module 6: real-time operations · module objectives: real-time operations upon completion of this...

Module 6: Real-Time Operations

Module Objectives: Real-Time Operations

Upon completion of this module,

learners will be able to:

• Describe the Settlement impacts of Real-Time Operations

• Demonstrate how Energy is Settled after Real-Time Operations

• Explain the Settlement impacts of Base Point Deviation.

• Calculate the impacts of Emergency Operations.

• Recognize the Real-Time Settlements associated with Ancillary Services.

• Explain the impacts of the CRR Auction, Trades and Day-Ahead Market on Real-Time Settlements.

Day 3

Real-Time

Statements &

8:30 A

1:00 P

Invoicing

RUC

Commitment

• Make-Whole

• Clawback

Decommitment

DAM Commitment

• Make-Whole

DAM

Participation in DAM

• Energy

• AS

• PTP Obligations

Settlement of CRRs

purchased in the

Auction

Course Topics

• Charges and Payments for CRRs

CRR Auction

• Revenue

Distribution

Real-Time Real-Time Activities

• Imbalances

• Base Point Deviations

• Other odds & ends

Settlement of PTP

Obligations purchased in

the DAM

Revenue Neutrality

Supplemental Ancillary

Services Market (SASM)

Reconcile CRR

Short payments

CRR Balancing

Account

Real-Time Operations

Purpose of Real-Time Operations

• Manage reliability

– Match generation with demand

– Operate transmission system

within established limits

• Operate the system at least cost


• Network Security Analysis

identifies transmission

constraints

• Security Constrained

Economic Dispatch (SCED)

determines least-cost

solution

Network Security Analysis

Security Constrained

Economic Dispatch

Network Security Analysis and SCED


Network Security Analysis and SCED


Provide Real-Time system data


Identify Constraints, both Transmission & Resource

Transmission Constraints & Resource Dispatch Limits


SCED evaluates Offers to determine least-cost solution

Transmission Constraints & Resource Dispatch Limits

SCED uses Energy Offer Curves:

Energy Offer Curve

Part of Three-Part Supply Offer

• Committed by DAM

• Committed by RUC

Stand Alone Energy Offer Curve

• Committed by DAM

• Submitted during Adjustment

Period



SCED produces Prices and Dispatch Instructions


How often does all this happen?

At least

every 5

minutes

Real – Time Settlements


• Imbalances



Settlement of PTP

Obligations purchased in

the DAM

Revenue Neutrality

Supplemental Ancillary

Services Market (SASM)

Real –Time Energy Imbalance

Who: All QSEs that have Generation, Load, Trades, DAM purchases

or sales, and Self-Schedules at any Settlement Point

What: A charge or payment for the imbalance of Energy at a

Settlement Point

Why: To pay or charge a QSE for their injection or withdrawal at a

Settlement Point

Fundamentals of Real–Time

Energy Imbalances


• Imbalances



Real-Time Energy Imbalance

The basic form of the Real-Time Energy Imbalance calculation at any Settlement Point looks like this:

MINUS RTSPP ($/MWh) Real-Time Settlement Point Price

MULTIPLIED

BY

INJECTIONS ( ) WITHDRAWALS ( ) Now, we simply fill in the

appropriate elements for each

Settlement Point

Real-Time Energy Imbalance Sales / Purchases

RTSPP ($/MWh) Real-Time Settlement Point Price X (-1)

AT A LOAD ZONE


( )

( ) Self Schedule at Source

+ Energy Offers cleared in the DAM

+ Energy Trades where QSE is the seller

+ Adjusted Metered Load

Non-Modeled Metered Generation

+ Self Schedule at Sink

+ Energy Bids cleared in the DAM

+ Energy Trades where QSE is the buyer


Metered Generation

+ Self Schedule at Sink




AT A RESOURCE NODE

( )


( ) Self Schedule at Source

+

Energy Offers cleared in the DAM +

Energy Trades where QSE is the seller



AT A HUB


Self Schedule at Sink



Self Schedule at Source

+

Energy Offers cleared in the DAM +

Energy Trades where QSE is the seller ( )

( )

Real-Time Energy Imbalance and Self-Schedules

Self-Schedule

Specifies the amount of energy supply at one

Settlement Point used to meet the QSE’s energy

obligation at another Settlement Point

Source

Sink

Settlement Impact Without Self-Schedule

Sink


Resource

Node

Load

Zone

Payment for

injected energy

Source

Charge for withdrawn

energy


Payment or Charge

for net energy

Settlement Impact With Self-Schedule

Any congestion impact will be collected (or paid) through a separate charge.

Sink

Resource

Node

Load

Zone

Source

Real – Time Energy: Triggers

Trigger

#3

A QSE has

Generation, Load,

Trades, DAM bids,

DAM offers, or

Self-Schedules at

a Resource Node

Trigger

#2

A QSE has

Generation, Load,

Trades, DAM bids,

DAM offers, or

Self-Schedules at

a Load Zone

A QSE has

Generation, Load,

Trades, DAM bids,

DAM offers, or

Self-Schedules at

a Hub

Trigger

#1

Real-Time Energy Imbalance at a Hub

At a Hub a QSE may have:

• Trades

• Self-Schedules

• DAM Bids & DAM Offers

If a QSE has… The QSE will receive…

Net Injection Payment

Net withdrawal Charge

Trigger

#2

Outcome

Outcome

#2


Injections Withdrawals

SSSK Self-Schedule at Sink SSSR Self-Schedule at

Source

DAEP DAM Energy Purchase DAES DAM Energy Sale

RTQQEP Real-Time QSE to QSE

Energy Purchase (Trade)

RTQQES Real-Time QSE to QSE

Energy Sale (Trade)

QSE3

• 8MW DAM Energy Sale (2MWh)

• Self-Schedule at Sink of 12MW (3MWh)

• Settlement Point Price is $40/MWh at H1

(-1) * Price * (Injections – Withdrawals)

(-1) * $40/MWh * (3MWh – 2MWh) = -$40

Outcome

Outcome

#2


RTEIAMT q, p = (-1) * RTSPP p * {(SSSK q, p *¼) + (DAEP q, p* ¼)) +

(RTQQEP q, p* ¼) - (SSSR q, p* ¼) – (DAES q, p* ¼) –

(RTQQES q, p* ¼)}

-$40 q, p = (-1) * $40/MWh p * {(12MW q, p *¼) + (0MW q, p*¼) ) +

(0MW q, p* ¼) - (0MW q, p* ¼) – (8MW q, p* ¼) –

(0MW q, p* ¼)}

QSE3

• 8MW DAM Energy Sale (2MWh)

• Self-Schedule at Sink of 12MW (3MWh)

• Settlement Point Price is $40/MWh at H1

Outcome

Outcome

#2

Activity: Now it’s your turn!

