energyworld No 14 | September-October 2016
Oil & Gas • Electricity • Renewables • Environment
EUROPEAN ENERGY UNION AFTER BREXIT
NEW MOVES ON THE NATURAL GAS CHESSBOARD THE RETURN OF THE ZOMBIE PROJECTS IN BULGARIA TIME FOR A DIFFERENT ENERGY MIX IN SERBIA
September-October 2016 Price: 5 Euros
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The english edition for SE Europe & Eastern Mediterranean Issue Nr 14 September - October 2016 ISSUE PRICE 5 Euros
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INSPECTIONS AT ROMANIAN GAS COMPANIES BY THE EU
ONE YEAR OF EPS RESTRUCTURING IN SERBIA
IS THE BULGARIAN GAS GRID FOR SALE?
THE RETURN OF THE ZOMBIE PROJECTS IN BULGARIA
LARGE INVESTMENTS NEEDED IN ROMANIAN ENERGY SECTOR
THE COMMERCIAL LOGIC OF NORD STREAM-2
ENERGY PROSPECTS BETWEEN ISRAEL & TURKEY
NEW MOVES ON THE NATURAL GAS CHESSBOARD
WHAT BREXIT MEANS FOR THE EUROPEAN ENERGY UNION?
NEWS IN BRIEF
01 02 03 04 05 06 07 08 09 10 11
THE DEVELOPMENT OF HYDROELECTRIC POTENTIAL IN ALBANIA
A NEW RENEWABLES INCENTIVE SCHEME FOR SERBIA
THE LATEST BILL ON THE FRM IN GREECE
ROMANIA FREEZES GAS PRICES UNTIL NEXT YEAR
NEW WAYS FOR PIPELINES IN ROMANIA
THE... DARK (AND BLACK) SIDE OF COAL IN ROMANIA
CHEAPER NATURAL GAS FOR HOUSEHOLDS AND INDUSTRIES
THE APPROPRIATE ISLAND ELECTRIFICATION MODEL IS REQUESTED
ROMANIA TURNS TO THE... GREEN MODE
TIME FOR A DIFFERENT ENERGY MIX IN SERBIA
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ΤΗΕ EU IS LOOKING FOR VIABLE SOLUTIONS IN THE CASE OF BREXIT
Two months after the referendum and as questions about Britain leaving the European Union not only persisted but also seemed to multiply, the two sides have yet to start the formal (or at least informal…) discussions about the procedure. As for the timeline, the new British government of Theresa May insists that London has no intention to trigger Article 50 of the Lisbon Treaty which regulates the exit process of every single country from the Union, before next year. At the same time, and as a result of the mixed and confusing picture that is described above, there are many who suggest that EU and British authorities are secretly looking for a solution that will, one way or another avoid Brexit. Nonetheless, leaders of the three most powerful European countries, Germany, France and Italy, have had their first meeting about Brexit and its consequences for Europe on June 22. And on September 16th the heads of states
or governments of the 27 member states (Britain excluded) are planning to meet in Bratislava, the Slovakian capital, to discuss their next steps and seek a common line towards London, but also in the face of the crucial problems the EU is facing. Regarding Brexit, there are many challenges ahead for the “27” –whichever scenario eventually prevails. Energy is one of these challenges, as the project of the European Energy Union faces many obstacles. Especially as the relations with the main provider of gas and oil for the EU countries, Russia, remain unclear. In this issue, EnergyWorld presents the various scenarios discussed by EU officials and energy experts – even though the outcome remains highly unclear. Which means, in other words, that we shall return to this issue very soon…
News in brief
2016, on track to become the hottest year ever... 2016 is clearly on track to become the hottest year ever recorded. According to the existing data, July was the 15th month in a row to break temperature records. Nasa’s results, which combine sea surface temperature and air temperature on land, showed July 2016 was 0.84OC hotter than the 1951 to 1980 average for July, and 0.11OC hotter than the previous record set in July 2015. This means that July was about 1.3OC warmer than the pre-industrial average. At the same time, the last month in which global temperatures were below the 20th-century average was December 1984. “Another month, another record. And another. And another. Decade-long trends of climate change are reaching new climaxes, fuelled by the strong 2015/2016 El Nino”, said the chief of the World Meteorological Organization, Petteri Taalas. The El Nino event developed in 2015 and contributed to the record temperatures in the first half of 2016 before disappearing in May. “The El Nino event, which turned up the Earth’s thermostat, has now disappeared. Climate change, caused by heat-trapping greenhouse gases, will not. This means we face more heatwaves, more extreme rainfall and the potential for higher impact tropical cyclones”, Taalas added. As the string of hottest months continues, 2016 is “virtually certain” to be the hottest year on record, said David Karoly, a climate scientist from the University of Melbourne. Karoly said about 0.2OC of that anomaly was likely due to the El Nino, leaving about 1.1OC mostly due to humaninduced climate change. Does anyone really remember what was decided during the recent Global Climate Summit in Paris?
