lessons learned from wholesale transactive techniques and

Lessons Learned from Wholesale Transactive Techniques and their Application to Retail Transactions Farrokh A. Rahimi, Ph.D. Vice President, Market Design and Consulting Ali Ipakchi, Ph.D., Vice President, Smart Grid and Green Power

Transactive Energy Workshop Yorktown Heights, New York March 28-29, 2012

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Wholesale Transactive Techniques - Background • Electricity Industry Restructuring (mid 1990s)

– Transmission Open Access • Transmission Reservation and Scheduling • Tagging

– Market-based Pricing • Energy • Contingency Reserves • Regulation

– Demand Participation • Very limited price-responsive demand • Measures against supply market power due to inadequate demand

elasticity

• Advent of Smart Grid – Enabling technologies: Advanced Metering Infrastructure, Smart

Devices – Demand-side participation – Possibility to extend transactive techniques from wholesale to retail


Traditional Power System Operations

Wholesale Supply

Reliability

Economics

Demand

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0:00

4:40

9:20

14:0

018

:40

23:2

04:

008:

4013

:20

18:0

022

:40

3:20

8:00

12:4

017

:20

22:0

02:

407:

2012

:00

16:4

021

:20

2:00

6:40

11:2

016

:00

20:4

01:

206:

0010

:40

15:2

020

:00

0:40

5:20

10:0

014

:40

Load

Load Forecast, Demand Bid

Economic Supply


Power Flow

Information Flow

Operation under Smart Grid Paradigm

Reliability

Economics

Environmental

PHEV

Smart Appliances

Distributed Resources

Variable Gen.Variable Generation

Wholesale Supply

Demand


New Requirements • Need for coordinated management of a large number

of distributed and demand-side resources, while – Maintaining a high degree of grid reliability – Improving operational economics

• Requirement – Information exchange among many systems, entities,

and users: distribution system operators, transmission system operators, independent system operators, generators, load serving entities, aggregators, marketers, end users, etc.

– New customer/device enrollment, aggregation, scheduling, monitoring, and control functions

– Diverse resource types: conventional resources, variable generation, distributed generation, distributed storage, demand response, electric vehicles

– Diverse control and communication devices and systems • Need for new end-to-end management, operations

planning, scheduling, dispatch, and Real-Time operation


Supply

End-to-End Power System Operation

Wholesale

Prices

Wholesale Markets

Transmission Grid

Retail Rates and

Incentives

Supply and Demand

Data

Pricing

Electricity

Legend:

Retail Operations

Merchant Operations

Bulk Generation

Distribution Grid

Consumers, Devices Bi

ds;

Sche

dule

s

Enrollment; Controls

Demand Forecast Resource Availability

Bids, Offers; Awards

Capacity, Energy, Ancillary Services

Transmission

Sub - Transmission

Distribution Substation

Transmission Substation

Distribution

Generation

Congestion

Reta

il O

pera

tion

Bu

lk P

ower

Ope

rati

on


Main Areas for Potential Application of Wholesale Transactive Methods • Scheduling and Dispatch of Demand-Side Resources

– Virtual Power Plants vs. Conventional Power Plants – Availability and Performance Issues

• Distribution Congestion Management – Voltage/Reactive Power Impacts – Stationary vs. Mobile Resources

• Distribution Capacity Auction – Auction Design – Hedging vs. Arbitrage

• Pricing Paradigms – Locational Marginal Pricing vs. Average Pricing – Pricing based on active power vs. consideration of reactive power

requirements – Uplift payments and charges – Single settlement vs two-settlement systems

• Variable Generation Balancing using Demand Response – Need for new Products and Services – Scheduling Practices and Timelines


Scheduling and Dispatch • Forward Bilateral vs. Spot Market Transactions • Market-clearing/scheduling/dispatch based on

competitive bids and offers • Incorporation of demand-side resources through

aggregation and Virtual Power Plants (VPPs) • VPP bidding/scheduling based on

– Incremental cost (based on $/MWh DR deployed) – Opportunity cost (based on perceived future

displacement value of DR) – Price taker scheduling

• VPP availability (Pmax) based on temporal, ambient, and/or historical performance factors


