The Grid of the Future
Farrokh Albuyeh, Ph.D.
Farrokh Rahimi, Ph.D.
Smart Grid Conference 2014
Grid Renovation Workshop
December 8, 2014
Session 2
Smart Grid Conference 2014 (SGC’14) - Grid Renovation Workshop
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Agenda
•
Session 1
–
–
–
–
–
–
–
•
•
Introductions
Driving forces changing the electric utility landscape
The impacts of the proliferation of Variable Energy Resources (VER)
Operational challenges at the wholesale/transmission and at retail/distribution levels
Increased visibility and situational awareness requirements at the distribution level
Using Advanced AMI and customer data to increase visibility to last mile distribution circuits
Managing Demand Response (DR) and Distributed Energy Resources (DER)
Break
Session 2
–
–
15 Minutes
75 Minutes
A new construct: Distribution System Operator (DSO)/Distrusted System Platform (DSP)
•
•
•
•
75 Minutes
Overall Description
Implementation
The emerging Transactive Energy paradigm and its convergence with DSO/DSP constructs
Break
Session 3
–
–
15 Minutes
60 Minutes
Illustrative examples and case studies
Concluding Remarks/Question and Answer
Smart Grid Conference 2014 (SGC’14) - Grid Renovation Workshop
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Experience with Use of DR/DER
in Wholesale Markets
Smart Grid Conference 2014 (SGC’14) - Grid Renovation Workshop
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End-to-End Operational Transactions
ISO and Wholesale
Markets
• Energy
• Ancillary Services
• Capacity
• Day-Ahead
• Real-Time
Trans.
Constraints
Wholesale
Prices
and
DR,
Ancillary
Services
Legend
Data
Pricing
Electricity
Bulk Power Operation
DR Info. and
Dist. constraints
Settlement
Charges
Supply
Distribution System
Retail
Prices
Direct
Load
Control
Supply and
Demand
Response
Customers
Smart Grid Conference 2014 (SGC’14) - Grid Renovation Workshop
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Linking Demand-Side Capabilities to Wholesale Operations
– Virtual Power Plant (VPP) Construct
Bulk Power Products
Virtual Power Plant
• Hour-Ahead Firm
• Grid Location
• Non Spin
• PMAX , PMIN
• Spinning Reserves
• Ramp Rate
• Market-Based Prices
• Min/Max Up and Down Time
• Incremental Cost Curve
Capability Data
Telemetry
Dispatch
Instructions
Retail Tariff
•
•
•
•
•
•
Direct Load Control
Time of Use
Critical Peak Price
Dynamic Pricing
Commercial and Industrial
Curtailment Contracts
Etc.
©2014 OATI, Inc.
Smart Grid Conference 2014 (SGC’14) - Grid Renovation Workshop
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Examples of Government Directives to Enable the
Use of DR/DER for Bulk Power Operation
• FERC Order 719 – ISOs Treatment of DR
— Equal Treatment of Supply and Demand Side Resources for
provision of Ancillary Services
— Aggregators of Retail Customers (ARC) also known as
Curtailment Service Providers (CSP)
• FERC Order 745 – DR Compensation
— DR must be paid Locational Marginal Pricing (LMP) if it clears
ISO Energy Market and its Cost is less than its benefit to the
market
— Net Benefit Test
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Net Benefit Test
FERC Order 745 (March 2011): DR to be paid LMP subject to Benefit > Cost
$/MWh
Benefit = MW* ∆LMP
(Savings by the Served
Load)
Generation Offer
Curve
∆LMP
Slope = LMP/ MW
Cost = LMP* ∆MW
(Paid to DR)
Slope = ∆LMP/ ∆MW
MW
∆MW = DR
Benefit > Cost
means MW*∆LMP > LMP*∆MW, i.e.