Nuclear... clouds in the Sino-British relations Britain “looks forward to strengthening cooperation with China on trade, business and on global issues”, Theresa May wrote in a letter addressing the Chinese leadership. The letter was sent in the aftermath of the frustration expressed by Beijing after the surprise decision of the new British prime minister to review the building of her country’s first nuclear plant in decades, a $24 billion project. May tried to reassure Chinese president Xi Jinping and prime minister Li Keqiang that Chinese money is still welcome in the UK, despite the freezing of the Hinkley Point nuclear plant, which was until recently described as the jewel illustrating a “Golden Era” of excellent relations between the two countries, which together account for 17 percent of the (nominal) global GDP ($11,3 billion and $2,4 trillion respectively). The deal was signed last year by then prime minister David Cameron and the Chinese president, during the official visit of Mr Xi in London. But May seems to be more concerned about the security implications of the planned Chinese investment. According to Reuters, “May’s most striking corporate intervention since winning power in the turmoil which followed the Brexit vote indicates a more cautious view of Chinese investments and a willingness to follow a tough line with EU allies such as France”. It should be noticed that the cost of the plant would be funded (under plans drawn by Cameron government) by both French utility EDF and China General Nuclear Power Corp. As for Beijing, it should be noticed that it faces a further “nuclear” issue, as the city of Lianyungang in east China has suspended preliminary work on a nuclear waste processing plant following days of angry protests. The $15 billion project was to be run by the state-owned CNNC in collaboration with France’s Areva and the construction was scheduled to be started in 2020 and completed by 2030. Hard days for nuclear cooperation...
A “new deal” for energy between Putin and Erdogan Less than a year ago, in October 2015, Recep Tayyip Erdogan was angered by Russia’s bombing campaign in Syria and warned Moscow that Ankara held the option to look elsewhere for partners to supply natural gas and build its first nuclear power plant. And in November, after the downing of the Russian Sukhoi fighter plane by the Turkish air force near the borders with Syria, the two countries entered an era of “cold war” that caused, among others, the freezing of their energy cooperation. Today, after the reestablishment of the bilateral relations, as it was demonstrated during the August meeting of Turkish president and his Russian counterpart in St. Petersburg, the energy projects between Turkey and Russia regarding the so-called Turkish Stream gas pipeline and the $20-25 billion nuclear plant in Akkuyu, seem to be on track again, opening the way for further energy deals. After all, Turkey remains Gazprom’s second largest customer after Germany and its interests largely coincide with those of Russia, at least regarding energy. Calling Putin his “dear friend” and offering him his apology for the unfortunate episode (as he had already done towards the family of the dead Russian pilot), Erdogan rushed to hail the start of “a very different period” in relations between the two countries, highlighting his decision to back down from the hostile stance against Moscow and to play the Russian card in his foreign policy. The U-turn of the Turkish president was forced by
the danger of being totally isolated in a region that is dramatically changing, leading to a new geopolitical equilibrium. As a matter of fact, a new and powerful alliance seems to be already emerging in the Middle East between Russia, Turkey, Iran and Russia, radically reshaping the map, especially regarding Syria. This alliance is alarming the US and (most of) its Western allies who look more and more desperate and powerless against the forceful Russian intervention guided by the modern “tzar” of Kremlin. But unfortunately for Washington, it might be too late to undo the changes... All in all, Putin played his cards brilliantly by hosting a successful visit of Erdogan, with emphasis on putting the relationship back on track on an upward trajectory. And as the veteran Middle East hand Robert Fisk wrote, “There is a long list of the potential losers in the theater of St. Petersburg. First, Isis (IS) and al-Qaeda/Nusra/Fatah el-Sham, and all the other Islamist outfits now fighting the regime in Syria, who suddenly find that their most reliable arms conduit has teamed up with their most ferocious enemy… the Russian air force. Then there’s the Saudi and Qatari billionaires who have been supplying the cash and guns for the Sunni warriors who are trying to overthrow both Damascus and Baghdad, and humble the Shia of Iran, Syria… and Lebanon”. Some of the losers are traditional US allies – or aren’t they?
Geopolitics of energy George Pavlopoulos
WHAT BREXIT MEANS FOR THE EUROPEAN ENERGY UNION? What is the analysts and experts opinion, regarding the consequences of Brexit on the energy sector, both for the EU and the UK, in both the short and long term? Are international investors more concerned about their assets and their future plans? How is Brexit going to affect UK’s and Europe’s energy security and the project of the European Energy Union? Before trying to answer these (and many more) questions, we should wait to see whether, when and based on which terms Brexit takes place…
In February, the chiefs of oil and gas majors BP, Shell and Centrica were among the 200 business leaders who signed a letter warning that a vote to leave “put the British economy at risk”. Four months later, and just one day after the people of Britain voted clearly in favor of Brexit, the Reuters news agency published an analysis about the consequences of the northern country leaving the EU. “Leaving the EU could make UK energy infrastructure investment costlier and delay new projects at a time when the country needs to plug a looming electricity supply gap. The uncertainty after Brexit could make energy investors demand higher returns for the risk of less favorable conditions. Oil and gas majors BP and Shell are among energy companies who warned about the potential downside”, it wrote regarding the energy sector. Still, two months after the referendum and as the next steps of Theresa May’s new British government and the time schedule for leaving the block are unclear, especially regarding the invoking of Article 50 of the Lisbon
Treaty that would trigger the negotiations between London and Brussels, the main questions remain unanswered: How is Brexit going to affect UK’s energy policy and, at the same time, the project of the European Energy Union? And what could change in the stance of the international investors? According to the Natural Gas World, “it is impossible to make a full assessment of the implications of the United Kingdom’s departure from the European Union on the European Energy Union because there is uncertainty associated with both the so-called Brexit and the European Energy Union”. “Britain’s departure from the EU will force broad changes to the block’s energy and climate policies, and remove a crucial ally for Central Europeans – but it will also give London far more freedom to pursue nuclear projects”, suggested Sara Stefanini, editor of Politico, assuming at the same time that “there’s a lot to lose on both sides of the Channel”. The analysts of NGW have asserted that “in terms of energy security, the UK is in great shape: it enjoys a high
