Gas and Petrol Infrastructure

Gas and Petrol Infrastructure

Existing gas supply:  The supply of natural gas in the West Balkans has been mainly ensured through long term import contracts with Gazprom supplying natural gas from Russian sources, together with and some domestic production. The exception is Croatia which has been buying gas on short term and spot contracts from other European suppliers for the last three years, together with domestic production. Domestic production in Serbia and Croatia accounts for around 25% and 65% of consumption respectively. The reserve levels in both countries, though small, in relation to domestic are still significant at 48 Bcm (Serbia) and 25 Bcm (Croatia) respectively. At current production levels the reserves would be depleted in 80 years and 14 years respectively, ie these are the current reserves/production ratios (R/P). With increasing demand, however, production levels are likely to rise and reserves would be depleted more quickly. In the other gas consuming countries in the region, ie FYR of Macedonia and Bosnia and Herzegovina, no significant domestic production exists and gas supplies are fully sourced from Russia.

In Serbia, where gas supplies from Russia constitute a more important source of supply than in Croatia, gas contracts were renewed in 201332. These are reported to ensure annual supply volume of 2.5 Bcm until 2021. Gas supplies in Serbia are complemented with one of two underground storage facilities in the West Balkan region, with a working gas volume capacity of 0.45 Bcm per year. In Croatia, the long term gas contracts with Gazprom were not renewed in 2010 and a 3-year contract with ENI for gas supplies from Italy was agreed. The volumes were reported to lie between 0.7 and 1 Bcm per year. In 2013, this contract was not renewed and gas supplies are expected to be purchased on the spot market from 2014 onwards 33. With the underground storage facility at Okoli (capacity of 0.6 Bcm 34), spot and market and short term contract supplies will be complemented with strategic reserves in Croatia. Production volumes are unlikely to increase, as they are already very close to their maximum capacity.

Any decision on South Stream is unlikely to change the prospect of the Trans Anatolian Pipeline (TANAP) and Trans-Adriatic Pipeline (TAP). Both projects are in development and will materialise over the next years regardless of South Stream. In fact, TAP has now become an even more important supply route for the region and it is likely that this will give the project even more traction and interest. The capacity will remain as planned at 10 Bcm, with potential extension to 20 Bcm, but additional offtake points in Greece and Albania might be prioritised more highly by the Governments of FYR of Macedonia, Albania and Greece.

The Croatian LNG project, which had been slow moving and even was stalled in 2013, is likely to receive additional impetus after the recent decision on South Stream. This is not only for the diversification of supply for Croatia, an EU member state, but also to secure additional supply sources for the wider region, which is heavily dependent on supplies through the Ukrainian transit pipeline. Serbia in particular might now have increased interest in connecting its gas market to those of its western neighbours to have access to the LNG terminal and a diversified supply route.

The Eagle LNG project is unlikely to be influenced significantly by South Stream. The majority of its 4-8 Bcm capacity is intended for the Italian market, which is not severely affected by South Stream. The project is therefore likely to proceed as planned with a targeted commencement date in 2017. Nabucco West could be revived if indeed the Black Sea II pipeline materialises and Turkey becomes a major gas pooling hub. We see the likelihood of the Turk Stream project to be developed as very low. The investment costs are likely to be as high (if not higher due to greater sea depth) as South Stream. Simultaneously, gas delivered to Turkey would have to be priced more competitively, as Turkey’s transmission costs are added for gas to reach its final EU destination market. However competition from Caspian gas, falling LNG prices and increased spot trading in Europe is likely to see Russian gas margins squeezed. This brings into question the commercial feasibility of the Black Sea II pipeline project and with it the development of Nabucco West. White Stream and Agri LNG are likely to see renewed interest, particularly from Bulgaria. However these projects have been dormant and to a certain extent superseded by TANAP and TAP. Both projects are costly and their development is now more probable than before South Stream cancellation, however still relatively low. These projects will largely depend on the financial and political support they receive from the EU.

