presentation - fall 2014 release settlements training

Fall 2014 Release Settlements

Training

Cynthia Hinman

External Training

September 3, 2014

These fall 2014 release projects impact settlements

Project Name aka:

Contingency Reserve Cost Allocation FERC Order 789

Standard Capacity Product Availability Calculations Many-to-Many

Flexible Resource Adequacy and Must Offer Obligation FRAC MOO

Full Network Model Expansion FNM Expansion

Energy Imbalance Market EIM

Contingency Reserve Cost Allocation

FERC Order 789

What is it?

• Contingency reserve obligations specify the quantity and

types of spinning and non-spinning reserves required to

ensure reliability under normal and abnormal conditions.

– FERC Order 789 updates the current reserve

requirements

– Change will be effective October 1, 2014

• Due to changing requirements cost allocation will also

change.

The minimum contingency reserve calculation is based

on the greater of:

The amount of Contingency Reserve equal to the loss of the most severe single contingency;

The amount of Contingency Reserve equal to the sum of three percent of hourly integrated Load plus three percent of hourly integrated generation.

AS operating reserve obligation

SPN / NSPN Obligation = 7% (ML + FE - FI) +

100% (NFI) +

0% (NFE) +

-2% (Hydro)

ML = Metered Load

FE = Firm Export

FI = Firm Import

NFI = Non-Firm Import

NFE= Non-Firm Export

(CC 6194 / 6294)

AS operating reserve obligation

SPN / NSPN Obligation =

6% Load + 3% Exports – 3% Imports

( CC 6194 / 6294)

Impacted Charge Codes

Charge Code Title

Pre-calc Ancillary Service

6194 Spinning Reserve Obligation Settlement

6294 Non-Spinning Reserve Obligation Settlement

6090 Ancillary Service Upward Neutrality Allocation

Example

Notes

• Scheduling Coordinator’s hourly initial obligation can be

less than zero

• Dynamics are excluded if ISO is procuring AS for them

• Requires responsible entities to restore contingency

reserves within 60 minutes following a Disturbance

Recovery Period (as opposed to 90 minutes under the

NERC Reliability Standard)

Standard Capacity Product (SCP)

Availability Calculations Part of the Many-to-Many Substitution project

Standard Capacity Product (SCP) Availability

Calculations

• With the introduction of the Outage Management System

(OMS), newly defined outage categories impact the

settlement of SCP

• Outage MWs associated with approved forced outages

that are not subject to SCP shall be exempted within the

SCP pre-calculation configuration

New Fields in OMS

• Opportunity

– Off Peak Opportunity

– Short Notice Opportunity

• SCP Exempt Flag

– The exempt MW capacity is not part of the availability

assessment

– Automatically set in OMS based on business rules

• Nature of Work

When is the “SCP exempt” flag set?

Outage Type Difference between

date of outage

submission and

planned start date/time

of outage *

SCP Exempt Flag is set

Forced 4-7 calendar days Yes

Forced 3 calendar days or less No

Planned N/A No

(*excluding the date outage was submitted and planned start date of outage)

Example 1 – SCP Availability Calculation

• Assumptions

– A resource has a Pmax of 100 MW

– 1 assessment hour (60 min)

– Two forced outages

• Outage 1

• Outage 2

Period Curtailed by

Minute 0 to 30 50 MW

Minute 31 to 60 0 MW (fully available)

Period Curtailed by

Minute 0 to 42 0 MW (fully available)

Minute 43 to 60 100 MW (fully curtailed)

Example 1 – SCP Availability Calculation (cont’d)

100 MW Pmax

- 25 MW Outage 1

- 30 MW Outage 2

45 MW Resource availability

Example 2 – SCP Availability Calculation

• Assumptions

– A resource has a Pmax of 100 MW

– 1 assessment hour (60 min)

– Two forced outages

• Outage 1

• Outage 2 – Reported 5 days prior to outage

(SCP exempt forced outage)

Period Curtailed by


Period Curtailed by


Example 2 – SCP Availability Calculation (cont’d)

100 MW Pmax

- 40 MW Outage 1

60 MW Resource availability

BPM Configuration Guide: Standard Capacity Product

Pre-calculation (Updated Business Rules)

• SCP exempt capacity MWs shall not be subject to SCP

Non-Availability Charges and Availability Payments.