level of diversification in terms of fuel mix, supply source countries and transit routes, and its energy import dependency is below the EU average”. On the other hand, the impact of Brexit on the EU and its energy policies, NGW describes the situation as follows: “In some ways there will be no impact at all: the European Union’s recent security of supply legislative package is not controversial in the UK, so the country’s departure doesn’t tip the scale on the EU outcome. In other words, there will be room for energy issues to move where they could not before: the UK opposed the European Union’s effort for an ambitious energy efficiency target, so that issue could actually advance more quickly now in Brussels”. From its side, the UCL European Institute sees limited impact on the short-term, because EU rules (the so-called “acquis communautaire”) would remain in place at least until 2020. “Post-2020 effects would depend on the extent to which Brexit slowed down the construction of new electricity interconnectors (cables carrying electricity to and from Britain), and on the arrangements
the UK negotiated with the rest of the EU”, according to the same analysis, which sees three main scenarios for
Britain after Brexit: joining the European Economic Area (EEA, like Norway), entering into a Customs Union (like
Headache for British offshore wind projects Britain is the world’s largest offshore wind market, expected to be worth 20 billion pounds ($27 billion) from 2010-2020 according to Britain’s renewable energy industry body RenewableUK. It has more than 5 gigawatts (GW) of capacity which the government wants to double by 2020 in order to meet climate change targets for lower carbon emissions. It is followed by Germany, which is quickly catching up with Britain with around 3.4 GW of capacity currently installed. Denmark is next in line at 1.3 GW, while France and the Netherlands have ambitious targets to build offshore wind turbines by the end of the decade. But now, in the aftermath of the Brexit vote, analysts and the sector’s experts predict that Britain will become more vulnerable against its main
competitors, as it will be much more difficult for offshore wind investors, who are mainly international, to predict foreign exchange rates, an important factor as many of them buy equipment in Euros. As a matter of fact, and according to Reuters, Portugal’s Energias de Portugal-EDP has already stated it could delay its Moray Firth offshore wind energy project in Scotland. From its part, the German engineering giant Siemens said it was reconsidering plans for an expansion of its planned manufacturing plant in the port of Hull in north east England. More companies could follow in the same path during the next months, especially in the case that political and economic uncertainty about Brexit prevails.
Two months after the referendum and as the next steps of Theresa May’s new British government and the time schedule for leaving the block are unclear, the main questions remain unanswered
The case of Scotland Immediately after the result of the Brexit referendum became clear, the leaders of the Scottish independence movement renewed their bid for creating a new state, which would remain part of the EU – or, at least, would soon request membership, hoping that the application would be accepted on the short term and without serious opposition from Brussels and the great European powers. In such a case, if the Scottish independence debate gains momentum, it’s easy to predict one of the main points of controversy between the two sides: The revived question of whether the robust North Sea oil and gas assets can be claimed by London or Edinburgh would put a damper on things, forcing the European Union either to take sides or to freeze the case.
Turkey), or negotiating a Free Trade Agreement (FTA, like Canada)”. As a matter of fact, it seems to be too soon for anyone (even for Brussels…) to predict the changes in the European energy sector resuming from Brexit. Except, maybe, the fact that after leaving, Britain will have a free hand to aid ailing companies or industries without fear of EU action but it will also not be able to oppose subsidies granted by EU governments to their own national champions. In any case, the consequences are of great interest not just for Britons and Europeans, but also for many outside the continent. Among others, Moscow and Washington haven already taken a note, as the Kremlin hopes there will be less opposition for its ambitious projects in Europe and the White House tries to rebalance its (potentially) lost influence in the EU.
Geopolitics of energy Penelope Mitroulia
NEW MOVES ON THE NATURAL GAS CHESSBOARD The important role that the natural gas reserves of the Eastern Mediterranean can play towards enhancing European energy security and reducing EU’s dependency on Russia, has come back under the spotlight, with the United States demonstrating a very strong interest and declaring present at both a political and business level, in order to support and participate in projects that could form another natural gas transfer “road” to Europe.
The US policy on the issue of Europe’s energy supply is clear and well defined. They seek to limit the Russian influence and simultaneously open the way for their own liquefied natural gas, as well as the gas from areas that maintain strong interest such as Azerbaijan, or the eastern Mediterranean. Given that the TAP which will transport Azeri gas to Europe is now entering into its construction period, the American interest now lies in Israel’s and Cyprus’s deposits in the Eastern Mediterranean. At the same time, the rapprochement between Turkey and Russia, which creates the conditions to unfreeze the Russian South pipeline, triggers the US reflexes and rekindles their interest in our region. The recent tour of the special envoy and coordinator for US international energy relations, Mr. Amos Hochstein in Eastern Europe, which ended up in Athens and in a meeting of the American officer with the Greek Environment and Energy Minister Mr. Panos Skourletis, depicts the American mobility. Mr. Hochstein also previously participated in a European Commission conference on the Energy
Union and met with the Energy Minister of Cyprus Mr. George Lakkotrypis. Mr. Hochstein was in Greece for the second time within a few months (he had attended the TAP inauguration in Thessaloniki in April) and as announced by the Greek energy ministry, he discussed the evolution of the TAP with Mr. Skourletis, the prospects of the Greek-Bulgarian gas pipeline IGB and the plan for a floating liquefied natural gas terminal (LNG) in Alexandroupolis. According to authoritative sources, these twin projects, namely the IGB and the floating LNG station in Alexandroupolis, attract the American interest not only for the export of LNG from the slate of US deposits, but also for the supply of gas that will derive from Eastern Mediterranean fields. It is also worth noting that the Hochstein visit was preceded by a meeting of members of the Ministry of Environment and Energy with representatives of the American Cheniere company which seems most interested in participating in the construction of the LNG terminal in
Alexandroupolis, that had been ruled out in previous phases.
