Regulatory incentives for smart grids
demonstration and deployment in Italy,
within the European framework
Luca Lo Schiavo
Infrastructure Division, Regulation Department,
deputy director
IRED 2014
Kyōto, 20 November 2014
The EU context (1/3): the 2020 European targets for RES
> Share of renewables in final energy consumption in 2005
> Target in 2020
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
2
The EU context (2/3): liberalisation and unbundling rules
• Generation liberalisation: since 1999, including DG; dispatching
priority for Renewable Energy Sourced (RES) generation units
• Retail liberalisation: since 2007, with Universal Supply Regime for
small customers that do not choose their own supplier
• Unbundling of Transmission System Operator (TSO)
in Italy, full ownership unbundling for Terna from 2006 (certified according 3rd energy
package rules)
• Unbundling of Distribution System Operator (DSO): DSOs with
more than 100.000 customers can not operate as retail suppliers
and must treat every supplier on a non-discriminatory basis
(in Italy, Enel 32 million customers; ACEA-Rome and A2A Milan-Brescia more than 1 million
customer each; other 8 DSOs with more than 100.000 customers; as a whole, DSOs >
100.000 customers distribute energy to 97% customers)
• Network Codes advanced development but different voltage levels
(in Italy: EHV-HV Transmission; MV-LV distribution; only exception: city of Rome)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
3
The EU context (3/3): European Regulators cooperation
• Position Paper on Smart Grids (2009)
Issued for public consultation
(50! contributions were received)
• Conclusions paper (2010)
10 final Recommendations
for National Regulators
• Status Review of regulatory (2011)
regulatory approaches
to smart electricity grids
• Second Status Review (2014)
Ref: C13-EQS-57-04
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
4
European Regulators recommendations (2010)
Ensure stable regulatory
framework and long-term
return on investments
Decouple profits and volume
for grid operators
Incentivise innovative solutions
(demonstration pilots)
Introduce output regulation:
value for money of users
Improve consumer awareness
for energy use and market
opportunities
Kyōto, 20 November 2014
Distinguish grid-related versus
market-related activities
Perform societal cost-benefit
assessment
Adopt open protocols and
standards for interoperability
Disseminate the results and
lessons learned from the
demonstration projects
Learn from best regulatory
practices
Luca Lo Schiavo, AEEGSI (Italy)
5
1. Italian power system:
the impact of renewables
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
6
RES evolution due to State incentives
23,3
Puglia
19,5
+86%
GW
15.9
Wind
12.7
PV
Sicilia
2.4
1.9
1.0
Campania
1.2 0.5
1.7
Lombardia
1.7
1.7
Sardegna
9.3
1.4
3.9
2.8
1.6
1.9
1.6
2005
1.9
0.1
2.7
3.5
2006
2007
2008
3.5
Veneto
1.1
0.4
Calabria
4.9
5.8
2009
2010
2.9
1.0 0.5 1.5
8.6
Emilia Rom. 0.2 1.5
6,0
3.8
6.8
7.4
2011
2012
Target
PAN
2020
Altre regioni
1.4
1.7
1.4
1.0 0.3 1.3
0.8
6.1
7.0
Italian Power System (2013): distributed RES 26 GW
53 GW (peak), ~20 GW (min.load, night), ~30 GW (min.load, daylight)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
7
RES energy production (2013): 108 TWh (out of 288 TWh tot)
Produzione lorda da fonti rinnovabili in Italia dal 1996 a oggi
Impianti termoelettrici da biomasse e rifiuti
Impianti fotovoltaici
GWh
Impianti eolici
Impianti geotermoelettrici
95.000
Impianti idroelettrici
2013:
90.000
85.000
80.000
37 TWh
wind & PV
75.000
70.000
65.000
60.000
55.000
(more than
half produced
by DG units
connected to
distribution
grids)
50.000
45.000
40.000
35.000
30.000
25.000
20.000
15.000
10.000
5.000
0
1996
1997
1998
1999
Kyōto, 20 November 2014
2000
2001
2002
2003
2004
2005
2006
2007
2008
Luca Lo Schiavo, AEEGSI (Italy)
2009
2010
2011
2012
8
Impact on hourly residual load (working days)
March 2010 – working days,
Southern regions
Hour (h)
Load covered by
wind and PV
Kyōto, 20 November 2014
March 2013 – working days,
Southern regions
Apparent
reduction in the
morning
Luca Lo Schiavo, AEEGSI (Italy)
Hour (h)
Steep ramps
in the evening
9
Impact on wholesale prices (yearly average per hour)
Rapporto
trabetween
il PUN medioHourly
orario e il PUN
medio
complessivo
Ratio
price
and
PUN
1,5
1,4
1,3
1,2
PUN:
electricity
average price
(nation-wide)
1,1
1,0
2011: 72,23
€/MWh
0,9
0,8
0,7
0,6
Anno 2010
0,5
Anno 2011
0,4
Anno 2012
0,3
Anno 2013
Impact on tariffs of the RES incentives:
~45 €/MWh
0,2
0,1
0,0
1
2
3
4
5
6
Kyōto, 20 November 2014
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Luca Lo Schiavo, AEEGSI (Italy)
2012: 75,47
€/MWh
2013: 62,99
€/MWh
2014: ≈50
€/MWh ?
