1. ENTSO-E NET TRANSFER CAPACITY (NTC) CALCULATION METHODOLOGIES
ENERGY TECHNOLOGY AND GOVERNANCE PROGRAM
Black Sea Transmission System Planning Project (BSTP)
ENTSO-E NET TRANSFER CAPACITY (NTC) CALCULATION METHODOLOGIES
March 20, 2017
Tbilisi, Georgia
This presentation is made possible by the support of the American people through the United States Agency for International Development (USAID). The contents are the responsibility of the United States Energy Association and do not necessarily reflect the views of USAID or the United States Government.

2. Contents I CAPACITY CALCULATION Introduction
Definitions of transfer capacities (TTC, TRM, NTC, ATC)
NTC calculation procedures
Generation shift keys
Static security calculations and criteria
Dynamic security calculations and criteria
NTC calculation in case of HVDC interconnections
NTC results harmonization
II CAPACITY ALLOCATION
Capacity allocation principles and methods
Market/non-market based
Explicit/implicit
Transaction-based methods (NTC/ATC based)
Flow-based methods
EU legislation regarding the Capacity Allocation

3. Net Transfer Capacity - NTC
I CAPACITY CALCULATION
Introduction
Definitions of transfer capacities (TTC, TRM, NTC, ATC)
NTC calculation procedures
Generation shift keys
Static security calculations and criteria
Dynamic security calculations and criteria
NTC calculation in case of HVDC interconnections
NTC results harmonization
II CAPACITY ALLOCATION
Capacity allocation principles and methods
Market/non-market based
Explicit/implicit
Transaction-based methods (NTC/ATC based)
Flow-based methods
EU legislation regarding the Capacity Allocation

4. Definition of Transfer Capacities: TTC
Base Case Exchange (BCE)
Basic exchange program, eventually existing in network model used for capacity calculation
Additional exchange (ΔEmax)
Maximal additional exchange between the areas, compatible with security standards
Total Transfer Capacity (TTC)
Maximum exchange program
between two areas, compatible
with operational security
standards applicable at each system
Typically: n-1 security criteria
TTC = BCE + ΔEmax

5. Definition of Transfer Capacities: TRM
Transmission Reliability Margin (TRM)
Security margin that deals with uncertainties on the computed TTC values
• Unintended deviations of physical flows during operation due to the physical functioning of load-frequency control (LFC)
• Emergency exchanges between TSOs to deal with unexpected unbalanced situations in real time
• Inaccuracies, e. g. in data collection and measurements
In practice: Typically TRM is agreed and fixed for longer time period.
Usually it is defined as fixed figure (50, 100, 150 MW), or as percentage of TTC.

6. Definition of Transfer Capacities: NTC, ATC
Net Transfer Capacity (NTC)
Maximum exchange program between two areas compatible with security standards applicable at each system, taking into account the technical uncertainties on future network conditions
NTC = TTC – TRM
Already Allocated Capacity (AAC)
Already allocated transmission rights
E.g. at previous auction rounds
Available Transmission Capacity (ATC)
A part of NTC that remains available, after each phase of the allocation procedure, for further commercial activity.
ATC = NTC- AAC
ATC IS A SUBJECT FOR ALLOCATION!

7. Definition of Transfer Capacities: Programs vs. Physics
In meshed systems, typically program values are different than the physical flows
Notified Transmission Flow (NTF)
Physical cross-border flow between the considered areas observed in the base case It results from the Base Case Exchanges (BCE).
The additional physical flow ΔFmax is the physical flow over the tie lines between the two areas, induced by the maximum generation shift ΔEmax.
Total transfer Flow (TTF) is the net physical flow across the border associated with an exchange program of magnitude TTC
TTF = NTF + ΔFmax
Difference in program and physical values is not expected as a major effect at Caucasus region, since systems are not highly meshed...

8. Definition of Transfer Capacities: Programs vs. Physics
… but difference in program and physical values can appear.
possibly: part of program AZ-GE could flow over RU, in case of “triangle” synchronous connection AZ/GE/RU.
It is OK, as long as the network is secure.

