Regulatory incentives for smart grids demonstration and ...Kyōto, 20 November 2014 Luca Lo Schiavo,...

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

Kyōto, 20 November 2014 Luca Lo Schiavo, AEEGSI (Italy) 2

> Share of renewables in final energy consumption in 2005

> Target in 2020

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)


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

18 February 2014 4


European Regulators recommendations (2010)

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

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


1. Italian power system:

the impact of renewables


RES evolution due to State incentives

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Calabria

Veneto

Emilia Rom.

Sardegna

Lombardia

Campania

Sicilia

Puglia

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2005 2006 2007 2008 2009 2010 2011 2012 TargetPAN2020

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23,3

GW

Wind

PV

+86%

Italian Power System (2013): distributed RES 26 GW

53 GW (peak), ~20 GW (min.load, night), ~30 GW (min.load, daylight)


RES energy production (2013): 108 TWh (out of 288 TWh tot)

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Produzione lorda da fonti rinnovabili in Italia dal 1996 a oggi

Impianti termoelettrici da biomasse e rifiuti Impianti fotovoltaici

Impianti eolici Impianti geotermoelettrici

Impianti idroelettrici

2013: 37 TWh wind & PV (more than half produced by DG units connected to distribution grids)


Impact on hourly residual load (working days)

Hour (h) Hour (h)

Steep ramps in the evening

Load covered by wind and PV

March 2013 – working days, Southern regions

March 2010 – working days, Southern regions

Apparent reduction in the

morning


Impact on wholesale prices (yearly average per hour)

PUN: electricity average price (nation-wide) 2011: 72,23 €/MWh 2012: 75,47 €/MWh 2013: 62,99 €/MWh 2014: ≈50 €/MWh ?

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Rapporto tra il PUN medio orario e il PUN medio complessivo

Anno 2010

Anno 2011

Anno 2012

Anno 2013

Impact on tariffs of the RES incentives:

~45 €/MWh


Ratio between Hourly price and PUN

Hour (h) Hour (h)

March 2013 – Sundays & holidays Southern regions

March 2010 – Sundays & holidays Southern regions

Impact on hourly residual load (Sundays and public holidays)

Load covered by wind and PV

Reverse power flow (from MV to HV)


Impact on wholesale prices: Sundays/Holydays

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

SUNDAY 16 March 2014 average price in Italy

Source:

GME (Market Operator)


Impact on power flows: DSOs’ view

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2010 2011 2012 2013

Numero sezioni AT/MT con inversione di flusso > 5%

Nord

Centro

Sud e Isole

TOTALE

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

In Italy, there are around 4.000 HV/MV transformers Typical voltages: HV 132-150 kV MV 15-20 kV LV 230-380 V


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)


Potential impact on system security (voltage dips on T-grid)

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)

80% Vn

ante PV

80% Vn

post PV

Distance

Residual Voltage

0

1 p.u.


Potential impact on system security (frequency response)

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)

Scenario 2020, RSE simulation


2. The Italian Regulator response:

connection requirements for DG


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)


Voltage fault ride-through capabilities for DG units (PV)

PV plants: CEI 0-16 revised version, Terna Grid Code approved by AEEGSI

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LVRT Curve

Disconnecting the plant is allowed

Plants must be connected

Disconnecting the plant is allowed


Reduced risk in case of deep voltage dip in the grid

With new FRT requirements Without new FRT requirements


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


3. The Italian Regulator initiative:

smart grid demonstration projects














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)


SMART

POWER

SYSTEMS

DISTR. NETWORK

AUTOMATION

DISTRIBUTED

GENERATION

VOLTAGE

REGULATION

MICRO

GENERATION

active grid

ELECTRIC

VEHICLES

RECHARGING

INFRASTRUCTURE E-mobility

ELECTRONIC

METERS

smart metering

MULTIUTILITY

INFRASTRUCT.

