.5 x (40-35) = - $62.5 (credit)


Example 11 understanding virtual transactions virtual offer

|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

MP1

Load1

Gen1

MP1 DA Virtual Offer Curve

DA Energy Award = 12.5 MWh

Net Energy Settlement = - DA Award x (DA LMP – RT LMP) = -12.5 x (40-45) = $62.5 (charge)


Example 12 understanding virtual transactions virtual bid

|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

MP1

Load1

Gen1

MP1 DA Virtual Bid Curve

DA Energy Award = 6 MWh

Net Energy Settlement = DA Award x (DA LMP – RT LMP) = 6 x (40-35) = $30 (charge)


Example 13 understanding virtual transactions virtual bid

|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

MP1

Load1

Gen1

MP1 DA Virtual Bid Curve

DA Energy Award = 6 MWh

Net Energy Settlement = DA Award x (DA LMP – RT LMP) = 6 x (40-45) = - $30 (credit)


Co optimization

CO-OPTIMIZATION


Understanding co optimization

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)


Understanding co optimization1

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.


Understanding co optimization2

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?


Understanding co optimization examples

Understanding Co-optimization: Examples

MP1

MP2

Balancing Authority 1

Balancing Authority 2

  • 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?


Understanding co optimization examples1

Understanding Co-optimization: Examples

MP1

MP2

Consolidated Balancing Authority

  • 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.


Example 14 understanding co optimization non co optimized case

|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)

MP1

MP2

  • 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.


Example 14 understanding co optimization non co optimized case1

|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)

MP1

MP2

  • 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.


Example 14 understanding co optimization non co optimized case2

|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)

0 MW >>

MP1

MP2

LMP = 8 $/MWH

LMP = 8 $/MWH

Spin Market Clearing Price = 2 $/MW

Total System Operational Cost = $ 1,850


Mopc workshop series on future markets session i august 24 2010

|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)

0 MW >>

MP1

MP2

LMP = 8 $/MWH

LMP = 8 $/MWH

Spin Market Clearing Price = 2 $/MW

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


Mopc workshop series on future markets session i august 24 2010

|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)

0 MW >>

MP1

MP2

LMP = 8 $/MWH

LMP = 8 $/MWH

Spin Market Clearing Price = 2 $/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


Example 14 understanding co optimization non co optimized case3

|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)

0 MW >>

MP1

MP2

LMP = 8 $/MWH

LMP = 8 $/MWH

Spin Market Clearing Price = 2 $/MW

MP1 Profit = $ 3,180

MP2 Profit = $ 3,470


Example 15 understanding co optimization co optimized case

|Example 15|Understanding Co-optimization: Co-optimized case

Market Participants offer their true economic limits and let SPP co-optimize the market

MP1

MP2

Consolidated Balancing Authority

  • 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.


Example 15 understanding co optimization co optimized case1

|Example 15|Understanding Co-optimization: Co-optimized case

Market Participants offer their true economic limits and let SPP co-optimize the market

15 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

Spin Market Clearing Price = 4 $/MW

Total System Operational Cost = $ 1,825

(vs. $ 1,850 in Example 14)


Example 15 understanding co optimization co optimized case2

|Example 15|Understanding Co-optimization: Co-optimized case

Market Participants offer their true economic limits and let SPP co-optimize the market

15 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

Spin Market Clearing Price = 4 $/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


Example 15 understanding co optimization co optimized case3

|Example 15|Understanding Co-optimization: Co-optimized case

Market Participants offer their true economic limits and let SPP co-optimize the market

15 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

Spin Market Clearing Price = 4 $/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


Example 15 understanding co optimization co optimized case4

|Example 15|Understanding Co-optimization: Co-optimized case

Market Participants offer their true economic limits and let SPP co-optimize the market

15 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

Spin Market Clearing Price = 4 $/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


Mopc workshop series on future markets session i august 24 2010

|Example 15|Understanding Co-optimization: Co-optimized case

Market Participants offer their true economic limits and let SPP co-optimize the market

15 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

Spin Market Clearing Price = 4 $/MW

MP1 Profit = $ 3,200

(vs. $ 3,180 in Example 14)

MP2 Profit = $ 3,475

(vs. $ 3,470 in Example 14)


Example 15 understanding co optimization co optimized case5

|Example 15|Understanding Co-optimization: Co-optimized case

Market Participants offer their true economic limits and let SPP co-optimize the market

15 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

Spin Market Clearing Price = 4 $/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).


