RDRP Stakeholder Initiative - California ISO · RDRP Stakeholder Initiative Slide 7 •RDRP Settlement Agreement Design Principles •NAESB M&V Standard •Reliability Events Data

Reliability Demand Response Product

RDRP Stakeholder InitiativeWorking Group Meeting

June 18, 2010

CAISO- Folsom, Building 101A

North/South Lake Tahoe Conference Room

INTRODUCTION

RDRP Stakeholder Initiative

Slide 2

• House Keeping• Introductions/Sign In• Agenda Review• Meeting Purpose & Goal• Milestones

Agenda- June 18, 2010

Slide 3

TIME TOPIC PRESENTER

9:30 to 9:45 Introduction John Goodin

9:45 to 10:30 Review

RDRP Design Principles

NAESB M&V Standard

Product Design Matrix

John Goodin

10:30 to 11:00 Market Monitoring Perspective

RDRP and Resource Adequacy

Eric Hildebrandt

11:00 to 12:00 Issue Review & Resolution

Registration

Qualification

Scheduling & Bidding

Notifications

Metering

Performance & Compliance

All

12:00 to 12:45 Lunch & PDR Visualization Tool Presentation Rizwaan Sahib

12:45 to 3:20 Issue Review & Resolution

Registration

Qualification


Notifications

Metering


All

3:20 to 3:30 Wrap-up & Next Steps John Goodin

Meeting Purpose & Goal

Purpose:

Resolve RDRP Design Elements in Accordance

with the Settlement Agreement Principles

Goal:

Complete Product Design Matrix so that core

product features can be sufficiently described in

the CAISO straw proposal

Slide 4

Product Milestones

Slide 5

Working Group Meetings: June 2010

Straw Proposal Published: July 2010

Draft Final Proposal Published: September 2010

Board Approval of RDRP: November 2010

FERC Filed Tariff Amendments: January 2011

FERC Approval: March 2011

Product Build: March 2011

Short-term Milestone: Straw Proposal

June 18

Working Group

Meeting

July 12

Publish Straw Proposal

August 5

Stakeholder Meeting

August 12

Straw Proposal

Comments Due*

Slide 6

* Submit comments to [email protected]

REVIEW


Slide 7

• RDRP Settlement Agreement Design Principles• NAESB M&V Standard• Reliability Events Data• Product Design Matrix

RDRP Design Principles

Compatible with IOU reliability-DR programs

Meet minimum operating requirements and technical

requirements, including max availability limits

Not “price responsive,” but economically dispatched

once available for dispatch (Op Procedure E 508B)

Underlying customers have “high strike” prices

Multi-reliability uses: system emergencies and local

transmission emergencies

Eligible to all Demand Response Providers, subject to

applicable rules of the Local Regulatory Authority

Settled through the CAISO market

Dispatchable by location and quantity

Slide 8

Demand Response Event Timing

NAESB Baseline Methodologies

Baseline Type – I

A Baseline performance evaluation methodology based on a

Demand Resource’s historical interval meter data which may also

include other variables such as weather and calendar data

Baseline Type – II

A Baseline performance evaluation methodology that uses

statistical sampling to estimate the electricity consumption of an

Aggregated Demand Resource where interval metering is not

available on the entire population

Chart from NAESB draft Retail Standards for Measurement & Verification

Slide 11

Total Reliability Events per Year

TYPE 2004 2005 2006 2007 2008 2009 2010

YTD

Transmission

Emergency6 5 0 4 0 6 0

Warning 2 2 5 3 1 2 1

Stage 1 1 1 3 1 0 0 0

Stage 2 0 2 1 0 0 0 0

Stage 3 0 0 0 0 0 0 0

Warning Issued In: MarJul

Aug

Jun

JulAug Oct Dec Jan

Used for Trans

Emergency:3 1 0 0 0 0 0

Used for System

Emergency:4 3 1 0 0 0 0

MARKET MONITORING PERSPECTIVE


Slide 12

RDRP & Resource Adequacy

Resource Adequacy Requirements and the

Reliability Demand Response Product

Eric Hildebrandt, Ph.D.

