ENERGY TECHNOLOGY AND GOVERNANCE PROGRAM Black Sea Transmission

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.

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 • Introduction • Capacity allocation principles and methods o Market/non-market based o Explicit/implicit • Transaction-based methods (NTC/ATC based) • Flow-based methods • EU legislation regarding the Capacity Allocation

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 • Introduction • Capacity allocation principles and methods o Market/non-market based o Explicit/implicit • Transaction-based methods (NTC/ATC based) • Flow-based methods • EU legislation regarding the Capacity Allocation

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 4

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.

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!

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. . .

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.

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.

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

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. 11

Generation Shift Keys n 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 ¨ n 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 ¨

Generation Shift Keys n 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) new increased generation new decreased generation minimum permissible generation (for the generators participating in decreasing) step of the generation shift active power generation of respective production unit maximum permissible generation (for the generators participating in increasing)

Static security calculations n Static security assessment – Normal contingencies ¨ ¨ ¨ ¨ n 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 ¨ n 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 ¨

Dynamic security calculations n n 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 ¨

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: 1) From GE to HVDC (GEgen++, HVDC--) 2) 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

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

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

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

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!!!

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

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

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 • Introduction • Capacity allocation principles and methods o Market/non-market based o Explicit/implicit • Transaction-based methods (NTC/ATC based) • Flow-based methods • EU legislation regarding the Capacity Allocation

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)

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.

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: “its” half) Bilateral, with capacity split (e. g. 50: 50, each TSO organize separate allocation, at 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)

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.

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.

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) Explicit auctions could be the right choice for BSTP, whether jointly, or at least with 50: 50 capacity split. PROCESS: Auction calendar is published, with the schedule of actions and dates

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

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

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

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).

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.

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.

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)

PTDF matrix • The sensitivities of the critical branches are called PTDFs (Power Transfer Distribution Factors). • These FB parameters are calculated in the following way: o The PTDFs are calculated by varying the exchange program of a zone (=market area), taking the corresponding GSK (Generation Shift Keys) into account. o For every single zone-variation the effect on every CB loading is monitored and the effect on the load flow is calculated. o 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. o 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.

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

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 (https: //www. entsoe. eu/major-projects/networkcode-development/capacity-allocation-andcongestion-management/Pages/default. aspx) It becomes EU-wide law Requiring implicit auctions at dayahead and intra-day level

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.

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 o Fref – Base Case reference flows o FAV – Final adjustment value representing remedial actions o FRM – Flow reliability margin is a safety margin compensating for approximations and simplifications of the FBMC methodology • The zonal PTDFs o Calculated through Generation Shift Keys (GSK) –assumed nodal contribution of the zonal net export. o GSKs intend to predict the power plants that would be called in case of net export change. o Each TSO calculates the GSKs for its own control area in its own way. • Patches o 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

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

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

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. o 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.

Questions and Discussion