10
Impact on hourly residual load (Sundays and public holidays)
March 2010 – Sundays & holidays
Southern regions
March 2013 – Sundays & holidays
Southern regions
Hour (h)
Hour (h)
Load covered by
wind and PV
Kyōto, 20 November 2014
Reverse power flow (from MV to HV)
Luca Lo Schiavo, AEEGSI (Italy)
11
Impact on wholesale prices: Sundays/Holydays
SUNDAY 16 March 2014
average price in Italy
During Sundays
and Holydays the
load is low, but
PV generation
can be very high
(in proportion to
the demand)
if the sun is
shining
Source:
GME (Market Operator)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
12
Impact on power flows: DSOs’ view
900
In Italy,
there are
around 4.000
HV/MV
transformers
Numero sezioni AT/MT con inversione di flusso > 5%
800
700
600
500
Nord
Centro
Sud e Isole
400
TOTALE
300
200
Typical voltages:
HV 132-150 kV
MV 15-20 kV
LV 230-380 V
100
0
2010
2011
2012
2013
REVERSE POWER FLOW TIME: % of time (hours) during which energy
flows from Medium Voltage (distribution) to High Voltage (Transmission)
Extremely relevant indicator of distribution criticalities
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
13
Distribution networks: possible impact on voltage profiles
For the time being we do not have congestions on MV lines: RES have been
connected only after due network reinforcement («fit and forget» approach)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
14
Potential impact on system security (voltage dips on T-grid)
Residual
Voltage
1 p.u.
80% Vn
post PV
80% Vn
ante PV
0
Distance
Due to reduction of rotating machines
connected to Transmission grid, there is
less Shortcircuit-Power available and
therefore voltage dips generated at
T-level have larger impact
(in this simulation the spatial distribution
of DG has been assumed homogeneous)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
15
Potential impact on system security (frequency response)
Scenario 2020, RSE simulation
The current primary
regulation band is 1.5%.