∆LMP/ ∆MW > LMP/MW
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CAISO NBT Thresholds for January 2014
Off-peak NBT
Threshold: $57.42
On-peak NBT
Threshold: $56.63
Source: CAISO Monthly Demand Response Net Benefit Test Results for January 2014; published Dec. 10, 2013
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CAISO NBT Thresholds for March 2014
Off-peak NBT
Threshold: $80.26
On-peak NBT
Threshold: $79.43
Source: CAISO Monthly Demand Response Net Benefit Test Results for March 2014; published Feb. 11, 2014
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Potential Energy Revenues of DR (DA Markets)
Typical Day-Ahead LMP Probability Distribution
$200
CAISO DA - 2012
Price Threshold ($/MWh)
$180
MISO DA - 2012
$160
PJM DA - 2012
$140
Net Benefit Threshold
NYISO DA - 2012
$120
$100
$80
$60
$40
$20
$0
0%
5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
Probability of LMP Exceeding Price Threshold
Net Benefit Test Threshold
Expected Day-Ahead DR Revenues
$50
CAISO
MISO
PJM
NYISO
Total DA DR Rev above NBT Threshold $31,436 $16,273 $26,834 $36,632
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Impact of FERC Order 745
•
•
FERC Order 745 Issued March 15, 2011
Implemented at PJM Starting Summer 2012
Source: Association for Demand Response & Smart Grid Presentation on July 08, 2014 based on EnerKnol Analysis of PJM Data
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Product Differentiation
• Retail/Distribution Operation
– Energy Differentiated by
• Speed of response
• Minimum size
• Directional change
• Automatic vs manual control
• Need to map Retail Capabilities to Bulk Power Operations Services
– Energy
– Capacity (Forward Market-based Auctions; Resource Adequacy Requirements)
– Ancillary Services
• Non-Spinning/Supplemental Reserve (10 minutes; 30 minutes)
• Spinning Reserve (10 minutes)
• Regulation (5 to 10 minute ramp; 4-second response)
– Emerging Flexibility Reserves (5 to 15 minute: Ramping; Load Following)
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Demand-Side Programs and Wholesale Products
Demand-Side Programs
Non-Dispatchable
Voluntary
Dispatchable
Demand-limiting
Control
Economic
Reliability
Wholesale Products
Notification
Firm
Commitment
Notification
Direct Load Control
Conservation
(DLC)
Voltage
Regulation
Conventional
Maybe
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Flexible
Maybe
Maybe
Yes
Yes
Yes
Yes
Yes
Yes
Day Ahead
Maybe
Maybe
Maybe
Yes
Yes
Yes
Yes
Yes
Real-time
Maybe
Yes
Yes
Yes
Yes
30 Min Non-Spin
Maybe
Yes
Yes
Yes
Yes
10 Min Non-Spin
Maybe
Maybe
Yes
Yes
Yes
10 Min Spin
Yes
Yes
Yes
Regulation
Maybe
Yes
Maybe
Balancing
Ramping
Maybe
Yes
Maybe
(New)
Flexibility Reserve
Maybe
Yes
Maybe
Capacity
Energy
Ancillary
Services
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Typical Ancillary Service and Capacity Values
ISO/RTO
CAISO
PJM
MISO
NYISO (WEST)
Non-Spinning Res. ($/MW/h)
$1.50
$1.00
$1.50
$0.99
Spinning Res. ($/MW/h)
$5.00
$7.00
$4.00
$4.34
Regulation ($/MW/h)
$10.00
$15.00
$12.00
$9.73
$25.00
$40.00
$2.00
$54.00
CAISO
PJM
MISO
NYISO (WEST)
Non-Spinning Res.
$13,000
$8,000
$13,000
$8,000
Spinning Res.