Virtual Power Plant (VPP) • A VPP is a construct to aggregate small demand-side assets

into a system resource that may be scheduled and/or dispatched

• Objectives – Convenience for system operators (similarity of VPP

with conventional resources) – Flexibility of defining constituent assets of a VPP as

needed – Based on

• Operational need (e.g., congestion management) • Contractual constraints • Economic considerations

• Methodology: Aggregation of demand-side assets based on different dimensions (device category, DR/DER program, geographical location, customer class, etc.)


Virtual Power Plant: Linking Demand-Side Capabilities to Wholesale Operations

Retail Tariff • Direct Load Control

• Time of Use

• Critical Peak Price

• Dynamic Pricing

• Commercial and Industrial Curtailment Contracts

• Etc.

TransmissionOperator

BalancingAuthority

Bulk PowerMarkets

Virtual Power PlantDispatch & Operations

Substation

Substation

SubstationSubstation

Bulk Power Products • Hour-Ahead Firm

• Non Spin

• Spinning Reserves

• Market-based Prices

Virtual Power Plant • Grid Location

• PMAX , PMIN

• Ramp Rate

• Min/Max up & Down Time

• Incremental Cost Curve

Capability Data

Telemetry

Dispatch

Instructions Virtual Power Plant


Congestion Management • Use of VPPs for Congestion Management similar to

conventional resources – Consideration of distribution congestion and losses

in assessment of VPP availability – Consideration of Phase Balancing in assessment of

VPP availability

• Use of demand-side assets for distribution congestion management – Voltage/reactive power impacts – Stationary vs mobile resources


Impact of PEVs on a Typical Distribution Feeder

Substation

138 kV

12.47 kV

21 MVA 138/12.47

5 MVA12.47 kV

50 kVA12.47kV/220V

Single Phase Residential Lateral – 1.5 MVA

50 kVA12.47kV/208Y/120

Three-Phase Residential Lateral – 1.5 MVA

Recloser

Three Phase Commercial Lateral - 2 MVA

1 MVA12.47kV/4160/480V

1.5 MVA12.47kV/4160/2.4kV

Open Tie

120 A Fuse

400-A peak600-A emergency

Feeder rating

Voltage Regulator

25 kVA

Secondary Distribution

Primary Feeder

Single Phase Residential

Three-Phase Residential


Residential Circuit – Secondary Voltage

Commercial Customer - Primary Feeder Voltage


Potential for Distribution Congestion

-200400600800

1,0001,2001,4001,6001,8002,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24kV

A

Total base Load PHEV Load (kWh) Feeder Rating

Substation

138 kV

12.47 kV

21 MVA 138/12.47

5 MVA12.47 kV

50 kVA12.47kV/220V

Single Phase Residential Lateral – 1.5 MVA

Three-Phase Residential Lateral – 1.5 MVA

Recloser

Three Phase Commercial Lateral - 2 MVA

1 MVA12.47kV/4160/480V

1.5 MVA12.47kV/4160/2.4kV

Open Tie

120 A Fuse

400-A peak600-A emergency

Feeder rating

Voltage Regulator

25 kVA

Secondary DistributionSingle Phase Residential

Three-Phase Residential


DistributionCongestion

6-9PM

Distribution Congestion 8-11AM

-

10

20

30

40

50

60

70

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hours

kVA

PHEV Load (kWh)Residential Transformer Rating


Transmission/Distribution Capacity Allocation and Auction • Transmission Capacity Rights

– Physical rights • Grandfathered • Bilateral transactions (Open Access Same-time