Refer to your Settlements Workbook

In a small group, respond to the questions that

relate to Scenario #RT1.

You have 10 minutes to complete your questions.

If you can not complete all questions, don’t worry

– all questions will be reviewed as a class.


Trigger

#3

A QSE has

Generation, Load,

Trades, DAM bids,

DAM offers, or

Self-Schedules at

a Resource Node

Trigger

#2

A QSE has

Generation, Load,

Trades, DAM bids,

DAM offers, or

Self-Schedules at

a Load Zone

A QSE has

Generation, Load,

Trades, DAM bids,

DAM offers, or

Self-Schedules at

a Hub

Trigger

#1

Real-Time Energy Imbalance at a Load Zone




At a Load Zone a QSE may have:

• Metered Load

• Non-Modeled Generation

• Trades

• Self-Schedules


Trigger

#1

Outcome

Outcome

#1

Real –Time Energy Imbalance at a Load Zone

+ ( ) Non-Modeled

Generation

( ) ( ) - DAM Energy Purchases

Trade Purchases

Self - Schedules

DAM Energy Sales

Trade Sales

Self - Schedules

RTSPP

Adjusted

Metered Load

*

Subtle Pricing Difference . . .

Real-Time Energy Imbalance at a Load Zone =

- RTSPPEW *


Real-Time SPP Energy-Weighted (RTSPPEW)

• RTSPP is

• MW-weighted by SCED Interval

• Time-weighted by Settlement Interval

• RTSPPEW is

• Weighted by (MW * Time) during SCED Interval

• Summed over Settlement Interval

There are similar pricing

mechanisms at Resource Nodes.


Injections Withdrawals

SSSK Self-Schedule at Sink SSSR Self-Schedule at Source

DAEP DAM Energy Purchase DAES DAM Energy Sale

RTQQEP Real-Time QSE to QSE

Energy Purchase (Trade)

RTQQES Real-Time QSE to QSE

Energy Sale (Trade)

RTMGNM Real-Time Metered

Generation Non-Modeled

RTAML Real-Time Adjusted

Metered Load

RTEIAMT q, p =

(-1) * {[RTSPP p * [(SSSK q, p *¼) + (DAEP q, p*¼) + (RTQQEP q, p* ¼)

– (SSSR q, p* ¼) – (DAES q, p* ¼) – (RTQQES q, p* ¼)]]

+ [RTSPPEW p * (RTMGNM q, p – RTAML q, p)]}

Translated into a Settlement Equation,


QSE4

• Has a 12MW DAM Energy Purchase (3MWh)

• Purchased 20MW through a Trade (5MWh)

• Has Load at LZ3 of 10MWh

• The RTSPP is $100/MWh at LZ3

• The RTSPPEW is $101/MWh at LZ3

Outcome

Outcome

#1

RTEIAMT q, p =

(-1) * {[RTSPP p * [(SSSK q, p *¼) + (DAEP q, p*¼) + (RTQQEP q, p* ¼)

– (SSSR q, p* ¼) – (DAES q, p* ¼) – (RTQQES q, p* ¼)]]

+ [RTSPPEW p * (RTMGNM q, p – RTAML q, p)]}

RTEIAMT q, p =

(-1) * {[$100/MWh p * [(0MW q, p *¼) + (12MW q, p*¼) + (20MW q, p* ¼)

– (0MW q, p* ¼) – (0MW q, p* ¼) – (0MW q, p* ¼)]]

+ [$101/MWhp * (0MWh q, p – 10MWh q, p)]} = $201


Trigger

#3

A QSE has

Generation, Load,

Trades, DAM bids,

DAM offers, or

Self-Schedules at

a Resource Node

Trigger

#2

A QSE has

Generation, Load,

Trades, DAM bids,

DAM offers, or

Self-Schedules at

a Load Zone

A QSE has

Generation, Load,

Trades, DAM bids,

DAM offers, or

Self-Schedules at

a Hub

Trigger

#1

Real-Time Energy Imbalance at a Resource Node

At a Resource Node A QSE may have:

• Metered Generation

• Trades

• Self-Schedules





Trigger

#3

Outcome

Outcome

#3


If all Generation Sites were simple . . .

Real-Time Energy Imbalance at a Resource Node =

( ) ( ) - Generation

DAM Energy Purchases

RT QSE to QSE Purchases

Self - Schedules

DAM Energy Sales

RT QSE to QSE Sales

Self - Schedules

Price *


But in reality . . .

Many Generation Sites are complex

• Multiple generators per meter

• Multiple owners

• Load and generation

• Combined Cycle Resources

ERCOT uses a single

methodology to settle all

Generation Sites.

Real –Time Energy Imbalance at a Resource Node

+ ( ) Splitting Percentage

( ) ( ) - DAM Energy Purchases

RT QSE to QSE Purchases

Self - Schedules

DAM Energy Sales

RT QSE to QSE Sales

Self - Schedules

Price

* Total Site Payment

*

Introducing Net Metering . . .