9. Loop flows
Continental Europe is highly meshed system> schedules and real flows often differ a lot > LOOP FLOWS (WHEELING)
As long as network security is OK, electricity wheeling is acceptable phenomena, manageable by scheduling and accounting mechanism.
“My electricity can flow over the third systems, as long as it comes to the destination.”
Security: enabled in advance, through capacity calculation & load flow analyses. Real-time dispatch measures are the last resort solution.
Transit compensation is resolved in multilateral mechanism, post festum: Inter-TSO Compensation (ITC) mechanism.

10. NTC Calculation Procedure
Generation is increased stepwise in control area A and decreased in control area B giving rise to power flow from area A to area B.
In each step the security criteria (static and dynamic) is checked
This is done up to the point where security rules are violated
in system A, or
in system B, or
in some neighboring systems highly dependent on transactions among A and B
Resulting: ΔEmax value
NTC = BCE+ΔEmax-TRM

11. NTC Calculation Procedure
Bilateral vs. Composite NTC (for meshed networks…)
TTC calculation in the presence of a transit system
In calculation of e.g. NTC GE->TR, and if all generation reserve in GE would be used in calculation, and still no critical contingencies appear, the calculation can be continued with increasing generation in Azerbaijan.

12. Generation Shift Keys
Proportionally to the engagement of the generation units in base case
Fast calculations
No additional information except base case network model
No engagement in base case no engagement in generation shift
Non-feasible generation patterns
Priority list of generation units
Common operational practice
Can be made according to economic dispatch or market prices
Additional information in form of generation shift list
Realistic scenario

13. Generation Shift Keys
Proportionally to the active power reserve in respective units
Shift is shared among the engaged generators according to their remaining reserve
Real capability of the generation units
Additional information about Pmin and Pmax (comprised into corresponding network model)
minimum permissible generation
(for the generators participating in decreasing)
new increased generation
new decreased generation
step of the generation shift
maximum permissible generation
(for the generators participating in increasing)
active power generation of
respective production unit

14. Static security calculations
Static security assessment – Normal contingencies
Generator
Transmission circuit (overhead, underground or mixed)
Transformer between two voltage levels of the transmission system
Shunt device (capacitors, reactors)
Single DC line
Equipment for load flow control (phase shifter, FACTS, HVDC back-to-back station…)
A line with two or more circuits on the same towers if a TSO considers this appropriate and includes this contingency in its normal contingency list
Static security criteria
Imax for transmission lines (in Amps) / (usually first step of overcurrent protection)
Apparent power for the transformers (in MVA) (usually first step of overcurrent protection)
Permissible voltage ranges
Some critical contingencies can be neglected due to:
imperfection of the used network model
preventive & fast post-event measures (remedial actions)
low probability according to existing experience

15. Dynamic security calculations
Dynamic security assessment – rotor angle stability, frequency stability, voltage stability in case of network disturbances (normal contingencies of network elements, symmetrical or unsymmetrical faults cleared by primary protection system etc.)
Dynamic security criteria
Small-disturbance (or small-signal) rotor angle stability - ability of power system to maintain synchronism under small disturbances
Large-disturbance rotor angle stability or transient stability - ability of the generators to maintain in synchronism after a severe disturbance (such as a short circuit on a transmission line or bus)
Frequency stability - ability of a power system to reach and maintain a stable operating point following a severe disturbance
Voltage stability - ability of a power system to maintain acceptable voltages at all buses in the analyzed network under normal conditions and after a disturbance

16. NTC in case of HVDC links
HVDC ties - in present case line Akhaltsikhe-Borchka: connects two synchronous areas: IPS/UPS (GE, AZ, RU…) and ENTSO-e (TR, BG, GR…)
Capacity of HVDC known and stabile, not an issue in NTC calculation GE-TR, but
Network states of surrounding grids of GE and TR should be checked through NTC calculations
“Serial” NTC calculation to be done:
From GE to HVDC (GEgen++, HVDC--)
From HVDC to TR (HVDC++,TRgen--)
Maximal possible value for both is the HVDC capacity.
If maximum (HVDC full capacity) is not reached, then minimum among the two parts of NTC should be adopted as common NTC (GE TR)
Note: Outage of HVDC itself should be checked in n-1, monitoring static and dynamic stability due to large imbalance in both areas