• A resource’s MW Capacity entered into a grandfathered

contract as specified in Tariff Section 40.9.2(2) & (3) shall

be treated as SCP exempt capacity.

• Outage MW Capacity associated with an RA

maintenance outage or short-notice opportunity outage

that is approved as a forced outage not subject to SCP

shall be treated as SCP exempt capacity.

New Input Variable Name

• Represents the RA Capacity exempt from SCP due to:

– RA Maintenance outage

– Off-Peak Opportunity RA Maintenance Outage

– Short Notice Opportunity Outage

BARAResourceOutageExemptQuantity BrtF’S’mdh

New Output Variable Name

Pre 10/1/14

• BAHourlyRAResourceSCPCapacityNotGrandfatheredQuantity BrtF’S’mdh

After 10/1/14

• BAHourlyRAResourceSCPCapacityNonExemptQuantity BrtF’S’mdh

Flexible Resource Adequacy Criteria

and Must Offer Obligation FRAC MOO

Why do we need backstop capacity?

SC for LSE does not submit a plan that meets its flex RA requirement and does not cure the

deficiency

ISO’s monthly RA assessment

indicates that there is insufficient capacity

for a particular category

The ISO may exercise backstop

procurement to meet the operational flex

needs

Key points - FRAC MOO Settlements

• Settlement starts January 1, 2015

• Two CPM types:

– CPM (for generic capacity)

– CPM Flexible Capacity

Changes to the “Metered Demand Over TAC Area and

CPM Pre-Calculation”

• Purpose – Determines the metered demand allocation

by TAC Area(s) (minus qualified TORs), CPM payment

quantity, CPM allocation factors, and CPM availability

percentages for the settlement of CPM Capacity.

• Affects the following charge codes:

Charge Code/ Pre-calc Name

CC 7872 – Monthly CPM Significant Event Settlement

CC 7873 – Monthly CPM Significant Event Allocation

CC 7874 – Monthly CPM Insufficient Local Capacity Area Resources Settlement

CC 7876 – Monthly CPM Collective Deficiency Settlement

CC 7877 – Monthly CPM Collective Deficiency Allocation

CC 7880 – Monthly CPM Exceptional Dispatch Settlement

CC 7882 – Monthly CPM Capacity at Risk of Retirement Settlement

CC 7883 – Monthly CPM Capacity at Risk of Retirement Allocation

CC 7884 – Monthly CPM Insufficient Resource Adequacy Resources Settlement

CC 7881 – Monthly CPM Exceptional Dispatch Allocation


CPM Pre-Calculation” – Business Rules

• A resource with overlapping CPM and CPM Flex

Capacity shall be paid based on the highest MW amount

of either designation for the period when the

designations overlap (Rule 3.0)

MW

CPM – Generic RA

CPM – Flex RA

Both of these are CPMs are for the same

period. The payment will be based on the

highest MW amount.


CPM Pre-Calculation”- Business Rules (cont’d)

• For overlapping CPM capacity, the resource’s CPM

settlement shall be reflected in the Flexible CPM charge

code. (Rule 3.1)

– New charge codes

• CC 7886 – Monthly CPM Flexible Resource

Adequacy Resources Settlement

• CC 7887 – Monthly CPM Flexible Resource

Adequacy Resources Allocation



• For a resource with more than two concurrent CPM

designations, where one of these designations is for

Flexible CPM, the overlapping capacity shall be

proportionate to the generic RA CPM designation. (Rule

3.2)

CPM – Generic RA

CPM – Flex RA

60 MW

40 MW

Exceptional Dispatch

Monthly RA

The payment amount is based on the highest MW = 60 MW

Settlement Quantities =

20/60 X 20 = 6.6 MW ED CPM (Generic RA)

40/60 X 20 = 13.3 MW Monthly RA CPM (Generic RA)

40 MW Flex RA CPM

Legend



• For a resource with concurrent CPM designations, where

one of these designations is for Flexible CPM, the cost

allocation shall be proportionate to the deficiency MW

from both the generic and flexible resource adequacy

capacity. (Rule 4)

CPM – Generic RA

CPM – Flex RA

2/3 Generic Capacity x CPM Payment = Generic Allocation

1/3 Flex Capacity x CPM payment = Flex Allocation

80 MW

40 MW

New charge code - Monthly CPM Flexible Resource

Adequacy Resources Settlement (CC 7886)