Real-Time Energy Imbalance at a Resource Node =


Total Site Payment: NMSAMTTOT

• For all Resources at Site

• For all QSEs at Site

Splitting Percentage: GSPLITPER

• QSE’s share of Total Site Payment

• Calculated from SCADA telemetry

Outcome

Outcome

#3 ( ) Splitting Percentage * Total Site Payment


( ) Splitting Percentage * Total Site Payment

Price * Quantity

Outcome

Outcome

#3

Price: RTRMPR

• Average price at meter

• Weighted by (Base-Point * Time) during SCED Interval (RNWF)

Quantity: MEB

• Metered Energy* at bus

*Negative energy is settled at a Load Zone.


Total Site Payment

• Only one generator at site

• Dispatched to 40MW for entire interval

• The Metered Energy at the bus was 10MWh

• The LMP at the bus is $30/MWh through

entire interval

Real-Time Resource Meter Price

RTRMPR = ∑(RNWF b,y

* RTLMP b, y

)

$30/MWh = 3 * ((.33) * $30/MWh)

Total Site Payment

NMSAMTTOTa = ∑ (RTRMPR b

* MEB me

)

$300a = ($30/MWh * 10MWh)

Trigger

#3

Outcome

Outcome

#3


QSE1

• Has 100% of the generation at this bus

• Facility payment was $300

• Has a 40MW DAM energy Sale (10MWh)

• The Settlement Point Price is $30/MWh at RN4

(-1) * [(QSE share of site payment )

+ Price * (Non-Generation Injections – Withdrawals)]

(-1) * [(100% * $300 ) + $30/MWh * (0MW – 10MWh)] = $0

Outcome

Outcome

#3


RTEIAMT q, p = (-1) * { ∑(GSPLITPER r * NMSAMTTOT a ) + RTSPP p *

[(SSSK q, p * ¼ ) + (DAEP q, p* ¼) + (RTQQEP q, p* ¼)–

(SSSR q, p* ¼) – (DAES q, p* ¼)–(RTQQES q, p* ¼)]}

$0 q, p = (-1) * {( 1 r * $300 a ) + 30 p * [(0 q, p * ¼ ) + (0q, p* ¼) + (0 q, p*

¼)–(0 q, p* ¼) – (40 q, p* ¼)–(0 q, p* ¼)]}

QSE1

• Has 100% of the generation at this bus

• Facility payment was $300

• Has a 40MW DAM energy Sale (10MWh)

• The Settlement Point Price is $30/MWh at RN4

Outcome

Outcome

#3

Real-Time Energy Settlements - Combined Cycle Resources

CCGR 1

CCGR 2

Combined Cycle Plant

Train 1 Train 2

ST1 CT1 CT2 CT3 ST2 CT4 CT5 CT6

SCED will dispatch only the

CCGR that is currently online.

Metered generation is settled

at the Logical Resource Node.

Resource Node Resource RTLMP

Bill Determinant Description

Logical

Resource

Node

Physical

Resource

Node CC Train Gen Site

Resource

ID

RTEIAMT Real Time Energy Imbalance Payment X

DAES Day Ahead Energy Sales X (3PO)

GSPLITPER Generation Unit Splitting Percentage X X X

MEBMP Metered Energy Bus (MP) X X

NMRTETOTMP Net Metered Real Time Energy Total (MP) X

NMSAMTTOT Net Metering Settlement Payment X

RTRMPR Real Time Resource Meter Price X X

RTEIAMT Real Time Energy Imbalance Payment X

DAEP Day Ahead Energy Purchase X

DAES Day Ahead Energy Sales X (Energy

only)

RTQQEP Real Time QSE to QSE Purchase X

RTQQES Real Time QSE to QSE Sale X

SSSK Self Schedule at Sink X

SSSR Self Schedule at Source X

Real-Time Energy Settlements - Combined Cycle Resources

Real-Time Energy Payment for DC Tie Import

Who: A QSE that has a DC Tie import

What: A Payment for the Energy that is imported into the ERCOT grid

through a DC Tie

Why: When a QSE brings Power into the ERCOT grid they need to

receive a payment for it

Fundamentals of Payment for DC

Tie Import


• Imbalances



DC Tie Import Payment: Triggers

Trigger

#1

A QSE Schedules

a DC Tie to import

power into ERCOT

area

DC Tie Import Payment

• A QSE Schedules a DC Tie to import energy

into ERCOT area

• The QSE receives a payment for the injection

of energy

Trigger

#1

Outcome

Outcome

#1

DC Tie Import Payment

A QSE1

• Schedules 100 MW import on DC Tie one

• The Settlement Point Price is $50/MWh at

DCTIE1

RTDCIMPAMT q, p = (-1) * RTSPP p * (RTDCIMP q, p * ¼)

$-1250q, p = (-1) * $50 p * (100MW q, p * ¼)

Outcome

Outcome

#1

Generation Resource Base Point Deviation Charge

Who: QSEs that have Resources that do not follow Base Points as

dictated by SCED

What: A charge for over generation or under generation – May not

receive this charge when helping frequency

Why: The Resource did not follow Dispatch Instructions and

Ancillary Services deployments within defined tolerances

Fundamentals of Base Point

Deviation Charge

Real-Time Real-Time Actions

• Imbalances



Base Point Deviation Charge

• Resource did not follow

Dispatch Instructions and

Ancillary Services Deployments

within defined tolerances

• Tolerances

± 5% or ± 5MW, whichever

is greater

+ 10% for Intermittent

Renewable Resources

(when curtailed)


SCED

Base

Point Subject to Base

Point Deviation

Charge.

Subject to Base

Point Deviation

Charge


• Exclusions

– No charge during a

Frequency deviation greater

than 0.05 Hz if the QSEs

deviation helps frequency

– No charge for any intervals

with Responsive Reserve

deployments


SCED

Base


Point Deviation

Charge.

Subject to Base

Point Deviation

Charge


• Exemptions

– RMR Units

– Qualifying Facilities (QFs) that

do not submit Energy Offer

Curves

– Quick Start Generation

Resources (QSGRs) exempt

for the first Settlement Interval

in which they are deployed


SCED

Base


Point Deviation

Charge.