17. NTC results harmonization
Two neighboring TSOs typically should both calculate the NTCs for the same border/direction
The best practice: harmonization of results, checking issues (especially for problems encountered in other TSO’s area)
Rule: If no agreement, lower of the two values to be taken as common NTC

18. NTC Calculation Procedure
Reference model
Monthly model
LF Calculation
DYN Calculation
Limit checking
Calculation setup
Corrections
Monitoring and Contigency lists
Area definition
Generation shift
Calculation parameters
NTC calculation
Results
Critical outages
Report (NTC form)

19. Monitoring and contingency lists/Area definition
Calculation Setup – PSS/E
Monitoring and contingency lists/Area definition

20. Calculation Setup – PSS/E
Generation shift procedure
semi-automatic via SCAL function (option proportionally to base case generation)
other generation shift options manually or with Python files
Python (or .idv) file can be saved as incremental change
Enabled only in the automatic file recording!!!

21. Calculation Setup – PSS/E
Setting up the calculation parameters
Area interchange should be updated, set value in 2-terminal DC, LF for new regime
Inter-area transfer

22. NTC Calculation – PSS/E
NTC results, critical outages
AC Contingency solution
AC Contingency Report
Complete procedure should be re-run, until critical contingencies are discovered

23. I CAPACITY CALCULATION
Introduction
Definitions of transfer capacities (TTC, TRM, NTC, ATC)
NTC calculation procedures
Generation shift keys
Static security calculations and criteria
Dynamic security calculations and criteria
NTC calculation in case of HVDC interconnections
NTC results harmonization
II CAPACITY ALLOCATION
Capacity allocation principles and methods
Market/non-market based
Explicit/implicit
Transaction-based methods (NTC/ATC based)
Flow-based methods
EU legislation regarding the Capacity Allocation

24. Introduction European electric power system:
Initially interconnected for reliability reasons
More recently, these systems are used for commercial purposes through exchange contracts
Limited cross-border transfer capacities need to be allocated to various market players by clear rules
Congestion:
Physically: when network element is overloaded (in full topology, or would be in case of outage (n-1))
Commercially: when more MW requests then capacity for the transfer at certain profile (e.g. border)

25. Introduction Cross-border transmission capacity allocation means
Process of in-advance allocation of transmission capacities (primarily at borders between systems/countries) to the electricity market players
Cross-border Transmission Capacity allocation is an
Essential part of Congestion Management process
which also considers load flow analyses such as Day Ahead Congestion Forecast and operational measures, such as redispatching or topology actions.

26. Cross-border capacity allocation principles
and methods: differentiation
There are many different ways to classify European capacity allocation methods usually realized through auctioning procedure (Currently annual and monthly capacity allocation are carried out in explicit way through auctions):
Level of coordination: Bilateral, with capacity split (e.g. 50:50, each TSO organize separate allocation, at “its” half)
Bilateral, joint (100% capacity jointly allocated)
Coordinated, multilateral (at multiple borders/directions, at once)
Technical: Transaction-based (NTC or ATC, as transaction-based limit, one value/direction.
Bilateral or coordinated)
Flow-based (PTDF/Maxflow, complex coordinated method, following physical flows.
For highly meshed systems)
Subject to allocation: Explicit (allocation of transmission capacity only, electricity trade is a separate
process)
Implicit (trade of electricity, transmission capacity obtained “implicitly”, together with
electricity trade)
Market-based or no: Market-based (price offered for the capacity is a subject to the allocation algorithm)
Non market-based (Capacity allocated by the methodology that does not
consider/require price offers)

27. Non-market based methods
Non-market based methods for NTC allocation are:
Capacity reservation
Practically not allocation method. National power utility, being at the same time owner of the network, reserves the transmission capacities for their own needs, rarely allowing others to pass.
Priority list (first-come, first-served)
The fractions of the transmission capacity are provided to the market actors, according to the order of their application.
Pro-rata rationing
If the requested capacity is higher than the offered ATC, each participant obtains the smaller portion of capacity, in proportion to its request.

28. Market based methods Market based methods for NTC allocation are:
Explicit Auctions,
Implicit Auctions (and its advanced coordinated versions, like market splitting/coupling)
Market-based methods: “No congestion – no payment principle”
Market based methods require the offer in money for the transmission capacity, and ranks the offers according to the price.
The main principle with universal application at all public lines in Europe, is “No congestion – no payment”:
This means, that if the sum of the requests is lower then the ATC, participants do not pay for the capacity.