Apart from large scale international gas supply projects, a number of pipeline and LNG projects within the West Balkan region have been identified as priority projects by the Energy Community Secretariat and its contracting parties. These projects were selected on the basis of a social cost benefit assessment and labelled as Project of Energy Community Interest (PECI). PECI projects are prioritised as key regional gas projects and their selection results in a higher likelihood (though not certainty) of funding from European and/or international financing institutions. The most notable projects for this study selected as PECI projects include:

  • The Ionian-Adriatic Pipeline (IAP) is a proposed gas pipeline forming part of the initially proposed EC Gas Ring. It connects Croatia (Split), Montenegro, Bosnia and Herzegovina and Albania (Fier) through a 525 kilometre pipeline. Cooperation among the countries has been progressing and a feasibility study on the project was completed in March 2014. In Croatia, the 5 Bcm/y bi-directional pipeline would be connected with the existing gas transmission system and in Albania it will connect to an offtake from TAP. The project is expected to cost € 620 million with the majority costs for the segment in Croatia (€ 330 million). A more detailed discussion on IAP is provided in the Annex.
  • The Serbia – Bulgaria gas interconnector – With an initially planned capacity of 1.8 Bcm/y, which can be increased to 4.5 Bcm/y, the bidirectional interconnector between Nis and Dimitrovgrad will expand import capacity for Serbia and enable Bulgaria to diversify its supply sources. The project already secured partial financing from European Structural Funds (‘EU Competitiveness Operational Programme’). However, the interconnector stalled over recent years, as it ran parallel to South Stream’s route. With South Stream cancelled, there is now a great opportunity for both Serbia and Bulgaria to develop this project and strengthen their gas supply security. As reverse flow on the Bulgaria Greece interconnector is now secured, this could provide access to the Greek LNG terminal at Revithoussa. o Interconnections Serbia – Croatia – the interconnection between the northern Serbian city of Backo Novo Selo and the north-eastern Croatian city of Slobodnica was initially designed to ensure Croatia’s access to South Stream. However it seems that now, the interconnector is of greater interest for Serbia to diversify its supply mix and potentially provide access to a more diversified gas market in Croatia (supply from Hungary and LNG once the project is developed). This project is still at very early stages of development and so far no clear commitments have been made of its development. Depending on Serbia’s reaction to events surrounding South Stream, this could become a key project for regional integration.
  • Interconnection Bosnia – Croatia – In total three interconnections between the countries have been selected as PECI projects. Two interconnectors are particularly worth highlighting: o Connection between Zenica (BiH) and the eastern Croatian city of Slobodnica. This would connect the largest demand centres in Bosnia with the potentially well diversified Croatian gas system. o Connection of Sarajevo with south-western Croatia (Ploce) and the IAP. This would also connect the Bosnian with the Croatian system, however its development would depend on the completion of the IAP. These projects have proven difficult to advance due to opposition to northern interconnections from Bosnia Herzegovina. Without a suitable alternative supply route (from South Stream), these projects could however gain additional traction.
  • Croatian and Albanian LNG projects – These were already presented in section 3.3.1.
  • Trans Adriatic Pipeline (TAP)



The agreement between Sofia and Brussels came the same day as a final investment decision was taken on the IGB pipeline that is expected to become operational in 2018. The pipeline will primarily deliver gas from Greek to Bulgarian opening up a vertical gas corridor in the region. The 180 km pipeline is designed to transport up to 5 Bcm/year in forward flow to Bulgaria and up to 2 Bcm/year in reverse flow. Romania could also help contribute to a regional hub as it works toward bringing online offshore gas discoveries. One is the major Domino (Neptun) discovery in Romania’s sector of the Black Sea which is thought to hold resources of up to 2.5 Tcf (71 Bcm).


