smart grid & demand response creating a shared resource

B O N N E V I L L E P O W E R A D M I N I S T R A T I O N

Smart Grid & Demand ResponseCreating a shared resource

PNDRP

Feb.23, 2012

Lee Hall, BPA Smart Grid Program Manager


Building DR knowledge, experience and scale

1984-2008 2008-2009 2010-2012 2013-2015 2016 +

Overview

Utilities / Partners

Sectors / Technology

Benefits /Outcome

<1 MW<10 MW

50-100 MW250+ MW

EmergingDrivers

BPA DRPortfolioMW Scale

< $1M

> $10 M

Annual Cost

Transmission / distribution

deferral

6th Power Plan encourages

pilots

TRM price signals –

utility peak demand

Balancing reserve

constraints

Overgeneration Economic opportunities

Individual projects designed to address a specific research or operational objective

Not continuous

Based on specific need or utility interest

Example: OPALCO submarine cable deferral in late ‘90s

Manual event dispatch/notification

Focused on peak load reduction

Successful projects ensured reliability during deferral

Two residential and one commercial proof-of-concept pilot project projects

Developed marketing materials and evaluation approach

Seattle City Light and LBNL Kootenai Electric Central Electric

Commercial building management systems

Residential water heater and HVAC

Curtailment only

Technical feasibility Programmatic lessons Marketing refinement Open Auto DR success

Additional residential pilots Added commercial and

industrial pilots Largely focused on utility peak Introduced wind integration

and load increase testing

12 additional utilities Joint project with TI (Ecofys) Many additional partners –

commercial, academic, etc.

Added thermal storage, in-home displays, irrigation, cold storage and industrial processes

Curtailment, load increase, HLH to LLH load shift

Technical feasibility and data Programmatic lessons Scalability assessment Testing dispatch based on

wind and balancing needs

Larger scale (10s of MWs) Shared/multiple use projects Multiple acquisition methods Initial cost allocation

methodology Joint utility/BPA dispatchability

5-6 additional projects Blend of customer types Utility as aggregator and

commercial providers

Portfolio of projects rather than specific sectors or technologies

Some focus on commercial and industrial loads

Testing routine dispatchability More sophisticated technologies

Multiple/shared use feasibility Delivery of MWs for BPA needs Significant regional DR learning Test commercial arrangements

Continue to scale larger based on evolving business needs

Refined funding and cost allocation

Portfolio of varied DR resources

Multiple utility and commercial partners

Likely to span all sectors

Ongoing testing of emerging technologies

Program scaled to address multiple regional needs

Ongoing evolution

Current Concept

Planning still in progress

potentialpotential


Brief history of DR in the PNW

From 1992-1994, both Seattle City Light and Snohomish PUD operated residential direct load control pilot programs. The Seattle City Light program involved 410 residential participants, each of which received a one-time payment of $75 for allowing the utility to control the water heater up to 20 times per winter.

In 1995, OPALCO formed a partnership with BPA called Energy Partners to control demand to help meek their peak. They had exceeded demand on an existing 34.5 kV submarine cable.

In 2004, the Olympic Peninsula Project tested whether it was possible to decrease the stress on the electric grid by at times of peak demand by more actively engaging typically passive resources, in particular end-use loads and idle distributed generation.

Seattle City Light partnered with BPA in a year-long demand response pilot which concluded with a report in March 2010. It tested automated demand response with pre-programmed control strategies in a local energy management control system.


Now evaluating multiple technologies for both reducing and increasing load

Electric Water Heaters (residential and commercial)

Cold Storage HVAC (thermostats) Industrial processes (and

electric boilers) Irrigation Municipal water pumps Battery storage Building energy

management systems Space heating (thermal

storage) In home displays


1) Operational reserve and capacity constraints (1000s of MW) Wind integration: BPA faces significant balancing reserve demands due to Balancing Authority obligations to integrate

over 3,500 MW of wind now, and likely over 6,000 MW in the next 2-3 years River management: BPA is at the limits of balancing reserves but must ensure sufficient margin to meet multiple use

requirements of the FCRPS, including managing high wind/high water events Additional reserves are needed to ease supply constraints and operational demands on FCRPS assets during summer and

winter peaks and large unit outages Opportunity to market FCRPS capacity freed up by DR

2) Transmission expansion challenges Further renewable development is expected in the BPA BA, further affecting borrowing authority, over-supply, siting and

reserve capacity challenges Opportunity to avoid or defer potentially contested and costly transmission infrastructure investments where non-wire DR

solutions are a viable least-cost alternative and could help mitigate reserve capacity, debt, and stranded cost risks DR may be the only solution available if new lines cannot be built or face lengthy delays