• Settlement of CPM capacity that the ISO procures in

response to all flex RA CPM designations

• Applies the CPM price

• Provides the total amount of SC payment for flex RA

CPM capacity procured during the trade month

• So this would also include overlapping generic CPM

capacity

New charge code - Monthly CPM Flexible Resource

Adequacy Resources Allocation (CC 7887)

• Allocation of the cost of the CPM capacity procured in

the event that an SC fails to demonstrate an annual or

monthly RA plan procurement of sufficient flex RA

resources to comply with their LSE requirements

• Allocations will be prorated to each LSE based on the

proportion of its deficiency to the aggregate deficiency

• Monthly charge

Example – Flex RA Allocation

Changes to “RUC No Pay Quantity Pre-Calculation”

• Rescinds RUC capacity payment for resources when

one of the following occurs:

– RUC capacity is availability-limited

– Undispatchable due to an outage or rerate

– Is undelivered outside of a tolerance band

– Ineligible for a RUC award because it is RA capacity

(generic or flex)

• The calculation has been changed so that flex RA

capacity will be included

Summary

• CPM designation – minimum commitment term of one month;

maximum 1 year.

• Same price for backstop procurement of flexible as the applicable

capacity procurement price mechanism.

• Cost for a CPM designation will be allocated to all deficient LSEs

within the deficient LRA (unless the LRA has established other

rules).

• Simultaneous or overlapping designations - the megawatt amount

of the capacity procurement mechanism capacity payments shall be

the highest megawatt amount of either designation.

Full Network Model Expansion

Transaction IDs and Registered Resources

Phase 1 and

Phase 2 changes

39

October 1, 2014

Applications impacted by this change

Application What is it? Change

Master File Holds resource-specific

information

Define external BAA scheduling points

SIBR Bid/Schedule/Forecast

submission

Transaction IDs will be created based on

SC submission

DAM/RTM Day-ahead and Real-time

market

Receive transaction IDs, perform

analysis which includes external BAA

constraints and outages

CMRI Market Reports Use transaction IDs (as applicable) in

reports

ADS Binding instructions Use transaction IDs (as applicable) in

ADS instructions

Settlements Market settlement

information

Use transaction IDs (as applicable) for

settlements

Use intertie/scheduling point combination

Intertie transaction inputs

Field Description

Scheduling Coordinator Scheduling Coordinator identifier (required)

Scheduling Point Intertie Scheduling Point identifier (required)

Primary Tie Primary Intertie identifier (required)

Direction Direction (required): I for import, E for export

Bid Type Bid Type (inserted): P for physical, V for Virtual

Alternate Tie Alternate Intertie identifier (optional)

Energy Type Energy Type (required for physical transactions):

F – Firm

N – Non-Firm

U – Unit Contingent

D – Dynamic Interchange

W – Wheeling

Purchase- Selling Entity

Identifier

A registered Purchase-Selling Entity identifier

(required for physical transactions); allow PSE,

PSE.1, PSE.2 …PSE.9

41

Intertie Transaction - fictitious examples

Non-resource specific Physical Import bid :

SC05-AMARGOSA_1_SN001-AMARGO-I-P-F-DECM01

SC05-AMARGOSA_1_SN001-AMARGO-I-P-F-DECM01.1


…


Non-resource specific Physical Export bid:

SC05-AMARGOSA_1_SN001-AMARGO-E-P-F-DECM01

SC05-AMARGOSA_1_SN001-AMARGO-E-P-F-DECM01.1

Non-resource specific Physical Wheeling Import bid:

SC05-AMARGOSA_1_SN001-AMARGO-I-P-W-DECM01

Non-resource specific Physical Wheeling Export bid:

SC05-BLYTHE_1_N101-BLYTHE-E-W-P-DECM01

Scheduling

Coordinator

Intertie Scheduling

Point

Primary Intertie

Identifier

Direction

Bid Type

Energy Type

Purchase-Selling

Entity Identifier

Transaction ID

43

FMM Schedule – Effective Intertie

44

Transaction ID includes the

primary tie information

Effective Intertie – will show which tie

was used (primary or secondary, if

applicable)

Settlements

• Scheduling point and intertie will both be considered in

settlements

• This will be accounted for in the attributes of the

formulas.