The push for improved regional gas interconnectivity comes as first the South Stream project to bring 63 Bcm/year of Russian gas to southeast Europe was canceled, and now its replacement TurkStream is frozen. Although the EU had legal issues with South Stream, it would have provided the region with much needed diversity of route instead of having to depend on pipelines bringing Russian gas via Ukraine. The replacement TurkStream is designed to allow Russian gas to be sold on to Europe at its border with Turkey. But that project is on hold due to the political spat between Moscow and Ankara, so question marks remain over what sources of gas can help create a Balkan hub. There is gas from Azerbaijan set to come to Greece by the end of the decade.

The TANAP/TAP pipeline network that is currently under development will bring Azeri gas through Turkey to Greece, and with the IGB interconnector to Bulgaria in place gas could wind up there, helping create a Balkan gas hub in Bulgaria.

Romania is gradually unfolding its long-term natural gas strategy. It intends on becoming the major gas hub in the region and will exploit its domestic reserves.

The Azerbaijan-Georgia-Romania Interconnector (AGRI) project, oft-named the focal point of Bucharest’s regional gas strategy, aims to open yet another diversification route for the Caspian reserves into the EU markets by passing not only Turkey but also Greece and Bulgaria. The project got an initial kick-off in September 2010 when the participating states declared their intention of proceeding with that project, which also includes a substantial LNG infrastructure.

Gas is planned to be transferred from a terminal in Romania and then via an upgrade of the domestic pipeline transmission system in Hungary and from there it will branch out to the gas hub of Austria and further North to Slovakia, Czech and Poland. It will be an integral artery of the newly conceived Aegean-Baltic gas route.

Commenting to Natural Gas Europe in 2013, energy specialist Liana Jervalidze said, “We don’t see now immediately chances for this project to be realized but in ten years’ time when Shah Deniz Two and TANAP will be implemented and additional volumes of gas will be available in Azerbaijan from other projects… maybe there will be room left for LNG as part of Azerbaijan energy diversity strategy.”

Since then, new developments have shed more light into the subject. In particular, the current Romanian Energy Minister Andrei Gerea, recently relayed in the local media that the vertical gas corridor that will connect Romania with Greece via Bulgaria will have been finalized by 2020 and will also include Hungary via other interconnectors. Thus, by the time the Southern Corridor via TAP and TANAP will be officially on-stream, then the rest of the diversification process via the Black Sea Basin could commence, an attribute to the long-standing AGRI project.

Moreover, the Romanian Energy Ministry strategists have already focused on upgrading indigenous production via the exploitation of potential gas reserves offshore the country’s Danube Delta that optimistically would start producing gas by 2020 as well. Andrei Gerea pointed out that “Romania has little import needs, mostly in winter period, thus when new gas volumes come online in the next decade, new investments should be in place to boost the capacity of the local transmission system in order to export excess amounts. Thus, the acquisition of new compressors for the local pipeline system is a necessity to run in parallel with the strategic diversification process the county is investing into.”

Romania aims not only to eliminate its gas imports from Russia but also to become a net gas exporter and at the same time becoming a major electricity exporter from gas-fired power plants. In that sense natural gas sector is the main focus of the incumbent administration and for the long-term. Already the country has started exporting small volumes of gas to the neighboring Republic of Moldova, with an average price tag of $260 per 1000 bcm, a competitive pricing compared to Gazprom. The plan is to stabilize in the coming years a 1 bcm per annum export to that country.

On the other hand, for several years Romania placed great importance into its perceived shale gas deposits, which proved to be far less than expected. Chevron has, after a series of in-depth investigations, abandoned its investment program in the country which started in early 2013. Chevron had also resigned from similar efforts in Poland, Lithuania and Western Ukraine. The cost of extracting shale gas in Europe for the moment exceeds conventional supplies and there was intense opposition by local communities and environmentalists.