Information System (OASIS)) – Financial Rights

• Auction Design • Hedging vs. Arbitrage

• Distribution Capacity Auction Design – Competitive forward auction – Position limits to guard against hoarding – Use-it-or-lose-it vs. bilateral trading – Fixed vs. variable rights accounting for impact of

voltage and distribution losses


Pricing Methods • Product Pricing

– Energy Pricing – Pricing of Contingency Reserves (Spin and Non-Spin) – Pricing of Regulation – Pricing of Capacity

• Energy Locational Marginal Pricing vs Average Pricing – LMPs based on congestion (ignoring losses) – LMPs based on congestion and marginal losses – LMPs based on congestion and average losses – Zonal Pricing

• Consideration of reactive power requirements – Wholesale Operation

• Lack of competition for reactive power due to its locational nature • Sunk cost due to long-term contracts • Uplift payments and charges

– Retail Operation • Uplifts for losses and non-energy service costs • Possibility to price reactive power separately • Marginal pricing of real and reactive power combined


Balancing of Variable Generation • Use of conventional vs. new products and services

– Conventional Products • Regulation (small unpredictable variations) • Contingency Reserves (large unpredictable variations)

– New Products and Services (relying on demand-side resources) • Ramping (slow DR-based regulation) • Up/Down Balancing Energy (fast DR)

• Scheduling Practices and Timelines – Hourly vs. sub-hourly scheduling – Interchange transaction-based variable energy

shaping • Dynamic scheduling • Pseudo tie transformation


• A 200 MW wind farm in Utah • Data from May 06 - June 10, 2010

0

50

100

150

200

2501 7 13 19 25 31 37 43 49 55 61 67 73 79 85 91 97 103

109

115

121

127

133

139

145

151

157

163

169

175

181

187

193

199

205

211

217

223

229

235

241

247

253

259

265

271

277

283

289

295

301

307

313

319

325

331

337

MW

Hours

0

50

100

150

200

250

1 7 13 19 25 31 37 43 49 55 61 67 73 79 85 91 97 103

109

115

121

127

133

139

145

151

157

163

169

175

181

187

193

199

205

211

217

223

229

235

241

247

253

259

265

271

277

283

289

295

301

307

313

319

325

331

MW

Hours

Typical Variable Generation Data


19

Typical Conventional Generation Dispatch

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0:00

4:40

9:20

14:0

018

:40

23:2

04:

008:

4013

:20

18:0

022

:40

3:20

8:00

12:4

017

:20

22:0

02:

407:

2012

:00

16:4

021

:20

2:00

6:40

11:2

016

:00

20:4

01:

206:

0010

:40

15:2

020

:00

0:40

5:20

10:0

014

:40

Load

Nuclear Base Load

Fossil Base Load

Interchange

Cycling

Ramping


Wind Generation Data

0.0

200.0

400.0

600.0

800.0

1000.0

1200.0

1400.0

1600.0

0:00

0:32

1:04

1:36

2:08

2:40

3:12

3:44

4:16

4:48

5:20

5:52

6:24

6:56

7:28

8:00

8:32

9:04

9:36

10:0

810

:40

11:1

211

:44

12:1

612

:48

13:2

013

:52

14:2

414

:56

15:2

816

:00

16:3

217

:04

17:3

618

:08

18:4

019

:12

19:4

420

:16

20:4

821

:20

21:5

222

:24

22:5

623

:28

MW

0.0

200.0

400.0

600.0

800.0

1000.0

1200.0

1400.0

1600.0

0:00

0:33

1:06

1:39

2:12

2:45

3:18

3:51

4:24

4:57

5:30

6:03

6:36

7:09

7:42

8:15

8:48

9:21

9:54

10:2

711

:00

11:3

312

:06

12:3

913

:12

13:4

514

:18

14:5

115

:24

15:5

716

:30

17:0

317

:36

18:0

918

:42

19:1

519

:48

20:2

120

:54

21:2

722

:00

22:3

323

:06

23:3

9

MW

1 hr

Time


• Increased need for Ancillary and Energy Imbalance Services

• The additional Ancillary/Energy Imbalance Services are needed during all hours of the day – Ramping and “Slow Regulation” Services