Subject to Base

Point Deviation

Charge

Determining Basepoint Deviation Charges

ERCOT compares Adjusted Aggregated Base Points to the

Time-Weighted Telemetered Generation.

Adjusted Aggregated

Base Point

Time-Weighted

Telemetered Generation



Calculating Adjusted Aggregated Base Point

Average Base

Point

Adjusted Aggregated

Base Point

Average

Regulation = +

Considers

Ramping

15 Minute

Value

Base Point Deviation Charge: Triggers

Trigger

#1

Resource did not

follow Dispatch

Instructions and

OVER Generated

Trigger

#2

Resource did not

follow Dispatch

Instructions and

UNDER Generated

Base Point Deviation Charge – Over Generation

• Resource did not follow Dispatch Instructions

and OVER Generated

• The Over Generation is outside of the 5% or 5

MW tolerance

• The grid frequency is 60.02 Hz

• QSE is charged:

Settlement point Price * the MW above

Tolerance

If grid frequency had been less than

59.95 Hz, then the QSE would not be

charged

Trigger

#1

Outcome

Outcome

#1


QSE1 unit 5

• Adjusted Aggregated Base Point of 40MW

• Time Weighted Telemetered Generation of

12MWh (Operated at 48MW)

• Tolerances are 5% or 5MW

• Settlement Point Price is $20/MWh at RN5


= Price * (Generation – ¼h * Max (AABP + 5% or AABP + 5MW))

= $20/MWh * (12MWh – ¼h * Max (42MW or 45MW))

= $20/MWh * (12MWh – 11.25MWh)

= $15

Outcome

Outcome

#1


BPDAMT = Max (PR1, RTSPP) * OGEN

0, TWTG – ¼ * Max (1 + K1) * AABP, (AABP + Q1)

BPDAMT q, r, p Base Point Deviation Amount

OGEN Over Generation Volume

TWTG q, r, p Time Weighted Telemetered Generation

AABP q, r, p Adjusted Aggregated Base Point

PR1 Minimum price for over-generation, $20.

K1 The percentage tolerance for over-generation, 5%.

Q1 The MW tolerance for over-generation, 5 MW.

Translated into Settlement Equations,

OGEN = Max


Outcome

Outcome

#1

QSE1 unit 5





• Settlement Point Price is $20/MWh at RN5

BPDAMT = Max (PR1, RTSPP) * OGEN

0, TWTG – ¼ * Max (1 + K1) * AABP, (AABP + Q1) OGEN = Max

OGEN = Max (0, (12MWh – ¼h * Max (42 MW, 45MW))) = 0.75 MWh

BPDAMT = Max ($20/MWh, $20/MWh) * OGEN = $15

Key Differences between Intermittent Renewable Resources

(IRRs) & Conventional Resources

IRR must be Curtailed

– Curtailment Flag

IRR must be Over-Generating

– Telemetered generation

– Instructed Base Point

Wider tolerance for deviation from Base Point

Base Point Deviation Charge – IRRs

When are IRRs exposed to deviation charges?

IRR output within

10% acceptable range

IRR output exceeds

10% acceptable range

Curtailment Flag is not set No Charge No Charge

Curtailment Flag is set No Charge Charge



SBPBHDLFLAG SCED Base Point Below HDL FLAG


OGENIRR Over Generation Volume per IRR Generation Resource



PR1 Minimum price for over-generation, $20.

KIRR The percentage tolerance for IRRs, 10%.


If SBPBHDLFLAG = 1, then

BPDAMT = Max (PR1, RTSPP) * OGENIRR

0, TWTG – ¼ * AABP * (1 + KIRR) OGENIRR = Max

Base Point Deviation Charge: Triggers

Trigger

#1

Resource did not

follow Dispatch

Instructions and

OVER Generated

Trigger

#2

Resource did not

follow Dispatch

Instructions and

UNDER Generated

Base Point Deviation Charge – Under Generation

• QSE is charged:

Settlement Point Price * the MW below

Tolerance

• Resource did not follow Dispatch Instructions

and UNDER Generated

• The Under Generation is outside of the 5% or 5

MW tolerance

• The grid frequency is 59.98 Hz

If grid frequency had been greater than

60.05 Hz, then the QSE would not be

charged

Trigger

#2

Outcome

Outcome

#2


QSE4 unit 8





• Settlement Point Price is -$20/MWh at RN8


= (-1) * Price * (¼h * Min (AABP – 5% or AABP – 5MW) – Generation)

= (-1) * -$20/MWh * (¼h * Min (38MW or 35MW) – 8MWh)

= (-1) * -$20/MWh * (8.75MWh – 8MWh)

= $15

Outcome

Outcome

#1



UGEN Under Generation Volume



PR2 Minimum price for under-generation, -$20.

K2 The percentage tolerance for under-generation, 5%.

Q2 The MW tolerance for under-generation, 5 MW.

KP Settlement Point Price coefficient, (1.0, for now)


BPDAMT = (-1) * Min (PR2, RTSPP) * Min(1, KP) * UGEN

UGEN = Max 0, Min (1 – K2) * ¼ AABP, ¼ ( AABP – Q2 ) – TWTG


QSE4 unit 8





• Settlement Point Price is -$20/MWh at RN8

Outcome

Outcome

#1

UGEN = Max (0, Min (9.5MWh, 8.75MWh) – 8MWh)

BPDAMT = (-1) * Min (PR2, RTSPP) * Min(1, KP) * UGEN

UGEN = Max 0, Min (1 – K2) * ¼ AABP, ¼ ( AABP – Q2 ) – TWTG

BPDAMT = Min (-$20/MWh, -$20/MWh) * Min (1, 1) * UGEN = $15

Generation Resource Base Point Deviation Payment

Who: QSEs that have load

What: Distributes the funds collected from Base Point Deviation

Charges.

