Network Code for Requirements for Grid
Connection applicable to all Generators (RfG)
Progress Update – 28 January 2013
2
CAVEAT
Work in progress!
Final positions on all areas may change.
3
Issues & Implementation
As the first Code, RfG has pioneered the process…and definitions are expected to be used in other Network Codes.
Significant complications for application within GB, especially regarding new categorisation of users.
(replacing Large, Medium & Small Power Station classifications with A (800W to 1MW), B (1MW to 10MW), C (10 to 30MW) and D (larger than 30MW or connected at or above 110kV)
Initial options for implementation of RfG provisions being drafted by NG in discussion with other GB parties.
4
Code Development Process & ACER Opinion
Final code submitted to ACER 13 July 2012.
GB stakeholder workshop held 2&3 August 2012.
ACER workshop held 3 September 2012.
ACER review of code published 13 October 2012 (opinion of how code meets Framework Guidelines). Generally positive with 4 areas identified for improvement:
Significance test for small scale units
Insufficient justification for:
Deviation from existing practice with regards to Fault Ride Through requirements;
Exemption of CHP units (proposal that the exemption should be extended to cover heat as well as steam);
Amendments required to national scrutiny for those elements to be determined on a national level (to ensure appropriate oversight and clarity of requirements);
Recovery of costs incurred by TSOs and DSOs (not required in the Network Code and should be deleted).
5
Progress Since ACER Opinion
Two meetings held (22 Nov) with Pan-European Stakeholders regarding the
issues raised in ACER’s opinion.
User group meeting with all pan European organisations registered for RfG
re the 4 issues. ACER and EC present.
Meeting with DSO EG to examine practicality of ACER’s opinion related to
transfer of FRT requirement for Type B generators to DSOs at T-D interface.
ENTSO-E published its intended “next steps” 17 Dec
GB stakeholder meetings –
Teleconference with MicroCHP “community” 20 Dec
Meeting with AMPS (type B generators) 9th Jan
Further UG meeting 16 Jan – well attended – lively on all topics
Feedback from users:
Want to see national detail.
Support piloting using selected national examples.
6
Target Milestones
SDC 17th Jan agreed the following programme:
18/01 Meeting with EC on Art 4(3)
21/01 Short feedback to the User Group
Meeting with ACER/NRAs on all issues – TBA week commencing 28 Jan
Feb - DT finalises proposals, internal ENTSO-E approval process
Early March - public information session
ENTSO-E presentations on all 4 issues
Invite to EC and ACER to present
6th March target resubmission to ACER
7
Status of issues raised in Opinion
Significance test - Looking at exemption / derogation process.
Deviations from existing requirements:
(a) FRT for Type B – Required for frequency stability; difficult technical issue.
Progressing.
(b) Exemptions for CHP units – Agreed and closed.
Article 4 (3); determination of T&Cs in accordance with national law -Looking to pursue pilot national processes in parallel with Comitology.
Progressing 15 missing references to art 4(3) which fall into several categories.
Cost recovery – Importance of retention stressed by DSOs. Does CACM now
set precedent?
8
Significance test – 800W
ENTSO-E stresses that requirements are clearly limited to just
frequency stability for Type A
All these are justified based on aggregated impact, even for small scale
generators
Exemptions would lead to a discriminatory approach
Manufacturers continue to press for technology based exemptions
(especially small generators, micro-CHP)
Position:
Looking at exemption / derogation process.
9
Significant deviations from existing
requirements: (a) FRT for Type B
Previously:
ACER requirement was for voltage stability
ENTSO-E provided evidence including real fault examples to
demonstrate that the issue is frequency stability
DSO EG confirmed that requirement cannot be moved to T-D interface
Complex and difficult issue – also some limitations of technology (non-
synchronous plant).
Position:
Still progressing.
10
Significant deviations from existing
requirements: (b) Exemptions for CHP units
Request to extend an exemption on some power control
requirements from just “steam” to include “heat”
Following discussions with industry affected, need case
understood better.
Conclusion:
Exemptions for the limited requirements extended to include heat for
production processes of its own industrial site
This issue appears AGREED and CLOSED
11
Article 4 (3) – determination of T&Cs in accordance with national law
Previously:
Request to remove second para of article 4(3)
Problem relates to Spain, Norway and Sweden – NRA roles different
ENTSO-E acknowledge need for greater clarity
New clauses added to resolve uncertainties.
Position:
No major new arguments at 16 Jan user group meeting.
Post meeting: Looking to pursue pilot national processes in parallel with Comitology.