• Conventional Generation Resources may not be adequate to meet the needs

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,0000:

002:

355:

107:

4510

:20

12:5

515

:30

18:0

520

:40

23:1

51:

504:

257:

009:

3512

:10

14:4

517

:20

19:5

522

:30

1:05

3:40

6:15

8:50

11:2

514

:00

16:3

519

:10

21:4

50:

202:

555:

308:

0510

:40

13:1

515

:50

18:2

521

:00

23:3

52:

104:

457:

209:

5512

:30

15:0

517

:40

20:1

522

:50

1:25

4:00

6:35

9:10

11:4

514

:20

16:5

519

:30

22:0

50:

403:

155:

508:

2511

:00

13:3

516

:10

Load Generation Wind

MW

Variable Energy Resources (VER)


CAISO: Expected Increase in Load Following Capacity, Regulation, Ramping Requirements at 33% RPS in 2020

Requirements Increase Over 2006 Levels

2006 2012 2020 2012 2020

Load Following Capacity (MW)

Up 2,292 3,027 4,423 735 32% 2,131 93%

Down -2,246 -3,275 -5,283 -1,029 46% -3,037 135%

Load Following Ramp Rate (MW/Min)

Up 150 168 325 18 12% 175 117%

Down -138 -162 -541 -24 17% -403 292%

Regulation Capacity (MW) Up 227 502 1,135 275 121% 908 400%

Down -382 -569 -1,097 -187 49% -715 187%

Regulation Ramp Rate (MW/Min)

Up 67 122 447 55 82% 380 567%

Down -66 -90 -310 -24 36% -244 370%

Source: CAISO Presentation at Renewable Integration and Product Review Forum: Folsom, CA, July 16, 2010


Hourly Scheduling Practice

• Balancing Area Operators Require New Capabilities - Intra-Hour Scheduling - 15-minute intervals - Accurate Short-Term Forecast of VER - “Slow Regulation” a.k.a. Energy Imbalance Service Product

• 1-minute Regulation Service (Up and Down)

-150.0

-100.0

-50.0

0.0

50.0

100.0

150.0

0:00

0:08

0:16

0:24

0:32

0:40

0:48

0:56

1:04

1:12

1:20

1:28

1:36

1:44

1:52

2:00

2:08

2:16

2:24

2:32

2:40

2:48

2:56

3:04

3:12

3:20

3:28

3:36

3:44

3:52

4:00

4:08

4:16

4:24

4:32

4:40

4:48

4:56

5:04

5:12

5:20

5:28

5:36

5:44

5:52

Ener

gy Im

bala

nce

(MW

)

Time

Hourly Energy Imbalance

900.0

1000.0

1100.0

1200.0

1300.0

1400.0

1500.00:

000:

080:

160:

240:

320:

400:

480:

561:

041:

121:

201:

281:

361:

441:

522:

002:

082:

162:

242:

322:

402:

482:

563:

043:

123:

203:

283:

363:

443:

524:

004:

084:

164:

244:

324:

404:

484:

565:

045:

125:

205:

285:

365:

445:

52

Win

d Gen

erat

ion (

MW

)

Representative Wind Power Generation PatternGenetration Schedule


Impact of 15-Minute Scheduling

-150.0

-100.0

-50.0

0.0

50.0

100.0

150.0

0:00

0:08

0:16

0:24

0:32

0:40

0:48

0:56

1:04

1:12

1:20

1:28

1:36

1:44

1:52

2:00

2:08

2:16

2:24

2:32

2:40

2:48

2:56

3:04

3:12

3:20

3:28

3:36

3:44

3:52

4:00

4:08

4:16

4:24

4:32

4:40

4:48

4:56

5:04

5:12

5:20

5:28

5:36

5:44

5:52

Ener

gy Im

bala

nce

(MW

)

