1. SLED scenario assessment for Albania
László Szabó, PhD – András Mezősi PhD
Regional Centre for Energy Policy Research
Tirana, Albania
October 26, 2015

2. Outline of the presentation
1. Modelling methodology
2. Scenario definitions
Main assumptions on demand supply and taxation
Input data
3. Model results
Prices
Generation mix
Carbon emissions
RES support costs
Investment costs

3. Methodology The SLED analysis is based on assessing three scenarios:
Reference scenario (REF);
Currently Planned Policies (CPP);
Ambitious Climate Scenario (AMB).
Scenario assumptions were related to six dimensions:
carbon value;
energy/excise tax;
environmental standards;
deployment of renewable energy technologies;
deployment of conventional generation technologies; and
electricity demand (integrating assumptions on end-use energy efficiency improvement).
Main tools: Electricity Market Model and Network model

4. 1. European Electricity Market Model and EKC network model

5. Introduction
Market impacts in the three analysed scenarios of SLED (REF, CPP, AMB) are modelled with REKK European Electricity Market Model (EEMM)
Highlights:
Electricity trade is modelled within the whole EU
Hydro generation is modelled under average rainfall conditions, but in the sensitivity assessment the impacts of dry years are also simulated
Fossil generation modelling is important even in Albania, as in the future two gas fired blocks are planned.

6. Model functionality 6 Comments:
The map shows the main results of the model:
Competitive market equilibrium prices by countries
Electricity flows and congestions on cross-border capacities
36 countries are handled in the model.
Morocco, Tunisia, Turkey, Moldova, Russia and Belarus are considered as exogenous markets
In these markets the net export position are equal with the fact in 2013 (assumed a baseload flow)
The model is calculating the marginal cost of around 5000 power plant blocks and sets up the merit order country by country.
Taking into consideration the merit order and exports/import, the model calculates equilibrium prices.
Power flow is ensured by 85 interconnectors between countries. 6

7. Basic economics in the model
Competitive behavior by power generators
„if someone is willing to pay more for my energy than what it costs me to produce it, then I will produce”
Prices equalize supply and demand
Efficient cross-border capacity auctions
„we export electricity to wherever it is more expensive and import from wherever it is cheaper”
Capacity limits
in production and cross-border trade
Large country prices around the region are exogenous to the model, the rest are determined by the model

8. Economic description and main assumptions
Main inputs and outputs of the model
Main model assumptions
The applied model is a partial equilibrium microeconomic model in which a homogeneous product is traded in several neighboring markets.
Production and trade are perfectly competitive, there is no capacity withholding by market players.
Production takes place in capacity-constrained plants with marginal costs and no fixed cost.
Electricity flows are modeled as bilateral commercial arrangements between markets with a special spatial structure.
Power flows on an interconnector are limited by NTC values in each direction.
Fuel prices reflect power plant gate prices, transportation/ transmission costs are taken into consideration.
Only ETS countries buy CO2 allowances
The model calculates regional power supply – demand balance at certain capacity and import/export constraints
Demand evolution, power plant capacities, availability and cross border power flow defines market price
Fuel prices are estimated based on available information

9. Model characteristics
In a year 90 reference hours are modelled, representing well the daily, weekly and seasonal variations
Power plant data comes from international database (PLATTS), but modelled country capacity data are coming from national sources of information
Future capacity expansion are from national strategic documents
Fossil fuel prices are based on international forecasts of EIA and IEA.
Natural gas price projections depend on the country:
TTF Spot price (Western Europe)
OIL index price
Mix of oil index and spot price

10. Components of marginal cost

11. Efficiency parameters, utilization rates
Taken from literature; dependent on the commission year and the type of the PP
Availability/utilization rates:
Hydro availabilities: dependent on country and season (based on historical utilization rates)
Wind an PV: taken from JRC

12. Determining short-term marginal cost=
Fuel cost +
CO2 cost
Variable part of the OPEX
Energy tax

13. Merit order curves - examples

14. Modelled baseload prices in 2015 (€/MWh), and the yearly trade flows14

15. Modelled baseload prices in 2025 (€/MWh), and the yearly trade flows15

16. Model output Equilibrium price in a demand period
Baseload and peakload prices
Electricity trade between countries
Price of cross border capacities
Production by plants
Gas consumption
CO2 emission