Presently Romania consumes around 16 bcm of gas per year and produces approximately 11 bcm, whilst it has about 100 bcm of proven reserves according to the US Energy Information Administration. Although it is well positioned as a result of its domestic resources, especially compared to the rest of the EU member states, it faces a long-term supply issue since it has around 20 years before its reserves are completely exhausted. Thus the whole planning of the Romanian government is to speed processes, so as to find new offshore reserves and at the same time secure new suppliers and most notably Azerbaijan. Regarding the latter it has to be noted that Baku has already made the strategic decision fully back the TANAP-TAP system of pipelines and unless the rest of the Central Asian states open up their own supply routes to the EU, there are no amounts of importance to be exported and for the long-term.

Albania is the country in the West Balkans with one of the higher potentials for gas infrastructure and market developments. This is largely due to its geographic location and the prospective developments of three major international gas infrastructure projects: TAP, IAP and Eagle LNG 46. However currently major impediments for successful gasification in Albania remain. The size of the domestic market is likely to be small and gas is unlikely to play a major role in power generation, given significant hydro capacity. This means that the development of Albania’s gas market, reflecting the potential size of the TAP offtake potential, significantly depends on cooperation with its neighbours.

The major hurdle for developing the gas sector and attracting investment in power generation in general, is the financial difficulty of the energy sector in Albania. Low electricity prices, high technical and commercial losses (42%) and a heavy reliance on electricity imports is burdening the state owned electricity sector with significant debts. Closely related to the barrier above is that electricity prices would have to increase with a greater penetration of gas in the power generation mix or power purchase agreements would have to be secured above current electricity prices. It is not clear whether these price increases can be sustained and would be implemented. Due to the inexperience of Albania in the gas sector, the Government has limited technical, regulatory, and administrative capability in the development for a gas 46 TAP is the only one of these three projects at FID stage SEE Gas Power Consortium: Interim Report, June 2015 Gas market assessments by country 69 market and sector. A case in point is the host government agreement with TAP, where no gas price arrangements have been agreed and gas supplies have not been secured. This in combination with the changing Cabinet and Government positions, has made it difficult for the sector to follow a long term trajectory. To develop the gas sector in the country, a major capacity building and support programme would be required. Despite the potential development of many regional and international gas infrastructure projects in Albania, gas supplies have so far not been secured. Even the gas volumes from TAP not contracted to Italy have not been secured by the Albanian Government. Instead a small number of gas traders have secured the remaining volumes; they may or may not supply gas to Albania depending on gas market development there. This means that gas supplies from these projects is not a given and in order for Albania to benefit from its ‘regional hub’ position, it must ensure anchor demand to obtain supplies.

The potential for gas infrastructure developments and investments in gas fired power generation largely depends on the gasification strategy the Government of Serbia will adopt in light of the discontinuation of the South Stream project. The gas market has the potential to develop significantly from its current levels of 2.2 Bcm to up to 3.5 Bcm in 2030. The petrochemical, fertiliser and steel industries as anchor customers together with more expansive use of fuel from distribution customers (district heating and residential use) could be the main drivers of future growth for gas demand. The relatively well-developed and existing gas transmission system and existing distribution grids mean that Serbia would not rely as heavily on the power sector as an anchor customer as other countries in the region, who still need to develop their transmission networks for investments in gas infrastructure. Additionally, the country has significant domestic gas reserves as well as gas storage potential which could act as a catalyst for gas sector development.

Gazprom’s decision to scrap the South Stream project has on one side been detrimental for prospects of further gas developments and security of supply prospects in Serbia. On the other side, however, it opens up new possibilities for integrating Serbia’s gas sector with neighbouring gas markets. The Government of Serbia (GoS) had focused its efforts and gas sector planning strategy almost exclusively around South Stream. This meant that a number of planned gas transmission projects were stalled and given lower planning priority by GoS. The Bulgarian gas interconnector is a case in point, where even with a partial grant funding from the European Union for the Bulgarian section, the project did not gain sufficient traction to be developed. The development of Croatia’s gas infrastructure will also significantly depend on the response from GoS to the cancellation of the South Stream pipeline; a Croatia-Serbia interconnector would be a significant step towards wider gasification of the region. We provide a more detailed discussion on the possible gas infrastructure investments in Serbia in Section  Development of the gas sector in Serbia over the last decade has been slow. While this can be explained by the almost exclusive focus on South Stream for gasification, other factors, that still remain today, have caused lower investment activity in the gas sector. These include:

