Managing Electrical Demand through Difficult Periods: California s Experience with Demand Response

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Managing Electrical Demand through Difficult Periods:

California’s Experience with Demand Response

Greg Wikler

Vice President and Senior Research Officer Global Energy Partners, LLC

Walnut Creek, CA USA

EDF Workshop: The Peak Power Problem Paris, France

24 June 2009

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Page 2 December 17, 2007

Presentation Outline

• A few words about Global Energy Partners

• Overview of California’s electrical infrastructure and peak demand

• Demand response – what it is and why it is so important for California

• Types of demand response programs

• Technology enablement efforts that enhance demand response programs

• Common barriers to demand response

• Plans for the future – Smart Grid, AMI, ARRA

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Global Energy Partners, LLC

• Economic and engineering consulting company serving the electric power industry to provide demand side technical services

• Headquarters: Walnut Creek, California (near San Francisco)

• 55+ Employees

– Engineers (mechanical, chemical, electrical) – Economists, business administrators

– Most with advanced degrees

• Employee-owned

• Areas of practice

– Energy planning and analysis – Applied technology research

– Energy efficiency and demand response program implementation

• Greg Wikler: 14 years with the firm. Nationally recognized expert

in the demand response area having run EPRI research programs,

full-scale DR implementation programs for CEC, PG&E and SCE,

and a participant in other industry-leading efforts

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California’s Electrical Infrastructure

• Electrical generation is over 290,000 GWh/year

• Peak demand (noncoincident): approximately 65,000 MW

• 32,000 miles of transmission lines

• Electrical generation

– Natural gas: 42%

– Large hydro: 19%

– Coal: 16%

– Nuclear: 13%

– Renewable resources: 11%

• Five utilities provide over 80% of electricity consumed:

– Pacific Gas & Electric (“PG&E”): 30%

– Southern California Edison (“SCE”): 31%

– San Diego Gas & Electric (“SDG&E”): 7%

– Los Angeles Department of Water & Power (“LADWP”): 9%

– Sacramento Municipal Utility District (“SMUD”): 4%

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California’s Electrical Infrastructure (cont.)

• Electrical consumption by sector (2006) – Residential: 32% (90,356 GWh)

– Commercial: 37% (103,712 GWh) – Industrial: 16% (44,038 GWh)

– Other: 14% (Mining, Agriculture, Transportation, Streetlighting)

• California Independent System Operator (Cal-ISO)

controls transmission of all power for the state’s 3 IOUs

plus smaller municipal systems (not LADWP, SMUD or

most of the other municipal utilites in the state)

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Demand Response – How California Defines It

Demand response is a resource that allows end-use electric

customers to reduce their electricity usage in a given time period, or shift that usage to another time period, in response to a price

signal, a financial incentive, an environmental condition or a reliability signal. Demand response saves ratepayers money by lowering peak time energy usage, which are high-priced. This lowers the price of wholesale energy, and in turn, retail

rates. Demand response may also prevent rolling blackouts by offsetting the need for more electricity generation and can mitigate generator market power.

Source: California Public Utilities Website:

http://www.cpuc.ca.gov/PUC/energy/Demand+Response/

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Demand Response – History of DR Efforts in California

• California deregulated its electricity market in 1998 – Market forces and poor regulatory policies left the

electrical infrastructure in near collapse by early 2001

• California initiated DR programs in 2001 following the energy crisis and the resulting havoc it created for California’s electrical grid

– DR programs largely pilots (e.g., Statewide Pricing Pilot) and technology demonstrations (e.g., PG&E Auto-DR

program)

• Policies and procedures were put into place to prioritize

Demand Response above Renewable Resources, Distributed Generation and Clean Fossil-Fueled Generation (loading

order)

– But implementation was limited

– IOUs adopted business-as-usual programs (i.e.,

traditional load management, some pricing)

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A Second Crisis Propels DR

• July 2006 brought about record temperatures (average temperatures of 40

^o

C statewide for nearly 2 consecutive weeks)

• The entire Western US electrical grid was under strain due to the heat storm

– Traditional purchases from Pacific Northwest were limited

– Wholesale prices were at record levels

• California’s electrical system was once again on the verge of collapse

– Air conditioning loads were high

– Aging distribution systems were also experiencing strain

• Policymakers ordered the utilities to initiate massive

expansions of their DR program portfolios beginning in the

summer of 2007

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Types of DR Programs Currently in California

• Direct Control programs

– Direct load control with switch (e.g., air conditioners, water heaters, etc.)