DEMAND

AGGREGATION

SMART

APPLIANCES DR & EE

SMART

DISPLAYS

DEMAND

RESPONSE

LARGE SCALE

INTERMITT.GEN.

wind

integr.

STORAGE

SYSTEMS

storage

V-2-G

SERVICES

Focus of pilot demonstration projects

AEEG DECISIONS

292/06 393/13 631/13

AEEG DECISION 96/11

AEEG DECISION 12/11

AEEG DECISION

5/10

AEEG DECISION

66/13

AEEG CONSULTATION

232/14


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


P-smart concept: hosting capacity in safe conditions

MV

HV

MV MV

LV LV

REVERSE

POWER-FLOW

TIME: 1% of year Vcontrol

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

Passive network: NO flow from MV to HV

Smart network – latency 10-20 s remote voltage regulation

Smart network – latency 200 ms remote intertrip (no islanding)*

Smart network – latency 200 ms: + storage (regulatory issues)

Min.

Load

PDG

PDG= 0 P

sm

art

* Very critical in Italy

due to fast reclosure (400ms) for network automation


«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)


KPI approach for smart grid pilot projects evaluation

Synthetic indicator IP used to assess ex-ante the expected performance of the demonstration projects

C

AjP

IP

m

ij

smart

8760

EIEIP

prepostsmart

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

Quantitative cost and main benefit indicator

Further benefits qualitative scoring


Selected smart grid pilot projects: Enel distrib. – Isernia

Voltage Control

Participation of MV Distributed

Generation to Voltage regulation

on MV feeders

Anti – Islanding

Detection of possible islanding

condition on MV Network and

disconnection of relevant

generators

TSO-DSO integration

Measurement collection, DG

production forecasting and data

transmission towards TSO

systems - observability

Fast MV fault Isolation

Detection on isolation of MV fault

sections without the tripping of

the breaker at the line departure

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

Main functions tested in the Enel D. pilot (first four ones are similar to other pilots)


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


4. Regulatory incentives for Smart

grids: input-based vs output-based














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


Output-based vs Input-based incentives: a synthesis

OUTPUT-BASED

• e.g. Quality of Supply

• Reliable and fair metrics: 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 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)

INPUT-BASED

• e.g. Innovation (so far)

• Metrics not yet fully available however, regulator needs simple cost/benefit ratios, KPI and filter tools, in order to avoid “lenghty proceedings” (differently from US)

• 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

• Learning process evaluation and selection process, monitoring performance and dissemination of results; evolution in output-based regulation


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 RES-penetration

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)


5. Customer awareness of its

consumption behaviour














Selected smart grid pilot projects: Enel distrib. – Isernia

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).

Enel Info+ Kit


Extremely interesting results from field sperimentation

Experimenters average gross reduction:

-7%

Control group average reduction:

-3%

Experimenters net reduction:

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Pre SI

Average load profile pre- and post-usage of the kit


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)


6. The new role of DSOs: recent

European developments


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


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

• To allow for well functioning customer-centric retail markets, 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

• DSOs shall remain neutral facilitator for competitive 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.

Neutral market

facilitator

Active grid

management

Data

management

System

security


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.


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


Thank you for your attention [email protected]

www.autorita.energia.it

www.energy-regulators.eu

www.acer.europa.eu

Please visit:

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


Back-up:

- lessons from pilot projects

- models for local dispatching


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



• 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 multi-vendor 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



• 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?


Model 1. Centralised Extended Dispatching

• 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

DSO • DG connected to MV and LV networks

• MV and LV final customers

TSO

• Conventional plants connected to EHV/HV networks

• RES connected to EHV/HV networks

• Final customers connected to EHV/HV networks

• 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)

Local resources

(fixed price)


Model 2. Federated Central+Local Dispatching

TSO




DSO

System resources

(ASM)

System resources

(ASM_D)

Local resources

(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)





Model 3. Scheduled program at TSO/DSO interface

• 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)

TSO







DSO

Resources to guarantee

the scheduled program


Local resources


Scheduled program

at TSO/DSO interface


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