Why: To keep ERCOT revenue neutral

Fundamentals of Base Point

Deviation Payment


• Imbalances




Trigger

#1

Charges for Base

Point Deviations

are collected


• Resources Over or Under Generated

• ERCOT charges the QSEs representing

the Resources

• ERCOT calculates the QSE’s Load

Ratio Share

• ERCOT sums all charges made for the

interval

• ERCOT pays QSEs for their portion of

the revenue based on their share of the

load

Trigger

#1

Outcome

Outcome

#1



Ratio Share

• ERCOT sums all charges made for the

interval

• ERCOT pays QSEs for their portion of

the revenue based off of their share of

the load

• For interval one ERCOT charged for deviation

– Total Charges $255

• QSE 5 has thirty percent of Load

– QSE 5 is paid for 30 percent of the $255

Outcome

Outcome

#1


For interval one ERCOT charged for deviation

• Total Charges $255

QSE 5 has thirty percent of Load

• QSE 5 is paid for 30 percent of the $255

LABPDAMT q = (-1) * BPDAMTTOT * LRS q

$-76.50 = (-1) * $255 * 0.30

Outcome

Outcome

#1

RMR Service Charge


What: A Charge based off of a QSEs Load Ratio Share to cover the

costs of RMR units

Why: To cover the costs of a service to ensure ERCOT reliability

Fundamentals of RMR Service

Charge


• Imbalances



RMR

RMR UNIT

A Generation Resource operated under

the terms of an Agreement with ERCOT

that would not otherwise be operated

except that it is necessary to provide

voltage support, stability or management

of localized transmission constraints

under first contingency criteria where

market solutions do not exist.

RMR Service Charge

Trigger

#1

ERCOT region has

RMR units

RMR Service Charge

• There are RMR Units in the ERCOT region and Load must pay for the costs associated for them

• ERCOT will Sum all the RMR charges and

payments and the delta will be charged to load

– Standby payment

– RMR energy Payment

– RMR adjustment Charge

– RMR Day-Ahead Energy Sale Real-Time Value

– DAM Energy Revenue

– DAM Make-Whole Revenue

– RMR Non-Performance

Trigger

#1

Outcome

Outcome

#1

RMR Service Charge

QSE5 is Charged its portion of the RMR Service Charge

• RMR stand-by payment RMRSBAMTTOT

• -$1000

• RMR energy payment RMREAMTTOT

• -$5000

• RMR adjustment charge RMRAAMTTOT

• $500

• RMR Day-Ahead Energy Sale Real-Time Value RMRDAESRTVTOT

• $300

• DAM Energy Revenue RMRDAEREVTOT

• -$400

• DAM Make-Whole Revenue RMRDAMWREVTOT

• -$200

• RMR Non-Performance RMRNPAMTTOT

• $0

• QSE5 has 10% if the load HLRS

Outcome

Outcome

#1

RMR Service Charge

RMR charges and Payments

• Standby payment -$1,000

• RMR energy Payment $-5,000

• RMR adjustment Charge $500

• RMR Day-Ahead Energy Sale Real-Time

Value $300

• DAM Energy Revenue $-400

• DAM Make-Whole Revenue $-200

• RMR Non-Performance $0

• QSE5 has 10% of the load

LARMRAMT q = (-1) * (RMRSBAMTTOT + RMREAMTTOT + RMRAAMTTOT

– ∑RMRDAESRTVTOT i – (RMRDAEREVTOT +

RMRDAMWREVTOT) + RMRNPAMTTOT / H) * HLRS q

$520 = (-1) * (-$1,000 + -$5,000 + $500 – $300 – ($-400 + $-200)

+ $0 /Hours in Operating day) * 0.1

Outcome

Outcome

#1

Voltage Support Service

Who: QSEs that have received instructions to provide Reactive

Power from Resources exceeding their URL

What: • Payment for providing VAR exceeding URL

• Payment for reduced MW (If applicable)

Why: For providing a service that will ensure ERCOT reliability

Fundamentals of Voltage Support

Service Payments


• Imbalances



Voltage Support Service

Voltage Support Service (VSS)

• Required to maintain voltages

within acceptable limits

• Required from all On-Line and

available Generators

– No payment for VSS up to Unit

Reactive Limit (URL)

– Payment for VSS above Unit Reactive

Limit

◦ Payment for Mvars provided

◦ Payment for lost opportunity cost

(reduced MW)

Receives

Payment

Receives

Payment

PF=1

URL Lagging

URL Leading

Mvar Output

Mvar Output

Lost

Opportunity

Lost

Opportunity

Voltage Support Service Charge


What: A Charge to cover the costs of VSS service


Fundamentals of Voltage Support

Service Charge


• Imbalances




Trigger

#1

Payments for VSS

are Made


• ERCOT needed VSS

• ERCOT made Payment for providing

VAR exceeding URL and for reduced

MW

• QSE has load in the ERCOT market

• ERCOT calculates the QSEs Load

Ratio Share

• ERCOT Sums all payments made for

interval

• The QSE pays for its portion of the

service based on its share of the load

Trigger

#1

Outcome

Outcome

#1


• ERCOT calculates the QSEs Load Ratio

Share

• ERCOT Sums all payments made for interval

• The QSE pays for its portion of the service

based on its share of the load

• For interval one ERCOT made VSS Payments

– Payment for Vars $45.40

– Payment for Lost Opportunity $2416.67

– Total Payments $2462.07

• QSE 3 has fifty five percent of Load

– QSE 3 pays for 55 percent of the $2462.07

Outcome

Outcome

#1


• For interval one ERCOT made VSS

Payments

– Payment for Vars $45.40

– Payment for Lost Opportunity $2416.67


• QSE 3 has fifty five percent of Load


LAVSSAMT q = (-1) * (VSSVARAMTTOT + VSSEAMTTOT) * LRS q

$1354.13 = (-1) * ($-45.40 + $-2416.67) * .55

Outcome

Outcome

#1

Payment for Emergency Power Increases

Who: QSEs that receive Emergency Base Points

What:

A payment to provide additional compensation for energy

produced in response to Emergency Base Points

Why:

To make up the difference between the Settlement Point Price

and the QSE’s actual cost for operating at the Emergency

Base Point

Fundamentals of Emergency

Power Increases Payment


• Imbalances




Emergency Power Increases

• Can be required when

ERCOT is in an emergency

condition

• There is no market

mechanism to set the price

for the output level

40MW

50MW

Eligible for

Emergency

Energy

Payment

SCED

Base

Point

Emergency

Base Point

Paid RTSPP for all

energy produced



• Quick Start Generation

Resources may also be

eligible

– SCED Base Point below

COP LSL

– QSE requests manual

override of Base Point

15MW

20MW

Eligible for

Emergency

Energy

Payment

SCED

Base

Point

COP LSL

Paid RTSPP for all

energy produced


Trigger

#1

A resource

receives a

Emergency Base

Point


• ERCOT Declares a Emergency Condition

• ERCOT instructs resources to move to an

Emergency Base Point (EBP)

• Resource moves to EBP

• Calculate the emergency energy the Resource

produced

• Calculate the price for emergency energy

• Pay the Resource when emergency price is

higher than RTSPP

• No payment when emergency price is

lower than RTSPP

Trigger

#1

Outcome

Outcome

#1


Determine the Emergency Energy

• Lesser of the EBP or Actual Output minus the

original Base Point (BP)

Determine the Emergency Energy Price

• EBP average weighted price

minus the RTSPP

• EBP average weighted price

– From Resource ‘s offer

curve at EBP

– Time Weighted for the

SCED Interval

– Averaged for all Resources

at that Node

Outcome

Outcome

#1

$/MWh

MW

EBP LSL BP

RTSPP

Emergency Price


QSE4 Unit 9 Receives Emergency Base Point

– BP of 150 MW

– EBP of 200 MW

– RTMG of 50 MWh

Outcome

Outcome

#1

$/MWh

MW

EBP LSL BP

RTSPP

Emergency Price Pricing Information

– RTSPP is $50/MWh

– Unit 9 price at EBP is $55/MWh

– Unit 9 is only Resource at Resource Node


EMRE q, r,p = Max (0, Min (AEBP q,r,p , RTMG q,r,p) – ¼ * BPq r,p)

12.5MWh q, r,p = Max (0, Min (200MW q,r,p * ¼h , 50MWh q,r,p) – ¼ * 150MWq r,p)

Outcome

Outcome

#1

Determine the Emergency Energy

EMRE q, r, p Emergency Energy

AEBP q, r, p Aggregated Emergency Base Point

RTMG q, r, p Real-Time Metered Generation

BPq, r, p Base Point


Outcome

Outcome

#1

Determine the Emergency Energy Price

EMREPR q, r, p Emergency Energy Price

EBPWAPR q, r, p Emergency Base Point Weighted Average Price

RTSPP p Real-Time Settlement Point Price

EMREPR q,r,p = Max(0, EBPWAPR q,r,p – RTSPP p)

$5/MWh q,r,p = Max(0, $55/MWh q,r,p – $50/MWh p)


• Payment when emergency price is

higher than RTSPP

• No payment when the emergency price

is lower than RTSPP


EMREAMT q, r, p = (-1) * EMREPR q, r, p * EMRE q, r, p

$-62.50 q, r, p = (-1) * $5/MWh q, r, p * 12.5MWh q, r, p

Outcome

Outcome

#1

Charge for Emergency Power Increases


What: A Charge to cover the costs of Emergency Power payments


Fundamentals of Charges for



• Imbalances




Trigger

#1

Payments for

Emergency Power

are made


• ERCOT needed Emergency Power

• ERCOT made Payments for resources

that provided Emergency Power

• QSE has load in the ERCOT market


Ratio Share


interval



Trigger

#1

Outcome

Outcome

#1



Ratio Share


interval



• ERCOT made Emergency Energy Payments


• QSE 5 has thirty percent of Load


Outcome

Outcome

#1


For interval one ERCOT made Emergency

Energy Payments

• Total Payments $62.50

QSE 5 has thirty percent of Load

• QSE 5 pays for 30 percent of the $62.50

LAEMREAMT q = (-1) * EMREAMTTOT * LRS q

$18.75 q = (-1) * $-62.50 * .30 q

Outcome

Outcome

#1

Payments and Charges for PTP Obligations Settled in Real-Time

Day-Ahead

Market Real-Time

Settlements

A QSE

Purchases

PTP

Obligation in

Day-Ahead

Market.

PTP

Obligation

settled in the

Real-Time

market

Payments and Charges for PTP Obligations Settled in Real-

Time

Who: QSEs that have purchased PTP obligations is the DAM

What: A Charge or Payment based on Real-Time Congestion

Why: To Hedge the Cost of congestion in Real-Time

Fundamentals of PTP Obligations

Settled in Real-Time

Real-Time Settlement of PTP

Obligations purchased

in DAM


Trigger

#1

A QSE buys a PTP

obligation in the

DAM


• A QSE buys a PTP obligation in the Day-

Ahead Market.

• The Price is the Difference between the

RTSPP of the Source and Sink

• If the Source RTSPP is less than the Sink

RTSPP then the QSE receives a payment

• If the Source RTSPP is greater than the

Sink RTSPP then the QSE receives a

charge

Trigger

#1

Outcome

Outcome

#1


Settlement for DAM PTP Obligations

Real-Time Obligation

Amount

Determinants

q = QSE

j = Source Settlement Point

k = Sink Settlement Point

Real-Time Obligation Price

Real-Time Obligation

RTOBLPR (j, k) = S (RTSPP k – RTSPP j) / 4

Real-Time Settlement Point

Price

RTOBLAMT q, (j, k) = Max (0, RTOBLPR (j, k)) * RTOBL q, (j, k)

Real-Time

Settlement of PTP


in DAM


• A QSE3 bought 10 MW of PTP obligations in

the Day-Ahead Market.