  • Low electricity prices – Electricity prices are too low for any gas fired power plant to operate at commercially viable levels. Serbia has by far the lowest electricity prices in the region, which is largely due to the high degree of penetration of low cost lignite and hydro power generation. In the residential sector, low electricity prices have meant that, after solid fuels, electricity is used as a main space heating source in poor, low income and middle income households.
  • Low cost and domestic availability of lignite together with high gas prices over recent years has further squeezed the profitability of gas fired power generation plants. The sparks spread is estimated at -26 €/MWh, while the dark spread is closer to 22 €/MWh.
  • Security of supply concerns – Serbia is one of the countries in South Eastern Europe most exposed to a supply disruption of the Ukrainian gas transit pipeline. Currently all gas is supplied through one entry point via the international gas transit system connecting Russia, Ukraine, and Hungary. This creates uncertainty for investors to invest in gas to power infrastructure and large users to switch to gas.
  • The financial difficulty of Srbijagas might have also been a contributing factor for a lack in investments in gas transmission networks and gas interconnectors. Investment in the network is therefore reliant on the private sector, as Srbijagas was not in a position to raise the necessary financing.

After Croatia and Serbia, Bosnia and Herzegovina (BiH) has the potential to become the third largest gas market in the region with an offtake of 1.6 Bcm by 2030. However, the existing gas market is very small, but with a planned CHP plant in Zenica, and the potential for large volumes of industrial offtake from the steel industry, BiH could prove an important country in gasification efforts in the region. Interest in gas is currently high, though there are few advanced projects.

Despite BiH’s considerable potential to develop a gas market and associated infrastructure, the gas sector and infrastructure has developed slowly. The major reasons for low penetration rates of gas in the power sector include:

RS and F BiH divisions – the need for both entities (the Republika Srpska and the Federation of BiH) to approve gas infrastructure, regardless of the pipelines routing, means that key interconnector and pipeline projects have stalled. As both entities have different objectives and aspirations for gasification, finding a common gasification policy has proved difficult. There is a real likelihood for this hurdle to become less pronounced as the South Stream project becomes increasingly unlikely. SEE Gas Power Consortium: Interim Report, June 2015 Gas market assessments by country 70% of Pipeline capacity and security of supply – The current network is limited with only one entry point at Zvornik on the Serbian border. The capacity is close to 0.7 Bcm. In light of the demand projections shown in the sections above, this capacity would not be sufficient to meet existing demand as well as increased offtake at Zenica.

Gas prices vs. lignite prices – the gas prices paid by Arcelormittal for steel production at its steel mill in Zenica in 2014 was 375 €/mcm. Assuming the same for power plants, this would imply an electricity generation cost 47 of 66 €/MWh. The cost of electricity production in different coal plants is 45 €/MWh (Kakanj) and 42.5 €/MWh (Tuzla). This implies that gas prices would have to fall by 40% to become competitive compared to lignite as a baseload plant.