Due to reduction of
rotating machines,
the system inertia
is decreasing and the risk
of cascade effects for
EU-wide frequency
perturbation is higher
A first EU-wide incident already
happened on 4th Nov. 2006:
split of European synchronous
area due to a RES-related
problem in Northern Germany
(sudden wind decrease, not
meshed network for works)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
16
2. The Italian Regulator response:
connection requirements for DG
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
17
Main regulatory actions for system security (Grid Code)
Connection requirement:
• Voltage fault ride-through capabilities for DG units (PV and wind)
• extends some existing HV rules also to the PV plants connected at the
MV and LV levels
• Avoid disconnection for low frequency perturbation
• retrofitting of existing DG units: MV units, over 50 kW 92% achieved;
LV units, over 6 kW scheduled until the end of April 2015
Distributed generation shedding:
• First phase (2012-2014): only DG directly connected to Primary Station
MV busbars can be disconnected in < 30 min (but: no observability)
• Second phase (2015>): all DG units at MV level can be disconnected
remotely through a simple but secure SMS-based device at TSO request
(both new & existing DG units)
• Third phase: improve observability (to be defined in next months)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
18
Voltage fault ride-through capabilities for DG units (PV)
PV plants: CEI 0-16 revised version, Terna Grid Code approved by AEEGSI
1,3
1,25
1,2
1,15
1,1
Disconnecting the plant is allowed
OVRT Curve
1,0
0,9
0,85
0,8
Plants must be connected
LVRT Curve
Caratteristica LVRT
0,7
0,6
Zona di distacco ammesso
0,5
0,4
Disconnecting the plant is allowed
0,3
0,2
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
2300
2200
2100
2000
1900
1800
1700
1600
1500
1400
1300
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
-100
0,1
Time
(ms)
19
Reduced risk in case of deep voltage dip in the grid
Without new FRT requirements
Kyōto, 20 November 2014
With new FRT requirements
Luca Lo Schiavo, AEEGSI (Italy)
20
Frequency variation tolerance requirements for DG units
Before approval of Annex A.70
to Network Code
After approval of Annex A.70
to Network Code
Extremely risky condition before the new requirements: if automatic load shedding
was called, the effect would have be less, or even the opposite, than desired
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
21
3. The Italian Regulator initiative:
smart grid demonstration projects
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
22
European Regulators recommendations (2010)
Ensure stable regulatory
framework and long-term
return on investments
Decouple profits and volume
for grid operators
Incentivise innovative solutions
(demonstration pilots)
Introduce output regulation:
value for money of users
Improve consumer awareness
for energy use and market
opportunities
Kyōto, 20 November 2014
Distinguish grid-related versus
market-related activities
Perform societal cost-benefit
assessment
Adopt open protocols and
standards for interoperability
Disseminate the results and
lessons learned from the
demonstration projects
Learn from best regulatory
practices
Luca Lo Schiavo, AEEGSI (Italy)
23
The Italian Regulator’s approach to innovation pilots
• Demonstration pilot: real operations in real grid (no lab)
• Regulatory attention to both effectiveness (performance) and
efficiency (cost): pilots are paid by all customers….
• Transparency of the rules: procedures, evaluation methods and
criteria, etc., known ex-ante
• Knowledge development with the involvement and the support
of the best expertise (RSE and University like Politecnico MI)
• Continuous monitoring in the medium and long term: cost
benefit analysis for the whole life-time of the new components
• Replicability and dissemination of the best-practices
• Output disclosure: because demonstration pilots are paid by all
customers > results must be public (no patents)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
24
AEEG DECISION
12/11
Focus of pilot
demonstration projects
active grid
AEEG
DECISION
5/10
AEEG
DECISION
66/13
DISTR. NETWORK
AUTOMATION
VOLTAGE
REGULATION
DISTRIBUTED
GENERATION
wind
integr.
LARGE SCALE
INTERMITT.GEN.
V-2-G
SERVICES
AEEG DECISION
96/11
Kyōto, 20 November 2014
E-mobility
ELECTRIC
VEHICLES
DR & EE
ELECTRONIC
METERS
smart metering
SMART
DISPLAYS
STORAGE
SYSTEMS
storage
RECHARGING
INFRASTRUCTURE
MICRO
GENERATION
AEEG
DECISIONS
292/06
393/13
631/13
MULTIUTILITY
INFRASTRUCT.
SMART
APPLIANCES
DEMAND
RESPONSE
DEMAND
AGGREGATION
AEEG
CONSULTATION
232/14
Luca Lo Schiavo, AEEGSI (Italy)
SMART
POWER
SYSTEMS
25
Requirements for smart grid demonstration pilots
• Focus on MV networks: 75% of DG rated power
• Active grids only: at least reverse power-flow for 1% of time
from MV to HV
• Real time control system at MV level: the selected MV network
has to be controlled (voltage limits / anti-islanding)
• Open grid: non-proprietary communication protocols only, in
order to minimize interface costs for network users
• Selection process with both quantitative benefit/cost ratio and
qualitative score
• Awarded with extra-WACC (+2%) for 12 years (“input-based”)
• Dissemination: report to the Regulatory Authority every six
months for selected projects, published on Regulator’s website
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
26
P-smart concept: hosting capacity in safe conditions
Vcontrol
HV
REVERSE
POWER-FLOW
TIME: 1% of year
PDG
Smart network – latency 200 ms:
+ storage (regulatory issues)
Psmart
MV
MV
LV
MV
Smart network – latency 200 ms
remote intertrip (no islanding)*
Smart network – latency 10-20 s
remote voltage regulation
LV
Min.