$43,000
$61,000
$35,000
$38,000
Regulation
$87,000
$131,000
$105,000
$85,000
$25,000
$40,000
$2,000
$54,000
Ancillary Services (Average Prices):
Capacity Value ($/kW-yr)
Expected Annual Values
($/MW DR/yr)
Ancillary Services:
Capacity
Flexibility Reserves
(Expected Range per MW-Year)
$15,000 - $75,000
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Experience with DR Participation in North
American ISO Markets
• ISO Control Room operators do not feel comfortable relying
on DR to actually deliver when dispatched
• Distribution utilities do not feel comfortable with third party
Curtailment Service Providers signing up their customers just
for DR
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DSO/DSP Construct
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Consideration of Power System Characteristics for Endto-End Operation
• Power system characteristics can impact delivery of
transacted quantities from distributed DR/DER assets
–
–
–
–
Reactive power/voltage impacts
Phase unbalance impacts
Impact of distribution losses
Impact of distribution congestion
• Bulk Power/Wholesale Operator is oblivious to such
distribution system impacts associated with its DR/DER
resource scheduling and dispatch
• Distribution Management Systems (DMS) can help determine
such impacts
• Distribution System Operator (DSO) can act as facilitator to
ensure such impacts are avoided or mitigated
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Example: Distribution Grid Volt/Var Effect on
Available DR
• Use Case
– Feeder Voltage: 13.8 kV
– Feeder Base Load: 9 MW with Unity Power Factor: 3 MW Constant
Impedance (Z); 3 MW Constant Current (I); 3 MW Constant Power (P)
– Participating DR: 900 kW with 0.8 Lag Power Factor
– Remaining load after deployment of DR: 8,100 kW with Lead Power
Factor
– Feeder Voltage Increase due to Lead Power Factor: 1.5%
– Increase in base load due to voltage increase: 135 kW
– Net Demand Reduction: 900-135 = 765 kW
Voltage
Increase (%)
Z Load
I Load
P Load
1.5%
3%
1.5%
0%
90 kW
45 kW
-
Smart Grid Conference 2014 (SGC’14) - Grid Renovation Workshop
Total
135 KW
18
Example: Operational Impact of Phase-Unbalanced
DR
• Use Case:
– Feeder Voltage: 13.8 kV
– Feeder Base Load: 9 MW phase-balanced (3 MW per phase)
– Participating Demand Response: 900 kW with different amounts on
each phase: 300 kW on Phase A; 100 kW on Phase B; 500 kW on
Phase C
– For simplicity, assume both the base load and the DR are unity
power factor
– When the 900 kW DR is deployed, the remaining load will no
longer be phase-balanced
– This results in neutral current and losses for the remaining load;
thus reducing the effective DR
– For a system operator, it is important to know the expected
effective DR beforehand
– With 1% Neutral Losses for Remaining Load, Net Demand
Reduction: 900 - 1%*8,100 = 819 kW
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The DSO Construct – Linking Bulk Power and Distributed
Resource Operations
•
DSO to ISO/RTO
– Forecast Net Load and
Dispatchable Products
•
– Schedules and Bids
ISO/RTO to DSO
– Metering and Telemetry
•
•
DSO Functions
– Distribution Planning
•
•
Schedules
Dispatch
Instructions
Prices
Settlements
– Distribution Reliability
– Operations Scheduling
•
•
Forecasting (Load, DR, DER)
Scheduling (DR, DER, Market)
– Dispatch and Real-Time Control
– Retail Metering and Settlements
– Retail Market Administration
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DSO Construct
• Basic Responsibilities
– Distribution System Planning
– Distribution System Reliability/Protection
• Possible Responsibilities as Linkage Between Bulk
Power/Wholesale and End-Use/Retail Market
– Operations Scheduling
•
•
•
Forecasting and Availability Assessment (Load; DR; DER)
Aggregation; Virtual Power Plant Creation (Aggregation of distributed
demand-side capabilities for provision of different products such as
Energy, Ancillary Services, Flexible Ramping, etc.)
Scheduling/Bidding into Wholesale Market
– Dispatch and Real-Time Control
•
•
•
DR/DER Resource Dispatch
Real-time Control
Interchange Management (MSS or Pseudo-BA function)
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DSO Construct (Continued)
• Possible Responsibilities as Linkage Between Bulk Power/Wholesale
and End-Use /Retail Market (continued)
– Metering and Settlements
•
•
•
•
Interval Metering
Measurement and Verification
Settlement with Bulk Power/Wholesale Market Operator
Settlement with DR/DER asset operators
– Retail Market Administration
•
•
•
DR/DER Programs
DR/DER offers (single buyer)
Bilateral DR/DER (Full Transactive)
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Different DSO Models
DSO-Lite
Pseudo BA DSO
Reliability & Protection
Reliability & Protection
Forecasting &
Scheduling