Director, Market Monitoring

Reliability Demand Response Product Working Group

June 18, 2010

Overview

Review of current Resource Adequacy requirements and

processes.

How would RA be applied to RDRP?

Illustrative examples using data from SCE’s 2009 Demand

Response Load Impact Evaluations.

Southern California Edison’s 2009 Demand Response Load Impact

Evaluations Portfolio Summary, Final Report. April 22, 2010

2009 Load Impact Evaluation of California’s Statewide Base Interruptible

Program. Final Report. April 1, 2010.

2009 Load Impact Estimates for SCE’s Demand Response Programs:

Residential and Commercial Summer Discount Plan, Agricultural and

Pumping Interruptible Program, Real Time Pricing. Final Report. April 1,

2010.

Slide 14

Resource Adequacy requirements

System

RAR is calculated using an LSE’s forecast load by month, plus a

reserve margin of 15%, for a total of 115% of forecast load.

LSE forecast load is based on a 1 in 2 year loads (50%

probability).

LSEs must demonstrate procurement of 90% RAR year ahead

(October)

LSEs must demonstrate procurement of 100% RAR month ahead.

Local

Local Capacity Area (LCA) requirements set based on extreme 1-in10 year peak (10% probability) load event.

LSEs must demonstrate procurement of 100% of LCA requirements year ahead (October)

Slide 15

Checking RA compliance

CPUC and CAISO staff cooperate to record and validate

compliance by each LSE individually each month

LSEs submit year ahead/month ahead RA plans

showing resources to be used to met LSE’s RA

requirement to CPUC and ISO.

RA resources owners submit supply plans to ISO.

ISO checks LSE’s RA plan against supply plan submitted by

resource owners to ensure all capacity matches.

Resulting list of resources is flagged as RA in ISO system.

Slide 16

CPUC determines counting criteria for most RA resources, including demand response.

Determination of qualified capacity of all resources made

by local government entity (i.e. CPUC for IOUs).

Under CPUC’s current counting rules, DR multiplied by

115% when determining RA capacity

DR capacity based on CPUC’s Protocols for Load Impact

Estimation for Demand Response.

CPUC counting criteria:

System RA capacity from DR during all months based on projected

impact under 1-in-2 year loads during peak month (e.g. August).

Local RA capacity from DR based on impact under 1-in-10 year

loads by LCA during peak month.

Slide 17

Bidding requirements for RA resources are incorporated in ISO tariff.

Hydro and intermittent resources (wind, solar, cogen)

Technically subject to must-offer requirement.

ISO provides resource owner with flexibility to schedule or bid

resources depending on availability.

Not required to bid into RUC.

Use limited thermal resources

Units must apply to ISO for Use Limited resource status.

Generally limited to specific environmental constraints (e.g. 365

run hour per year limitation on many CTs).

Must submit Monthly Use Plan to ISO

Required to bid all capacity that is available consistent with Use

Plan.

Slide 18

Summary of evaluation results for SCE’s reliability programs.

Slide 19

Source: Southern California Edison’s 2009 Demand Response Load Impact Evaluations Portfolio Summary, April 22, 2010, p.19 (Table 5-1)

DR capacity used to meet system RA requirements based on projected impacts under 1-in-2 year loads during peak month.

Slide 20

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

1,300

1,400

1,500

Jan Feb Mar Apr May Jun Jly Aug Sep Oct Nov Dec

Pea

k M

W (

1-in

-2 S

yste

m C

on

dfi

tio

ns) SDP COM-B

SDP COM-A

SDP RES-B

SDP RES-A

API

BIP-30

BIP-15


DR capacity used to meet local RA requirements based on projected impacts under 1-in-10 year loads in peak month by LCA.

Slide 21

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

1,300

1,400

1,500

Jan Feb Mar Apr May Jun Jly Aug Sep Oct Nov Dec

Pea

k M

W (

1-in

-10

Syst

em C

on

dfi

tion

s) SDP COM-B

SDP COM-A

SDP RES-B

SDP RES-A

API

BIP-30

BIP-15


Evaluation results provide impact estimates for different LCAs.

