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ISO PUBLIC - © 2015 CAISO

Energy Storage and Aggregated

Distributed Energy Resource

Education Forum

April 16 & 23, 2015

California ISO

The information contained in these materials is provided for general information only and does not constitute legal or regulatory advice. The ultimate

responsibility for complying with the ISO FERC Tariff and other applicable laws, rules or regulations lies with you. In no event shall the ISO or its employees

be liable to you or anyone else for any decision made or action taken in reliance on the information in these materials.


Today’s topics

Item 1 – Context, background and purpose

Item 2 – Introduction to ISO and market concepts

Item 3 – Overview of current rules

Item 4 – Wholesale demand response products

Item 5 – Non-generator resource

Item 6 – Procurement and resource adequacy

Item 7 – Other efforts and challenges

Slide 2


Education forum – context,

background and purpose


California energy and environmental policies drive

renewable integration needs

• Greenhouse gas reductions to 1990 levels by 2020

• 33% of load served by renewable generation by 2020

• 12,000 MW of distributed generation by 2020

• Ban on use of once-through cooling in coastal power

plants

• Governor Brown’s 2030 goals:

– 50% renewables

– 50% reduction petroleum use – cars & trucks

– Double energy efficiency existing buildings

– Make heating fuels cleaner

Slide 4

ISO PUBLIC - © 2015 CAISO Slide 5

Solar generation doubles between now and 2020

(IOU data through 2017 and RPS Calculator data 2018 – 2020)


Wind & solar profiles

Slide 6

Peak demand

44,000 MW

Sample winter day in 2020


Flexible resources will be essential to meeting the net

load demand curve

Sample winter day in 2020

Slide 7


The ISO experiences over-generation conditions due

to abundant renewable supply and dispatch limitations

on some resources.

Ramp need

~13,000 MW

in three hours

Potential over-

generation

Slide 8

Curtailment date Time

Duration

(minutes)

Wind Curtailment

(max MW)

Solar Curtailment

(max MW)

Total

MWh

February 19, 2014 11:11 170 114 148 742.3

March 7, 2014 3:44 60 123 0 123.0

April 12, 2014 12:40 30 174 25 99.5

April 27, 2014 8:40 90 485 657 1713.0

Total 350 896 830 2677.8


Renewable curtailment in 2024 at 40% RPS

Slide 9

Solutions

Increase storage and demand response

Enable economic dispatch of renewables

Decarbonize transportation fuels

Retrofit existing power plants

Align time-of-use rates with system conditions

Target energy efficiency

Deepen regional coordination


California’s energy storage procurement targets

resulted in approximately 2,000 MW of storage

projects in the ISO interconnection queue.

Slide 10

The initial target for

transmission interconnected

storage is 700 MW.


California’s energy storage roadmap

• In 2014, a California energy storage roadmap was

published.

– Developed in collaboration with the CPUC and CEC

to understand stakeholder challenges bringing energy

storage to market.

– Also touched on challenges with aggregating

distributed energy resources (DER).

• The roadmap identified needed actions to address these

challenges.

Slide 11


Roadmap identified several high priority action items

for the ISO

• Rate treatment – Clarify wholesale rate treatment and ensure

that the ISO tariff and applicable BPMs and other

documentation provide sufficient information.

• Market participation –

– Clarify existing ISO requirements, rules and market

products for energy storage to participate in the ISO

market.

– Identify gaps and potential changes or additions to existing

ISO requirements, rules, market products and models.

– Where appropriate, expand options to current ISO

requirements and rules for aggregations of distributed

storage resources.

Slide 12


ISO has developed a plan for carrying out these

roadmap action items

• Host a forum to educate stakeholders on existing ISO

requirements, rules, market products and models for

energy storage and aggregated DER to participate in the

ISO market.

– April 16 and 23

• Conduct a stakeholder process to specify and address

any needed enhancements to these existing rules.

– Launching in April/May

– Present scope and timeline at July Board meeting

Slide 13


Purpose of today’s education forum

• Provide information about how energy storage and

aggregated distributed energy resources may participate

in ISO markets today.

– The focus is on current tariff approved rules.

• Discussion of enhancements to current rules is not a

topic of this education forum.

– That’s the focus of the subsequent stakeholder

initiative.

Slide 14


By the end of this forum you will…

Slide 15

Gain a high-level understanding of how storage and

aggregated DER can participate in ISO markets under

today’s rules


Questions?

Slide 16


Introduction to ISO and market

concepts


Independent system

operator

Coordinates, controls and monitors the

electrical power system

Acts as a marketplace for wholesale

power

Slide 18


What does the ISO do?

• Operate the grid reliably and

efficiently

• Operate effective spot markets for

energy and reserves

• Plan and identify future grid

infrastructure needs

• Promote grid infrastructure

development

• Provides fair and open

transmission access

• Manage new generation

interconnections

Slide 19


ISO roles

Slide 20

• Operates a transmission control area

• Matches generation with load and maintains electric frequency of the grid

Balancing authority

• Runs day-ahead and real-time markets for energy and ancillary services

• Manages energy imbalance market across participating areas

Market operator


California balancing authorities

• The ISO manages the flow

of electricity for about 80

percent of California

• There are certain pockets of

California where local public

power companies manage

their own transmission

systems

Slide 21


Energy imbalance market balancing authority areas

• Neighboring balancing

authorities have partnered with

the ISO to develop a real-time

energy imbalance market

• EIM operates across

participating balancing areas

• PacifiCorp was activated on

October 1, 2014

• NV Energy activation

scheduled for October 2015

• Puget Sound Energy

scheduled for October 2016

Slide 22


Electricity is produced, delivered, and consumed at the

speed of light while balance must be maintained.

Slide 23


The flow of electricity today

Low-voltage utility distribution lines carry power to consumers

ISO operators manage flow of electricity to utility sub-station

ISO market fine-tunes supply/demand in real time

Forecastingdemand Buying and selling

between parties before it is scheduled for delivery by ISO Power

supplied/stored

Day-ahead marketrun to clear bids,

procure reserves and manage congestion

Slide 24


How the ISO fits in…

Local utility

Customer

Utility owned generation

ISO

Power marketers

Scheduling

Suppliers

coordinators

Slide 25


Market concepts


Majority of the ISO’s electricity demand is met through

utility-owned or bilaterally procured resources

Slide 27


Procurement of generic resource adequacy

CPUC

LSE

LSE

Supplier

Supplier

CPUC CAISO

1. Local regulatory authority

(LRA) mandates procurement

of capacity to meet peak load

forecast.

2. Load serving entities (LSEs)

engage in bi-lateral

procurement of capacity to

meet this requirement.

3. LSEs demonstrate

procurement to LRA and ISO

4. Suppliers demonstrate RA

sales to ISO.

5. LRA ensures LSE

compliance.

6. ISO ensures suppliers

corroborate LSE showings and

met needs.

“You must procure”

Bi-lateral procurement activity

Demonstrations


The ISO has two markets

Day-ahead energy market

• Enables parties to schedule contracted supply/demand

• Enables suppliers to offload excess supply in the form of energy or ancillary services

• Enables load serving entities the ability to secure pricing for load due to changes in load forecasts or for incremental changes in demand

• Transactions are settled at day-ahead prices

Real-time energy market

• Fifteen-minute market and five minute dispatch intended to meet instantaneous demand

• Fifteen-minute market supports renewable integration

• Includes ISO BAA and EIM BAAs

• Transactions are settled at fifteen-minute and five-minute prices

Slide 29


Day-ahead market


Clears bid-in supply against bid-in

demand

Day-ahead schedules and

awards

Day-ahead prices

Procures 100% ancillary services

Ancillary service awards

Day-ahead ancillary

services prices

Residual unit commitment

RUC awards

Day-ahead RUC prices for

capacity

Slide 31

Day-ahead market activities and pricing


Physical energy is the electricity needed to meet the

needs of the ISO consumers – industrial, commercial,

and residential alike

Energy demand

CAISO forecast of CAISO demand (CFCD)

Energy supply

Through ISO markets

Bilateral contracts

Utility-owned generation

Slide 32

Procured outside of the ISO

markets, but submitted to the ISO

through bidding and scheduling


The ISO procures reserves in the day-ahead market

Ancillary services

used to maintain grid

reliability


used to meet the forecasted

demand

Slide 33


Ancillary services ensure reliability as electricity is

moved from generating sources to customers

• Under ISO control through automatic generation control (AGC)Regulation up

• Under ISO control through automatic generation control (AGC)

Regulation down

• Synchronized to the grid and available to provide energy in 10 minutes

Spinning reserve

• Not synchronized to the grid, but can provide energy in 10 minutes

Non-spinning reserve

Slide 34


Ancillary service procurement is regional

ISO system region

ISO system region +

expanded

North of path 15 +

expanded

North of path 26 +

expanded

South of path 15 +

expanded

South of path 26 +

expanded

P26

P15

Slide 35


A method of ensuring

reliability of the grid

Capacity procurement

from additional day-ahead supply for real-time

Selects from resource adequacy

capacity and economic bids

Awarded resources

must submit an energy bid

in the real-time markets

Slide 36



Capacity procurement targets

• Percentage of CAISO forecast of CAISO demand (CFCD) for each hour based on the need to meet WECC and NERC performance standards (CPS1 and CPS2)

Regulation requirement

• Based on WECC and NERC reliability standards

Contingency reserve

requirements (Spin/Non-spin)

• Based on total CAISO forecast of CAISO demandResidual unit commitment

Slide 37


Residual unit commitment determination

Supply bids

Demand bids

Energy

$/MWh

MW

Total cleared demand

RUC

ISO forecast of demand

Slide 38


RUC is procured in zones

Regional requirements align with PG&E,

SCE, SDG&E and VEA

service territories

Slide 39


Real-time market


What’s the purpose of the real-time market?