Croatia Croatia’s gas market is the most attractive for gas infrastructure and gas to power investment in the region. Croatia has a diversified gas supply mix including domestic production, relatively low natural gas prices 48 compared to its neighbours, a stable and cost reflective electricity pricing regime and an established network of gas transmission and distribution networks. It is the only country in the region with a positive spark spread – although this is still lower than the dark spread, suggesting that gas has the potential to play a greater role in the energy mix. A stimulus to new gas infrastructure investments is the renewed interest in the LNG Croatia project, which has the potential to provide a new competitive gas supply to Croatia and other countries in the region, as well as a significant security of supply benefit. Other favourable factors for investment in Croatia’s gas market are the strong political willingness to develop gas and gas to power infrastructure further (including the LNG plant and a CCGT plant) as well as its eligibility for grant funding from the EU for strategically important energy infrastructure projects. Additionally, imported gas volumes and prices are not locked into long term contracts but instead are procured through spot trading through one of its two interconnectors with Hungary and Slovenia. The size of the Croatian gas market enables gas imports in larger volumes thereby reducing the traditional ‘small volume’ markup observed in smaller countries in the region. Additionally the proven financial health of gas offtakers means that gas suppliers need to ‘price in’ less risk than for an unknown gas offtakers in developing gas markets. Our gas demand projections suggest the total gas market to grow from a current level of 2.9 Bcm to 4.3 Bcm in 2030 with most demand growth potential coming from the industrial sector (petrochemicals, steel and cement industry) and power generation sector.

Despite the reasons for optimism for gas to power development in Croatia, there remain obstacles. The price differential between gas and coal prices is significant and gas is unlikely to replace coal and lignite as a baseload fuel. This is a reoccurring problem for the entire West Balkan region. As noted above however, the price differential in Croatia is not as accentuated as in other countries in the region. The spark spread is estimated at 17 €/MWh compared to the dark spread at 42 €/MWh. Another difficulty in increased gas usage in power generation in Croatia is the reliance on electricity imports from the part-Croatian owned nuclear power plant in Slovenia. Nuclear imports act as baseload capacity displacing most thermal power generation. Until recently, Croatia planned further nuclear developments (1,000 MW plant) in the country. These plans have not featured in the latest power sector development plans, but instead the Government of Croatia has set a renewable energy target of 900 MW. This is likely to make it difficult for gas to enter the power generation mix substantially and creates a hurdle for private sector participation in gas fired power generation projects. We provide a detailed list of possible gas infrastructure projects and potential gas fired power plants in the next section. It is noteworthy here however, that the cancellation of South Stream in December 2014, has increased the potential for regional gas infrastructure projects in Croatia. The planned LNG terminal, IAP, and interconnectors to Serbia and BiH are now more likely to be developed than previously. This makes Croatia one of the key gas entry market for the entire region despite the impediments that still exist in gas to power development.

With a small (0.2 Bcm) gas market compared to its population, FYR of Macedonia’s gas development potential is relatively high. There is also strong interest in the country to develop gas distribution. However, growth in demand will crucially depend on the ability to source lower gas prices 49, a clear decision on the priority of gas transmission expansion projects, and on the development of distribution networks. Interest from international finance institutions to invest in gas transmission in the country is high; however it seems that uncertain demand has been the main obstacle for securing financing. There is also interest in further interconnections with neighbouring countries although the lack of potential demand centres along the proposed pipeline routes is a barrier. The country could play a key role as an international gas transmission country in the region, by providing access to TAP via Greece and/or access to the Albanian LNG terminal through a possible interconnector to Albania. The gas from alternative sources could then be transported north either directly to Serbia or via Kosovo. The demand in other regions could provide the necessary volumes of gas to justify investments in gas infrastructure, which FYR of Macedonia gas demand on its own would not. Interconnection plans with the abovementioned countries have not been pursued actively by the Government of Macedonia (GoM). This means that until GoM starts actively pursuing interconnections, gas infrastructure development in FYR of Macedonia will have to be carried by domestic demand, which has been small and is likely to remain small. Ambitious gas to power plans are unlikely to materialise unless gas prices become more competitive and can be negotiated downward. The major impediments for gas sector development in FYR of Macedonia are a combination of high wholesale gas prices mainly driven by excessively high import prices and low lignite prices preventing gas fired power generation to develop, heating consumers switching away from district heating to electricity, and a Government strategy geared toward increased coal/lignite usage in power generation. Figure 39 shows the estimated demand projections and possible entry points for gas supply into the country. The Government of Macedonia (GoM) has detailed and extensive gas transmission expansion plans, which seem unrealistic to implement over the envisaged time period. Additionally, the Russian Federation is planning to finance one gas pipeline segment to compensate for outstanding debts owed by the Russian Federation. This has been a proposal for a long time and it seems like little progress has been made. This together with relatively low demand levels has created uncertainty and consequently investments have been limited.