support by part of the US and the EU on the pipeline has created optimism.
The floating LNG station in Alexandroupolis (a project promoted by Gastrade, of the Kopelouzos Group in cooperation with DEPA and now the Bulgarian BEH, as Sofia shows strong interest) is directly associated to the Greek-Bulgarian pipeline, as well as they shall be the entry gate to the gas Balkans from third party sources (with the exception of Russia).
It must be noted that the IGB pipeline, with a total length of 182 km is considered as the first step for the “Vertical Corridor”, which interconnects the Greece with the Balkan countries, such as Hungary and possibly Austria. It is the first project that can give Bulgaria and other Balkan countries access to non-Russian gas, increasing the security of supply.
The final investment decision on the Greek-Bulgarian pipeline is expected to be made in the Fall, on which the implementation of the terminal depends directly. It should be noted that within the framework of the first market test for the project, nine companies including American Cheniere and Noble expressed interest and thus the competent authorities do not seem to be particularly concerned about the participation in the second market test at the moment, in which companies will be invited to submit specific offers on the capacity commitment to the pipeline. Besides, the strong political
The “Poseidon” company, which is controlled 50%-50% by DEPA and the Italian Edison, holds 50% of the IGB and the remaining 50% belongs to BEH, the Bulgarian energy holding company. The implementation of the GreekBulgarian pipeline will give the final green light for the construction of the floating liquefied gas terminal (LNG) in Alexandroupolis, while it is critical for the promotion of Azeri gas which comes to SE Europe through the TAP pipeline. This explains the interest of Socar, the Azerbaijan state natural gas company, one of the main shareholders of TAP and
prospective buyer DESFA in the project. A Socar spokesman recently said the company is interested in the IGB and selling natural gas to Bulgaria. The construction cost of the IGB is estimated at 220 million. Euro, and according to the Bulgarian Minister of Energy the project will be able to be added to the Junker package for funding, provided that the market test with the binding offers will be successful. At a first phase, the various studies for the project have been financed with 45 million Euros from European funds and programs. Moreover, by the end of 2016, the gas pipeline that will link Romania to Bulgaria is expected to be ready, under the Danube. This interconnector pipeline may be supplied with gas from Greece via the IGB in the future. The goal is that all three projects, the terminal in Alexandroupolis, the IGB and the TAP are operational by 2020. At this point it is interesting to mention that the Bulgarian Energy Minister Temenuzhka Petkova, recently spoke
about the possibility of supplying Iranian gas through the IGB pipeline. This statement by Mrs. Petkova which demonstrates how “open” the gas game is in the broader area, came after she met with her Iranian counterpart Bijan Namdar Zangeneh in Tehran. Iran appears ready to dispose gas quantities both in Greece and Bulgaria, when the pipeline is constructed and ready to operate, while the country is also interested in supplying the terminal liquefied gas station in Alexandroupolis.
According to authoritative sources, the IGB and the floating LNG station in Alexandroupolis, attract the American interest Furthermore, both Washington and Brussels seem to favor the promotion of Israeli and Cypriot gas to Europe. Cyprus and Israel are seeking an outlet for their gas reserves while Greece aims to become a gas transmission bridge to Europe. The important role that the reserves of the Eastern Mediterranean can play in strengthening the European energy security was also stressed in his speech at an energy conference in Bratislava
by the Cypriot Minister of Energy, Commerce, Industry and Tourism Mr. George Lakkotrypis, who pointed out the need to develop infrastructures linking Member States in order to create a single European energy market. Our strategy, he said, includes the development of a new gas corridor – that of the Eastern Mediterranean – for supplying the EU. These developments may still be at an early stage but it is no coincidence that the East Med gas transfer pipeline, a pipeline connecting the marine deposits of Cyprus and Israel through Crete, mainland Greece and Italy returns to the foreground after the cooperation agreement signed by the “Poseidon” company with the American Noble for the project’s preliminary designs. The “YAFA Poseidon” is a mixed activity company 50%-50% between DEPA and the Italian Edison, a subsidiary of the French group EdF, which promotes the Greece - Italy and Greece - Bulgaria pipelines and Noble, one of the groups active in the offshore deposits of SE Mediterranean (the Leviathan basin). In fact, the announcement of cooperation between Poseidon and Noble came only a few days after the approval received by Noble from the competent authorities of Israel for the exploitation of the Leviathan deposit. The project involves the development of a submarine system linking productive wells with a stable platform, which shall be located in the sea and will be connected via a pipeline to a region in northern Israel.