To procure “balancing” energy to meet the instantaneous demand that draws energy from the grid

To dispatch supplies to meet the demand forecast and export schedules

To reduce supply if there is not enough demand

In extreme conditions, to curtail demand based on economic signals when supply is exhausted or unavailable (ISO BAA)

To procure ancillary services as needed (ISO BAA)

Slide 41


Procure balancing energy

15-minute market awards and

5-minute real-time dispatch

Real-time 15-minute and 5-minute prices

Procures additional

ancillary services

Ancillary service awards

Real-time ancillary

services prices


Convert day-ahead RUC awards to

energy if needed

Real-time prices for energy

Slide 42

Real-time market activities and pricing


Benefits of ISO spot markets

Centralized economic dispatch optimizes use of all resources – reduces cost of serving demand

Resolve transmission constraints economically

Transparency on constraints and costs

System is re-dispatched every five minutes to meet current system conditions

Slide 43


Real-time energy bids

Submitted by generators, curtailable loads, intertie resources, EIM participating resources

Submitted by resources with RUC awards or RA capacity without a day-ahead commitment

May also come from non-RA resources not committed in the day-ahead market

Bids are all co-optimized and may be used to increase or reduce supply

They are used to manage the instantaneous demand movement on the grid

Slide 44


Master file, outages, and resource availability

Resource information maintained in master file

Availability values are sent to market systems - setting the limits for forward schedules and real-time dispatches

Each time a unit has a physical restriction that limits its output, an outage card should be submitted to prevent being dispatched to a level it cannot achieve

An outage card is the only way to submit or change the availability

Slide 45


Ancillary services in real-time

• May convert contingency reserve capacity into energy

In the event of a grid disturbance in

the ISO BAA

• Replacement for IFM awards that are not available in real-time

• Changes to load forecast

• Replacement of converted capacity

• Additional requirements in regional areas

The ISO accepts bids for ancillary

services in the real-time market due to:

• Is designated as contingency only capacityCapacity awarded

in real-time

Slide 46


Market pricing


Nodal pricing

Supply resource

is paid the nodal

price

Load pays the

weighted average

price of all load nodes

in the service territory

Imports and

exports are paid

or pay the price

at the scheduling

point

Slide 48

PDR/RDRR is paid

the weighted average

of the prices for the

nodes over which they

are aggregated


Components of the locational marginal price *

Energy Congestion LossesLocational marginal

price

Slide 49

* LMP for EIM entities also contains a greenhouse gas component


Determining the energy component

Supply bids

Demand bids

Energy

$/MWh

MW Total cleared demand

Market

clearing

price

Slide 50


Congestion

• A situation in which the lowest-priced electricity can’t flow

freely to a specific area due to heavy use of the

transmission system

• Caused by:

– Lack of transmission capacity

– Outages

Slide 51


Loss component example

Slide 52

150 MWEnergy lost in transmission 140 MW

Losses are calculated by the use of the full network model and the optimal power flow solution and will affect the LMP calculated

by the market system


Industry landscape


Integrating renewables, storage, and distributed

energy resources

Implement environmental

policy

Maintain reliability

Mitigate upward

pressure on costs

Slide 54


Questions?

Slide 55


Overview of current rules

How storage and aggregated distributed energy resources may participate in ISO market today


Topics

• Market participation models

• Storage and non-aggregated DER scenarios

• Aggregation

Slide 57


Examples of how resources may participate in the

ISO’s energy and ancillary services markets today

• Participating Generator

• Participating Load

• Proxy Demand Resource (PDR)

• Reliability Demand Response Resource (RDRR)

• Non-Generator Resource (NGR)

Slide 58

Today’s education forum will focus on those of most interest to

storage and aggregated DER:

Wholesale Demand Response Products (PDR & RDRR)

Non-Generator Resource (NGR)


Definitions / clarification of terminology

Slide 59

Transmission Connected

Means connected to the ISO controlled grid

Distribution Connected

Means connected to

distribution facilities

controlled by a

distribution company,

regardless of voltage

level, and served by

the ISO grid

Distributed Energy

Resources (DER)

Includes any distribution

connected resources

regardless of size or

whether it is connected

behind or in front of the

end-use customer meter

DER includes DR, EV, DG and storage


Transmission connected storage scenarios

• Stand alone storage

• Storage behind the meter of a generating facility

Slide 60


Transmission connected storage scenarios under

current participation models

Slide 61

Storage scenario

Participation Models

Participating

Gen

(PG)

Part.

Load

(PL)

PDR RDRR NGRPump Storage

Hydro model

Stand aloneFor Energy Storage,

NGR is a better fit

Energy

Storage

Pump Storage

Gen/Load


Transmission connected storage scenarios under

current participation models (continued)

Slide 62

Storage scenario


Participating

Gen

(PG)

Part.

Load

(PL)


Hydro model

Behind meter of

generating facility

For Energy Storage,

NGR is a better fit

Energy

Storage

Pump Storage

Gen/Load


DER scenarios

• Interconnected under WDAT/WDT

– Stand alone

– Behind meter of generating facility

– Behind end-use customer meter

• Interconnected under Rule 21

– Behind end-use customer meter

Slide 63

DER may currently participate in ISO markets as

Part. Gen., Part. Load, NGR, or PDR

if they meet minimum capacity requirements


WDAT-connected DER scenarios under current

participation models

Slide 64

Scenario


Part. Gen

(PG)

Part.

Load

(PL)


Hydro model

Stand alone Gen PumpsEnergy

Storage

Pump Storage

Gen/Load



participation models (continued)

Slide 65

Scenario


Part. Gen

(PG)

Part.

Load

(PL)


Hydro model

Behind meter of

generating facilityGen Pumps

Energy

Storage

Pump Storage

Gen/Load




Slide 66

Scenario


Part. Gen

(PG)

Part.

Load

(PL)


Hydro model

Behind end-use

customer meterGen Pumps

Energy

Storage

Pump Storage

Gen/Load


Rule 21-connected DER scenarios under current


Slide 67

Scenario


Part.

Gen

(PG)

Part.

Load

(PL)


Hydro model

Behind end-use

customer meterGen Pumps

Demand

Response

Demand

Response

Energy

Storage

Pump Storage

Gen/Load


Aggregation

Slide 68

Generally means a combining of multiple sub-

resources, at single or multiple locations, into

a single market resource that participates in

ISO markets.


Aggregation in the ISO tariff

• Participating Generator

• Physical Scheduling Plant

• Aggregated Participating Load


Slide 69


Aggregation in the ISO tariff

Participating Generator

A generator or other seller of energy or AS through a SC

over ISO controlled grid from a generating unit

i. with a rated capacity of 1 MW or greater

ii. with a rated capacity of from 500 kW up to 1 MW for

which the generator elects to be a Participating

Generator

iii. providing AS or submitting energy bids through an

aggregation arrangement approved by the ISO

which has undertaken to be bound by the terms of the ISO

Tariff.

Slide 70


Aggregation in the ISO tariff (continued)

Physical Scheduling Plant

A group of two or more related generating units which either by

physical necessity or operational design must be operated as if

they were a single unit, or any generating units containing

related multiple generating components which meet one or more

of the following five criteria:

1. Multiple generating components are related by a common

flow of fuel which cannot be interrupted without a substantial

loss of efficiency of the combined output of all components;

2. The energy production from one component necessarily

causes energy production from other components;

Slide 71



Physical Scheduling Plant (continued)

3. The operational arrangement of related multiple generating

components determines the overall physical efficiency of the

combined output of all components;

4. The level of coordination required to schedule individual

generating components would cause the ISO to incur

scheduling costs far in excess of the benefits of having

schedule such individual components separately; or

5. Metered output is available only for the combined output of

related multiple generating components and separate

generating component metering is either impractical or

economically inefficient.

Slide 72



Aggregated Participating Load

• A collection of participating loads enabling participation

in ISO markets

– like generation by submitting supply bids when

offering curtailable demand and

– as non-participating load by submitting demand bids

to consume in the day-ahead market only

• Registered as a custom load aggregation point (set of

pricing nodes used for submission of bids and settlement

of demand)

• Individual participating loads must be ISO metered

Slide 73



Proxy Demand Resource (PDR)

• A load or aggregation of loads that provides demand

response services pursuant to a Demand Response

Provider Agreement (DRPA) between the ISO and a

Demand Response Provider.

• Aggregations of locations in a PDR must be contained

within a Sub-LAP.

• PDRs are Scheduling Coordinator Metered Entities.

• More on PDR later in the forum…

Slide 74


Existing aggregation arrangements involving ISO grid

connected resources

• Common examples

– Hydroelectric facilities on same river system

– Cogeneration / combined cycle (a combustion turbine

aggregated with a heat recovery steam generator)

– Multiple combustion turbines at the same location

– Wind turbines

– Geothermal

– Solar

• Many pre-dated the ISO’s formation

Slide 75


General requirements for aggregation of grid

connected resources under current rules

• Individual sub-resources must be ISO metered entities*

– Unless electrically connected (see diagram below)

Slide 76

* PDR and RDRR are exceptions



connected resources under current rules (continued)

• Individual sub-resources must be related

– Each under the same agreement type (e.g., PGA,

PLA, or DRPA, etc.)