• In Phase 1, there is a one-to-one correspondence

between scheduling point and the intertie, so this change

will have minimal system configuration impact

45

Old Attribute New Attributes

Financial Node APNode

APNode type

Intertie ID

Pricing Node

Example

Today After 10/1/14

HourlyDAFinancialNodeMCLPricej’mdh HourlyDAFinancialNodeMCLPriceAA’pmdh

Attachments

Energy Imbalance Market

EIM

Real-time energy charge codes

CAISO Charge

Code

PACE Charge

Code

PACW Charge

Code

Instructed Imbalance

Energy (IIE)

6460 FMM

6470 RTD

64600 FMM

64700 RTD

64600 FMM

64700 RTD

Uninstructed Imbalance

Energy (UIE)

6475 64750 64750

Unaccounted for Energy

(UFE)

6474 64740 64740

Congestion Offset 6774 67740 67740

Marginal Losses Offset 6985 69850 69850

Imbalance Energy Offset

(RTIEO)

6477 64770 64770

REAL-TIME CONGESTION

OFFSET

EIM settlement changes

Real-time congestion offset

Step 1 - Real time dispatch is used to resolve load

imbalances

PACW

PACE

1000 MW Demand

- 100 MW from ISO

= 900 MW from PACE or PACW

ISO

1000 MW Demand

+ 100 MW to PACE

= 1100 MW Dispatch

100 MW


Step 2 - Building buckets

PACW PACE

900 MW X $40 = $36,000

ISO

1100 MW X $30 = $33,000

100 MW

Assume

- PACE LMP is $40

- ISO LMP is $30 Assume MCC =

$0 PACW

$2 PACE

$4 ISO


Step 3 - Congestion settlement (CC 6774, 67740)

ISO

1,100 MW X $30 = $33,000

1,100 MW X $0 = $0 PACW

1,100 MW X $2 = $2,200 PACE

1,100 MW X $4 = $4,400 ISO

Total congestion = $6,600

Congestion cost due to ISO’s dispatch

Assume MCC =

$0 PACW

$2 PACE

$4 ISO

Allocation

• Allocated to ISO Measured Demand

Charge Code 6774

• Allocated to EIM Entity SC

Charge Code 67740

Key concept – virtual bid adjustment

• “The CAISO Real-Time Congestion Charges less Virtual

Bid Adjustment shall be distributed back to non-ETC

Control Area metered Demand and exports in Real Time

Congestion Offset (CC 6774)”

• If virtual bid causes real time congestion in EIM BAA the

Virtual Bid adjustment will be charged to the virtual

bidders who caused the congestion

REAL-TIME LOSS OFFSET


Key Concepts

• The Real Time Marginal Losses Offset for each BAA is

the sum for each BAA of the product of the contribution

of that Balancing Authority Area’s Transmission

Constraints to the marginal loss component of the LMP

at each resource location in the EIM Area and the

imbalance energy, at that resource

• If energy is all flowing into ISO then all the losses will be

part of ISO allocation.

Allocation

• Allocated to ISO Measured Demand

Charge Code 6985

• Allocated to EIM Entity SC

Charge Code 69850

REAL-TIME IMBALANCE

ENERGY OFFSET


Real-time Imbalance Energy Offset

• Total Energy Imbalance Offset

= (IIE + UIE + UFE) – Congestion – Losses

= ((6460 +6470) + 6475) – 6774 – 6474)

or

= ((64600 +64700) + 64750) – 67740 – 64740)

Real-time Imbalance Energy Offset

• Total Energy Imbalance Offset

– EIM Transfer falls into this bucket

– Allocated to other BAAs

– Could be a payment or a charge

Real-time imbalance energy offset

Step 1 - Real time dispatch is used to resolve load

imbalances

PACW

PACE

1000 MW Demand

- 100 MW from ISO

= 900 MW from PACE or PACW

ISO

1000 MW Demand

+ 100 MW to PACE

= 1100 MW Dispatch

100 MW

Real-time imbalance energy offset

Step 2 – Building buckets

PACW

PACE

900 MW X $40 = $36,000

+ 100 MW X $30 = $ 3,000

$39,000

ISO

1100 MW X $24 = $26,400

- 100 MW X $30 = $ 3,000

$ 23,400

100 MW

Assume

- PACE LMP is $40

- ISO LMP is $30

The price for the BA transfer quantity (100 MW) based on the transfer

scheduling point ($30)