• The Source was RN4

• RTSPP $30/MWh for each interval in the hour

• The Sink was LZ2

• RTSPP $65/MWh for each interval in the hour

• QSE3 receives a payment

Trigger

#1

Outcome

Outcome

#1


RTOBLPR (j, k) = S (RTSPP k, i – RTSPP j, i) / 4

$35/MW (j, k) = [($65/MWh k, i– $30/MWh j, i)

+($65/MWh k, i+1– $30/MWhj, i+1)

+($65/MWhk, i+2–$30/MWhj, i+2)

+ ($65/MWhk, i+3–$30/MWhj, i+3)] / 4

QSE3 receives a payment

RTOBLAMT q, (j, k) = (-1) * RTOBLPR (j, k) * RTOBL q, (j, k)

-$350 q, (j, k) = (-1) * $35/MW (j, k) * 10 MW q, (j, k)

Outcome

Outcome

#1

Payments for PTP Obligations with Links to Options

Who: NOIE that owns PTP Options before DAM and buys PTP

Obligations in DAM linked to those Options

What: A Payment based on Real-Time Congestion

Why: To Hedge the Cost of congestion in Real-Time

Real-time Settlement of DAM PTP

Obligations with Links to Options

Real-Time Settlement of PTP


in DAM


Trigger

#1

NOIE buys DAM

PTP Obligations

based on PTP

Options they own


Settlement for DAM PTP Obligations

with Links to Options

Real-Time Obligation with

Links to an Option

Amount

Determinants

q = QSE

j = Source Settlement Point

k = Sink Settlement Point

Real-Time Obligation Price

Real-Time Obligation with

Links to an Option

RTOBLPR (j, k) = S (RTSPP k – RTSPP j) / 4

Real-Time Settlement Point

Price

RTOBLLOAMT q, (j, k) = Max (0, RTOBLPR (j, k)) * RTOBLLO q, (j, k)

Real-Time

Settlement of PTP


in DAM

Who: Day-Ahead and Real-Time CRR Owners

What: Prices to settle CRRs

Why: If Day-Ahead Market does not clear there are no Day-

Ahead Market Prices to Settle CRRs

Prices for Settling CRRs when

DAM does not clear

Settlement of NOIE

CRRs in Real-Time

Shortfall Charge for CRRs Settled in Real-Time

DAM

Settlement of CRRs in

the DAM

Real-Time Settlement of CRRs when no DAM

• DAM does not clear

• All CRRs settled in Real-Time using

RTSPP

• No Derating

• No Shortfall Charges

Trigger

#1

Outcome

Outcome

#1

Real-Time Revenue Neutrality Allocation


What: An Allocation on of a QSEs Load Ratio Share

Why: To keep ERCOT revenue neutral

Fundamentals of Real-Time

Revenue Neutrality Allocation

Real-Time Revenue Neutrality

Revenue Neutrality

• ERCOT Must Be

revenue Neutral

• All revenue from Real-

Time Charges are used

to fund Real-Time

Payments

Revenue Neutrality

• Any money left over is

paid out to QSEs that

represent Load

Revenue Neutrality

• If there is not enough

revenue collected to

cover payments, QSEs

will proved the extra

revenue based on LRS


• All charges and payments related to energy

and congestion are summed

• Allocated to QSEs with Load

RTEIAMTTOT Real-Time Energy Imbalance Amount Total

BLTRAMTTOT Block Load Transfer Resource Amount Total

RTDCIMPAMTTOT Real-Time DC Import Amount Total

RTDCEXPAMTTOT Real-Time DC Export Amount Total

RTCCAMTTOT Real-Time Energy Congestion Cost Amount Total

RMRDAESRTVTOT RMR Day-Ahead Energy Sale Real-Time Value Total

RTOBLAMTTOT Real-Time Obligation Amount Total

RTOBLLOAMTTOT Real-Time Obligation with Links to an Option

Amount Total

Outcome

Outcome

#1


Outcome

Outcome

#1

• Hourly values must be divided by 4

• Allocated based on Load Ratio Share

RTEIAMTTOT + BLTRAMTTOT

+ RTDCIMPAMTTOT + RTDCEXPAMTTOT

LARTRNAMT q = (-1) * + RTCCAMTTOT + RMRDAESRTVTOT * LRS q

+ RTOBLAMTTOT/4 + RTOPTAMTTOT / 4

+ RTOPTRAMTTOT /4


RTEIAMTTOT + BLTRAMTTOT

+ RTDCIMPAMTTOT + RTDCEXPAMTTOT

LARTRNAMT q = (-1) * + RTCCAMTTOT + RMRDAESRTVTOT * LRS q

+ RTOBLAMTTOT/4 + RTOBLLOAMTTOT/4

= (-1) * ($625 + $375 – $1000/4) * .20

= (-1) * ($750) * .20

= -$150

Outcome

Outcome

#1

• RT Energy Imbalance Total = $625

• DC Tie Import Amount Total = $375

• RT Obligation Amount Total = -$1000

• QSE 4 has 20 percent of the load

Payments for Ancillary Services Sold in a SASM

Who: QSEs that sold Reg-Up, Reg-Down, Responsive, or Non-Spin in a

SASM

What: A Payment for the services sold in a SASM

Why: To cover the costs of a services to ensure ERCOT reliability

Fundamentals of Payments for

Services Sold in SASM

Real-Time Supplemental

Ancillary Services

Market (SASM)

Supplemental Ancillary Services Market

ERCOT may procure Ancillary Services in the

Adjustment Period for 3 reasons:

1) Replacement of Ancillary Services capacity due to a QSE’s failure to

provide or purchase (trade) from someone else

2) Replacement of Ancillary Services capacity that

is undeliverable due to transmission constraints

3) Increased need of Ancillary Services capacity above what was

specified in the Day-Ahead


Trigger

#1

ERCOT executes a

SASM and

Ancillary Services

are sold


• ERCOT executes a SASM

• A QSE sells its capacity for

– Regulation Up and/or

– Regulation Down and/or

– Responsive Reserve and /or

– Non-Spin

• ERCOT holds A SASM

• QSEs offer Capacities

• ERCOT will determine the Market

Clearing Price and Awards

• The QSE will receive a payment for the

services supplied

Trigger

#1

Outcome

Outcome

#1


• ERCOT executes A SASM

• QSEs offer Capacities

• ERCOT will determine the Market Clearing Price and

Awards

• The QSE will receive a payment for the services

supplied

In SASM1

• QSE1 is awarded 50 MW of Regulation Up

– The Clearing Price is $8/MW

• QSE4 is awarded 4 MW of Regulation Down


• QSE4 is awarded 20 MW of Responsive Reserve


• QSE1 is awarded 40 MW of Non-Spin


Outcome

Outcome

#1


In SASM1

• QSE1, 50 MW of Regulation Up at $8/MW

• QSE4, 4 MW of Regulation Down at $4/MW

• QSE4, 20 MW of Responsive Reserve at $8/MW

• QSE1, 40 MW of Non-Spin at $12/MW

RTPCRUAMT q, M = (-1) * MCPCRU M * RTPCRU q, M

RTPCRDAMT q, M = (-1) * MCPCRD M * RTPCRD q,M

RTPCRRMT q, M = (-1) * MCPCRR M * RTPCRR q, M

RTPCNSAMT q,M = (-1) * MCPCNS M * RTPCNS q, M

-$400 q, M = (-1) * $8/MW M * 50MW q, M

-$16q, M = (-1) * $ 4/MW M * 4MW q,M

-$160 q, M = (-1) * $ 8/MW M * 20MW q, M

-$480 q,M = (-1) * $12/MW M * 40MW q, M

Outcome

Outcome

#1

Charges for Ancillary Service Capacity Replaced Due to

Failure to Provide

Who: QSEs that fail on their Ancillary Service Supply Responsibility

What: A charge for the Failure to Provide Ancillary Service Capacity

Why: To ensure costs are met in order to replace Failed Ancillary

Service Capacity

Fundamentals of Charges for

Failure to Provide


Ancillary Services

Market (SASM)

Charges for Ancillary Service Capacity Replaced Due to Failure to

Provide

RUFQAMT q = Max (MCPCRU M ) * RUFQ q,

RDFQAMT q = Max (MCPCRD M ) * RDFQ q,

RRFQAMT q = Max (MCPCRR M ) * RRFQ q,

NSFQAMT q = Max (MCPCNS M ) * NSFQ q,

Charge for Failure to Provide

Max Price of AS Markets * Failed Quantity

Outcome

Outcome

#1

Adjustments to Costs for Ancillary Services Procurement

Who: QSEs that have Ancillary Service obligations

What: A charge to the QSE for its share of the net total costs incurred

in both DAM and SASMs less its DAM charge

Why: To cover the costs of a services to ensure ERCOT reliability

Fundamentals of Adjustments to

Cost for Ancillary Services


Ancillary Services

Market (SASM)


Trigger

#1

ERCOT has net

costs for AS that

must be collected

from the market


Failed AS

Amounts

•DAM Procured

Amounts

•SASM Procured

Amounts


A QSE’s share of the net total cost for an

Ancillary Service for an Operating Hour is

simply

(AS Price) * (AS Quantity)

= AS Price

ERCOT Total AS Cost

( ) ERCOT Total Obligation not Self-Arranged

= AS Quantity ( ) QSE Obligation - ( ) Self-Arranged Qty

Total

AS Costs


(ERCOT Total AS Capacity) * HLRS

+ AS Replaced as Undeliverable

QSE Obligation =

QSE’s AS Obligation from Load Ratio Share

QSE’s AS that was undeliverable

QSE Obligation


ERCOT Total AS Capacity

Total ERCOT

AS Capacity

Self-Arranged Qty in all Markets +

AS Procured in Real-Time +

AS Procured in DAM –

AS Replaced as Undeliverable –

AS Failed to Provide

= ∑ All

QSEs


ERCOT Total AS Capacity


Putting it all together,

+ AS Replaced as Undeliverable

QSE

Obligation

=

Self-Arranged Qty in all Markets +

AS Procured in Real-Time +

AS Procured in DAM –

AS Replaced as Undeliverable –

AS Failed to Provide

∑ All

QSEs

HLRS *


Now, the QSE’s AS Cost is simply

Is this what the QSE pays for each Ancillary

Service in Real-Time?

AS Price * [ QSE Obligation – (Self-Arranged Qty) ]


The QSE already paid part of this AS

Cost in the Day-Ahead Market.

In Real-Time, the QSE pays or is paid for any difference

between their AS Cost and their Day-Ahead AS Charge

DAM Participation in DAM

• Energy

• AS

• PTP Obligations

AS Cost – RT AS

Amount

= Day-Ahead

AS Amount


Ancillary Services

Market (SASM)


Where:

• Net price for Reg-Up

RUPR = RUCOSTTOT / RUQTOT

• A QSE’s net quantity for Reg-Up

RUQ q = RUO q – SARUQ q

Outcome

Outcome

#1

QSE’s Net Cost for Reg-Up is calculated as

RUCOST q = RUPR * RUQ q


Where:

• A QSE’s net quantity for Reg-Up

RUOq = (SARUQq+ (RTPCRUq,m ) + PCRUq, – RURPq– RUFQq) * HLRSq

+ RURPq,m

Outcome

Outcome

#1

QSE’s Net Cost for Reg-Up is calculated as

RUCOST q = RUPR * RUQ q

𝑞

𝑚

𝑚


The Real-Time Reg-Up Amount for a QSE

RTRUAMT q = RUCOST q – DARUAMT q

Outcome

Outcome

#1

Finally, the QSE is charged the difference

between their net Reg-Up Cost and their Day-

Ahead Reg-Up Charge

There is a similar Charge Type

for each Ancillary Service Type.

Module summary

Day 3

Real-Time

Statements &

8:30 A

1:00 P

Invoicing

$ Describe the Settlement impacts of

Real-Time Operations.

$ Calculate various charges and

payments associated with Real-

Time Operations

$ Explain the impacts of the CRR

Auction, Trades and the Day-Ahead

Market on Real-Time Settlements

module 6: real-time operations · module objectives: real-time operations upon completion of this...

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