– Operate as a single market resource under a single

resource ID

• Dispatch and control signals will be at the single market

resource level

Slide 77



connected resources under current rules (continued)

• Single ISO controlled grid point of interconnection*

– Not across multiple pricing nodes

• Rated capacity of single market resource at least 500

kW**

* Except for PDR and RDRR

** Except for PDR

Slide 78


Questions?

Slide 79


Wholesale demand response

Proxy Demand Resource

Reliability Demand Response Resource


The ISO offers several market models to enable load

participation

Slide 81

Model General Application

Participating load • Large pumps

• Loads

Pumped storage • Large pumped storage

• Small storage devices

Proxy demand resource

(PDR)

• Aggregated, economically bid

demand response

Reliability demand response

resource (RDRR)

• Aggregated, emergency

demand response


Topics

• Terms and acronyms

• Overview and purpose

• Characteristics

• Pre market processes– Agreements & system access

– Registration

• Market participation– Bidding

– Dispatch

– Outage management

• Post market processes– Meter data submission

– Performance evaluation

– Settlements

Slide 82


Terms and acronyms


Terms and acronyms


• Reliability Demand Response Resource (RDRR)

– Reliability Demand Response Product (RDRP)

• Demand Response Provider (DRP)

• Load Serving Entity (LSE)

• Utility Distribution Company (UDC)

• Demand Response Registration System (DRRS)

• Demand Response System (DRS)

• Default Load Adjustment (DLA)

Slide 84


Terms and acronyms

• Default Load Aggregation Point (DLAP)

• Sub Load Aggregation Point (sub-LAP)

• Pricing Node (Pnode)

• Scheduling Coordinator Metered Entity (SCME)

• Residual Unit Commitment (RUC)

• Locational Marginal Price (LMP)

• Settlement Quality Meter Data (SQMD)

• Scheduling Coordinator (SC)

• Scheduling Infrastructure and Business Rules (SIBR)

Slide 85


Purpose and overview


PDR and RDRR were developed in response to FERC

orders and CPUC rulings to integrate utility programs and

provide open access to 3rd party participation

Slide 87

PDR

Proxy Demand Resource implemented in 2010

RDRR “aka” RDRP

Reliability Demand Response Resource (Product)

implementation finalized in 2014 after FERC ruling and

compliance filing delays

2010

2014


These initiatives developed models to provide enablement

specific to demand resources

Provided a wholesale demand response model that

enabled:

• Direct participation of existing retail demand

response programs

• Simplification of forecasting and scheduling

• Participation independent of load serving entity

• Comparable treatment

• Enabled demand response participation all hours

and days of the year

Slide 88


PGE1

PGE2

Direct participation of load and simplification in the

scheduling of load curtailment participation as a supply

resource

• LSEs load is forecasted and

scheduled or bid-in at the DLAP

• DRPs bid the demand response

portion of the load into the ISO

• PDR/RDRR bid as a pseudo

generator

• The LSE and the DRP could be

the same entity or two separate

entities

Slide 89

DRPPDR

RDRR

LSE Load

DLAP


Overview of participation options for PDDR and RDRR

Design Services Market dispatch Description

Proxy

Demand

Resource

Energy, AS non-

spinning, AS spinning,

and residual unit

commitment (RUC)

Economic day-

ahead and real-

time

Bids into ISO

markets as

supply

Reliability

Demand

Response

Resource

Energy Economic day-

ahead

Reliability real-

time

Bids into ISO

markets as

supply

Used for

reliability

purposes

Slide 90

PDR and RDRR rely on the same technical functionality and

infrastructure but have different participation options and

requirements


Characteristics


PDR provides DR load curtailment participation

comparable to supply resources

PDR can bid into the following markets:

– Energy: day-ahead and real-time

– Ancillary services: day-ahead and real-time

• Non-spinning reserve

• Spinning reserve

PDR may also:

– Submit RUC availability

– Self-provide ancillary services

• Self schedule must be = to minimum load

Slide 92


A PDR must be capable of providing measurable and

verifiable load curtailment with characteristics of supply

Minimum load curtailment ≥ 100kW for energy

Minimum load curtailment ≥ 500kW for AS

Smaller loads may be aggregated to achieve minimum targets

Can bid load curtailment in 10kW minimum increments

Telemetry is required for resources ≥ 10MW or participating in AS

Scheduling coordinator metered entity (SCME)

Slide 93


Telemetry requirements were slightly modified for PDR

• Current ISO tariff requirements Section 7.6.1. (d)

– Resources ≥ 10 MW

– Resources providing ancillary services

• Business practice manual for direct telemetry

– Section 6.10 exempted DRP from RIG aggregation location

limits

– Section 6.21 increased scan rates for PDR

Slide 94

Resource Type Scan Rate

Resources > 10 MW, or

AS participation at any size

2 Seconds

PDR 60 Seconds*

*not applicable for spinning reserve participation


RDRR participation options:

– Energy: day-ahead

– Offer uncommitted capacity and respond to a reliability

event for the delivery of “reliability energy” in real-time

• May elect discrete dispatch for real-time only

Slide 95

RDRR enables emergency responsive demand response

resource participation

Modeled like a supply resource relying on the functionality

and infrastructure designed for PDR

RDRR may not:

– Submit RUC availability or ancillary service bids

– Self-provide ancillary services


A RDRR must be capable of providing measurable and

verifiable load curtailment with similar characteristics of

supply

Minimum load curtailment ≥ 500kW

Smaller loads may be aggregated to achieve minimum targets

Can bid load curtailment in 10kW minimum increments

Telemetry is not required

Scheduling coordinator metered entity (SCME)

Slide 96


Additional RDRR resource specific characteristics

created for real time reliability participation

Must be capable of delivering reliability energy in real-time, reaching full curtailment within 40 minutes

May elect to receive discrete dispatches in real-time, under this option

-Size limited to 50MW

-Cannot participate in day-ahead market

Minimum run time cannot be greater than one (1) hour

Must have sustained response period or maximum run time of at least four (4) hours

Slide 97


RDRR may elect to be discretely dispatched when

participating in real-time

Discrete dispatch provides “block” non-marginal dispatching

Figure illustrates discrete dispatches

10 MW Underlying LoadRDRR, PMax = 8 MW

MW

10

0

2

Firm service level

6MW

4MW

6 MW

3 MW

HE12 HE 13 HE 14 HE 15 HE 16 HE 17

Hour Ending

Load Profile

66MW


RDRR has specific participation expectations

RDRRs are not required to participate economically therefore

day-ahead market participation is optional

Slide 99

All uncommitted RDRR capacity must be offered as energy in

the real-time market

•Bids between $950 - $1000/MWo 95% -100% bid price cap

•Used for reliability-only purposes

RDRRs electing discrete dispatch submits single-segment bids

• Must do so for entire term

• Must register in master file o Discrete dispatch

o Pmin value = 0MW

o Minimum load cost compensation = $0


RDRR terms enable the participation of both seasonal &

annual DR programs and in establishing availability limits

A term is a defined 6 month period

• Must be available for up to 15 events and/or 48 hours per

term

• Economic participation in the day-ahead market will not

reduce availability limits

• Availability standards apply for RDRR identified as

resource adequacy resources

Slide 100

Summer 2015 6/1/2015 9/30/2015

Winter 2015 10/1/2015 5/31/2016


RDRR can be used in real-time for system emergencies

• ISO system emergencies in accordance with OP #4420

oTransmission emergencies on ISO controlled grid

oMitigating imminent operating reserve deficiencies

Slide 101

• Resolving local transmission and distribution system

emergencies by participating transmission owners (PTOs)

During Alerts Warning Emergency AWE Warning Stage:

1. Issue Flex Alert

2. Exhaust available resources (except Spin/Non-Spin)

3. Reduce Participating Pump Load

4. Dispatch any unloaded gen capacity

5. Dispatch Spin/Non-Spin

6. Dispatch RMR

7. Dispatch PTO DRs and RDRRs8. Canvas external entities for assistance


Example of RDRR real-time participation steps

SC submits bids between

$950 -$1000/MW

The ISO has a system or

local emergency

RDRR bids are added to the bid pool

Resources are

economically dispatched…

And settled like

generation

Slide 102


RDRR specific participation expectations include

periodic performance testing

• One unannounced test dispatch per year to ensure

availability and performance of resource

• Test events will count toward RDRR availability limit of

15 events and/or 48 hours per term

• Test events instructed through exceptional dispatch and

settled as test energy

Slide 103


Unlike traditional generation, demand response resources are

comprised of an aggregation of locations, aka “sub-resources”,

potentially geographically disbursed, to meet minimum

participation capacity requirements.

Aggregations are therefore permissible:

Slide 104

PDR and RDRR aggregation requirements have been

established

Across multiple

pricing nodes

Within the same ISO defined sub-LAP

Within the same ISO defined Sub

Lap

With the same

load serving entity


PDR_1 = ISO Resource

Sub-LAP 1

LSE1

PNode

A

Trans

Substation

DistributionTransmission

PNode

B

Trans

Substation

Utility

Meter

UM

UM

Substation

UM UM

PDR/RDRR aggregation illustration

Substation

UM

Slide 103


Each PDR and RDRR and their underlying locations are

required to be within a single sub-LAP

106

Ensures demand response resource dispatch does not create

additional congestion

• A sub-LAP is an ISO-defined

subset of pricing nodes

(PNodes) within a default LAP

• 24 sub-LAPs were created to

reflect major transmission

constraints within each utility

service territory (DLAP)

Slide 106


Each PDR and RDRR and their underlying locations are

required to be served by a single LSE

107

• Provides visibility of DR awards to LSEs

• Ensures ability to identify individual

default load adjustment (DLA)

contribution of LSE specific location

performance

Sub-LAP

LSE1 LSE2 LSE2D

R

1

D

R

2

D

R

3

DRP

SC

ISO

Slide 107


Resource aggregations of 10 MW and above and those

providing ancillary services require telemetry.