3) Economic impacts on utilities TRM creates incentives for customers to invest Additional potential benefits enhance value Utilities will invest in approaches that address their needs, but

may not benefit the region and preference customers

DR can help address major BPA and utility challenges

Potential utility economic benefit from DRTRM demand charge

avoidance

Load shaping charge avoidance

Deferred distribution system investments

Integration of renewables

5


BPA has an evolving portfolio of DR pilots to assess BPA and regional needs

Utility

Resid

entia

l

Com

merc

ial

Irrig

ation

Industr

ial

Build

ing

mana

gem

en

t

Sto

rage -

batterie

s

HV

AC

therm

osta

t

In-h

om

e d

ispla

y

Pro

cess

ad

justm

ent

Refr

igera

tion/

co

ld s

tora

ge

The

rma

l sto

rage

sp

ace h

eatin

g

Wate

r heate

r

co

ntr

olle

r

Wate

r pum

pin

g

Central Electric

City of Forest Grove

City of Richland

Columbia REA

Consumers Power

Cowlitz County PUD

Emerald PUD

Kootenai Electric

Lower Valley

Mason County PUD #3

Orcas Power & Light

Cu

rren

t D

R P

ilo

ts

TechnologySector

City of Port Angeles

EWEB


DR pilots – Update• Recently completed pilots with

Central Electric Co-op and Kootenai – evaluation for Kootenai now available.

• Seven active pilots and Ecofys thermal storage pilot, with 15 utilities. 1250 installed controllable water heaters.

• Ecofys pilot successfully demonstrated ability to move load in response to BPA balancing signal without inconvenience to customers. Council is part of pilot team.

• Preparing to support an 18-40 MW test in Port Angeles.


The City of Port Angeles

:http://www.youtube.com/watch?v=vgyIM0_F2w4&feature=share


Energy Storage PilotObjectives:• Use controllable loads to

help integrate variable renewables such as wind and solar

• Implement commercial / industrial end- use storage projects.

• Develop a demand response business case and marketing materials to support utilities

Lower Valley Energy

City of RichlandCowlitz PUD

EPUDConsumers Power

Forest Grove

City of Port Angeles

EWEB

Participants:Spirae, Steffes Corporation, EnerNOC, PNNL, Montana State, Renewable Northwest Project, Horizon Wind, Energy Northwest, Power and Conservation Council

Commercial & industrial: cold storage

Residential: ceramic heaters and water heaters

10


Energy Storage Pilot


Evolving DR Business Plan

Team presented the DR Business Plan proposal for BPA to the Agency Strategy Forum on October 27th. Work has included:

– Cost effectiveness: completed assessment of demand response products and a representative 100 MW DR portfolio relative to alternative resources.

– Infrastructure: With Strategy, Power and Transmission, continued assessment of potential systems /business process impact of demand response products both in the near-term (fy12-fy13) and longer term.


Evolving DR Business Plan DR Executive Steering Committee:

Launched an Executive Steering Committee composed of executives from Power, Transmission, Corporate Strategy and EE

Project identification: Working with utilities and utility groups who have expressed interest in near-term DR projects.

Outreach: Created preliminary plan and materials for outreach to utilities and utility groups to evaluate interest in DR, to be presented to DR Executive Steering Committee for refinement/approval during the coming month. AE advisory committee established.


We incorporated key lessons learned and advice we heard from established programs during the September 29th summit

What We Heard BPA DR Business Plan

DR is used nationally on a large scale• Ten of thousands of MW in use

Start with smaller scale and unique BPA needs (e.g., DECs)

DR is cost effective• PJM: $4 kW/month• ISO-NE: <$4 kW/month• TVA: $3-6 kW/month

Will be cost effective, but costs will likely be higher than established programs with long-term contracts

Programs developed using step approach • Four to ten years to build current programs

Phased approach, building on current pilots

As portfolios become complex, systems and business process impact increases

• TVA used “technology by-pass” strategy to reduce IT costs in first five years

Minimize system automation and investment during Phase 1

Utility outreach as a key to success • TVA distributors opt-in and are involved with product

development

Collaborate with utilities in design, procurement and implementation

15


Ancillary Service Variant

Planning Variant (Economic & Reliability)

Type

Energy Variant

80 to 160 hours shifted from HLH to LLH during dry period

BPA or UtilityMultiple frequencies possible

<60 hrs/yr and <16 hrs/mo

BPA

Up to multiple times per day, multiple frequencies possible


Seasonal (not deployed each year)

Detailed Frequency

8 hours/day, 5 days/week, 12 weeks equals 480 hoursHeavy spring run-off

Pre-schedule (at least one day-ahead)

Seasonal (not deployed each year)

Up to 480 hours shifted from HLH to LLH during spring run-offBPA or Utility

Frequency Notes

BPAAs needed, location-specific

Load shifting (HLH to LLH)