Gas sector development in Kosovo will depend on regional gas infrastructure projects connecting Kosovo with either Serbia, FYR of Macedonia or Albania. Kosovo’s potential gas market is too small to justify stand-alone gas infrastructure investments. While industrial and residential gas demand could become significant in the long run at 0.2 and 0.4 Bcm respectively, the complete absence of expected gas to power development means that a necessary anchor load is missing. The cancellation of the South Stream project in December 2014 means that a northern interconnector to Serbia is unlikely, as no supply point and additional volumes exist in southern Serbia. This limits the options for gasification of Kosovo to the interconnector with FYR of Macedonia. While this is not a major roadblock for gas infrastructure investments, it simply means that Kosovo’s gasification is entirely reliant on the cooperation of the FYR of Macedonian (or Albanian) government. The Albanian gas interconnection is unlikely to materialise. The planned electricity transmission interconnector between the two countries means that a gas pipeline between Albania and Kosovo would not be needed. The complementarity of both countries’ electricity demand and the planned power generation in Albania suggest that a combined electricity market rather than gas market is more cost effective for both countries. Gas will not play an important role in Kosovo’s own power generation sector in the foreseeable future. This is due to the following factors: o Government of Kosovo’s (GoK) firm commitment to lignite – due to significant domestic reserves and support from international finance institutions, the Government is committed to replace the old Kosova A plant with a new 600 MW lignite fired power plant. o The economic viability of lignite over natural gas – besides the availability of domestic lignite sources, GoK’s decision to replace Kosova A with another lignite plant is based on the significantly lower cost of lignite or gas. Marginal costs of gas are estimated at 73 €/MWh compared to 12 €/MWh for lignite. o Underutilised hydro power potential – Kosovo has significant underutilised hydro power potential. The Zhur plant and smaller hydropower plants are estimated to have a capacity potential of 545 MW. For a country with peak demand of close to 1,200 MW in 2013 this is significant.

The primary barrier to investments in gas infrastructure and gas fired power generation in Montenegro is the small size of the potential market. With a potential demand of 0.1 Bcm in 2030, Montenegro lacks the anchor load to make unilateral investments worthwhile. Hence any gas potential is dependent on regional developments and in particular the Ionian Adriatic Pipeline (IAP). Two potential developments could, however, act as ‘game changers’ for Montenegro’s gas development: Significant offshore gas finds resulting from exploration activities to be started over the next five years. However, the small scale of Montenegro’s local energy demand would again limit the viability of gas investments other than close to a potential terminal for offshore gas pipeline – if gas is found. Montenegro’s current energy outlook reflects this uncertainty as it does not project being able to exploit significant oil and gas reserves before 2025. o The development of the Montenegro-Italy electricity interconnector. This would enable Montenegro to develop significant power generation capacity and if IAP gains traction and materialises, natural gas could form a credible fuel alternative to lignite. A further obstacle to power generation developments is that electricity prices are regulated and subsidised. This creates a barrier for private independent power producers (IPP) to enter the market. Envisaged changes in the new Law (compliant with the 3rd Energy package) would however nullify this obstacle. Additionally the dominance of the state owned power utility across all parts of the electricity market, might distract private investment in the electricity sector. Additionally the financial health of the single electricity buyer EPCG could deter investments from IPP’s. With significant commercial and technical losses, the loss of its main consumer (KAP), an outstanding court case relating to unpaid charges to the transmission system operator and subsidised and low electricity prices, EPCG would constitute a significant commercial risk for power generation developers in Montenegro.