Ensures visibility for real-time operation of the grid and

compliance to mandatory and enforceable NERC and WECC

approved reliability standards.

• RDRR does not require telemetry

• Telemetry must be provided for the aggregate resource

• A single remote intelligent gateway (RIG) can represent

multiple DR resources

Slide 108


PDR and RDRR are modeled as a generator

Slide 109

30 %

60 % 10 %

30 %

70 %

Pre-defined in sub-LAP

• Pre-modeled and pre-assigned a

generation distribution factor

(GDF ) by the CAISO

Custom in sub-LAP

• DRP customizes the resource

modeled by selecting buses and

defining the GDF to the buses

selected


Demand response systems support pre and post market

activities required for PDR/RDRR

• Manage registration process

o track underlying load locations and aggregated locations (ALOC)

• Consolidated events

o outages, awards, dispatches

• Meter data management

• Automated calculations

o Baseline

o Performance measurement

Slide 110


Questions before break?

Slide 111


Demand resource pre-market activities

Secure agreements

Obtain system access

Register

Obtain Market Resource ID


day-ahead

real time

Market

Settlement

Post-Market Activities

Pre-market activities are required to prepare PDR and

RDRR for market participation

Secure Agreements

Access DRS

Demand Response

System

Meter data

submission

Pre-Market Activities

Baseline

Calculation

7 minimum to

265 maximum BDApproximately 30

BD

Slide 113

Registration Process

Begin:

Provide end use load

location information

End:

Receive Market

Resource ID


Demand response providers must secure agreements for

wholesale participation

A DRP must:

• Have an agreement with the load serving entity (LSE) who

serves the demand responsive load

• Have an agreement with the utility distribution company

(UDC) who distributes the energy to the demand response

locations

• Execute a demand response provider agreement (DRPA)

with the ISO

• Become a SC or obtain the services of an SC

Slide 114


Once the DRP receives an ID they must obtain system

access to begin the registration process

Slide 115

System access requires authorization and a digital certificate

o Application access request form AARF submitted

o DRS and DRRS certificates received

o System access verified

DRP begins registration process prior to obtaining a PDR or

RDRR resource ID


Registration provides visibility and auditability of

aggregated participation to multiple entities.

Record location and create aggregate location (ALOC)

• Service Account Number (SAN) primary key

• Validationso duplication check across DRP locations and across ALOCs

o Completeness

o Aggregation consistency

LSE/UDC/ISO registration review

• 10 days to review registration, ALOC and locations

Create resource and confirm

• Resource ID provided

• Resource data template submitted

• Master file updated


Once registration is reviewed without comment by

LSE/UDC the ISO provides DRP with a resource ID

• DRP submits a completed ISO generator resource data

template (GRDT) providing resource specific

characteristics

• Registration is confirmed when resource modeling process

is completed and resource ID is effective in master file

• Changes to registration may require re-processing

o Market participation on hold

o Resource ID can remain associated to it

Slide 117


Market participation

Bidding

Dispatch

Outage Management


Meter data

submission

Day-ahead

Real- time

Markets

-Bidding

-Dispatch

-Outage

Management

Market

Settlement


PDR and RDRR participate in the market as a supply

resource

Secure Agreements


Baseline

Calculation

Slide 119

Registration Process


Scheduling Coordinator submit bids to ISO’s Scheduling

Infrastructure Business Rules system (SIBR)

Reliability real-time energy bids – w/discrete dispatch option

Economic day-ahead energy bids

Economic real-time energy bids

Day-ahead and real-time self provision of AS including self schedule

AS non-spin and spin capacity and real-time energy bids

Residual unit commitment capacity bids

PDR

RDRR

Slide 120


Master file and SIBR enforce bidding rules for PDR

and RDRR

• Types of bids

• Day-ahead and real-time bidding options

– single-segment vs multi-segment

– reliability vs economic

• Minimum load curtailment requirements

• etc.

Slide 121

RDRR SIBR bidding rule example:

No self-schedule bids in day-ahead and real-time markets


PDR and RDRR will receive and must respond to

awards and dispatches from the ISO

Customer Market Results Interface (CMRI)

• SCs retrieve proprietary market results

• Day-ahead energy schedules, AS awards, and RUC awards

Automated Dispatch System (ADS)

• Resource instructions sent to authorized users

• No opportunity to accept or decline the instruction

• Review within 90 seconds then begin ramping to instructed MW

Slide 122

Note: RDRRs with day-ahead schedules and remaining capacity in

real-time will not receive dispatch until operational conditions exist

such that the resource is activated in the market.


Scheduling Coordinators interface with the outage

management system (OMS) for PDR and RDRR

OMS is used to

• Provide resource

availability to the ISO

• Exclude days from the

baseline calculation for the

resource

Slide 123

PDR and RDRR are all-or-nothing resources

• OMS outages no longer require cause codes

• PMax derates must be = 0 MW



Meter Data Submission

Baseline Methodology

Settlement


Meter data

submission

• Historic meter

data

• Day of event

meter data

Market Post-Market Activities

PDR and RDRR participate in the market as a supply

resource

Secure

Agreements


Baseline

Calculation

• Performance

measurement

• Default load

adjustment

Slide 125

Registration

Process

day-ahead

real time

T+ 8B

T+ 48B

T+168- 172B

T+ 3B

T+ 12B

T+ 55B

T+ 9Month

Settlement

SC DRP

• PDR/RDRR

performance

SC LSE

• Default Load

Adjustment

trade

date = T


Post market functions performed in the DRS include

meter data submission and performance measurement

calculations

Upload & download meter data

Evaluate compliance and event information

Calculate & download customer baseline

information

Calculate & download demand response

energy measurement

Slide 126


PDRs and RDRRs are Scheduling Coordinator

Metered Entities

• Settlement Quality Meter Data (SQMD) submitted to the

demand response system DRS

• Submitted as an aggregation at the resource level

representing SQMD for all underlying load locations

• Used to establish a customer baseline and calculate the

performance of the resource

• Used to calculate meter before / meter after to determine

ancillary services performance

Slide 127


PDR and RDRR performance measurement and

verification is calculated using a standard baseline type

and methodology

• Customer baseline calculation based on a 10-in-10

methodology with a bi-directional morning adjustment

capped at 20%

• If approved by the ISO, a DRP may use a different

methodology for deriving DR energy measurement

– Conform to North American Energy Standards Board

(NAESB) baseline type I or II

– Will require FERC approval of tariff amendment

• “Hourly Gen” choice in DRS to accommodate this

option

Slide 128


A customer baseline is an average performance

measurement of DR when the resource is in a “non-

event” state

• Events are defined as anything that would change the

performance output of a resource

o OMS outage

o Day-ahead schedule

o Real-time dispatch

o Capacity award

• Requires sufficient historic meter data

– 45 calendar days of historical data is suggested

Slide 129


First step in developing the baseline is to select the

most recent similar non-event days for that resource

SUN MON TUES WED THUR FRI SAT

1 2 3 4 5

6 7 8 9 10 11 12

13 14 15 16 17 18 19

20 21 22 23 24 25 26

27 28 29 30

SUN MON TUES WED THUR FRI SAT

1

2 3 4 5 6 7 8

9 10 11 12 13 14 15

16 17 18 19 20 21 22

23 24 25 26 27 28 29

30 31

May 2010 June 2010

14.75

E

6.75

WE

6.75

WE15.50

NE

14.20

E

14.50

NE13.85

E13.75

NE

8.75

WE

6.25

WE

15.00

WE

14.80

WE

14.00

E14.75

NE

14.00

NE

13.75

NE

15.75

H

15.75

NE15.25

NE

15.50

NE

14.75

NE

13.75

NE

8.75

WE

14.75

E

6.75

WE

6.75

WE15.50

NE

14.20

E14.50

NE

13.85

E

15.00

WE

15.75

NE15.25

NE

15.50

NE

14.75

NE

13.75

NE

8.75

WE

14.75

E

6.75

WE

6.75

WE15.50

NE

14.20

E14.50

NE

13.85

E

15.00

WE

NE = Non-Event Day

E = Event Day

WE = Weekend

H = Holiday

Resource awarded or dispatched for trade date 6/15 HE 16

Slide 130


Raw baseline is calculated using simple average of

ten similar non-event days using most recent days

prior to the resource award or dispatch

Date Type Event HE 16 Meter Value

5/25/2010 Weekday N 14.75

5/26/2010 Weekday N 15.50

5/27/2010 Weekday N 15.25

5/28/2010 Weekday N 15.75

6/1/2010 Weekday N 13.75

6/2/2010 Weekday N 14.00

6/3/2010 Weekday N 14.75

6/7/2010 Weekday N 13.75

6/8/2010 Weekday N 15.50

6/10/2010 Weekday N 14.50

Total 147.5

Average for Baseline 14.75

Trade Date (TD) = 6/15/10

Hour Ending (HE) = 16

• Raw customer

baseline = 14.75

Slide 131


A load point adjustment (morning adjustment) ratio is

applied to the raw customer baseline once per day for

each hourly event

Load 6/15/10

Meter Data

Raw

Baseline

HE12 13.00 14.00

HE13 12.50 14.20

HE14 14.75 15.50

Average 13.42 14.57

Load Point Adjustment = 13.42 / 14.57

= .9210 or 92.10%

• load point adjustment will use 0.9210 multiplier against raw

customer baseline to establish adjusted customer baselineSlide 132

Trade Date (TD) = 6/15/10

Hour Ending (HE) = 16


Adjustment of raw customer baseline provides a more

accurate representation of how the load is behaving on

the day it is dispatched

• Load point adjustment factors in actual performance

conditions of the trade date including weather-related or

other conditions that would affect the performance

Raw

Customer

Baseline

Load Point

Adjustment

Adjusted

Customer

Baseline

Meter Load

(6/15/10 –

HE16 )