Load
Passive network:
NO flow from MV to HV
PDG= 0
Psmart is the increase in DG-production (PDG) that can be
connected to the grid in safe conditions (voltage, currents,
frequency) thanks to smart investments on the grid
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
*
Very critical in Italy
due to fast reclosure (400ms)
for network automation
27
«in safe conditions for voltage, currents and frequency»
• Power modulation: modulating active power
Related to Current (thermal) limits > latency: minutes
Costly solution due to loss of revenue for generators (not implemented)
Including instantaneous curtailment for emergency
• Voltage regulation: modulating reactive power
Related to Slow Voltage Variations > latency: some tens of seconds
Very low-cost solution for voltage network constraints
• Intertrip: combined dialogue between DSO and DG in order to
avoid inslanding in case of network fault and secure the system
Related to both Frequency perturbation and fast Voltage Dips > latency
hundreds of millisec
• Keep alive: in case ICT layer is not available, DG rolls back in old
setting in order to avoid risks (check every 1 second)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
28
KPI approach for smart grid pilot projects evaluation
Synthetic indicator IP used to assess
ex-ante the expected performance
of the demonstration projects
Further benefits
qualitative scoring
Quantitative
cost and main
benefit
indicator
IP 
m
Psmart   Aj
j i
C
EI post  EI pre
Psmart 
8760
Kyōto, 20 November 2014
IP: priority index
Aj: project benefits [point score]
C: project costs [€]
P-smart: increase in DG-produced
electricity / hour [MW]
EI-post: DG-produced electricity
that can be injected in the
network after the project in
safe conditions [GWh]
EI-pre: DG-produced electricity
that can be injected in the
network before the project
without reverse flow [GWh]
Aj: score for size, innovation,
feasibility, replicability
Luca Lo Schiavo, AEEGSI (Italy)
29
Selected smart grid pilot projects: Enel distrib. – Isernia
Main functions tested in the Enel D. pilot
(first four ones are similar to other pilots)
Anti – Islanding
Detection of possible islanding
condition on MV Network and
disconnection of relevant
generators
Fast MV fault Isolation
Detection on isolation of MV fault
sections without the tripping of
the breaker at the line departure
Voltage Control
Participation of MV Distributed
Generation to Voltage regulation
on MV feeders
TSO-DSO integration
Measurement collection, DG
production forecasting and data
transmission towards TSO
systems - observability
Electromobility
PV roof for workforce EV fleet
integrated with storage system
Customer awareness
Large demonstration (>4000
customers) of “SmartInfo”
device, a plug-in satellite of
smart meter
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
30
Unbundling issues
• In the pilot projects, some activities are performed by the
distribution system operator (DSO) even though in a strict
unbundling perspective a separate operator should be required
• Examples:
Electromobility: independent EV recharge provider is foreseen
by the recent “AFID” (Alternative Fuels Infrastructure Directive);
EV recharging should be a competitive activity
Visual displays: electricity retail supplier or other retailers (e.g.
telecom services) should be involved - see next section on
customer awareness
• Further, involvement of DG producers in pilots has been reached
only on a voluntary basis (so far, requirements are only for sake
of system security) - see next section on new role of DSOs
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
31
4. Regulatory incentives for Smart
grids: input-based vs output-based
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
32
European Regulators recommendations (2010)
Ensure stable regulatory
framework and long-term
return on investments
Decouple profits and volume
for grid operators
Incentivise innovative solutions
(demonstration pilots)
Introduce output regulation:
value for money of users
Improve consumer awareness
for energy use and market
opportunities
Kyōto, 20 November 2014
Distinguish grid-related versus
market-related activities
Perform societal cost-benefit
assessment
Adopt open protocols and
standards for interoperability
Disseminate the results and
lessons learned from the
demonstration projects
Learn from best regulatory
practices
Luca Lo Schiavo, AEEGSI (Italy)
33
Evaluating costs and benefits on a project basis…
“Many technical and economic features of the Smart Grid,
Distributed Generation and Demand Response provide
diffuse benefits to the customers that are hard to put a
value on.