Up until now Tel Aviv has not made its final decisions on gas exports, which will come from the full development of deposits. One part of the gas, both that of Cyprus and of Israel, appears to be channeled into the international market through liquefied gas terminals (LNG) in Egypt. However, other route pipelines are being examined, one from the Turkish side and the other via the East Med. The “East Med” project envisages the construction of a 1,900 km long pipeline with an annual transmission capacity of16 billion cubic meters from the Leviathan deposits to Cyprus – Crete – mainland Greece and then through the “Poseidon” pipeline to Italy. The East Med has joined the “EU Projects of Common Interest” and is co-financed by European funds, but that alone is not enough to appear as an indication of the project’s implementation. Both Geopolitical factors will play a decisive role, namely whether Turkey will be selected or not as the missing link for the transfer of Israeli and Cypriot gas and purely financial factors, based on the commercial viability of each project. The “Poseidon” agreement with Noble concerns the completion of the necessary procedures before the preparation of the Study on the Application of the Front End Engineering Design of the EastMed pipeline and to assess its viability.
Geopolitics of energy Yiannis Pispirigos
ENERGY PROSPECTS BETWEEN ISRAEL & TURKEY Relations between Israel and what was once its only Muslim ally crumbled after Israeli marines stormed an aid ship in May 2010 to enforce a naval blockade of the Hamas-run Gaza Strip and killed 10 Turkish activists on board.
Israel and Turkey announced they would normalize ties after a six-year rupture, a rare rapprochement in the divided Middle East driven by the prospect of lucrative Mediterranean gas deals as well as mutual fears over growing security risks. The Turkish Prime Minister Binali Yildirim said the two countries would exchange ambassadors as soon as possible. The mending in relations between the once-firm allies after years of negotiations raises the prospect of eventual cooperation to exploit natural gas reserves worth hundreds of billions of dollars under the eastern Mediterranean, officials have said. Israeli Prime Minister Benjamin Netanyahu said it opened the way for possible Israeli gas supplies to Europe via Turkey. The move also comes as the Middle East is polarized by Syria’s civil war and as the rise of Islamic State threatens regional security, leaving both countries in need of new alliances. Speaking after meeting U.S. Secretary of State John Kerry in Rome, Netanyahu said the agreement was an important step. “It has also immense implications
for the Israeli economy, and I use that word advisedly”, he told reporters. Kerry welcomed the deal, saying, “We are obviously pleased in the administration. This is a step we wanted to see happen”. Turkey expelled Israel’s ambassador and froze military cooperation after a 2011 U.N. report into the Israeli raid on the Mavi Marmara largely exonerated the Jewish state. Israel and NATO member Turkey, which both border Syria, reduced intelligence sharing and canceled joint military exercises. Netanyahu made clear the naval blockade of Gaza, which Ankara had wanted lifted under the deal, would remain in force, although humanitarian aid could continue to be transferred to Gaza via Israeli ports. “This is a supreme security interest of ours. I was not willing to compromise on it. This interest is essential to prevent the force-buildup by Hamas and it remains as has been and is”, Netanyahu said. But Yildirim said the “wholesale” blockade of Gaza was largely lifted under
the deal, enabling Turkey to deliver humanitarian aid and other non-military products. A first shipment of 10,000 tonnes would be sent next Friday, he said, and work would begin immediately to tackle Gaza’s water and power supply crisis. “Our Palestinian brothers in Gaza have suffered a lot and we have made it possible for them to take a breath with this agreement”, Yildirim said at a news conference in Ankara. Turkish President Tayyip Erdogan spoke to the Palestinian President Mahmoud Abbas by phone and told him the deal would improve the humanitarian situation in Gaza, sources in his office said. They said Westernbacked Abbas, who lost control of Gaza to Hamas in fighting in 2007, had expressed satisfaction.
The energy ties Restoring relations with Ankara is a crucial point in Israel’s strategy to unlock its natural gas wealth. It is looking for export markets and is exploring a pipeline to Turkey as one option, both for consumers there and as a connection to Europe.
“This is a strategic matter for the State of Israel. This matter could not have been advanced without this agreement, and now we will take action to advance it”, Netanyahu said. Gas, he said, had the potential to strengthen Israel’s coffers “with a huge fortune”. Shares in Turkey’s Zorlu Energy, which has activities in Israel, rose 11 percent on news of the agreement. Israeli energy stocks also rose in Tel Aviv. Yildirim was more cautious. “Firstly let normalization begin and, after that, the level to which we cooperate on whatever subject will be tied to the efforts of the two countries”, he said. “There is no point in talking about these details now”. Israel, which had already offered its apologies for the 2010 raid on the Mavi Marmara activist ship - one of Ankara’s three conditions for a deal - agreed to pay out $20 million to the bereaved and injured. The deal requires that Turkey passes a legislation protecting Israeli soldiers against related lawsuits. A senior Turkish official described the agreement as a “diplomatic victory”,
even though Israel pledged to maintain the Gaza blockade it says is needed to curb arms smuggling by Hamas, an Islamist group that last fought a war with Israel in 2014. “Israel comes out on top here”, said Louis Fishman, assistant professor of history at Brooklyn College in New York, who specializes in Turkish and Israeli affairs. “From the start it was believed that a deal could be worked out where Turkish aid was able to enter the Gaza Strip under Israeli supervision. It seems this is what was struck”.