Demand Response

Energy Measurement

14.75 X 0.92 = 13.57 - 12.42 = 1.15 MWH

Slide 133

Example: Trade Date (TD) = 6/15/10, Hour Ending (HE) = 16


A demand response energy measurement is the energy

quantity calculated by comparing the adjusted customer

baseline against its actual underlying load

Raw Customer Baseline

Noon 18:0006:00

Metered Load

Adjusted Customer Baseline

Using Load Point Adjustment

Demand Response Energy Measurement

Slide 134


Demand response provider

PDR and RDRR performance settlement

Load Serving Entity

Default Load Adjustment (DLA)

Settlements


PDR and RDRR are included as generation in the day-

ahead and real-time energy settlement calculations

Example 1: Perfect performance

Energy settlement with no uninstructed imbalance energy

Example 2: Over performance

Energy settlement with uninstructed imbalance energy

Example 3: Did not fully meet performance

Energy settlement with negative uninstructed imbalance energy

Example 4: Non Performance (no curtailment)

Energy settlement when there is zero performance

o A DR energy measurement < 0 MW will be set to 0

Slide 136


PDRs receive AS and RUC capacity payment subject to

no pay compliance when participating in those services

AS no pay

– Undelivered

– Unavailable

– Undispatchable

RUC no pay

– Undispatchable

– Undelivered

– Ineligible

Slide 137


Unique settlement rules for demand response may

impact the LSE for the PDR or RDRR

• FERC Order 745 required the ISO to implement a net

benefits test (NBT)

• NBT establishes a price threshold above which demand

response resource bids are deemed cost effective

• The NBT price is compared against the real-time dispatch

LMP to determine if a DLA might be applicable

Slide 138

LSE’s for PDR or RDRR resources that have DR energy

measurement when the real-time dispatch LMP is below

the NBT are subject to a default load adjustment


On a monthly basis the NBT threshold price is

established

Slide 139

Year Month Peak Type Threshold Price

2015 April ON PEAK $34.52

2015 April OFF PEAK $34.79

• When applicable, a DLA will be used to adjust the metered

load used in uninstructed imbalance energy UIE settlement

of the LSE’s default LAP

• This quantity represents the total DR energy measurement

delivered by all resources served by that LSE that do not

meet the real-time NBT


Questions?

Slide 140


Non-generator resource functionality in

the ISO wholesale markets

Non-Generator Resources and Regulation Energy Management


Topics

• Background and purpose

• Terms and acronyms

• Modeling and market participation

• Pre market processes

• Post market process

• Aggregation

Slide 142


Background and purpose


NGR background and purpose

• In 2010, the ISO began an effort to revise its tariff to treat non-

generator resources on a comparable basis with conventional

generators

• In 2011, FERC approved tariff changes to facilitate non-generator

resources providing ancillary services.

– Reduced the minimum rated capacity requirement

– Reduced minimum continuous energy requirement

– Clarified that ‘Continuous Measurement’ begins once resource reaches

the awarded energy output, not at the end of 10 minute ramp

requirement

• In 2012, the ISO implemented non-generator resource functionality

within the wholesale markets

Slide 144


REM background and purpose

• Within the non-generator tariff framework, the ISO also

developed additional functionality for resources providing

regulation services called Regulation Energy

Management, or REM

• Regulation Energy Management was implemented to

remove barriers that limit the full participation of limited

energy resources in the ISO’s regulation markets

Slide 145


Terms and acronyms


Terms and acronyms

NGR – Non Generator Resource

– A new ISO resource type and model for energy

constrained resources that can operate continuously

between generation and load

REM – Regulation Energy Management

– An option for non generator resources that only

provide regulation services to the ISO

Slide 147


Terms and acronyms

Capacity (MW)

– Represents the potential to inject or withdraw energy

at a sustainable rate

Energy (MWh)

– Represents the amount of capacity used over time

SOC - State of Charge (MWh)

– The amount of energy (MWh) remaining in the

resource available for ISO participation

Slide 148


Non-generator resource

characteristics


Non-generator resource characteristics

• NGRs are modeled as a generator with positive and

negative energy

• NGRs are constrained by an upper and lower capacity

(MW) limit to inject or withdraw energy at a sustainable

rate

• NGRs are constrained by an energy (MWh) limit to inject

or withdraw energy on a continuous basis

Slide 150


Non-generator resource characteristics

• NGRs can be dispatched seamlessly within their entire

capacity range subject their available energy (SOC)

• NGRs may be made up of aggregated physical

resources as long as they meet modeling and

participation requirements

• Any resource with a MWh constraint that can be

seamlessly moved within its operational range can use

this functionality

Slide 151


Example of NGR performance

Slide 152


NGR modeling


The ISO non-generator resource model recognizes a

resource can move seamlessly from load to generation

Slide 154

0 MW

20 MW

- 20 MW

NGR Generation Load

Ram

p


NGR modeling and market participation

• NGR resources can be modeled from positive to

negative

– Minimum capacity is negative while maximum capacity is

positive

– Provides the ability to maintain continuous operation for energy

constrained resources

• NGR resources can be modeled on the positive side

– Minimum and maximum capacity is positive

• NGR resources can be modeled on the negative side

– Minimum and maximum capacity is negative

Slide 155


How capacity is used in the NGR model

Capacity parameters are used to determine appropriate

bidding ranges and dispatch targets for the resource by the

ISO Market and EMS

• Maximum Capacity(MW)

– Represents the resource’s maximum potential to inject or withdraw

energy at a sustainable rate

• Minimum Capacity (MW)

– Represents the resource’s minimum potential to inject or withdraw

energy at a sustainable rate

• Maximum capacity is greater than minimum capacity

Slide 156


How energy is used within the NGR model

Energy (MWh) parameters are used to keep ISO market

dispatches and regulation control signals within the

resource’s energy capability range

• Maximum Energy (MWh)

– Represents the maximum amount of energy the resource can provide

• Minimum Energy (MWh)

– Represents the minimum amount of energy the resource can store

• Instantaneous State Of Charge (MWh)

– Represents the amount of energy (MWh) remaining in the resource

Slide 157


How energy is used within the NGR model

• The ISO will use energy limits and SOC values to co-

optimize the NGR resource over multiple intervals in the

ISO markets

• The ISO will determine the best utilization of the

resource based on its submitted energy schedules or

regulation ranges

• The ISO will use SOC values to prevent infeasible

dispatches or control signals

• If these values are not provided, the resource may be

given an infeasible dispatch and subject to non

performance settlements charges

Slide 158


Example: 40 MW 10 MWh NGR

15 Minute Resource at Max Capacity

Slide 159

Time (Minutes)

MW MWh

+40

30 60

10

0-40

0 15 45

Gen SOC


NGR market participation


The ISO has created opportunities for the full

participation of energy storage resources in the day

ahead and real time wholesale market

Non-Generator Resource

(NGR) model

Slide 161

Energy

Regulation up

Regulation down

Spinning Reserve

Non-spinning reserve

Market

Products



• NGR must meet minimum capacity and continuous

energy requirements

– 0.5 MW - Minimum Capacity

– 60 Minutes - Day-ahead regulation up/down

– 30 Minutes - Real-time regulation up/down

– 30 Minutes - Spin and Non-Spin

• Telemetry is required for providing NGR SOC information

to the ISO energy management and market systems

Slide 162



• Optimal energy schedule and ancillary services awards

are based on the energy bid curve and ancillary service

bids

• In the day ahead and real time markets

– Energy schedule and ancillary service awards are co-optimized

subject to:

• Capacity constraints

• Ramping constraints

• State of charge constraints, subject to resource charge/discharge

efficiency rate

Slide 163


NGR certified capacity

NGR Resource: 40 MW - 10 MWh (4 - 15 min. intervals in hour)

Pmax = 40 MW, Pmin = -40 MW. Ramp rate = 10 MW/min

Slide 164

Service Capacity NGR MW

Regulation Up 10 MW (60 Min Day-Ahead)

Regulation Down 10 MW (60 Min Day-Ahead)

Spinning 20 MW (30 Min)

Non-Spinning 20 MW (30 Min)