[US] regulators must engage in lenghty proceedings to
set methods of measuring the value and then utilities must
administer them under the critical eye of regulators…”
P. Fox-Penner, Smart Power, 2010
Output-based Regulation is the key progress towards
«smart regulation»: efficiency and effectiveness
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
34
Output-based vs Input-based incentives: a synthesis
OUTPUT-BASED
INPUT-BASED
• e.g. Quality of Supply
• e.g. Innovation (so far)
• Reliable and fair metrics:
• Metrics not yet fully available
key outcome indicators that must be cleansed
from out-of-control effects; authoritative and
enforceable guidance for data recording and
auditing
• Baseline
(natural improvement trend): output based
incentive should be related only to additional
improvements on top of natural improvement
trend (historically observable)
• Output valuation
• Demonstration projects
“real networks, real voltages, real currents, real
bills”; selectivity indexes for identifying critical
network areas
• Incentive as extra-WACC
+2% for 12 years on top of ordinary WACC
value of outcome should be assessed taking into
consideration both customers view and societal
welfare (CEER 2011 report compares VoLL values;
Italy in the range 15 to 40 €/kWh-ENS)
Kyōto, 20 November 2014
however, regulator needs simple cost/benefit ratios,
KPI and filter tools, in order to avoid “lenghty
proceedings” (differently from US)
• Learning process
evaluation and selection process, monitoring
performance and dissemination of results; evolution
in output-based regulation
Luca Lo Schiavo, AEEGSI (Italy)
35
First thoughts for output-based for smart grids incentives
Indicator
Type of
network
Usability for
project
assessment
Usability for
output-based
regulation
Reverse
Power-Flow
Time
Distribution
Identifying critical
situations due to
high RESpenetration
Selective filter
(together with
DG capacity)
P-smart
Distribution
Measure of main
smart grid benefit
Possibly an
output indicator
(for incentive)
Energy not
withdrawn from
renewables due
to congestion
Distribution or
Transmission
Only on a
simulation basis
(ex-post indicator)
Possibly a
disbenefit indicator
(for penalty)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
36
5. Customer awareness of its
consumption behaviour
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
37
European Regulators recommendations (2010)
Ensure stable regulatory
framework and long-term
return on investments
Decouple profits and volume
for grid operators
Incentivise innovative solutions
(demonstration pilots)
Introduce output regulation:
value for money of users
Improve consumer awareness
for energy use and market
opportunities
Kyōto, 20 November 2014
Distinguish grid-related versus
market-related activities
Perform societal cost-benefit
assessment
Adopt open protocols and
standards for interoperability
Disseminate the results and
lessons learned from the
demonstration projects
Learn from best regulatory
practices
Luca Lo Schiavo, AEEGSI (Italy)
38
Selected smart grid pilot projects: Enel distrib. – Isernia
Enel Info+ Kit
Smart Info is based on Enel remote
metering system (installed 2001-06), on
the whole national territory:
• plugged into one of the house
electricity sockets;
• univocally associated to customer’s
own meter;
• makes consumption data available
(and local generation as well, if any).