29. Explicit Auctions based on ATC
Explicit auctions are the most common allocation method in Europe (for annual and monthly, for day ahead and intraday are implicit), whether as
with capacity split 50:50,
as joint auctions on 100% of ATC
or even coordinated at multiple borders (CEE currently)
PROCESS:
Auction calendar is published,
with the schedule of actions
and dates
Explicit auctions could be the right choice for BSTP, whether jointly, or at least with 50:50 capacity split.

30. Explicit Auctions PROCESS (cont’d):
- Calculation, publication of the NTC and ATC values, between the two TSOs. Both TSOs calculate the NTC and then communicate the results. If no agreement, lower value is accepted.
At some borders, TSOs reserve the fraction of capacity (calling it AAC, even if never allocated at some earlier rounds), and exempts it from the third party access, for “tariff supply” needs
- At capacity requests date, registered market participants send their requests, defining period, requested capacity in MW, and offered price. (fax, web-based software)
After the gate closure, all offers are validated, and ranked, starting from the ones with highest offered price. Offers up to the value of ATC are accepted.
After the auction, results are published, and market actors pay for a “promise of capacity”
Later: Use-it-or-loose-it; use-it-or-sell-it

31. Explicit Auctions: example capacity publication
Published capacities for monthly auction for July 2011, at border Serbia-Hungary (

32. Explicit Auctions: example results
Auction result of monthly auction for July 2011, at border Serbia-Hungary (

33. Implicit Auctions
Through a single contract, capacity and electricity are traded at the same time, which is the main difference from the explicit auctions.
Transmission capacity is "implicitly" allocated among the participants, based on the offered price of electricity.
Allocation of capacity is based on the bids of suppliers on one side of the border (e.g. TSO “A”), which are ranked in the spot market, which is located across the border (e.g. TSO “B”), for the claims of local consumers in TSO B area.
NTC has been awarded to suppliers by ranking their offers for the lease of capacity and electricity starting from the cheapest, while NTC (ATC) is not fully allocated.
A prerequisite for the existence of implicit auctions is a Power Exchange (Power Stock Market).

34. Market splitting, market coupling
Market splitting: An upgrade of implicit auctions principles.
Needed existence of Power Exchange in each of the areas / zones, or a single Power Exchange responsible for all areas / zones, and such advanced organization is existing in Scandinavian countries (Nordpool).
Market is divided in clearly defined geographical areas with NTCs defined in-between.
for the whole region the unique price is defined firstly
in case of noted congestions, areas are split, with different local prices
the trade is allowed between the areas, up to the value(s) of NTC
Market Coupling: similar method, applied at some borders of Central-Western Europe. At this variant, the algorithm starts with separate prices per areas, which are then “coupled” up to the value of NTC.

35. Redispatching
Redispatching (or counter-trading): not a capacity allocation method, but
Rather a corrective measure, applied close to real time, if TSOs notice physical network congestion, even if before the capacity allocation was properly applied (but e.g. due to the power wheeling out of the allocation border, some congestion occurs).
TSOs can have specific contracts with power plants “upstream” and “downstream” of the congestion, and in case of a need, they initiate a power transaction with a direction opposite to the congestion, and thus relieve it.

36. Flow-based methods
NTC allocation simple, but can cause problems in extremely meshed networks. Also in some cases NTC method is rather conservative and too much on the safe side
Flow-based methods: calculation of so-called Power Transfer Distribution Factors (PTDF), which provides information on relation of contractual exchanges and physical flows at network elements.
Influence of all transactions converted to the physical flows at predefined critical network elements (Critical Branches – CB), and that for the full “base case” topology, and for the case of Critical Outages – CO.
These influences superposed up to the value of physical limitation per CB, Available Maximum Flow (AMF)
Method complex, requires strong coordination
Preparation in Central-East Europe, investigated in South-East Europe
Central-West Europe is heading towards Flow-Based Market Coupling (implicit flow-based auctions)

37. PTDF matrix
The sensitivities of the critical branches are called PTDFs (Power Transfer Distribution Factors).
These FB parameters are calculated in the following way:
The PTDFs are calculated by varying the exchange program of a zone (=market area), taking the corresponding GSK (Generation Shift Keys) into account.
For every single zone-variation the effect on every CB loading is monitored and the effect on the load flow is calculated.
The GSK for the zone has an important influence on the PTDF, as it translates the zone-variation into an increase of generation in the specific nodes.
For example, additional export of some zone of 100 MW has an effect of 10 MW on a certain CB => PTDF = 10%).
The PTDF characterizes the linearization of the model. In the subsequent process steps, every change in the export programs is translated into changes of the flows on the CBs by multiplication with the PTDFs.