Planning
Dispatch
& Control
Settlements
Retail Market
Comprehensive DSO
Maximalist (Fully Transactive) DSO
Reliability & Protection
Reliability & Protection
Forecasting &
Scheduling
Dispatch
& Control
Settlements
Retail Market
Dispatch
& Control
Settlements
Retail Market
Planning
Forecasting &
Scheduling
Planning
Forecasting &
Scheduling
Planning
Dispatch
& Control
Settlements
Retail Market
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DSO as Retail/Transactive Facilitator
Balancing Authority
(Transmission Operator)
Balancing Authority
(ISO/RTO/Market Operator)
Bids and
Offers;
Forecasts
TX Substation
BEMS
TX Substation
DSO
HAN
µGrid
µGrid
Deployment
Instructions
Availability;
Forecasts
Dispatch
Instructions
TX Substation
BEMS
BEMS
HAN
HAN
TX Substation
BEMS
DSO
HAN
µGrid
µGrid
Smart Grid Conference 2014 (SGC’14) - Grid Renovation Workshop
µGrid
µGrid
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Functionality Timeline
Timeframes
Months
Ahead
Days
Ahead
Hours
Ahead
Real-Time
Post
Operations
Planning &
Resource Adequacy
Functions
Forecasting
Market/TE
Facilitation
Scheduling
Dispatch & Control
M&V and
Settlements
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Illustrative Example
S7
S5
S6
S13
S17
S16
S9
S8
SubStation-B
32 MVA
138-12.46 kV
S15
S4
S12
S18
S20
S11
S2
SubStation-A
32 MVA
138-12.46 kV
S10
S1
S14
S3
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Distribution Switching Operation
S7
S5
S6
S13
S17
S16
S9
S8
SubStation-B
32 MVA
138-12.46 kV
S15
S4
S12
S18
S20
S11
S2
SubStation-A
32 MVA
138-12.46 kV
S10
S1
S14
S3
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Changing Distribution Circuit Topology
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Changing Load and Voltage Profiles
S7
S5
S6
S13
S17
S16
S9
S8
SubStation-B
32 MVA
138-12.46 kV
S15
S4
S12
S18
S20
S11
S2
SubStation-A
32 MVA
138-12.46 kV
S10
S1
S14
S3
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Distribution Congestion
S7
S5
S6
S13
S17
S16
S9
S8
SubStation-B
32 MVA
138-12.46 kV
S15
S4
S12
S18
S20
S11
S2
SubStation-A
32 MVA
138-12.46 kV
S10
S1
S14
S3
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Distribution Congestion Management
S7
S5
S6
S13
S17
S16
S9
S8
SubStation-B
32 MVA
138-12.46 kV
S15
S4
S12
S18
S20
S11
S2
SubStation-A
32 MVA
138-12.46 kV
S10
S1
S14
S3
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Distribution Congestion Management
S7
S5
S6
S13
S17
S16
S9
S8
SubStation-B
32 MVA
138-12.46 kV
S15
S4
S12
S18
S20
S11
S2
SubStation-A
32 MVA
138-12.46 kV
S10
S1
S14
S3
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DSO Application Requirements
Customer Service
Resource & Market Operations
Grid Operations
Bulk Power Interfaces
Legend:
Conventional
New
Forecasting
Billing & Settlements
Scheduling & Dispatch
GIS
CIS
Retail Market/TE
Facilitation
OMS
Distribution Assets and Operations Data
MDMS
DERMS
DMS+
End-Use Customer Portal
AMI
R-SCADA
Smart Grid Conference 2014 (SGC’14) - Grid Renovation Workshop
D-SCADA
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Examples of DSO Regulatory Initiatives
• California State Public Service Commission promoting DSO
construct (Process started mid-2014)
• New York State Department of Public Service initiative for a
Distributed System Platform (DSP) which includes
specification of functions for a DSP Operator (Process started
mid-2014)
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New York State DSP Roles & Responsibilities
Utility and DSP Roles and Responsibilities
Market Functions
Administer distribution-level markets including:
- Load reduction Market
- Ancillary services
Match load and generator bids to produce daily schedules
Scheduling of external transactions
Real-time commitment, dispatch and voltage control
Economic Demand Response
Demand and Energy Forecasting
Aggregate Demand Response for sale to NYISO
Bid Load into the NYISO
Purchase Commodity from NYISO
Metering
Billing
Customer Service
System Operations and Reliability
Monitor real-time power flows
Emergency Demand Response Program
Ancillary Services
Supervisory Control and Data Acquisition
System Maintenance
Engineering and Planning
Engineering
Planning / Forecasting
Capital Investments
Interconnection
Emergency Response
Outage Restoration / Resiliency
Utility
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Smart Grid Conference 2014 (SGC’14) - Grid Renovation Workshop
DSP
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
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Illustrative DSO/DSP Use Case
•
•
•
•
Load pocket in DSO Service Area
An Energy Service Company (ESCO)
has access to cheap power from
resources outside load pocket and
signs up a contract to supply power
to a Direct Access (DA) customer
cheaper than utility rate.