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
39
Extremely interesting results from field sperimentation
Average load profile
pre- and post-usage of the kit
Experimenters average
gross reduction:
0.7
-7%
0.6
Post SI
0.2
Pre SI
0.1
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
23:00
22:00
21:00
20:00
19:00
18:00
17:00
16:00
15:00
14:00
13:00
12:00
11:00
10:00
9:00
8:00
7:00
6:00
5:00
4:00
0
0:00
-4%
0.3
3:00
Experimenters
net reduction:
0.4
2:00
-3%
0.5
1:00
Control group
average reduction:
40
Public consultation on tools for customer awareness
• Consultation paper 232/14: submitted many feedbacks
• Unbundling issues: the experimental kit includes the display but
this is not a device to be developed by the distributor
• Proprietary issues: for the time being, 3rd party devices are not
allowed by the smart meter technology currently implemented
• Market issues: how to involve suppliers without distort market
(there is also a different technology: optical coupling with meter)
• Tariff issues: European Directive 27/2012 on Energy efficiency
(currently national transposition pending): information on
historical consumption “in an appropriate way and free of charge”
• Innovation issues: towards the 2nd generation of smart meters
(“C-band” on the Power Line Carrier for 3rd parties messages)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
41
6. The new role of DSOs: recent
European developments
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
42
Evolution of the role of DSOs
• Traditional role:
Grid development, operation and maintenance
Connections
Metering (in most EU Member States)
• Role related to retail liberalization (“single-bill” model)
Non discriminatory relationship with suppliers
Switching process
No longer commercial activities towards final customers
• New role related to “resource transformation” (DG, DER)
Change in network management (reverse flow, congestions)
Local dispatching / ancillary services
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
43
ACER/CEER “Bridge to 2025” consultation process
• To meet new demand and generation patterns, DSOs will be
required to implement more active and intelligent network
management, monitoring and control of their networks
Active grid
management
• To allow for well functioning customer-centric retail markets,
Data
management
commercial data management will increase in weight as
well as in relevance and the role of DSOs has to be clarified
• The TSO-DSO interface must be designed to ensure efficient
information exchange for security of supply, coordinated
congestion management and integrated planning
System
security
• DSOs shall remain neutral facilitator for competitive
Neutral market
facilitator
Kyōto, 20 November 2014
market. It has to be investigated which services could be
better provided within competitive markets and which
additional safeguards (or boundaries) are required to ensure
that competitive market can develop.
Luca Lo Schiavo, AEEGSI (Italy)
44
ACER/CEER “Bridge to 2025” main conclusions
The regulatory framework must adapt to this new role of DSOs
in order to:
•
Enable DSOs to take on the role of a neutral market
facilitator;
•
Accompany the development of new flexibility markets to the
benefit of consumers, including load control and energy usage
monitoring;
•
•
Review distribution network tariff structure in order to ensure
cost recovery and focused incentives for smarter networks;
Clearly define DSOs’ and TSOs’ respective roles, establishing
coordination requirements.
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
45
Dispatching of local resources: a role for DSOs?
In Italy: Public consultation 354/2013:
•
•
Distinguish between system resources for global services and
local resources for local services
In principle 3 models are envisaged (hybrid solutions possible):
1. Centralised extended dispatching: lowering the threshold
(currently 10 MVA in most cases, except Spain), TSO remains fully in
charge for ancillary services, DSO role limited to local services
2. Federated central+local dispatching: lowering the threshold,
DSOs play active role on their network for procurement of resources
for global services, TSO accepts bids/offers from conventional plants or
DSOs
3. Scheduled program at TSO/DSO interface: DSO is engaged to
respect a scheduled program (nodal or zonal), but system resources
are not provided to TSO
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
46
Please visit:
www.autorita.energia.it
www.energy-regulators.eu
www.acer.europa.eu
Suggested reading on the Italian case
CHANGING THE REGULATION FOR REGULATING THE CHANGE
Innovation-driven regulatory developments in Italy
ICER Distinguished regulatory scholar Award 2012
http://www.iern.net/portal/page/portal/IERN_HOME/ICER_HOME/ABOUT_ICER/Distinguished_Scholar_Award_2012
Thank you for your attention
lloschiavo@autorita.energia.it
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
47
Back-up:
- lessons from pilot projects
- models for local dispatching
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
48
Lesson learned from pilot projects (1/3)
• The evolution can not be achieved through a single
integrated solution that covers the electrical system from
T&D networks to end-users
• Smart grids should be considered as a set of technological
solutions to customize, develop and implement according to
the DSO’s needs.