Previously:
Request to include 15 missing references to article 4(3)
Each of these 15 requirements analysed – 3 categories, with some in more than one:
“Plant Design”
Add specific reference to Article 4 (3)
“Parameters within same design”
Covers decisions needed to be taken quickly
NRA involvement through notification post decision
“Site specific decisions”
NRA informed through notification post decision
Position:
Still progressing
12
Cost Recovery
Previously:
Request to remove Article 5 -TSO cost recovery
ENTSO-E accept proposal not in FWGL but not in conflict with FWGL?
DSOs stress the importance of retaining this article
Position:
Does CACM precedent lead to agreement to retain?
European Electricity Balancing Code
Graham Hathaway
28 Jan 2013
14
EU Vision & ACER Balancing Code Objectives (1)
Integration, coordination and harmonisation of the
European balancing regimes
Efficient functioning of the internal market in electricity
and cross-border trade, security of supply, providing
benefits for customers
Objective, fair, transparent and non-discriminatory rules
for balancing
Take into account the regional specificities
Take into account both central dispatch and self-
dispatch arrangements
15
Roles and responsibilities of stakeholders involved in
electricity balancing, i.e.
The procurement of frequency restoration reserves (FRR)
and replacement reserves (RR)
The activation of balancing energy from frequency
restoration reserves and replacement reserves,
Reservation of interconnector capacity by TSOs for
balancing purposes
Imbalance settlement, pricing, rules, roles
Applied to cross-border and market intregration issues
EU Vision & ACER Balancing Code Objectives (2)
16
Content of Balancing Code
Procurement and
balancing product def’n
Capacity reservation on ICs
Imbalance settlement
17
Content of Balancing Code
Procurement and
balancing products
Reserves and
procurement
harmonisation
Procurement of
balancing services Procurement of
balancing energy
18
Content of Balancing Code
Capacity Reservation on
Interconnectors
Reservation for
operating reserves
Principle of co-
optimisationReserve sharing
19
Content of Balancing Code
Imbalance Settlement
Imbalance Settlement
Pricing
Settlement Period
DurationImbalance Calculation
20
What will it mean for GB Balancing?
New concepts,
products, contracts
Common merit order
Imbalance netting
GB Codes subservient
Share balancing
mechanism
Standard balancing
products
21
Coordinated Balancing Areas (CBA)
Coordinated Balancing Area (CBA)
Europe will be split into several CBAs
Each comprising a group of two or more adjacent control
areas with interconnected borders.
Intention is to make implementation more achievable
Towards 2020 extend code reqs to one single CBA pan
Europe
22
Common Merit Order (CMO) – proposed [1]
This is the keystone of the balancing code
TSOs obliged to offer all their “standard products” into CMO
– “standard products” to be defined
Will be several CMOs across Europe each corresponding to
its own CBA, and several CBAs may overlap like a big Venn
diagram
TSOs obliged to use or activate “standard products” for
national balancing first, from the CBA, before using any
specific national products.
23
Common Merit Order (CMO) – proposed [2]
TSOs initially can hold back a certain volume of bids from
the most expensive end of the bid stack (to secure system
only), but approaching 2020 none at all.
For GB actual availability limited by XB capacity.
TSOs obliged to share all information on unused generation
capacity / margins.
Transit TSOs within a CBA can only veto for system security
purposes (e.g. France buying from Ireland, GB can only veto
energy flow if system security concerns, but costs will be
ours to bear)
24
Strong links to other codes
LFC&R Code
[Market Codes]
BalancingCode
[Operational Codes]
Market Sphere
[Market Codes]
[Operational Codes]
Operations Sphere
Strong interaction
between market and
operational codes
25
Milestones and Project Plan I/II
05 06 07 08 09 10 11 12 01 02 03 04 05
2. S
take
ho
lde
rs
Wo
rksh
op
1. S
take
ho
lde
rs
Wo
rksh
op
Dra
ft N
C t
o M
C (
WG
AS
)
for
co
mm
en
ts
2012 2013
| Page 25
DT
B K
ick-O
ff
MC
ap
pro
va
l
Wri
tte
n A
ss
em
bly
ap
pro
va
l
Scoping w/ WGAS
& creation of KPIP
Step 1
Drafting
Step 2
Internal
Approvals
Step 3
Elaboration of
Supporting Document
Sta
rt (
EC
le
tte
r)
26
Wri
tte
n M
C A
pp
rova
l
As
se
mb
ly a
pp
rova
la
nd
pu
bli
ca
tio
n
| Page 26
3. S
take
ho
lde
rs
Wo
rksh
op
Public Consultation
(2 months over
summer TBC)
Step 4
Analysis
and
updated
Drafting
Step 5/6
Internal
Approvals
Step 7
Approval of NCB
(ACER Opinion, Monitor &
Manage Comitology)
ca. 12 Month
Co
nsu
lta
tio
n r
evie
w
an
d u
pd
ate
(WG
&M
C)
Su
bm