Pmax / Maximum Capacity 40 MW

Pmin / Minimum Capacity -40 MW


50% AGC optimization

• A feature specific to NGR that will level the resource’s

state of charge at a midpoint that maximizes continuous

energy output

• The 50% value is determined from regulation ranges

awarded by the ISO and evaluated every 15 minutes

• The option is set by a resource flag in the ISO system at

the time of resource modeling

• Due to reliability needs of the overall system, the ISO

can not guarantee the 50% AGC optimization when the

system in not in balance

Slide 165


• Day-ahead market

– The day-ahead market SOC for a NGR is determined

by the prior day’s day-ahead schedules at the end of

the day

– The initial SOC is defaulted to 50% of the maximum

defined energy limit if there are no previous day-

ahead schedules

• Real-time market

– The ISO real-time market receives the actual

resource SOC provided through telemetry

Slide 166

Determining state of charge (SOC)


Regulation energy management


NGR characteristics specific to REM

• NGR resources using REM only participate in the ISO

regulation markets

• The regulation capacity awarded in the day ahead

market is evaluated as 4 times the regulation energy it

can provide within 15 minutes

• Regulation up and regulation down must meet a 15

minute continuous energy requirement

• REM resources must provide energy limits and real time

SOC values

Slide 168


REM provides additional functionality to address

limitations of MWh constrained energy resources

Slide 169

Example: 20 MW / 5 MWh limited energy resource

Green – Generator/NGR requirement

Yellow – NGR under regulation energy management

0 MW

20 MW

15 MW

10 MW

5 MW

Minutes

15 30 45 60

Regulation Up


REM energy offset

• NGR resources providing regulation under the REM

option will be optimized through the use of an energy

offset (sale/purchase) of energy in the real-time market

• The energy offset allows NGRs under REM to meet the

continuous energy requirements for regulation and

ensures that those resources will remain available to

provide regulation service during intervals when it is

needed

Slide 170


NGR REM market participation

• Optimal regulation awards are based on the regulation

bids (no energy schedule for REM)

• In the day-ahead and real-time market

– Regulation awards are co-optimized subject to:

• Capacity constraints

• Ramping constraints

• In the real-time market

– Regulation awards are co-optimized subject to:

• State of Charge constraints

• Resource charge/discharge efficiency rate

Slide 171


Comparison of NGR and REM certified

capacity

Resource: 40 MW/10 MWh (4 - 15 min. intervals in hour)

Pmax = 40 MW, Pmin = -40 MW. Ramp rate = 10 MW/min

Slide 172

Service NGR MW REM MW

Regulation Up 10 MW (60 Min DA) 40 MW

Regulation Down 10 MW (60 Min DA) 40 MW

Spinning 20 MW (30 Min) n/a

Non-Spinning 20 MW (30 Min) n/a

Pmax 40 MW 40 MW

Pmin -40 MW -40 MW


Comparison of NGR and NGR with REM

Slide 173

NGR NGR - REM

Energy, Spin, Non Spin, and

Regulation Up/Down

Regulation Up/Down only

Managed through energy

schedules to maintain SOC

No energy schedules used

30-60 minute continuous energy

requirements

15 minute continuous energy

requirement for regulation service

Day-ahead AS capacity value is

based on 60 minute energy

requirement

Day-ahead AS capacity value is 4

times the regulation energy it can

provide in 15 minutes

Co-optimized in day-ahead and

real-time market subject to SOC

constraints

Co-optimized in real-time market

subject to SOC constraints


Questions before break?

Slide 174


NGR bidding rules


Bidding rules

Bid components specific to NGR and NGR REM

• Upper Charge Limit (MWh)

– Highest stored energy that should be maintained in the device.

Cannot be higher than the maximum energy limit value

registered in the master file.

• Lower Charge Limit (MWh)

– Lowest stored energy that should be maintained in the device.

Cannot be lower than the minimum energy limit value registered

in the master file.

Slide 176


Bidding rules

Bid components for NGR but not NGR REM

• Energy bid curve

• Self schedule

• Spinning and non-spinning reserves

• Contingency dispatch

Slide 177


Bidding rules

Bid components that do not apply to NGR and

NGR REM

• Start-up costs

• Minimum load costs

• Transition cost

• Daily energy limits (not upper/lower charge limit)

• Self provision of AS (excluding regulation)

Slide 178


Pre market activities


• The ISO uses existing business processes and

agreements to interconnect and model NGR resources

• Interconnection Agreements

– Participating generator agreement (PGA)

– Participating load agreement (PLA)

– Metered entity service agreement (MSA)

• ISO new resource implementation (NRI) process

– Resource data template (RDT)

– Network modeling

– Metering and telemetry

– Scheduling Coordinator

– Resource certification

Slide 180

Participation requirements


• Required telemetry points for observing capacity and

energy constraints

– Maximum Operating Limit (MW)

– Minimum Operating Limit (MW)

– Resource Connectivity Status (On/Off)

– Resource Instantaneous Output (MW)

– Instantaneous State Of Charge (SOC) (MWh)

– Resource AGC Control Status (On/Off)

Slide 181

Automatic generator control parameters -

EMS


EMS parameters for AGC operational control

Maximum

Capacity

Operating

Limit

(Real Time)Certified

Regulation

Limit

0

Slide 183


NGR post market activities


NGR

• Energy is settled at the locational marginal price in the day-ahead

and real-time market

• Procured AS capacity is settled in day-ahead and real-time market

NGR REM

• Procured regulation capacity is settled in the day-ahead and real-

time market

• Regulation energy dispatched through AGC is settled at the real-

time LMP

• Regulation energy produced or consumed outside of AGC is settled

at the real-time LMP as Uninstructed Imbalance Energy (UIE) or

another Instructed Imbalance Energy (IIE) type.

Slide 184

NGR post market


• NGR and NGR REM are subject to all existing

categories for rescission of AS capacity payments at the

relevant locational marginal day-ahead and real-time

market prices

• Energy is calculated based on the difference between

energy MW values

– If operating at -3MW and dispatched to 7MW, energy = 10MW

• NGR resources are eligible for regulation mileage

payments in addition to capacity payments

Slide 185

NGR post market


Round trip efficiency treatment of storage /

NGR resources

• The ISO does not consider NGR resources in the

charging mode as “consuming” energy, but rather storing

energy for later resale in the ISO’s markets

• Round trip efficiency (RTE) losses will be captured at the

resource level in the wholesale transaction.

– It is expected that the resource will require more energy from the

grid than it will generate

– These differences are accurately captured in the metered

settlement between the resource’s SC and the ISO

Slide 186


Rate treatment for energy storage

Slide 187

Energy Settlement

Price

TAC

Allocation

Measured Demand

Uplifts

Positive

Generation

(Discharge

Mode)

LMP No No

Negative

Generation

(Storage Mode)

LMP No No


Non-generator resource aggregations

Non-Generator resources and Regulation Energy Management


• An NGR made up of multiple physical sub-resources is

allowable under a single pricing node

• Aggregations are subject to metering, telemetry, and

modeling requirements

• NGR aggregations at a distribution level interconnection

for wholesale participation will be subject to distribution

interconnection requirements

Slide 189

NGR aggregations are possible at a

wholesale level subject to requirements


ISO

Resource

ISO sub-LAP 1

PNode

1

Transmission

Substation


Single ISO Resource

2 ISOME Aggregated within single sub-LAP and PNode

ISO Interconnection

Telemetry at ISO Resource Level

Transmission Aggregation

ISO M

ISO M

Reso

urc

e M

anager

ISO

Telemetry

Slide 190


ISO SubLAP 1

PNode

1

Transmission

Substation


Single ISO Resource

2 ISOME Aggregated with single SubLAP and PNode

WDAT Utility Interconnection

Telemetry at ISO Resource and PNode Level

Utility Distribution Aggregation

ISO Resource

ISO M

Reso

urc

e M

anager

ISO M

ISO

Telemetry


ISO Resource

Slide 192

ISO sub-LAP 1

PNode

1

Transmission

Sub-station


Resource Manager

Utility

Facility

Meter

Single ISO Resource

3 ISOME Aggregation

*WDAT Utility Interconnection


DER Aggregation*

Distribution

Sub-station

ISO

Telemetry

ISO M ISO M ISO M


ISO Resource

ISO sub-LAP 1

PNode

1

Transmission

Sub-station


Single ISO Resource

4 ISOME Aggregation

*WDAT Utility Interconnection


DER Aggregation*

ISO M

ISO

Telemetry

I M I M I M

Fleet Manager

Utility

Meter

Distribution

Sub-station

Resourc

e M

anager

Slide 192


Questions?