Slide 22

2009 Load Impact Estimates for SCE’s Demand Response Programs: Residential and Commercial Summer Discount Plan, Agricultural and Pumping Interruptible Program, Real Time Pricing. Final Report. April 1, 2010.p. 21

Illustrative example for LA Basin LCA

Slide 23

Emergency

Program

Projected

impact on

July peak

(MW)

% in LA

Basin LCA

Total Impact

in LCA*

(MW)

BIP 570.5 .83 473.5

API 36.7 .27 9.9

SDP-Res 581 .76 441.6

SDP-Non-res 78.4 .76 59.6

Total 1,267 984.6

Eligible to meet local RA

requirement.

* Actual impact based on “bottom up” calculation using impact per participant in LCA and forecast of number of participants in LCA.

Evaluation results appear to provide much of data and tools needed to develop hourly bids for RDRP resources.

Slide 24

TABLE 1: Menu options Uncertainty Adjusted Impact - Percentiles

Type of Results Aggregate 10th 30th 50th 70th 90th

Weather Year 1-in-2 1:00 539.1 539.1 0.0 71.3 -34.7 -14.2 0.0 14.2 34.7

Forecast Year 2010 2:00 534.1 534.1 0.0 69.8 -34.7 -14.2 0.0 14.2 34.7

Day Type July Monthly Peak 3:00 532.8 532.8 0.0 68.7 -34.7 -14.2 0.0 14.2 34.7

Customer Characteristic LCA - LA Basin 4:00 536.5 536.5 0.0 67.7 -34.7 -14.2 0.0 14.2 34.7

Annual Enrollment Growth 0.0% 5:00 552.5 552.5 0.0 66.7 -34.7 -14.2 0.0 14.2 34.7

No Growth After: 2009 6:00 576.2 576.2 0.0 66.4 -34.7 -14.2 0.0 14.2 34.7

TABLE 2: Output 7:00 589.9 589.9 0.0 67.1 -34.7 -14.2 0.0 14.2 34.7

Number of Accounts 538 8:00 604.7 604.7 0.0 71.0 -34.7 -14.2 0.0 14.2 34.7

Aggregate FSL (MW) 82 9:00 604.4 604.4 0.0 76.3 -34.7 -14.2 0.0 14.2 34.7

Proxy Date Tuesday, July 03, 2007 10:00 606.3 606.3 0.0 80.7 -34.7 -14.2 0.0 14.2 34.7

11:00 601.8 601.8 0.0 83.4 -34.7 -14.2 0.0 14.2 34.7

12:00 587.5 587.5 0.0 85.8 -34.7 -14.2 0.0 14.2 34.7

13:00 559.7 578.2 -18.5 88.4 -53.2 -32.7 -18.5 -4.3 16.2

14:00 553.4 469.5 83.9 90.6 49.2 69.7 83.9 98.0 118.5

15:00 544.4 135.4 409.0 91.1 374.3 394.8 409.0 423.2 443.7

16:00 535.5 129.2 406.3 91.1 371.7 392.2 406.3 420.5 441.0

17:00 526.4 122.6 403.8 90.4 369.2 389.6 403.8 418.0 438.5

18:00 521.1 116.5 404.6 89.4 369.9 390.4 404.6 418.8 439.2

19:00 528.8 274.3 254.5 87.4 219.9 240.4 254.5 268.7 289.2

20:00 541.9 389.5 152.5 84.6 117.8 138.3 152.5 166.7 187.1

21:00 558.1 454.1 104.0 79.5 69.4 89.8 104.0 118.2 138.7

22:00 560.0 493.6 66.4 75.3 31.7 52.2 66.4 80.6 101.0

23:00 555.0 513.5 41.5 72.9 6.9 27.4 41.5 55.7 76.2

0:00 551.7 533.9 17.8 71.3 -16.8 3.6 17.8 32.0 52.5

Uncertainty Adjusted Impact - Percentiles

10th 30th 50th 70th 90th

Daily 13,402.0 11,076.1 2,325.9 220.6 2156.1 2256.4 2325.9 2395.3 2495.6

Cooling

Degree

Hours

(Base 70)

Reference

Energy Use

(MWh)

Observed

Energy Use

(MWh)

Change in

Energy Use

(MWh)

Reference

Load

(MW)

Observed

Load

(MW)

Weighted

Temp (F)

Hour

Ending

Load

Impact

(MW)

0.0

100.0

200.0

300.0

400.0

500.0

600.0

700.0

1:00

3:00

5:00

7:00

9:00

11:00

13:00

15:00

17:00

19:00

21:00

23:00

Reference Load (MW) Observed Load (MW)

Illustrative example: Hourly bids for RDRP resources in LA Basin during different July days.