– Direct load control with automated controls (e.g., PCTs, energy management control systems)

• Price Response programs

– Critical peak pricing (“CPP”)/peak time pricing (“PDP”) – Peak time rebates

– Demand bidding/peak choice – Real-time pricing

– Contracts with curtailment service providers

• Emergency/Reliability programs – Interruptible/BIP

– Optional binding mandatory curtailment

– Cal ISO ancillary services

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DR Program Efforts Across the US

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Utility DR Plans (2009-2011)

• PG&E

– 1,313 MW by 2011 – Budget $147 million

– Dynamic pricing mandatory for all customers with demands greater than 200 kW

– Testing pilot efforts with Cal-ISO on locational DR and ancillary services

• SCE

– Budget $234 million

– Program goals consistent with PG&E (listed above)

– Significant emphasis on integrating SCE’s SmartConnect AMI program with existing and planned lineup of DR programs

• SDG&E

– Budget $60 million

– Four guiding principals: (a) simple programs; (b)

comprehensive; (c) provide automated controls and (d) enable programs to transition to Cal-ISO programs in the future

• SMUD – Beginning to expand DR efforts beyond pilots

• LADWP – Limited interest due to excess capacity

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Technology that Enhances Demand Response Impacts

1. Advanced Metering Infrastructure (AMI)

• AMI provides customers with so-called Smart Meters that enable access to pricing information that more accurately reflects actual market conditions and gives customers

greater control over their energy use and bills

• Smart Meters replace conventional customer electric meters and represent an integral part of the state's demand response efforts

• Current deployment plans:

– PG&E: 5.1 million smart meters to be deployed by 2012; to couple with CPP rate structure

– SCE: 5.3 million smart meters to be deployed by 2012;

to couple with Peak Time Rebates

– SDG&E: 1.4 million smart meters to be deployed by

2011; to couple with Peak Time Rebates

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AMI is Being Deployed Nationwide

Source: EEI Institute for Energy Efficiency (June 2009)

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Technology that Enhances Demand Response Impacts (cont.)

2. Home and Building Automation

• Home Area Networks/Programmable Communicating Thermostats (PCTs)

– Building standards being set by regulators

– Utilities deploying PCT-based direct load control programs

• Automated Demand Response (Auto-DR) – A

communication and technology platform designed to:

– Provide customers with automated, electronic price and reliability signals

– Provide customers with the capability to identify and automate site specific demand response strategies

– Improve the reliability of demand response programs so they can achieve the same operational status as

conventional generation resources at a fraction of the cost

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Auto-DR System Architecture

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California’s Auto-DR Program Efforts

Public Agencies: Expand the impact of DR to stabilize the power grid

Utilize advanced energy management infrastructures to improve DR program effectiveness through automation

Commercialize Auto-DR program delivery

Utility Auto-DR Goals:

PG&E: Enable additional 45 MW by 2011 applied to Peak Choice program

SCE: Expand Auto-DR technology to larger number of DR programs

SDG&E: Offer default CPP customers Auto-DR options

Lawrence Berkeley National Laboratory’s Demand Response Research Center:

DR Automation Server Standards being developed by

industry consortium including national standards groups

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Auto-DR Accomplishments by 2008

Approximately 55 MW of load reduction capability recruited with over half now tested and ready for program

deployment; remaining customers to be fully Auto-DR capable by 12/31/08

Auto-DR proved its value during 2008 DR events:

PG&E’s CPP customers performed at 70% of shed capability during 11 events held in 2008

PG&E’s DBP customers performed at 85% of bid amounts for 7/9/08 test event

SCE’s CPP customers performed at level of 15% greater than shed capability during 12 events held in 2008