• The innovative applications are enabled by TLC based on a
broadband “always on” technology that connects MV
producers, passive customers, and the primary and
secondary substations: it is the “extended substation”
• Issues: prototyping and small-scale costs, interoperability,
cost of telecom services
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
49
Lesson learned from pilot projects (2/3)
• Interoperability: conformance to IEC 61850 is not sufficient
• The communication profiles developed by each manufacturer
vary: different profiles from different vendors are said to comply
with the standard (!) but not 100% interoperable.
• Network users (DG) can install the equipment they prefer, so the
devices connected to the MV network are from many vendors.
• To allow the DSO to exchange information, a data model is
needed, in order to guarantee the interoperability between multivendor devices and allows the DSO to communicate with all third
party devices in the extended substation
• While we wait for a possible improvement in IEC technical
standards (?), each DSO needs to develop his own data model
today… role for national standardisation bodies
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
50
Lesson learned from pilot projects (3/3)
• The power grid and the ICT layer are complementary for SGs
• ICT performance: always-on and low-latency are essential
• In urban contexts, the public internet infrastructure is available:
pilots in these areas show that it’s fully compatible with the
applications related to inter-trip, V/Q regulation,
limitation/modulation of active power, even without specific
agreements signed with TLC providers!
• In rural areas, can new developments of the electricity network
be the driver for the ICT deployment? Doubts
• In order to reduce ICT costs: avoid too complex and customised
protocol solutions and avoid dedicated networks
• Extra-low latency might be an hurdle to large-scale efficient
deployment of smart grids: is it really always needed?
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
51
Model 1. Centralised Extended Dispatching
•
Conventional plants connected to EHV/HV networks
•
RES connected to EHV/HV networks
•
Final customers connected to EHV/HV networks
TSO
• Trader (DG with rated power ≤ 1 MW)
• DG connected to MV or LV networks (rated power > 1 MW)
• Trader (for MV and LV final customers)
DSO
Local resources
(fixed price)
•
DG connected to MV and LV networks
•
MV and LV final customers
• DSO verifies that the power flow in the planning phase and in real time due to the
participation of the DG to the Ancillary Service Market (ASM) are compliant with the
capacity of the distribution network…
…but constraints never occur with (costly) fit & forget approach.
• DSO requires to DG units (like PV plants) some local services (e.g., voltage regulation),
not in conflict with the system services
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
52
Model 2. Federated Central+Local Dispatching
TSO
System resources
(ASM)
•
Conventional plants connected to EHV/HV networks
•
RES connected to EHV/HV networks
•
Final customers connected to EHV/HV networks
System resources
(ASM_D)
DSO
• Trader (DG with rated power ≤ 1 MW)
• DG connected to MV or LV networks
(rated power > 1 MW)
Local resources
• Trader (for MV and LV final customers)
(ASM_D or fixed price)
• TSO: accepts bids/offers from conventional plants or DSOs in order to operate the
power system: solve residual congestions and create secondary and tertiary reserve at
minimum costs)  central dispatch.
• DSO:
 enters into purchase and sale contracts for the tradable resources by DG (like PV
plants) (ASM_D, Ancillary Service Market for Distribution network) and provides
system resources to the TSO;
 procures the resources necessary to operate the distribution networks, while
respecting all constraints (ASM_D or regulated price)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
53
Model 3. Scheduled program at TSO/DSO interface
TSO
Scheduled program
at TSO/DSO interface
•
Conventional plants connected to EHV/HV networks
•
RES connected to EHV/HV networks
•
Final customers connected to EHV/HV networks
Resources to guarantee
the scheduled program
(ASM_D or fixed price)
DSO
Local resources
(ASM_D or fixed price)
• Trader (DG with rated power ≤ 1 MW)
• DG connected to MV or LV networks (rated
power > 1 MW)
• Trader (for MV and LV final customers)
• TSO: procures the resources necessary to operate the power system, respecting all
system constraints  central dispatch.
• DSO:
 is obliged to maintain a scheduled cumulative program wrt each single HV/MV
interface (nodal model) or wrt one zone that includes more HV/MV interfaces
(zonal model). System resources for the TSO are not provided;
 procures the resources necessary to operate the distribution networks, while
respecting all constraints (ASM_D or fixed price)
Kyōto, 20 November 2014
Luca Lo Schiavo, AEEGSI (Italy)
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