17. EKC network model was used for the assessment
Network modelling
EKC network model was used for the assessment
Representatives hours of years 2020 and 2025 were modelled, to assess the network impacts on the whole region
The following assessments were carried out:
Steady-state and contingency analyses
Evaluation of net transfer capacity
Transmission grid losses

18. 2. Scenario definitions

19. Outline
Main information sources
The consultation process
Scenario definitions
Main input data to the models

20. Main information sources
Assessment of Energy Developments in Albania for the period 2012–2030 (USAID, January 2015) – providing demand and RES assumptions
Draft National Renewable Action Plan, June 15, 2015 (received from the Ministry of Energy in July 2015 as a document under revision)
National Renewable Action Plan of Albania (Ministry of Energy, 2014)
National Energy Efficiency Action Plan for the Republic of Albania 2010
National Background Report on Energy for Albania, 2012 (WBC-Inco)

21. The consultation process
A two-phase feedback-loop was built in the SLED project:
2014: consultation on main scenario assumptions
2015: preliminary results were delivered - further alignment of assumptions and data – to reflect the INDC process of the country
Timeline:

22. SLED Scenario definition- Reference
Scenario assumptions
Reference GHG scenario (REF)
Taxation
Introduction of EU ETS
ETS to be introduced in 2025
Introduction year of minimum excise duty
Year of introduction: 2020
Electricity supply
Enforcement of environmental standards (LCP Directive)
Due to the requirements of the LCP Directive, Fier TTP is not in operation in the modelled period.
RES-E deployment
NREAPs: 2,324 MW hydro; 30 MW wind; 32 MW PV; and 5 MW biomass by By 2030: 2,710 MW hydro; 100 MW wind; 79 MW PV; and 24 MW biomass.
Conventional capacity developments
CCGT Vlora I ( 200 MW) comes online in 2020 and CCGT Vlora II (160 MW) comes online in 2025.
Electricity demand
According to the June 2015 draft NREAP projections up to In the next period, a 3.1% growth rate is applied, which is a continuation of the trend between 2010 and : 12,990 GWh.

23. SLED Scenario definition- CPP, AMB
Scenario assumptions
Currently planned policies GHG scenario (CPP)
Ambitious GHG policy scenario (AMB)
Taxation
Introduction of EU ETS
CO2 cost in 2020 is 40% of the ETS price; from 2025 ETS is introduced
ETS to be introduced in 2020
Introduction year of minimum excise duty
Year of introduction: 2020
Year of introduction: 2018
Electricity supply
Enforcement of environmental standards (LCP Directive)
Due to the requirements of the LCP Directive, Fier TTP is not in operation in the modelled period.
Due to the requirements of the LCP Directive, Fier TPP is not in operation in the modelled period.
RES-E deployment
NREAPs: 2,324 MW hydro; 30 MW wind; 32 MW PV; and 5 MW biomass by By 2030: 3,097 MW hydro; 170 MW wind; 126 MW PV; and 42 MW biomass.
NREAPs: 2,324 MW hydro; 30 MW wind; 32 MW PV; and 5 MW biomass by By 2030: 3,869 MW hydro; 310 MW wind; 220 PV; and 80 MW biomass.
Conventional capacity developments
CCGT Vlora I. ( 200 MW) comes online in 2020 and CCGT Vlora II (160 MW) comes online in 2025.
CCGT Vlora I (200 MW) comes online in 2020 and CCGT Vlora II (160 MW) comes online in 2025.
Electricity demand
According to the USAID Energy Efficiency–Natural Gas scenario : 10,918 GWh
According to the USAID Energy Efficiency– Renewable–Natural Gas scenario : 10,857 GWh

24. Harmonisation between USAID and SLED scenarios
Correspondence between USAID and SLED scenarios:
USAID scenarios were modified in two main fields:
Electricity consumption
Renewable capacity deployment
Scenario
USAID model scenarios
EEMM model scenarios
Reference
Passive scenario
REF
Currently planned policies scenario
Energy Efficiency-Natural gas Scenario
CCP
Ambitious GHG reduction scenario
Energy Eff,-Renewable- Natural Gas Scenario
AMB

25. Electricity consumption
Reference: consumption forecast of NREAP up till 2020, than 3.1% growth rate (average of the previous ten years)
CPP and AMB corresponds to the USAID energy efficiency and energy efficiency + renewables scenarios