Determine the total “transfer from” amount

• The total “transfer from” = sum of the absolute value of

UIE, UFE and the EIM transfer quantity

• Transfer Out % x BAA RTIEO = Transfer from amount

5% x $23,400 = $1,170

Determine total “transfer to” amount

• The transfer to amount = Sum of transfer from $ *

transfer to %

$1,170 x 20% = $234.00

FLEXIBLE RAMPING

CONSTRAINT


Tariff section 11.25 Flexible Ramping Constraint

subsections

• Determination of shadow price 11.25.1

• Compensation of resources (payment) 11.25.2

• Rescission of payment for non-performance (no pay) 11.25.3

• Apportionment of costs 11.25.4

• Allocation of costs 11.25.5

Charge code 7050 – Flexible Ramp Up Capacity

Payment

• Applied to resources with awarded flex ramping capacity

which resolve the flexible ramping constraint(s) in the

EIM area in which they participate in the FMM.

Payment per resource = capacity award X derived price

Flexible ramping constraint derived price

• Equal to the lesser of:

– $800/MWh or

– Greater of

• Zero or

• Real-time spinning reserve ancillary service marginal price or

• Flexible ramping constraint shadow price minus 75% of the

maximum of

– Zero or

– The simple average real-time SMEC for each of 3 five

minute intervals in the applicable FMM interval

=min($800,max(0, AS Spin, (FRC -.75 x max (0, RT SMEC))))

Example 1 – Determining the derived price

• Assumptions

– Flexible ramp constraint award 10 MW

– Flexible ramp constraint price $250

– AS Spin price $3

– RT SMEC (simple average) $200

=min($800, max(0, $3, ($250 - .75 X max (0, $200))))

=min($800, max(0, $3, ($250 - .75 x 200)))

=min($800, max(0, $3, ($250- $150)))

=min($800, max(0, $3, $100))

=min($800, $100)

=$100 (the derived price)


Example 1 – Determining the derived price

Example 2a – Determining the derived price

• Assumptions



– AS Spin price $3


=min($800, max(0, $3, ($100 - .75 X max (0, $200))))

=min($800, max(0, $3, ($100- .75 x 200)))

=min($800, max(0, $3, ($100- $150)))

=min($800, max(0, $3, -$50))

=min($800, $3)



Example 2a – Determining the derived price

Example 2b – Determining the derived price

• Assumptions



– AS Spin price $0 (EIM Entity)


=min($800, max(0, $0, ($100 - .75 X max (0, $200))))

=min($800, max(0, $0, ($100 - .75 x 200)))

=min($800, max(0, $0, ($100 - $150)))

=min($800, max(0, $0, -$50))

=min($800, $0)



Example 2b – Determining the derived price

Examples - settlements

Example Capacity

Award

Derived

Price

Payment in

CC 7050

1 10 MW $100 $1,000

2a 10 MW $ 3 $ 30

2b 10 MW $ 0 $ 0

Other charge codes related to the flexible ramping

constraint

• The allocation of the total flexible ramping constraint

costs for each EIM Entity Balancing Authority Area will

be allocated to the applicable EIM Entity SC in charge

code 7056.

• If resource that was awarded flexible capacity, fails to

deliver, they will be subject to “Flexible Ramp Up

Capacity No Pay Charge” in charge code 7024.

Example – Resource Flexible Ramping Allocation

• Assumptions

200 MW Awarded

10 MW No Pay

190 MW Delivered

• Resource Specific Flexible Ramping Marginal Price =

$16.28

– Based on the resource’s total FRC cost in all BAAs

• Flexible Ramping Constraint Price = $10.00

Charge code 7056 – Flexible Ramp Cost Allocation

MW Delivered x FRC Price

Apportionment x Flexible Ramping Marginal Price

Total Cost x % allocation

ISO BAA allocates to measured

demand and gross negative supply

deviation

BID COST RECOVERY

NETTING CHANGE


EIM BCR sequential netting

Each interval the ISO will:

1. Determine if there is a shortfall

2. Calculate the 5-minute BCR pre-transfer amount

3. Calculate to the amount attributed to transfer out

4. Calculate the % of transfer allocated to transfer in and

transfer out

5. Calculate the amount of transfer in or transfer out $

6. Calculate the 5-minute BCR total

Example BCR netting – Step 1

• Compare costs and revenues for each generator in BAA

and determine if there is a shortfall


• Determine the 5-minute BCR pre-transfer amount for

each BAA

5-Minute BCR Pre-Transfer = Daily BCR/24/12


• Determine the total transfer out which is the sum of the

absolute value of UIE, UFE and the EIM transfer quantity

• Determine the BCR % transfer out by dividing the EIM

transfer quantity by the transfer out amount

• Determine the BCR % transfer in by adding EIM transfer

quantity for each BAA and dividing by the sum of the

total positive EIM transfer quantity



• Apply the BCR % transfer in or out to the 5-minute BCR

pre-transfer amount to determine the credit or debit

amount


• Sum the 5-minute BCR pre-transfer amount and the

transfer in or transfer out $ to determine the 5-minute

BCR total

OVER AND UNDER

SCHEDULING CHARGES


Key concepts

• Unique to participation in EIM

– Impacts all BAAs

• Purpose – To ensure that EIM Entity BAAs are not

leaning on the system to meet its load forecasts

• Charge codes

– 6045 – Over and Under Scheduling EIM Settlement

– 6046 – Over and Under Scheduling EIM Allocation

Over scheduling charge

• Using EIM Entity forecast

– If EIM Entity demand is less than the base schedule

of supply by

• More than 5% but less than 10% and by at least 2

MW, the UIE for that LAP will be paid at 75% of the

hourly price

• More than 10% and by at least 2 MW the UIE for

that LAP will be paid at 50% of the hourly price

• Using Market Operator forecast

– If forecast is < EIM Entity base schedule supply by >

1% then deemed to be using their own forecast and

subject to penalties above

Under scheduling charge

• Using EIM Entity forecast

– If EIM Entity demand exceeds the base schedule of

supply by

• More than 5% but less than 10% and by at least 2

MW, the UIE for that LAP will be paid at 125% of

the hourly price

• More than 10% and by at least 2 MW the UIE for

that LAP will be paid at 200% of the hourly price

• Using Market Operator forecast

– If forecast is < EIM Entity base schedule supply by >

1% then deemed to be using their own forecast and

subject to penalties above

GRID MANAGEMENT

CHARGES


Charge Code 4564 – GMC EIM Transaction Charge


– Participating generator

– Non-Participating generator

– Intertie Resources

– Load

• Covers staff and portions of the ISO systems used to

support EIM functionality.

* Total gross absolute value

Charge Code 4564 – GMC EIM Transaction Charge

• EIM Administrative Charge = $.19

• Base charge = 5% of supply + 5% of demand

• Charge for each EIM Participating and Non-participating

resource

– If this amount exceeds the base charge no additional

charges go to the EIM Entity SC

– If this amount does not exceed the base charge the

difference is charged to the EIM Entity SC

* Total gross absolute value

= EIM Administrative Charge X (FMM IIE*, RTD IIE*, UIE* of EIM

supply + UIE* of EIM demand)

GREENHOUSE GAS EMISSION

COST REVENUE


Charge code 491 – Greenhouse Gas Emission Cost

Revenue


• EIM will incorporate the cost of the greenhouse gas

compliance obligation within an EIM Entity to serve ISO

load, but will not consider this cost when it dispatches

this generation to serve load outside of the ISO.

• Obligation quantity = Net export to the ISO BAA for each

EIM resource GHG payment

• GHG marginal price - based on MW that were

dispatched and determined to be awarded the GHG

obligation

GHG payment = GHG obligation quantity X EIM GHG marginal

price

NEW ATTRIBUTES


New attributes, no change in calculation

Charge Code Name

4515 GMC Bid Transaction Fee

4560 GMC Market Services Charge (note – this will not apply

to resources in EIM BAA)

4561 GMC System Operations Charge (note – this will not

apply to resources in EIM BAA)

THANK YOU FOR ATTENDING!

Questions: [email protected]

Fall 2014 Release Settlements

presentation - fall 2014 release settlements training

Documents