There is an emergency generator at
the DA customer site which is
expensive to run. Based on the
ESCO contract with the DA, if there
is a shortfall, the emergency
generator can be used but the ESCO
will have to compensate the DA
customer for the cost.
A Curtailment Service Provider
(CSP) has singed up a number of
prosumers in the load pocket and
acts as aggregator of their DR/DER
capabilities to offer into an ISO
market
ISO
DSO
CSP
ESCO
Load
Pocket
DR
DR
DA
DR
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Illustrative DSO/DSP Use Case (Cont’ed)
•
•
•
•
•
•
•
Forecast is for a hot day
Load forecast within the load pocket
is large due to lots of air
conditioners expected to be on
Feeders into the load pocket are at
expected at their capacity limit; net
load in load pocket exceeding import
capacity into the pocket by 5 MW
The ESCO bids into the DSO retail
market (at $80/MWh) to have the
DSO serve any shortfall due to
potential load pocket import
limitations (the $80/MWh is
cheaper than the cost of running
the emergency generator.)
CSP offers Aggregated DR from
within the load pocket into the ISO
market (at $60/MWh)
There is a lot of solar generation
outside the load pocket
Wholesale market prices (LMPs at
transmission substations) are
moderate ($40/MWh)
ISO
LMP: $40/MWh
DSO
CSP Offer:
$60/MWh
ESCO Bid:
$80/MWh
DR
DR
Load
Pocket
DA
DR
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Illustrative DSO/DSP Use Case (Cont’ed)
•
•
•
CPS offer does not clear the ISO
market since its offer ($60/MWh)
exceeds the LMP ($40/MWh)
With no DSP platform the CSP’s
DR offer would be left unutilized;
the expensive emergency
generator would have to be
operated to supply the 5 MW
shortfall.
With the DSP in place, 5 MW of
DR is cleared locally against the
ESCO bid and the price is set
between $60/MWh and
$80/MWh depending on DSP
market-clearing rules (for
example allowing for 10%
distribution losses the price
would be $66/MWh)
ISO
LMP: $40/MWh
DSO
CSP Offer:
$60/MWh
ESCO Bid:
$80/MWh
DR
DR
DR
Load
Pocket
DA
DMP: $66/MWh
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Challenges and Opportunities
• Opportunities
– The DSO construct helps promote use of preferred
resources and avoid disruptive operational impacts
– There are no technological barriers for implementation of
fully transactive (maximalist) DSO
• Challenges
–
–
–
–
Regulatory barriers
Operator acceptance
Customer engagement
Incentive compatible market design
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Transactive Energy Paradigm
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Transactive Energy
• Definition
– “Transactive energy approaches use economic or
market based constructs to manage the generation,
consumption or flow of electric power within an
electric power system while considering grid
reliability constraints.”
Proceedings of the 2nd GridWise® Architecture Council Workshop on Transactive Energy. ww.gridwiseac.org
• Some Key Characteristics
– Coordinated distributed decision making
– End-to-End coverage from wholesale markets to enduse devices
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Wholesale vs. Retail Transactive Techniques
• Wholesale transactive tools and techniques have
been developed the last two decades for
management of bulk power operations in bilateral
and centralized markets including:
–
–
–
–
–
Physical and financial deals
Bidding and Scheduling
Bid-matching/market-clearing /pricing
Transmission capacity reservations and auctions
Congestion management
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Wholesale vs. Retail Transactive Techniques
(Continued)
• Lessons learned from bulk power operations and wholesale
energy markets can be applied to distributed resources,
demand response, retail markets, and distribution system
operations. These include:
– Scheduling and dispatch of demand-side resources with economic
and reliability based objectives
– Distribution congestion management and capacity reservations
– Distribution capacity auction to hedge against limited distribution
capacity
– Variable Generation balancing using demand-side resources –
scheduling and operational considerations
• Except for Energy, products transacted in wholesale markets
and used for bulk power operation do not have a corresponding
counterpart in retail markets and distribution operations
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Transactive Control: Definitions
• Transactive Control
A single, integrated, smart grid incentive signaling approach utilizing an
economic signal as the primary basis for communicating the desire to change
the operational state of responsive assets.