26. Renewable electricity assumptions
Till 2020 we stick to the draft NREAP (2015) values in the various RES-E technologies
AMB scenario: USAID modelled growth rates between
CPP scenario: 50% of the growth rate of AMB after 2020
REF scenario: 25% of growth rate of AMB after 2020
In this way capacity development is deteremined, while production is forecasted by the model up till 2030 assuming country specific utilisation hour (solar and wind) and average rainfall for hydro

27. REFERENCE scenario capacity values (MW)
RES-E capacities 1
REFERENCE scenario capacity values (MW)
REF scenario
2015
2016
2017
2018
2019
2020
2025
2030
Hydro*
1,801
1,893.5
1,941
1,991
2,264
2,324
2,538
2,710
Pumped storage
Geothermal
Solar 2 5 10 16 24 32 54 79
Wind 4 20 30 63
100
Biomass
REF + here some technologies are over presently set limits, e.g. wind 150 MW

28. AMBITIOUS scenario capacity values (MW)
RES-E capacities 2
AMBITIOUS scenario capacity values (MW)
AMB scenario
2015
2016
2017
2018
2019
2020
2025
2030
Hydro*
1,801
1,894
1,941
1,991
2,264
2,324
3,179
3,869
Pumped storage
Geothermal
Solar 2 5 10 16 24 32
120
220
Wind 4 20 30
160
310
Biomass 80

29. Present cross-border capacityHR HU
758
429
689
507 RS BA
403
488
162
250 BG
253
440
223
491 96
483
215 ME MK GR
329
151
400
223 IT
250
400
250 AL

30. Planned cross-border capacitiesHR HU RO
800
800 RS BA
600
600 BG
500
600
600
1000
400
600
600
Under construction and approved categories are used in the model runs till While AL-MK is also built, IT-AL is not realised in the modelling period. ME MK GR
1000
600
1000
600
500 IT
500
500 AL

31. Present installed capacity
Assumed capacities I.
Present installed capacity
New, planned non RES-E capacities
In Albania two CCGT plants are assumed in all scenarios according to official energy strategy:
CCGT Vlora I ( 200 MW) comes online in 2020
CCGT Vlora II (160 MW) comes online in 2025

32. 3. Scenario Assessment Results

33. Wholesale price impacts Generation mix, CO2 impacts
Outline
Wholesale price impacts
Generation mix, CO2 impacts
Impacts on system costs:
Investment costs,
RES support costs
Sensitivity assessment: Impacts of reduced rainfall
Network impacts
Contingencies
NTC valuations
Network loss impacts

34. Modelling result – baseload electricity price, €/MWh in real term

35. Modelling result – peakload price, €/MWh in real term

36. Wholesale price evolution
Both baseload and peakload electricity wholesale prices have a significant drop between , followed by a slight increase in the later period.
The main factors influencing the wholesale price developments in Albania are the followings:
Generation expansion in the fossil based generation in the region is high. Over 7000 MW capacity (mainly lignite and coal) is built in the countries: AL; BA; BG; GR; HR; HU; ME; MK; RS; RO according to the national plans
New RES capacities above MW are also contributing to the price drop till 2020.
Higher interconnectedness in the region also allows trade of electricity (higher NTC)
These new capacity expansion is illustrated in the following slide for the region

37. New PPs in the wider region*
New coal-based power generation, MW
New RES-E generation capacity, MW
Region includes the following countries: AL; BA; BG; GR; HR;HU; ME; MK; RS; RO;

38. Electricity mix

39. Generation mix and CO2 emissions
Albania is characterised by expanding hydro capacities and significant net import share till 2030 in all scenarios to satisfy increasing demand for electricity
Although there is 360 MW of natural gas capacity installed in the CPP and AMB scenario is characterised by a close to zero (3 kt CO2) emissions by It is due to the fact that the plant is running at very low level according to the modelling results (<50h).
Other than hydro RES is only appear in the AMB scenario from 2020, however their contribution become significant only in 2030.
The results show, that the Albanian electricity system could cover electricity demand without installing both gas plants. The results question the economic rational for the investment in the planned gas capacities (360 MW), mainly the second phase, as the resulting utilisation rate the investment will have no chance to recover any cost. Gas is not competitive enough compared to import, at the assumed prices
In addition import is quite limited in the CPP and AMB scenarios

40. Total investment cost of new PPs, m€, 2015-2030
Source of investment cost: Serbian Energy Strategy and Fraunhofer (2013)
There is a significant investment cost need in the various scenarios:
The Reference scenario has a 2.8 Billion € investment need over the following 15 years period, increasing over 6 Billion in the AMB scenario due to the higher RES expansion and to the gas plants. If this latter one is avoided. In this case investment cost would be below 6 Billion €.
The main contributing part is still hydro investments, but these are still the most economical RES options in the country.