Training and knowledge enhancement

Over a dozen technical coordinator firms were trained

Auto-DR system operations were enhanced

Load assessment and settlement techniques refined

Open standards and architecture developed and ready for

publication (see www.drrc.lbl.gov)

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Auto-DR Participants in California

Over 200 service

accounts representing 14 different types of industries

Baseline peak demand representing over 150 MW

Estimated demand reduction at 55 MW

Average reduction of 36% (mainly driven by large industrial participants)

Average facility

reduction of 20% (for non-industrial

participants)

Industry Type Number of Sites

Estimated Load Reduction

(kW)

kW Percent of Total

Biotechnology 5 240 0.4%

Chemical Products 5 25,085 45.3%

Electrical Equipment 2 4,650 8.4%

Food Processing 7 1,453 2.6%

Government Building 27 2,835 5.1%

Healthcare 4 383 0.7%

High Tech 22 3,670 6.6%

Miscellaneous 2 109 0.2%

Office Buildings 16 1,901 3.4%

Petroleum Products 2 1,040 1.9%

Primary Metals 3 5,432 9.8%

Retail 98 6,228 11.2%

School 4 58 0.1%

Transport Equipment 5 2,293 4.1%

Total 202 55,377

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Makeup of Auto-DR Participants

Program Participants by Industry Type

2.5% 3.5%

13.4%

2.0%

10.9%

7.9%

1.0%

1.5%

48.5%

2.0%

2.5%

1.0%

Biotechnology Chemical Products Electrical Equipment

Food Processing Government Building Healthcare High Tech Miscellaneous Office Buildings Petroleum Products Primary Metals Retail

School Transport Equipment

Prominent Segments:

(based on # of customers):

• Retail Buildings

• Government Buildings

• High Tech Buildings

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Technology that Enhances Demand Response Impacts (cont.)

3. Smart Grid

• Very early stages of development in California

• AMI plays

significant role

• Major connection

to ARRA efforts

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Importance of Applications/Components for

Implementing Smart Grid/Intelligent Utility

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Smart Grid Link to ARRA

The American Recovery and Reinvestment Act (“ARRA”) of 2009 defines smart grid functions for the purposes of funding projects to include the following (note emphasis added):

“…..(4) The ability to sense and localize disruptions or changes in power flows on the grid and communicate such information instantaneously and automatically for purposes of enabling automatic protective responses to sustain reliability and security of grid operations……..

……(6) The ability of any appliance or machine to respond to such signals, measurements, or communications

automatically or in a manner programmed by its owner or operator without independent human

intervention…….

……(8) The ability to use digital controls to manage and modify electricity demand, enable congestion

management, assist in voltage control, provide

operating reserves, and provide frequency regulation.”

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Common DR Barriers

• Regulatory: Regulatory barriers are caused by a particular

regulatory regime, market design, market rule, or the demand response program itself. They can be divided into three sub- categories: general, wholesale-level, and retail-level.

• Economic: Economic barriers refer to situations where the financial incentive for utilities or aggregators to offer demand response programs, and for customers to pursue these

programs, is limited.

• Technological: Potential technological barriers to implementation of demand response include the need for new types of metering equipment, metering standards, or communications technology.

• Other: Some additional barriers do not fall into the categories described above. These are generally related to customer

perceptions of demand response programs and a willingness to enroll.

Source: Federal Energy Regulatory Commission, National

Assessment of Demand Response Potential (June 2009)

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Long-Term DR Plans for California

• DR programs: Over $500 million proposed to be spent over the next 3 years with transition toward dynamic pricing (PUC decision pending)

• AMI: All of the state’s conventional meters will be replaced with Smart Meters that will allow consumers to better

understand their electricity usage

• Smart Grid: Most of the state’s utilities are applying for ARRA grant funding ($4.5 billion available nationwide) with the intention of:

– Demonstrating various aspects of Smart Grid including distribution-based DR and intermittency of renewable resources ($615 million available)

– Investing in massive technology deployments drawing from existing DR infrastructures ($3.375 billion

available)

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