Smart Grid & Demand Response Creating a shared resource
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Transcript of 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
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
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
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
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.
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
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
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
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
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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
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
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
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.
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
The City of Port Angeles
:http://www.youtube.com/watch?v=vgyIM0_F2w4&feature=share
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
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
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
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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
Energy Storage Pilot
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
Energy Storage Pilot
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
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.
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
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.
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
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
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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
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
<180 hrs/yr and <15 hrs/mo
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
Standing ready< 10 minutes notice to deploy
< 90 minutes BPA
Up to multiple times per day, multiple frequencies possible
<180 hrs/yr and <15 hrs/mo
4 hours per event, 4 events per month
Large generation unit outage or unit fails to start
Standing ready< 10 minutes notice to deploy
< 90 minutes BPA
As needed, BA-wide, multiple frequencies possible
<72 hrs/yr and <6 hrs/mo
4 events per month, 90 minutes per event
Pre-scheduled commitment(at least day-ahead based on utility algorithm)
<60 hrs/yr and <16 hrs/mo
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
<60 hrs/yr and <16 hrs/mo
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
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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
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
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
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
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
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
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
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?
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
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