Slide 194


Procurement and resource adequacy

Forward procurement of capacity resources


Overview

• Forward procurement

– Long-Term Procurement Plan (LTPP) – 10 years

forward

– Flexible Resource Adequacy Criteria and Must Offer

Obligation (FRACMOO) and Resource Adequacy

flexible capacity – 1 year ahead and 1 month ahead

• ISO day-ahead and real-time markets

– Flexible ramping

Slide 196


The CPUC authorizes the need for new capacity to

address system needs in LTPP

• LTPP review the system need for new capacity

• Historically, LTPP focused on the ability to meet system

peak

• Current LTPP (R.13-12-010) reviewing the need for new

capacity to meet

– All system load

• Peak load

• Off-peak load

– Flexibility needs

• Ramping

• Over generation

Slide 197


Load serving entities are required to demonstrate

adequate system, local and flexible capacity has been

procured

• Year-ahead and month-ahead demonstrations

• System and local capacity measurements based on resource

discharge capabilities that are deliverable for four hours

during peak

• Flexible capacity uses a single metric measured over three

hours targeted to address multiple flexible capacity needs*

– Longer sustained ramps

– Load following

• Non generator resources may provide flexible capacity for

charge and discharge cycles

* Currently interim, development of a permanent product is underwaySlide 198


RA flexible capacity categories enable a portion of

flexible capacity needs to be provided by preferred

resources that have limited availability

Slide 199

Category 1 (Base Flexibility): Set at level of the largest secondary 3-hour net-load ramp

(Secondary Ramp)

Category 2 (Peak Flexibility): Set at difference between largest secondary 3-hour net-load ramp

and 95% of maximum 3-hour net-load ramp ((0.95*Primary Ramp)-Secondary Ramp)

Category 3 (Super-Peak Flexibility): Set at 5% of maximum 3-hour net-load ramp (0.05*Primary

Ramp)


Must offer obligations associated with each category of

flexible capacity

Parameter Category 1 (Base Ramping) Category 2 (Peak

Ramping)

Category 3 (Super-Peak

Ramping)

Economic Bid

Must-Offer

Obligation

5:00 a.m. – 10:00 p.m. 5 hour block (determined

seasonally)

5 hour block (determined

seasonally)

Energy

Requirement

Minimum 6 hours at EFC Minimum 3 hours at EFC Minimum 3 hours at EFC

Daily Availability 7 days/week 7 days/week Non-holiday weekdays

Daily Start-Up

Capability

The minimum of two starts

per day or the number of

starts allowed by minimum up

and down time

At least one start per day At least one start per day

Examples of

resource Types that

Could Qualify for

Category

Conventional gas fired

resources, wind resources

hydro resources, and storage

resources with long discharge

capabilities

Use-limited conventional

gas fired resources, solar

resources and conventional

gas fired peaking resources

Short discharge battery

resources providing

regulation and demand

response resources

Slide 200


Other efforts and challenges


The ISO will examine many new provisions for flexible

capacity in the reliability services initiative

• Durable flexible capacity product and studies

– Potential changes to the existing flexible capacity

product

– Need for ramping capabilities for time intervals less

than three hours (i.e. five minute, 15 minute,1 hour)

– Identify system needs and capacity products to

address downward ramping and over-generation

– Continued assessment of current effective flexible

capacity values and Pmin

• Replacement and substitution rules for flexible capacity

resources on outage

Slide 202


Reliability services initiative – continued

• This initiative is targeted to launch in late April

• In the meantime, background information on this subject

is available at

– http://www.caiso.com/informed/Pages/StakeholderPro

cesses/FlexibleResourceAdequacyCriteria-

MustOfferObligations.aspx

– http://www.caiso.com/informed/Pages/StakeholderPro

cesses/ReliabilityServices.aspx

Slide 203

http://www.caiso.com/informed/Pages/StakeholderProcesses/ReliabilityServices.aspx

http://www.caiso.com/informed/Pages/StakeholderProcesses/ReliabilityServices.aspx


Flexible ramping product ensures sufficient ramping

capability is available in 5-minute market

• Secures ramping capability in the fifteen-minute market

and real-time dispatch

• Accounts for upward and downward ramping needs

• Compensates resource whose dispatch is held back in

financially binding interval to meet future ramping needs

• Only procures ramping capability for uncertainty when

expected value greater than cost

• Allocates costs to resource 5-minute movements (load,

supply, interties) that drive ramping need

Slide 204


Flexible ramping product ensures movement in net

system demand between intervals met economically

Market Forecast

Upper limit

Lower limit

Net system demand at t

t+5 (advisory interval)t (binding interval) Time

Net system demand

Minimum

requirement

Demand curve

Slide 205

Demand curve


Flexible ramping product – continued

• More information is available at

http://www.caiso.com/informed/Pages/StakeholderProcesses/

FlexibleRampingProduct.aspx

Slide 206

http://www.caiso.com/informed/Pages/StakeholderProcesses/FlexibleRampingProduct.aspx


Questions?

Slide 207


The ISO is proposing a framework for aggregation of

DER in the expanding metering & telemetry options

initiative

• Currently, the ISO tariff may not offer a clear platform for

these resources to participate in ISO markets.

• Allows a DERP to aggregate sub-resources within a sub

load aggregation point (sub-LAP) to meet the ISO’s

minimal resource participation requirements.

• Allows for multi-location or single-location aggregations

of less than 10 MW in aggregated capacity.

• Proposes the concept of a Distributed Energy Resource

Provider (DERP) as a new market participant.

Slide 208


DERP proposal (continued)

• Enables a DERP to aggregate sub-resources at different

pricing nodes within a sub load aggregation point (sub-

LAP)

• Enables a DERP to represent those sub-resources as a

single market resource located at a custom load

aggregation point (Custom LAP) DER represented by

DERP will be scheduling coordinator metered entities

(SCME) under the ISO tariff

• Allows DER to rely on data concentration services to

interact with the ISO through one point of contact

Slide 209


DERP proposal (continued)

• Straw proposal posted November 10, 2014

• Revised straw proposal to be posted in April/May

timeframe

– Targeting July board meeting for approval

• More information is available at

http://www.caiso.com/informed/Pages/StakeholderProce

sses/ExpandingMetering-TelemetryOptions.aspx

Slide 210

http://www.caiso.com/informed/Pages/StakeholderProcesses/ExpandingMetering-TelemetryOptions.aspx


Questions?

Slide 211


Multiple use applications of a storage

resource or an aggregated

distributed energy resource


Multiple-use applications – overview

• In a “multiple-use” scenario, the resource:

– provides service to multiple entities, and

– is compensated through multiple revenue streams.

• Stakeholders identified 3 main dual-use scenarios in the

2014 energy storage roadmap process:

1) Transmission asset + market participant

2) Service provider to both transmission and

distribution systems

3) Load-management for end-use customer + market

participant

Slide 213


Multiple-use scenario 1

1. Resource serves as an approved transmission asset

and recovers a portion of its costs via Transmission

Access Charge – AND – participates in the wholesale

market and earns market revenues

• Provisions for such arrangements do not currently exist

• Previous explorations have revealed concerns:

– As transmission asset, operational control must be with ISO, but

ISO cannot operate a market resource

– A transmission asset must be approved through ISO’s TPP as

preferred solution to an identified need, but no methods exist for

assessing cost effectiveness when resource seeks only partial

cost recovery via TAC, or only defers a transmission upgrade

– Prior FERC rulings on such proposals have stated the resource

must be either a transmission asset or a market participant, but

cannot be both. Slide 214


Multiple-use scenarios 2-3

2. Resource provides services to distribution system and

participates in wholesale market

– Existing provisions for such arrangements are limited to DR

– DR resource submits outage to ISO when serving distribution

– For other DER, must address dispatch coordination between ISO

and UDC when ISO dispatch conflicts with distribution needs

– Must define settlement rules to accurately compensate resource

for dual functions

3. Resource provides load-management services to end-

use customer and participates in wholesale market

– Provisions for such arrangements do not currently exist

– Must address dispatch priorities between ISO and end-user to

prevent conflicts between ISO dispatch and end-user’s needs

– Must define settlement rules to accurately compensate resource

for service to customer and market participationSlide 215


Questions?

Slide 216


Final thoughts

• Purpose of this forum is to educate stakeholders on

existing ISO requirements, rules, market products and

models for energy storage and aggregated DER to

participate in the ISO market.

– April 16 and 23

• Stakeholder process will be used to specify and address

any needed enhancements to these existing rules.

– Launching in April/May

– Market Notice will announce start of initiative and how

to participate

Slide 217


PDR/RDRR reference material

Links to detailed information

Settlement examples


Additional PDR/RDRR reference material

Slide 219

BPM for Direct Telemetry

http://bpmcm.caiso.com/Pages/BPMDetails.aspx?BPM=Direct%20Telemetry

BPM for Metering

http://bpmcm.caiso.com/Pages/BPMDetails.aspx?BPM=Metering

Operating Procedure #4420 details ISO controlled grid emergency

http://www.caiso.com/Documents/4420.pdf

Demand Response Provider Agreement DRPA provides general terms and conditions

http://www.caiso.com/Documents/AppendixB_ProFormaAgreements_Jul1_2014.pdf

Demand response participation guide

http://www.caiso.com/Documents/DemandResponseResourceParticipationGuide.pdf

Demand response registration systems user guide, technical specifications and web service

requirements

http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=4DB9EE7B-7ECF-42E4-BE8F-

0817538FD920

Resource data template

http://www.caiso.com/Documents/GeneratorResourceDataTemplate.xls

Net Benefit Test detail information

http://www.caiso.com/informed/Pages/StakeholderProcesses/DemandResponseNetBenefitsTest.

aspx

http://bpmcm.caiso.com/Pages/BPMDetails.aspx?BPM=Direct Telemetry

http://bpmcm.caiso.com/Pages/BPMDetails.aspx?BPM=Metering

http://www.caiso.com/Documents/4420.pdf

http://www.caiso.com/Documents/AppendixB_ProFormaAgreements_Jul1_2014.pdf

http://www.caiso.com/Documents/DemandResponseResourceParticipationGuide.pdf

http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=4DB9EE7B-7ECF-42E4-BE8F-0817538FD920

http://www.caiso.com/Documents/GeneratorResourceDataTemplate.xls

http://www.caiso.com/informed/Pages/StakeholderProcesses/DemandResponseNetBenefitsTest.aspx


Examples for informational purposes only, charge code

details may not be reflected

Example 1 DRP Energy Settlement with No UIE

Example 2DRP Energy Settlement with Positive UIE

Example 3DRP Energy Settlement with Negative UIE

Example 4DRP Non Performance

Example 5LSE UIE settlement with application of Default Load Adjustment (DLA)