Sources: Wall Street Journal, Reuters, Bloomberg
Geopolitics of Energy Anca Elena Mihalache, EPG Affiliated Expert
THE COMMERCIAL LOGIC OF NORD STREAM-2 Much ink has been spilt both against and in favor of Nord Stream 2, a natural gas pipeline proposal intended to bring Russian gas to Europe. The project was proposed last year by a consortium made up of Russian natural gas giant Gazprom and five European companies: German E. ON and BASF/Wintershall, Austrian OMV, French Engie and AngloDutch Royal Dutch Shell. Gazprom is to own a 50% stake in the pipeline, while its partners will make up for the remaining half, with a 10% stake each.
The project aims to expand on the existing northern route, Nord Stream 1, which connects Russia directly to Germany through the Baltic Sea. Nord Stream 2 is planned to add two new pipelines to the existing two which make up Nord Stream 1. This would effectively double the route’s capacity from a maximum of 55 bcm/y now, to 110 bcm/y if the new pipeline is built, sometime by the end of the decade. The controversy over the proposal revolves around whether it is a geopolitical (or at least political) weapon employed by Russia or whether it is in fact an inherently commercial project as claimed by the pipeline consortium and supported by the German government. The view that Nord Stream 2’s goals are geopolitical in nature is largely shared among Central and Eastern European governments, nine of which addressed the issue in a letter to the European Commission’s President Jean-Claude Junker in March this year, citing their own security of supply risk to arise from the pipeline’s construction. The fact that Nord Stream 2 would dislodge
significant gas volumes from the current Ukrainian route is also a problem often cited, mainly with reference to its financial implications on both Ukraine and Slovakia which could stand to lose currently existing transit fees. Moreover, the project’s mere existence has already exacerbated existing rifts within the EU, pitting Germany against Central and Eastern European governments on the one hand and against South Europe (Italy and Greece especially) on the other, since competing proposals to bring Russian gas through a Southern route (the now suspended South and Turkish Streams) have collapsed at their expense. It seems to also be opening a new fracture in the Germany-United States relations, since the latter is a fervent defender of keeping the Ukraine route –both because it makes commercial sense to everyone involved and because it sends a strong signal of support to a Kiev weakened by the covert Russian war waged against it. Considering these developments, if Nord Stream 2’s goal was to “divide and conquer”, then at least the divide
part is largely already won even though, if its supporters’ assertions are to be taken at face value, this was not the actual aim. The aim is purely commercial, something that the EU, which takes such pride in its economic and legislative value, should come to recognize, it could be argued, fairly quickly: European companies see a good business case in the pipeline; no money is asked of the taxpayers; and the pipeline will even cut emissions by an already calculated 8.9m tons of carbon dioxide equivalent compared to Ukraine transit, as the EU has recently learned from Gazprom’s CEO, Alexey Miller at the Sankt Petersburg Economic Forum.
So why the hesitation?
To answer this question, both the legislative and economic dimensions should come to the forefront of the discussion, rather than the political ones. The legal argument was rightfully made in mid-June by Junker himself, in a belated reply to the above-mentioned March letter. “If built”, Junker finally conceded, “Nord Stream 2 would have
to fully comply […] with applicable EU laws, including those on energy and the environment. This is also the case for off-shore infrastructure under the jurisdiction of Member States, including their exclusive economic zones. The construction of such an important infrastructure cannot happen in a legal void or only according to Russian law”. The offshore reference is the crux of the legal debate. Bizarrely, just like with failed South Stream before it, Gazprom is now pushing its own interpretation of European legislation as applying to Nord Stream 2. The Third Energy Package (TEP), according to Gazprom, only applies on Member States’ territory, not their territorial waters and exclusive economic zones. In this logic, it deems Nord Stream 2 an “import pipeline” and cites precedents of pipelines in the Mediterranean and even its own Nord Stream 1 which did not have to comply with the unbundling and third party access rules that make up the bulk of the TEP – in disregard, however, of the fact that the legislation was not yet in force at the time the construction of the pipelines in question began.