41. Calculation of the RES-E support budget
Support budget = (LCOEt-P)*Generated electricity
LCOEt: Levelized cost of electricity generation of technology t ~ average cost of electricity production
P: Modelled baseload electricity price (except PV, where peak load electricity prices are taken into account)
LCOE figures are based on literature data (Ecofys, 2014)
55 €/MWh for hydro
90 €/MWh for wind
110 €/MWh for biomass
105 €/MWh for PV
80 €/MWh for geothermal
Baseload and peakload prices are the results of the modelling
RES fee = RES support budget/ electricity consumption

42. Yearly RES-E support need, m€/year

43. Unit RES-E support, €/MWh

44. RES-E support
Present FIT support for new hydro is set around 70 €/MWh for capacities up to 15 MW
LCOE values show that this level of support will be sufficient to cover Hydro based generation, but other types of RES-E would require higher rates.
The higher rates for the AMB scenarios shown in previous figure is due to the new RES capacities in biomass, PV and wind, so careful timing of these capacities should be planned. In PV and Wind high cost saving could still appear due to the technology learning effect.

45. Sensitivity runs: dry years
In order to check the impacts of a dry year sensitivity runs were carried out on all scenarios:
A severe drought is modelled (lowest precipitation of last 8 years)
Droughts assumed to take place in the whole region of South-East Europe
Capacity values are the same as in the original scenarios, but hydro availability reduced according to the reduced rainfall

46. Impacts of reducing rainfall 1

47. Impacts of reducing rainfall 2

48. Impacts of reducing rainfall 3

49. Network modelling results - contingencies
The increasing consumption level and new generation pattern causes problem in the network of Albania as shown in the table
In all scenarios, tripping of the line OHL 220 kV Fierza (AL) – Titan (AL) leads to overloading OHL 220 kV VauDejes (AL) – Komani (AL). New OHL 220 kV Komani-Titan solves this problem (70 km).

50. NTC change with neighbours
2025 summer
Higher RES penetration has varying impact on NTC
The highest positive difference could be observed with RS, so trade opportunities increase in this directions, while in the other directions the impacts are mixed
2025 winter

51. Transmission losses
An increase in capacities and consumption levels generally increases losses over the modelled period, although the results also show that the AMB scenario, with an increased level of distributed generation, will reduce the overall loss level compared to the CPP scenario.

52. Conclusions 1
The stringency of climate policy commitments has limited impact on wholesale price development. The wholesale price is dependent on regional generational capacity expansion rather than on the ambition level of climate policy.
Albania is currently a net importer of electricity and continues to be an importing country in the REF and CPP scenarios. However, in the AMB scenario the country could become an exporter of electricity by This is due to the lower demand and the significant increase in hydro-based generation
CO2 emissions remain minimal in the modelled period even with the construction of the two CCGT plants. Albania has the least carbon intensive electricity system in Europe, due to its hydro-based generation, and continues to hold this position.
Albania could still develop significant capacities in hydro generation, which could be a very valuable asset for the future operation of the electricity system. At present, further deployment is constrained by security of supply considerations: the country would like to reduce its dependence on hydro, which is very sensitive to meteorological conditions (precipitation levels and patterns).

53. Conclusions 2
Our sensitivity assessment confirms that Albania is sensitive to meteorological conditions: in the short term, severe droughts could drive up prices by EUR 10/MWh, and in the long term by EUR 4/MWh. In such a year the country would still rely heavily on imports, but in the AMB scenario imports could be significantly reduced.
However, the results also show that the planned two gas-fired CCGT plants would not help much in terms of the country’s security of supply (SoS), as imports would be more competitively priced. In addition, the necessary infrastructure to supply gas in the country is still lacking.
The hydro sensitivity assessment also points to an important future policy direction for the country. If further cooperation is enhanced within the region and with EU member states, the country could further utilise its hydro potential. In this case Albania could be very supportive towards a stricter EU renewable policy, as it would create more demand for its hydro-based generation.
The assessment of network impacts shows that the Albanian electricity system would require some network reinforcements in the future to cope with the planned RES capacity increase in the scenarios. If the planned network additions are not built, contingencies would appear in the system.