Time

15 min Imbalance

900.0

1000.0

1100.0

1200.0

1300.0

1400.0

1500.0

0:00

0:08

0:16

0:24

0:32

0:40

0:48

0:56

1:04

1:12

1:20

1:28

1:36

1:44

1:52

2:00

2:08

2:16

2:24

2:32

2:40

2:48

2:56

3:04

3:12

3:20

3:28

3:36

3:44

3:52

4:00

4:08

4:16

4:24

4:32

4:40

4:48

4:56

5:04

5:12

5:20

5:28

5:36

5:44

5:52

Win

d Gen

erat

ion (

MW

)

Representative Wind Power Generation Pattern

Genetration 15 min - Schedule

-150.0

-100.0

-50.0

0.0

50.0

100.0

150.0

200.0

250.0

5 min 15 min 1 hour

MW

Energy Imbalance Levels

Max Imb. Min Imb. Std Div Ramp Size


DR/DER the “Dancing Partner” of VER

Two-Way SecureCommunications Network

AMISolar PV

Demand Response

ThermalStorage

PEV

Distributed ResourceManagement

Variable GenerationManagement

MerchantOperations

GridOperations

Balancing Authority / ISO

0

500

1,000

1,500

2,000

2,500

0:00

2:20

4:40

7:00

9:20

11:40

14:00

16:20

18:40

21:00

23:20 1:4

04:0

06:2

08:4

011

:0013

:2015

:4018

:0020

:2022

:40 1:00

3:20

5:40

8:00

10:20

12:40

15:00

17:20

19:40

22:00 0:2

02:4

05:0

07:2

09:4

012

:0014

:2016

:4019

:0021

:2023

:40 2:00

4:20

6:40

9:00

11:20

13:40

16:00

18:20

20:40

23:00 1:2

03:4

06:0

08:2

010

:4013

:0015

:2017

:4020

:0022

:20 0:40

3:00

5:20

7:40

10:00

12:20

14:40

17:00

Wind

• Under Generation Demand Response • Over Generation Storage • Time Variability “Fast” DR/DER (Short Term)


Demand Response as Market Product • Possible Demand Response-Based Market Products

– Capacity – Energy

• Day-Ahead • Real-Time

– Ancillary Services (Market-Based DR with required Real-Time Telemetry and Control) • Contingency Reserves

– Spinning Reserve/Responsive Reserve/Synchronized Reserve

– Supplemental Reserve/Non-Spinning Reserve

• Regulation


Retail Program to Wholesale Products Mapping

Ancillary ServicesEmergency Market Based

Product

Capacity M

arket

Day-Ahead Price

Hour-Ahead / R

T

Price

Emergency Pric

e

Reliabilit

y

30 Minute Non-Sp

in

10 Minute Non-Sp

in

10 Minute Spin

Regulation

Voltage/V

ar

Support

Time of Use Yes No No No No No No No No No

Critical Peak Pricing

Yes Yes Yes No No No No No No No

Real Time Pricing Yes Yes Yes No No No No No No No

Emergency Programs

Yes Yes Yes Yes Yes Yes Maybe Maybe No No

Direct Load Control

Yes Yes Yes Yes Yes Yes Yes Yes Maybe Maybe

Voltage Reg. Based

Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes


Main Products at ISO/RTO Markets

Product ISO-NE NYISO PJM MISO ERCOT CAISO SPP

Regulation X (DA, RT) X (DA, RT)

X (Day-of) Offer submitted during rebid period and

processed just before RT

X (DA, RT) X (DA) X (DA, RT) Self arranged

10 Minute Spin

X (DA, RT) X (DA,RT) X (DA,RT) X (DA) X (DA, RT) Self arranged

10 Minute Non-Spin

X (DA, RT) X (DA,RT) X (DA,RT) X (DA) X (DA, RT) Self arranged

30 Minute Non-Spin

X (DA, RT) X (DA,RT)

X (DA, Re-bid between 4:00-6:00

p.m., processed just before RT)