• Transactive node
A physical point within an electrical connectivity map of the system.
Electrical energy flows through a transactive node.
• Transactive Incentive Signal (TIS)
A representation of the actual delivered cost of electric power at a specific
system location (e.g., at a transactive node). Includes both the current value
and a forecast of future values.
• Transactive Feedback Signal (TFS)
A representation of the net electric load (responsive and unresponsive) at a
specific system location (e.g., at a transactive node) based on the balance of
power flowing into, out of and consumed at the node. Includes both the
current value and a forecast of future values.
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Transactive Nodes
• A transactive node includes an agent (i.e., a
computer and its software applications) that
orchestrates each transactive node’s responsibilities
to
• economically balance energy
• incentivize energy consumption or generation
• activate its own responsive generation and/or load
resources
• exchange both transactive incentive signals (TIS) and
transactive feedback signals (TFS) with each of its
neighboring transactive nodes.
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48
An Incentive Signal
Predict and share a dynamic, price-like signal—the unit
cost of energy needed to supply demand at this node
using the least costly local generation resources and
imported energy. May include
–
–
–
–
–
–
Fuel cost
Amortized infrastructure cost
Cost impacts of capacity constraints
Existing costs from rates, markets, demand charges, etc.
Green preferences?
Etc.
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49
A Feedback Signal
Predict and send dynamic feedback signal—power predicted
between this node and a neighbor node based on local price-like
signal and other local conditions. May include
–
–
–
–
–
–
–
–
–
–
Inelastic and elastic load components
Weather impacts (e.g., ambient temperature, wind, insolation)
Occupancy impacts
Energy storage control
Local practices, policies, and preferences
Effects of demand response actions
Customer preferences
Predicted behavioral responses (e.g., to portals or in-home displays)
Real-time, time-of-use, or event-driven demand responses alike
Distributed generation
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50
TIS-TFS Illustration
TIS
t=0
t = 72hrs
TFS
t=0
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t = 72hrs
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Transactive Control from Interaction of Price
Discovery & Customer Bidding Algorithms
Transactive Cooling Thermostat
User Adjusts Tmin, Tmax, and Price Elasticity k
More
Comfort
Price
($/MWh)
Demand Curve
(customer bids)
More
Savings
Load
(MW)
$/kWh
Price ($/kWh)
Slope = Elasticity k
Ppt
Ppt
Pbid
Pbid
Pav
Individual Demand
Curve (customer bid)
Pav
Tmin
Tnt Tair
Tmax
Indoor
Temperature
Qpt Q0 Qav
Load
(kW)
Price is normalized: P* = [ P – mean(P) ] / σ(P)
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Transactive Control from Interaction of Price
Discovery & Customer Bidding Algorithms
Transactive Cooling Thermostat
User Adjusts Tmin, Tmax, and Price Elasticity k
More
Comfort
More
Savings
Price
($/MWh)
Real-time Market Clears
Customer Bids
Demand Curve
(customer bids)
Node Supply
Curve
Rated Node
Capacity
Pclear
$/kWh
Slope = Elasticity k
Price
($/MWh)
Pclear
Pbid
Qclear
Load
(MW)
Demand Curve
(customer bids)
Node Supply
Curve
Pav
Tmin
Tnt Tair T Tmax
set
Indoor
Temperature
Rated Node
Capacity
Pclear
Pwholesale
Qclear
Load
(MW)
Price is normalized: P* = [ P – mean(P) ] / σ(P)
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Concluding Remarks
• Electric industry landscape is changing due to proliferation of
renewable resources and active demand-side participation
• Emerging technologies help improve efficiency and reduce
environmental impacts of energy production and consumption, but
create operational problems
– Preferred Resources (efficiency and environment viewpoints)
– Disruptive Technologies (operational viewpoint)
• The DSO construct helps promote use of preferred resources and
avoid disruptive operational impacts
• The DSO and Transactive Energy roadmaps have important touch
points in the emerging industry landscape
• There are no technological barriers for implementation of fully
Transactive (maximalist) DSO
• Regulatory barriers do exist. DSO scope increases as regulatory
barriers are lowered
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QUESTIONS
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