Under the TEP, Member States must ensure that network ownership is separated from production and distribution activity (ownership unbundling) and that the implementation of a system of third party access to the transmission and distribution system is applied objectively and without discrimination between system users. The controlling stake of Gazprom in the pipeline precludes it from complying with these two legal requirements. Even if the TEP is somehow interpreted as not applying to Nord Stream 2, Gazprom would still have to indirectly comply with the legislation, as is shown by present day’s Nord Stream 1’s case. Nord Stream 1 makes a landfall near Greifswald in Germany and from there onwards its gas is carried through two German pipelines: Nel and Opal. The latter is the export pipeline to the Czech Republic with a 36 bcm/y capacity that, however, can be used only partially in light of the TEP’s application. The situation would be similar for Eugal, a 51 bcm/y pipeline parallel to Opal set to be built in order to serve Nord Stream
The controversy over the proposal revolves around whether it is a geopolitical (or at least political) weapon employed by Russia or whether it is in fact an inherently commercial project as claimed by the pipeline consortium and supported by the German government
2. Eugal would need an exemption from TEP rules if it is to be used at full capacity. Opal, however, which long stood in a legislative limbo for obtaining a temporary partial exemption, stands as evidence of hurdles to come for Eugal as well, which will have to prove that it enhances not just gas supply security, but also gas supply competition, and that the investment undertaken has had such high risk that it can only be made if the exemption is granted. If German and European authorities do find a way to bypass the Third Energy Package, then there would be no doubt that Nord Stream 2 is indeed a political project and not a commercial one. In particular, they would have to explain why the same concessions could not be made for the South Stream a couple of years ago, albeit it could also be argued that the South Stream was cancelled by the Russian side before any such talk could even be opened. The economic factors underlying Nord Stream 2 are even more interesting than the legal hurdles and, surprisingly enough, less often taken into consideration. The pipeline’s construction would cost an estimated €9 bn, an investment well worth making in a favorable market environment. However, if one is to take a long term view and factor in all variables, the EU gas market might not look all that favorable after all. Gazprom insists that Nord Stream 2 will replace dwindling North Sea supply at affordable costs, often citing the
troubles at the Groningen field as a sign of what could come of the EU’s own gas production. But this argument leaves out other possible domestic natural gas sources such as Romania’s and Bulgaria’s Black Sea offshore fields or even the elusive shale gas projects especially in Britain. In terms of imports, however, Gazprom seems to have fully grasped the threat of LNG competition and, seen from this perspective, its attempts to secure a long-term market share are indeed a very rational commercial choice. Abundant LNG supply especially from the United States, Qatar and Australia is expected to keep prices low as technology advances to improve costs, possibly even to levels competitive with piped gas. This would add to LNG’s existing advantages such as market liquidity, diversified suppliers and the fact that its price is set by market factors preponderantly. Europe’s existing LNG import capacity is already significant at around 43% of demand in 2015 and several additional facilities are in planning or construction phase already. What makes little sense, however, from a purely commercial point of view is building new, expensive infrastructures in order to lock in market share instead of using the infrastructure already in place which suffices to supply even the most optimistic of European gas demand prospects. The fears claimed over Ukraine transit can be mitigated with EU mediation or even bilateral negotiation while old infrastructures
can be modernized at lower costs than building new ones instead of letting them go to waste. It makes even less sense if the new infrastructure is not used at full capacity so as to comply with the aforementioned legislation. A diligent investor should also look over towards the post-2020 European energy market as a whole and, more specifically, at what role gas is still expected to have. A premise widely believed a few years ago that gas will play the role of transit fuel towards a clean economy now looks less likely to be true. International Energy Agency (IEA) figures released this June show that global natural gas demand has increased by just 1% per year in the past four years, as opposed to the 2% annual growths predicted in 2011. Even with the current significantly low gas prices, the IEA predicts only a 1.5% annual growth over the next years. The sluggish natural gas demand is owed both in Europe and worldwide to an abundance of cheap coal available on the market and to strong policy support towards renewables. The 2% annual gas demand growth was supposed to usher in the Golden Age of Gas, expected to last well into the 2030s.
It was predicated on the North American shale gas revolution, the post-economic crisis demand growth, the increased availability of LNG supply and the climate change mitigation policies which seemed to favor gas thanks to its lower carbon footprint. But even this pro-gas climate-related argument rings less true today when efforts to curtail methane emissions are gaining momentum alongside those for carbon dioxide emissions reduction. It is unclear at this time whether the shift in the position of gas is structural or just temporary, but it’s still an important variable to factor in when building a large infrastructure pipeline like the Nord Stream 2. Furthermore, another recent report makes an even more compelling argument against the Golden Age of Gas scenario. Bloomberg New Energy Finance announced in its New Energy Outlook 2016 in June an expected fundamental transformation in the global electricity sector, as wind and solar power costs are expected to fall sharply over the next 25 years. Bloomberg expects renewable energy to overtake fossil fuels in electricity generation worldwide by 2040.
Despite last years’ fatigue in terms of adopting new and costly climate policies, Europe seems set to remain at the forefront of such shifts with Bloomberg expecting renewables to make up 70% of Europe’s electricity generation in 2040 from 32% in 2015. To conclude, factoring in all these trends, future European gas demand seems set to stagnate at best. Also considering supply-side opportunities, including but not limited to LNG, the Energy Union’s push for small interconnectors makes for a far more commercially-adequate approach than new large infrastructure projects. It’s difficult therefore to see the business case for new and costly infrastructure at a time when demand for the product it carries is hardly certain on the long term and when infrastructure is already in place to satisfy the demand which is certain.
This article was first published in Aspen Review
Overview Emilia Damian
LARGE INVESTMENTS NEEDED IN THE ROMANIAN ENERGY SECTOR The Romanian oil and gas sector needs investments of 1 billion Euros per year to maintain the same level of production. Maintaining the current level of oil and gas production in Romania requires annual investments of 1 billion Euros in the context in which production suffers a natural decline of 10pct, according to a portal launched by the Romanian Association of Oil Exploration and Production Companies (ROPEPCA).
The website of ROPEPCA brings together relevant data and figures about the Romanian oil sector to be better known by the public. According to the portal, Romania has almost a third of all employees in crude oil and gas drilling in the European Union, 25,600 respectively, out of the total 77,900. Romania holds 13,000 active wells, above the UK, which has 2,300 wells, Denmark - 1,500, Italy - 900 and Norway - 400. However, the production per well in Romania is the lowest of these countries, at 21 barrels per day, compared to 2,350 barrels per day in Norway, 964 in Denmark, 363 in UK and 271 in Italy.