RT Energy X X

X (Day-of) Offer submitted during re-

bid period; processes just

begfore RT

X X X X

DA Energy X X X X X

Capacity Market

X X XRA Requirement

(bilateral)RA Requirement

(bilateral)

"X" : Market Product Offerred/Procured in Short-term (Day-ahead/real-time) Auction Market by the ISOBlank (gray) = Market Product not facilitated by the ISO"DA" = Day-ahead Market; "RT" = Sub-hourly (Real-Time) Market

X (Day-of) Offer submitted during rebid period and

processed just before RT)

"Synchronized Reserve Market"

X


Distributed Resource Participation Allowed in ISO/RTO Markets

Product ISO-NE NYISO PJM MISO ERCOT CAISO SPP

Regulation StorageStorage (RT); DR from DG

behind the meterDR from DG behind

the meter only

10 Minute Spin

StorageDR from DG behind the

meter onlyDR from DG behind

the meter only

10 Minute Non-Spin

DR DR DR DR

30 Minute Non-Spin

DR DR

RT Energy Renewables, DR Renewables, DR Renewables, DR Renewables, DR Renewables Renewables Renewables, DR

DA Energy DR DR DRDR from DG behind the

meter only`

Capacity Market

DR, DG, Storage, Renewable



DR, DG, Storage, Renewable (for RA

obligation)

DR, DG, Storage, Renewable (for RA

obligation)

DR = Demand Response (block demand curtailment or variable demand reduction through distributed generation behind the meter)"DR from DG behind the meter generation only": DG providing DR without exporting power to the gridDG, Storage, Renewables = Resources that can export power to the gridBlank (gray) = Market Product not provided for DR/DER by the ISO

Storage, DR, DG

DR, Renewables

DR, Renewables


Distributed Resource Telemetry Requirements Product ISO-NE NYISO PJM MISO ERCOT CAISO SPP

Regulation 2 to 4- second resolution (ICCP)

4- second resolution (ICCP)

2-seconds (DNP 3)

10 Minute Spin



2-seconds (DNP 3)

10 Minute Non-Spin


4- second resolution (ICCP) (Exception: For

DRR Type I after-the fact metering with 1 min. resolution suffices)

2-seconds (DNP 3)

1-min from Resource to eDAC; 4

seconds eDAC to CAISO [Exception:

PIRP]

30 Minute Non-Spin


N/A

RT Energy 5 minutes (ICCP)

N/A (Except for RT energy dispatched from AS Capacity as

stated above)

N/A

4- second resolution (ICCP) (Exception: For

DRR Type I after-the fact metering with 1 min. resolution suffices)

N/AN/A (Except for

Energy from Non-Spin as above]


DA Energy N/A N/A N/A N/A

Capacity Market

N/A N/A N/A N/A N/A

N/A = There are no specific telemetry requirements for the provision of the product SCADA: Supervisory Control and Data AcquisitionICCP: Inter-Control Center ProtocolDNP 3: A specific communication protocol (standard) used in the industry eDAC: Data concentrator used by CAISO for Distributed Resource data acquisition and integrationPIRP = Participating Intermittent Resources ProgramBlank (gray) = Market Product not provided for DR/DER by the ISO

N/A

N/A


Concluding Remarks • Emphasis on environmental issues and energy conservation leads to

– Potential proliferation of Variable Generation – Active participation of demand (increased availability of Demand

Response) – Increased use of distributed storage – Increased use of electric vehicles

• This brings along both operational challenges and economic opportunities – Coordinated use of different new resources – Increased information and control interchanges among different

entities and functional layers – Potential market participation of demand-side assets in provision of

products and services – Application of transactive techniques to retail markets

• Lessons learned from wholesale market transactive techniques can be used as an advantage for retail markets/distribution operations

Farrokh Rahimi, Ph.D. Ali Ipakchi, Ph.D. [email protected] 763-201-2000

Thank You

lessons learned from wholesale transactive techniques and

Documents