Example 15 understanding co optimization co optimized case6

|Example 15|Understanding Co-optimization: Co-optimized case

Market Participants offer their true economic limits and let SPP co-optimize the market

15 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

Spin Market Clearing Price = 4 $/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.


Understanding co optimization conclusion

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


Mopc workshop series on future markets session i august 24 2010

Understanding Co-optimization: Conclusion

  • 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)

Co-optimized Scenario (Example 9): MCP for Spinning Reserve

Decreasing Gen 1’s energy schedule by 1 MW:

production cost impact = (114 – 115) x 8 = - $ 8

Lost Opportunity Cost = 2 $

Increasing Gen 2’s energy schedule by 1 MW:

production cost impact = (86 – 85) x 10 = $ 10

+

Increasing Gen1’s Spinning Reserve schedule by 1 MW: production cost impact = (6-5) x 2 = $ 2

MarginalUnit Offer Price = 2 $


Scarcity pricing

SCARCITY PRICING


Understanding scarcity pricing

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

      • May stimulate demand response

      • Draw supply from outside the SPP Balancing Authority

      • Incentivizes generation availability during peak loads

      • Promotes long-term contracting


Understanding scarcity pricing1

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:

    • Operating Reserve

    • Regulation – Up

    • Regulation - Down

Demand Curves are applied on a system-wide and reserve zone wide basis


Understanding scarcity pricing examples

Understanding Scarcity Pricing: Examples

MP1

MP2

Consolidated Balancing Authority

  • 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.


Example 16 understanding scarcity pricing no operating reserve shortage

|Example 16|Understanding Scarcity Pricing: no Operating Reserve shortage

MP1

MP2

Consolidated Balancing Authority

  • 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.


Example 16 understanding scarcity pricing no operating reserve shortage1

|Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage

7 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

RegUpMarket Clearing Price = 8 $/MW

Spin Market Clearing Price = 4 $/MW

Total System Operational Cost = $ 1,875.5


Example 16 understanding scarcity pricing no operating reserve shortage2

|Example 16| Understanding Scarcity Pricing: no Operating Reserve shortage

7 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

RegUpMarket Clearing Price = 8 $/MW

Spin Market Clearing Price = 4 $/MW

MP2 Profit = $ 3,448.50

MP1 Profit = $ 3,159.98


Example 17 understanding scarcity pricing operating reserve shortage

|Example 17| Understanding Scarcity Pricing: Operating Reserve shortage

MP1

MP2

Consolidated Balancing Authority

  • 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.


Example 17 understanding scarcity pricing operating reserve shortage1

|Example 17|Understanding Scarcity Pricing: Operating Reserve shortage

6 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

RegUpMarket Clearing Price = 200 $/MW

Spin Market Clearing Price = 4 $/MW

RegUpShortage = 3 MW

Total System Operational Cost = $ 1,883.5


Example 17 understanding scarcity pricing operating reserve shortage2

|Example 17|Understanding Scarcity Pricing: Operating Reserve shortage

6 MW >>

MP1

MP2

LMP = 10 $/MWH

LMP = 10 $/MWH

RegUpMarket Clearing Price = 200 $/MW

Spin Market Clearing Price = 4 $/MW

RegUpShortage = 3 MW

MP1 Profit = $ 2,864.00

MP2 Profit = $ 3,152.50


Understanding scarcity pricing conclusion

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


Objectives1

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


Mopc workshop series on future markets session i august 24 2010

Debbie JamesManager, Market [email protected] SimpsonSenior Market Analyst, Market Design [email protected]


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