iss
ion
to
AC
ER
Milestones and Project Plan II/II
2013 2014
06 07 08 09 10 11 12 01 02 03 04
27
Detail
28
X X+6X+1 X+2 X+3 X+4 X+5
Time [years]
MAX LENGTH OF THE TRANSITORY PERIOD
The determination of the transitory period shall be subject to consultation with the relevant stakeholders
FGEB foresees DEROGATIONS – a maximum period of 2 years when some provisions of the NCEB can be ignored (granted case-by-case)
Entr
y in
to f
orc
e o
f th
e N
CEB
After transitory period
Entry into force of the standards & requirements of NCEB for which there
is no specified deadline in FGEB
LEGEND
BE - Balancing EnergyCA - Control AreaCMO - Common Merit Order (all bids are shared)CMOm - Common Merit Order list with margins
(a certain among of the most expensive balancing energy bids can be not shared)
FGEB - Framework Guidelines on Electricity BalancingFRR - Frequency Restoration ReserveNCEB - Network Code on Electricity BalancingRR - Replacement Reserve
Entry into force of the multilateral TSO-TSO model with CMO of balancing energy from RR and manual FRR
Coordination between TSOs in activation of balancing energy from automatic FRR(it also includes coordination of automatic FRR with RR and manual FRR)
Entry into force of the multilateralTSO-TSO model with CMOm of BE from RR
Minimization of the counteracting active of balancing energy between CA (imb. netting)
TSOs’ proposal for the target model for the exchangesof balancing energy from automatic FRR
Harmonisation of the main features of the imbalance settlement
Entry into force of the multilateral TSO-TSO model with CMOm of balancing energyfrom RR and manual FRR
Implementation of the target model for automatic FRR
TSOs’ proposal for standard
balancing energy and balancing reserve
products
TSOs’ proposalfor the pricing
method based onmarginal pricing(pay-as-cleared)
TSOs’ proposal for modification of the FGEB’s multilateralTSO-TSO model with CMO of BE from RR and FRR manual
29
Progress and Timing
Code drafting team
formed July 12
Key concepts
Debated
Autumn 12
Ideas firmed up
Dec 12
Stakeholder draft
Mar 13
Stakeholder
Workshop Mar 13
Public Consultation
June 13
Demand Connection Code
Prioritisation Workshop Summary
28 January
2013
Demand Connection Code -
Overview
Key Dates
4th Jan 2013: ENTSO-e Code submitted to ACER
16th Jan 2013: DECC/Ofgem Prioritisation Workshop
20th Feb 2013: Additional DCC stakeholder meeting
4th Apr 2013: ACER opinion due
Prioritisation Workshop:
Subgroup of Stakeholder Group - facilitated by DECC and Ofgem
Informs the UK Position going into Comitology by providing the initial
prioritisation of the key issues and proposed amendments to DECC.
Stakeholders responsible for issue prioritisation and identification of
suitable amendments
Priority Issues
1. DCC Compliance, Data Provision and the Significance Test
Concern domestic consumers may be captured by default [e.g.purchase
of a DSR device (Art. 21(5)] triggering obligations on the consumer and
DSOs.
Clarification of the code intention and definition of “significant”.
2. National Regulatory Authority (NRA) Oversight (Art 9)
Needs to explicitly capture areas of code where decisions / definitions are
made outside of the code to ensure “reasonableness”
Adequate dispute resolution
Clarification required to ensure sufficient NRA oversight and involvement
3. Reactive Power
Limits imposed at the TSO/DSO interface for reactive power
Concerns re: location of assets and allocation of costs on TSO v DSO
Priority Issues (2)
4. Demand Side Response
General view that the code was a barrier to DSR although difficult to
identify key paragraphs.
E.g. Code compliance may be a disincentive to domestic/SME
participation
DCC scope is designed to identify technical capability – not commercial
arrangements
CBA may miss benefits delivered through the commercial
arrangements
Concerns re: market implications of mandatory System Frequency
Control (SFC) but no specific obstacles highlighted in code
SMEs may want to offer commercial services
More work by stakeholders required to identify key changes and
supportive arguments. Proposals to be presented on 20th Feb 2013.
Summary
The DCC prioritisation meeting defined the key areas of concern
Priorities 1-3:
DCC Compliance, Data Provision and the Significance Test
National Regulatory Authority (NRA) Oversight (Art 9)
Reactive Power
Specific code amendments can be developed by stakeholders
Priority 4: DSR – does not adequately take into account commercialisation
Problem is a generic concern with the code and is less easy to address
through specific amends
Specific code amendments difficult to identify currently
Responsibility rests with Stakeholders; additional time required to consider
best approach