Slide 25

0

200

400

600

800

1,000

1,200

1 5 9 13 17 21 1 5 9 13 17 21 1 5 9 13 17 21

Bid

MW

(Ju

ly L

oa

ds)

SDP-NonResSDP-Res

API

BIP Typical Day

1-in-2 Peak

1-in-10 Peak

DMM observations/suggestions

Evaluation protocols appear to provide bulk of data needed

to accurately project and represent available Emergency

DR capacity in ISO markets.

Hourly bidding of RDRP should reflect full available

capacity during each hour.

For most DR resources, this may involve daily updates based on

load forecasts.

RA provisions in ISO tariff and BPMs should clearly define

bidding requirements for RDRP resources.

ISO plans to extend Standard Capacity Product

Performance Standards to DR in 2011.

Slide 26

ISSUE IDENTIFICATION AND RESOLUTION


Slide 27

Constrained Output Generator Model

Qualification

Registration


Notifications

Metering


Constrained Output Generator Model

Accommodate Firm Service Level DR Resources

Discrete dispatch (single hourly block)

Energy performance based on Baseline Type I or II

Hourly variable Pmax/Pmin (Pmin = Pmax – 0.01 MW)

Registered Costs- Start-up & Pmin

Equate to energy bid

Fixed over RDRP Term (6 months)

Limit costs to equivalent energy bid of 95% Bid Cap ≤ Bid ≤ Bid Cap

50 MW Max RDRP resource size limit

Compliance based expected load consumption over Event

Slide 28

Firm Service Level-- PDR/COG Model

MW

0

2

FSL

t

10

2

7

4

8

6

3

HE 12 HE 13 HE 14 HE 15 HE 16 HE 17

0 to 8 MW

All-time Peak Load

• 10 MW Underlying Load

• 8 MW DR Resource

Business Process Driven Product Design

1. Qualification

Program definition, participant and resource qualification/eligibility

2. Registration

Resource attributes, enrollment, transfers, testing & auditing, terms

3. Scheduling & Bidding

Resource forecasting, scheduling & bidding

4. Notifications

Market schedules & awards, real-time dispatch, outage reporting

5. Metering

Data availability, data type, accuracy & granularity, systems

6. Performance & Compliance Evaluation

Resource, participant, and system performance

7. Settlements

Calculation of credits & charges

Slide 30

Qualification

Resource Adequacy:

Eliminated RA/Non-RA distinction

All RDRP resources must meet same requirements

Minimum Load Curtailment:

Minimum load curtailment is ≥ 500 kW per RDRP resource

Can be smaller on exception basis (CAISO Approved); not less

than 100 kW per RDRP resource under an exception

Multiple baselines accommodated at the registration level per

RDRP resource

Slide 31

Qualification

Resource Term:

Need term to track availability, i.e. availability over what period

2-terms/year-- 6 month duration

Capture seasonal and annual program types

May-October and November-April

Election Period??