Dispatch Frequency

Congestion management - transmission

INC (load down)

Reliability / emergency

Up to 3 months

BPA or Utility

Potential DR Use Constraint Example Commitment / Notice Duration

8 hours/day times 5 days/week, 2 weeks equals 80 hoursDry April I or August II

Pre-schedule (at least one day-ahead)

Tier 1 demand charge avoidance by utility Monthly

16 hours per month, not to exceed 192 hours per year

4 events per month, 4 hours per eventUtility

~2-4 weeks

90 minutes per event, 10 events equals 15 hours/month or 180 hours/year

Utility peak load avoidance

Pre-scheduled commitment(at least day-ahead based on utility algorithm)

Up to ~4 hours

Standing ready< 10 minutes notice to deploy

< 90 minutes

DEC (load up)

Capacity

Winter cold spell, summer heat wave

Up to ~4 hours

Wind integration

Defer or avoid transmission construction

Standing ready< 10 minutes notice to deploy Multi-hour

10 events per month

Wind integration


< 90 minutes BPA

Up to multiple times per day, multiple frequencies possible


4 hours per event, 4 events per month

Large generation unit outage or unit fails to start


< 90 minutes BPA

As needed, BA-wide, multiple frequencies possible


4 events per month, 90 minutes per event

Pre-scheduled commitment(at least day-ahead based on utility algorithm)


4 events per month, 4 hours per event

Congestion management - distribution

Defer or avoid distribution construction

Standing ready< 10 minutes notice to deploy Multi-hour Utility

As needed, feeder/substation-specific


4 events per month, 4 hours per event

Explanation:

Created matrix of discrete products to facilitate internal and aggregator discussions

Proved valuable in explaining potential utility and BPA business needs

Does not represent opportunity to stack uses across multiple needs (e.g., utility peak avoidance and balancing)

No intent to purchase nine separate products

This matrix originated with the Agency needs assessment, revised over time

We created a matrix of potential DR products to evaluate

16


Who benefits?

Utility

Aggregator

End use customer

BPA

Who dispatches?

Utility

Aggregator

End use customer

BPA

How funded? Rates – avoided costs Incentive payment Capacity purchase Asset purchase Capital investment avoidance

Use?

Load shift

INC

DEC

Peak avoidance

Capacity

Reliability

Congestion

Notification Period?

Instant

<10 minutes

<30 minutes

<60 minutes

Forward market

Day-ahead

Load type?

Residential

Commercial

Irrigation

Industrial

Who purchases asset?

Utility

End use customer

Aggregator

BPA

Who manages program?

Utility

Aggregator

BPA

Who pays?

Utility

End use customer

Aggregator

BPA

Numerous questions to address the “shared use” issue


Outreach accomplishments Benchmarking trip to TVA Hosted an executive briefing with PJM, TVA and NE ISO Presented to Oregon Citizen Utility Board Presented to Pacific Center of Excellence for Clean Energy Work Taskforce Active participation with Smart Grid Consumer collaborative Collaborated on an AESP presentation with Milton-Freewater Responded to inquiries from Southern California Edison, New Brunswick Power,

Hawaii Electric, California Governor’s office Presented to Clean Energy class at Evergreen State College

What’s next: – Next Generation Dynamic Load Management Industry Panel, March 8, San Diego– Utility customer “Common Ground” presentation, March 28, Spokane– 3rd DR Utility Cross-share, May 7, Portland


Moving forward

Seeking utility, regional involvement and perspective

Address multiple requirements – meet utility, regional and end-user needs

Shared use of resources Test dispatchability Determine commercial arrangements –

who pays for what? Increase size and scope of pilots, but

not full scale yet – lesson from TVA


Resources available to you – BPA has active membership with: Advanced Load Control Alliance: http://www.alca.info/Contact/ Peak Load Management Alliance: http://www.peaklma.com/home.aspx Smart Grid Consumer Collaborative: http://smartgridcc.org/ Association of Energy Service Professionals: http://www.aesp.org/

BPA has a membership with E Source, which opens the doors for our utility customers to log on for research and answers to questions. http://www.esource.com/

How can we help you?


Contact information Lee Hall, BPA Smart Grid Program Manager, 503-230-5189, [email protected] Katie Pruder-Scruggs, SG Outreach Coordinator, 503-230-3111, [email protected]

For more information: BPA SG and DR website:

http://www.bpa.gov/Energy/N/Smart_Grid-Demand_Response/index.cfm PNNL: www.pnl.gov DOE OE: www.oe.energy.gov DOE Smart Grid: www.smartgrid.gov BPA wind site: www.bpa.gov/corporate.WindPower

smart grid & demand response creating a shared resource

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