220


6011 = (-1) * day-ahead schedule * day-ahead LMP Price

6011 = (-1) * ( 1 MW) * $55.00 = (-$55.00)

6460 = (-1) * FMM dispatch * FMM LMP Price

6460 = (-1) * ( 0.05 MW) * $42.00 = (-$2.10)

6470 = (-1) * real-time dispatch * real-time RTD LMP Price

6470 = (-1) * (0.05 MW) * $ 45.00 = (-$2.25)

UIE = DR energy– (day-ahead schedule + FMM + RTD)

UIE = 1.10 MW – ( 1.0 MW + .05 MW + .05 MW) = 0 MW

6475 = (-1) * (UIE) * (real-time RTD LMP Price)

6475 = (-1) * ( 0 MW) * $ 45.00 = $0.00

Example 1 – PDR energy settlement with no UIEDRP SC = JBUG; Resource = NOCA_1_PDRP01 HE 15

Day-ahead schedule 1 MW

Real-time dispatch (FMM= .05 MW and RTED = .05 MW) 0.10 MW

DR energy measurement 1.10 MW

Day-ahead LMP Price $55.00

Real-time FMM LMP Price $42.00

Real-time RTD LMP Price $45.00

Total

Expected

Energy =

1.10 MW

Total Energy

Settlement =(-$55.00) + (-$2.10)

+ (-$2.25) + $0.00 =

(-$ 59.35)

payment to

DRP



6011 = (-1) * (1 MW) * $ 55.34 = (-$ 55.34)

6470 = (-1) * real-time dispatch * real-time RTD LMP Price

6470 = (-1) * ( .10 MW) * $ 72.75 = (-$7.28)

UIE = DR energy– (day-ahead schedule + real-time dispatch)

UIE = 1.15 MW – (1 MW + .10 MW) = 0.05 MW


6475 = (-1) * (0.05 MW) * $ 72.75 = (-$ 3.64)

Example 2 – PDR energy settlement with positive UIE

DRP SC = JBUG; Resource = NOCA_1_PDRP01 HE 16



DR energy measurement 1.15

Day-ahead APnode LMP Price $55.34

Real-time RTD APnode LMP Price $72.75

222

Total

Expected

Energy =

1.10 MW

Total Energy

Settlement =(-$ 55.34) + (-$7.28)

+ (-$ 3.64) =

(-$ 66.26)

payment to

DRP



6011 = (-1) * ( 1 MW) * $ 50.00 = (-$ 50.00)

6470 = (-1) * real-time dispatch* real-time RTD LMP Price

6470 = (-1) * ( 0.10 MW) * $ 60.00 = (-$ 6.00)

UIE = DR energy – (day-ahead schedule + real-time dispatch)

UIE = 0.90 MW– ( 1 MW + 0.10 MW) = - 0.20 MW


6475 = (-1) * ( -0.20 MW) * $ 60.00 = $ 12.00

Example 3 – PDR energy settlement with negative UIE




DR energy measurement 0.90



223

Total

Expected

Energy =

1.10 MW

Total

Energy

Settlement =(-$ 50.00) + (-$ 6.00)

+ $ 12.00 =

(-$ 44.00)

payment to

DRP



6011 = (-1) * ( 1 MW) * $ 50.00 = (-$ 50.00)

6470 = (-1) * real-time dispatch* real-time RTD LMP Price

6470 = (-1) * ( .10 MW) * $ 60.00 = (-$ 6.00)

UIE = DR energy– (day-ahead schedule + real-time dispatch)

UIE = 0.00 MW – ( 1 MW + .10 MW) = - 1.10 MW


6475 = (-1) * (- 1.10 MW) * $ 60.00 = $ 66.00

Example 4 – PDR energy settlement with no

performance




DR energy measurement ( -.85 set to 0.00 for settlement)

Performance = .85 load increase from adjusted baseline

0.00



224

Total

Expected

Energy =

1.10 MW

Total Energy

Settlement =(-$ 50.00) + (-$ 6.00)

+ $ 66.00 =

$ 10.00

charge to DRP


Example 5 – Determination of LSEs DLA due to

associated PDR/RDRR dispatched within their DLAP

225

Resource RTD

Interval

RTD LMP

price

NBT

met ?

DR energy

measurement (MW)

DLA Qty

(MW)

NOCA_1_PDRP01 1 $29.00 N 1.10 1.10

EBCA_1_PDRP02 1 $29.00 N 2.05 2.05

NOCA_1_PDR01 2 $35.00 Y 1.10 0

EBCA_1_PDRP02 2 $35.00 Y 2.05 0

NOCA_1_PDRP01 3 $35.00 Y 1.10 0

EBCA_1_PDRP02 3 $35.00 Y 2.05 0

NOCA_1_PDR01 4 $35.00 Y 1.00 0

EBCA_1_PDRP02 4 $35.00 Y 2.00 0

NOCA_1_PDRP01 5 $35.00 Y 1.00 0

EBCA_1_PDRP02 5 $35.00 Y 2.00 0

NOCA_1_PDR01 6 $35.00 Y 1.00 0

EBCA_1_PDRP02 6 $35.00 Y 2.00 0

PDR/RDRR Activity HE18 (intervals 1-6) NBT threshold price = $34.25

Total DLA

for interval 1

= 3.15 MW

Metered quantity used in the UIE settlement for associated LSE = NCAL


Example 5 (continued) - DLA Quantity applied to LSE

Load ID in UIE settlement

226

Metered quantity used in the UIE settlement for NORCAL_1_LD1

Resource DA

Qty

RTD

Qty

Actual metered

Qty

Total DLA

Qty

Adjusted metered

Qty

NORCAL_1_LD1 10 0 7 3.15 10.15

LSE DLAP settlement HE 18 interval 1

LSE = NCAL

DLAP Load ID = NORCAL_1_LD1 DLA for total PDR performance

UIE = DLAP (adjusted) metered load - day-ahead schedule

UIE = (-10.15) MW – (- 10 MW) = - .15 MW

6475 = (-1) * (UIE) * (hourly real-time lap price)

6475 = (-1) * ( - .15 MW) * $ 26.00** = $ 3.90

Total UIE

Settlement =

$ 3.90

Charge to LSE **Assuming hourly real-time lap price = $26.00

Where, hourly real-time lap price = the load deviation weighted average of the hourly average of the dispatch Interval

LMPs for the LAP in the relevant trading hour used for the settlement of UIE


The ISO offers comprehensive training programs

Date Training

April 20 Welcome to the ISO (webinar)

May 12 Introduction of ISO Markets (in person - Alhambra)

May 13 – 14 ISO Market Transactions (in person - Alhambra)

June 23 Settlements 101 (in person – Folsom)

June 24 Settlements 201 (in person – Folsom)

Slide 227

Training calendar - http://www.caiso.com/participate/Pages/Training/default.aspx

Contact us - [email protected]

http://www.caiso.com/participate/Pages/Training/default.aspx

mailto:[email protected]


Acronyms

Acronym Stands for

ADS Automated Dispatch System

AGC Automatic Generation Control

ALOC Aggregate Location

API Application Program Interface

AS Ancillary Services

BA Balancing Authority

BAA Balancing Authority Area

BD Business Day

BPM Business Practice Manual

CEC California Energy Commission

CFCD CAISO Forecast of CAISO Demand

Slide 228


Acronyms

Acronym Stands for

CPUC California Public Utilities Commission

DA Day-Ahead

DER Distributed Energy Resource

DLA Default Load Adjustment

DLAP Default Load Aggregation Point

DR Demand Response

DRP Demand Response Provider

DRPA Demand Response Provider Agreement

DRRS Demand Response Registration System

DRS Demand Response System

EIM Energy Imbalance Market

Slide 229


Acronyms

Acronym Stands for

FERC Federal Energy Regulatory Commission

GDF Generation Distribution Factor

GHG Greenhouse Gas

GIDAP Generation Interconnection and Deliverability Allocation Procedures

GMT Greenwich Mean Time

GRDT Generator Resource Data Template

ISOME Independent System Operator Metered Entity

LAP Load Aggregation Point

LMP Locational Marginal Price

LSE Load-Serving Entity

NAESB North American Energy Standards Board

Slide 230


Acronyms

Acronym Stands for

NBT Net Benefit Test

NERC North American Electric Reliability Corporation

NGR Non-Generator Resource

NRI New Resource Implementation

PDR Proxy Demand Resource

PG Participating Generator

PL Participating Load

POI Point of Interconnection

RA Resource Adequacy

RDRR Reliability Demand Response Resource

RDT Resource Data Template

Slide 231


Acronyms

Acronym Stands for

REM Regulation Energy Management

RIG Remote Intelligent Gateway

RT Real-Time

RUC Residual Unit Commitment

SAN Service Account Number

SC Scheduling Coordinator

SCME Scheduling Coordinator Metered Entity

SIBR Scheduling Infrastructure & Business Rules

SOC State of Charge (MWh)

SQMD Settlement Quality Meter Data

Slide 232


Acronyms

Acronym Stands for

TAC Transmission Access Charge

TPP Transmission Planning Process

UDC Utility Distribution Company

UI User Interface

UIE Uninstructed Imbalance Energy

WDAT/WDT Wholesale Distribution Access Tariff

WECC Western Electricity Coordinating Council

XML Extensible Markup Language

Slide 233

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