Availability Requirements:

15 events and/or 48 hours per term

Dual Participation:

No “dual participation” at the wholesale level

Slide 32

Registration

Custom Aggregations and Default Aggregations

Term (6 Months)

Single or roll-over election (default is roll-over)

Identify Performance Baseline Type by Registration

Resource Specific Information

PDR vs. PDR-COG

Service Account Specific Information

Scheduling Coordinator Identification

Slide 33


Real-time market (no Day-ahead bidding activity)

Bids submitted hourly

Bidding: PDR:

This will be $950 to $1,000 in 2012

Enable range to “prioritize” resources in the bid stack

Bidding: PDR-COG

Registered bid over RDRP Term

Min Load and Start-up Costs Equate to Energy Bid

Limited to equivalent bid cost of 95% Bid Cap ≤ Bid ≤ Bid Cap

Slide 34

Notifications

Real-time Dispatch through ADS

Respects modeled resource constraints

Dispatches by resource and megawatt quantity

Marginal or discrete dispatches based on model selected

Advance Notification and Ramp Period

Combined time not to exceed 40 minutes

Examples:

If Ramp Rate is ∞ then Advanced Notice ≤ 40 minutes

If 20 MW (Pmax) RDRP, then Ramp Rate can be 20MW/40Min or 0.5 MW/Min with 0 minutes Advance Notification Period

If 20 MW (Pmax) RDRP and Ramp Rate is 2 MW/min then it takes 10 minutes to reach full curtailment, thus could have up to 30 minutes for startup

Slide 35

Notifications

Outages

Used to manage exclusions for baseline calculation & Availability

Reported through SLIC

Report:

Unavailable Resource

Derated Resource

Local Transmission Emergency

Slide 36

Metering

5 to15 minute meter data availability

Meter Data Reporting

At the Registration Level

Data only required after an event

Include event data & meter data supporting adjustment window

Meter Data Audit

On-demand availability

Down to service account level

Sample data available on demand, including review of algorithm

Meter Data Reporting Deadline

Same as PDR- T+ 5B

Slide 37


Performance Incentive

Min performance standard at wholesale level

Original “Event counting” penalty proposal impacted those service

accounts that performed even though aggregation didn’t

Performance incentive needed for DRP that does not directly

impact underlying service accounts; penalties to service accounts

is under the purview of the DRP.

Slide 38

Performance incentive design principles

Provides performance incentive for participation

Reduction target met or exceeded = possible incentive payment

Not within 75% of reduction target = incentive charge

Features:

Applies to both PDR-COG and PDR Models

Applies to Baseline Type I and II

Charge rate is equal to ICPM capacity payment price (currently

$41/kW-year)

Settles Monthly

Incentive payment funded by incentive charges received

Slide 39

Performance incentive examples

Assumptions

Event occurs – RDRP dispatched for 5 MW for 3 hours

Scenario 1 – RDRP reduce load by 5MWh

Performance = Dispatch

Result – Eligible for incentive payment

Scenario 2 – RDRP reduce load by 6 MWh

Performance > Dispatch



Performance > 75% of Dispatch


Slide 40

Performance incentive examples (cont’d)

Assumptions

Event occurs – RDRP dispatched for 5 MW for 3 hours


Performance < 75% of Dispatch

Result – Performance incentive charge

Performance incentive charge = MW below performance target X Non

performance charge

Where:

MW below performance target = 9 MWh (3 MWh * 3 hour event)

Non Performance charge = (MW * 1000)*$41/12)

So:

9 MWh x 1000* ($41/kW-Yr/12) = $30,690

Allocate charges to RDRP resources that met dispatch instruction (pro rata)Slide 41


Other Baseline Parameters to Consider:

Other baselines CAISO should consider beside 10 in 10?

“Meter Before/Meter After” not appropriate given potential for

long duration events under this product

Exclusion Rules:

Event Days

Outages (full and partial outages)

Local Transmission Emergencies

Testing Events

Slide 42


Evaluation Plans- Baseline Type II:

Evaluate how statistical sampling can be used to determine the performance of

“Direct Load Control” devices, such as A/C cycling, pool pumps, etc.

Requirements to fulfill Baseline Type II

Precision and Accuracy Necessary to establish appropriate

sample sizes (underlying assumptions, margin of error,

confidence interval, distribution, etc.)

Techniques to borrow from Load Impact Protocols?

Measurement type- Regression, Average, etc. ?

Slide 43

WRAP UP & NEXT STEPS


Slide 44

RDRP Stakeholder Initiative - California ISO · RDRP Stakeholder Initiative Slide 7 •RDRP Settlement Agreement Design Principles •NAESB M&V Standard •Reliability Events Data

Documents