38. NTC/ATC vs Flow-based NTC, i.e. ATC-based:
single programme constraint per border for commercial transactions
Flow-based (PTDF/MF):
set of physical constraints MF per network elements, and sensitivity factors (PTDF)

39. Requirements of EU legislation regarding the Capacity Allocation
According to the Congestion Management Guidelines of Regulation 714/2009 of European Commission (EC), the market based methods are required to be applied at European borders, i.e. auctions.
Moreover, the coordinated methods among the multiple TSOs are required to be applied, where Europe is divided in different regions to apply the coordinated congestion management.
Flow-based methods are more and more preferred, as well as enhanced combinations, like Flow-based Market Coupling.
Network Code on Capacity Allocation and Congestion Management (ENTSO-e) entered into force in August 2015 (
It becomes EU-wide law
Requiring implicit auctions at day-ahead and intra-day level

40. NTC/ATC and Flow-based in Europe
Flow Based market coupling has been implemented in the CWE region for over a year after over a decade of testing.

41. Flow-based parameters
Determined by TSOs based on the underlying network data and security analyses
The Remaining Available Margin (RAM)
RAM = Fmax – Fref – FAV – FRM
Fref – Base Case reference flows
FAV – Final adjustment value representing remedial actions
FRM – Flow reliability margin is a safety margin compensating for approximations and simplifications of the FBMC methodology
The zonal PTDFs
Calculated through Generation Shift Keys (GSK) –assumed nodal contribution of the zonal net export.
GSKs intend to predict the power plants that would be called in case of net export change.
Each TSO calculates the GSKs for its own control area in its own way.
Patches
Undesirable solutions can avoided by “patches”, i.e. by adding or modifying constrain
Pre-congestion cases
The “Intuitive” patch
Flow-factor competition in times of scarcity

42. Simplified calculation example, for one CB at one CO
Flow-based: PTDF/MF calculation, definitions CEE/SEE, vs CWE
Simplified calculation example, for one CB at one CO
CWE:
Fmax
FRM /
inside FRM
Fref’
RAM
CЕЕ, SЕЕ:
Total Maximum Flow, TMF: Full capacity of element (MW): ТМF=3*U*Imax*cosФ
Flow Reliability Margin, FRM: General Margin
Base Flow (BFL): Shift for Base Case Flow
(local, outside, loop flows)
Base Flow Reliability Margin, BFRM: marging for the statistical uncertainty of outside flows (non-FB regions)
Already Nominated Flows, ANF: flow due to forward nominations
Available MaxFlow, AMF: Available for current auction
FRM
BFL
BFRM -
BFRM+
ANF
AMF -
AMF+

43. EXPERIENCE WITH CWE FB MARKET COUPLING
From technical perspective the system works
Bigger social welfare
Higher price convergence
Better utilization of transport capacities
Market transparency
From traders' point of view: the results are MUCH LESS PREDICTABLE
Variation in PTDFs (capacity domain) is great source of uncertainty
CWE Consultative Group – platform for further discussions
It seems that forecasting PTDFs is a big problem for many market participants

44. Applicable allocation methods for BSTP
Calculation and allocation of cross-border capacity should be applied at the directions where congestions are expected, by the requests of multiple market actors.
NTC/ATC limit and allocation can be defined even for the cases of island operation, or at the back-to-back connection
Transaction-based methods should be applied, i.e. those related to the calculated and published value of NTC/ATC
In NTC calculation, standard security criteria should be applied, plus the stability calculation where and when needed, according to the experience and practice by the local experts
As a first step, explicit bilateral auctions could be the right choice for allocation method, whether jointly, or at least with 50:50 capacity split.

45. Questions and Discussion45