The level of taxation in the oil sector was increased in 2013 to 15pct of revenues. The European medium (excluding the giant deposit Groeningen in the Netherlands) is 9.3pct - comparable to the permanent specific taxation in Romania, say oil specialists. However, if the temporary taxes in effect are added, the average taxation in Romania is double compared to the countries of
the European Union with comparable production per well, where there is an average specific tax of 7.5pct. The ROPEPCA representatives also said that 1 billion Euros invested in oil and gas sector creates or maintains 45,900 jobs, bringing to the state budget 1 billion Euros in taxes and has an impact of 3.2 billion Euros on the GDP. ROPEPCA was founded in 2012 and has 19 members: ADX Energy, Amromco, Aurelian Petroleum, Bankers Petroleum, East West Petroleum, Expert Petroleum, Fora Oil & Gas, Hunt Oil, Moesia Oil & Gas, NIS Petrol, Oilfield Exploration Business Solutions, OMV Petrom, Panfora Oil and Gas (MOL Group), Raffles Energy, Repsol, Sand Hill, Stratum Energy, Winstar Satu Mare/ Serinius Energy and Zeta Petroleum. These companies made total investments of 1.03 billion Euros last year, equivalent to 6.5pct of the total investments in Romania. Contributions to the state budget amounted to 2.4 billion Euros, representing 10pct of the total state budget.
The government will apply an additional tax of 35% on the upstream profit (to be called the “oil tax”) to oil and gas producers, as of 2017, with an additional deduction of 15% for new investments, but will cancel the incentives granted in 1999, which currently allow companies not to pay oil and gas tax or exports customs fees, said a draft quoted by local media. The new system will be gradually applied, first for oil and gas, then for mineral resources, and will be maintained for a period of 20 years – double when compared to the period of current royalties. The future taxation system will be applied for 20 years, under conditions in which taxes in the form of royalties were set in 2004 for a period of 10 years, under the law approving the privatization contract of Petrom, taken over by Austrian group OMV. The new system will be applied gradually, namely first for the oil and gas sector, following to be extended in the second phase to the mineral resources sector. In order to introduce the new system, the Government is facing a legal predicament, because the Petroleum Law from 2004 says that provisions of a petroleum agreement will remain valid throughout its duration, unless legal provisions are adopted in favor of the petroleum agreement holder.
Windfall tax extended
Moreover, this wording is included in
most petroleum agreements signed before 2011, as well as in other agreements. For this reason, the Government is preparing for next year a decisive discussion with directors of companies that are holders of petroleum concession agreements, so that the new system can be agreed by companies and the state is not sued including in international arbitration.
“1 billion Euros invested in oil and gas sector creates or maintains 45,900 jobs, bringing to the state budget 1 billion Euros in taxes and has an impact of 3.2 billion euros on the GDP” – Romanian oil and gas companies Until this new tax system is introduced, most likely in 2017, the Government has extended by one year, until December 31st 2016, the tax on the exploitation of natural resources, that on windfall gains of gas producers resulting from
price liberalization and that on the natural monopolies in electricity and gas transmission and distribution. The Ministry of Finance has recently announced that the current royalty system would remain in force this year and that the new system would be completed in the first half of next year, in order to come into force as of January 1st 2017. Royalties currently in force are percentages of gross value of production extracted, being established in 2004 under the Petroleum Law. For oil, they amount to 3.5% for fields producing less than 10,000 tons/quarter, 5% for fields producing between 10,000 and 20,000 tons/quarter, 7% for fields producing between 20,000 and 100,000 tons/ quarter and 13.5% for fields producing over 100,000 tons/quarter. For natural gas, royalties amount to 3.5% for fields producing less than 1 mln cubic meters/quarter, 7.5% for fields producing between 1 and 5 mln cubic meters/quarter, 9% for fields producing between 5 mln and 20 mln cubic meters per quarter and 13% for fields producing over 20 mln cubic meters/quarter.
Nuclear energy Ilin Stanev*
THE RETURN OF THE ZOMBIE PROJECTS IN BULGARIA Two energy projects in Bulgaria – the Nuclear Power Plant near the town of Belene and the South Stream gas pipeline, after being dead for a while, seem to be heading for resurrection.
The construction of the nuclear power plant was terminated in 2012 after it became evident that its sole investor – the Bulgarian National Electric Company (NEC) could go bankrupt by the mounting investment costs. South Stream was publicly canceled in December 2014 by no other than the Russian president Vladimir Putin himself. He accused the EU and Bulgaria of sabotaging Russian energy endeavors. “If Europe does not want to carry it out, then it will not be carried out”, the Russian president said in Ankara. Putin’s rage was fueled by the European Commission’s opposition to the project which, according to the EU’s executive body, breaches the EU energy antimonopoly legislation on several counts. Instead, the Russian president proposed an alternative pipeline – the Turkish Stream. After intense back door negotiations and legal manoeuvering, both projects are now in the focus of the Bulgarian and Russian governments. In early August, the Bulgarian government, pressured by the ruling
of the International Court of Arbitration in Geneva not on favor of the National Electric Company, began to discuss the restoration of the Belene NPP project. Almost at the same time, the South Stream returned forcefully on the government’s agenda, following the rapprochement between Turkey and Russia that might give new breath of life to the Turkish Stream. However, if the South Stream and NPP Belene are ever built, their reanimation will certainly look like some kind of energy necromancy. The NPP Belene and the South Stream have never been really put to an end. The project companies that were supposed to build the gas pipeline segments in the Black Sea and in Bulgaria have never been dissolved even after the cancellation of the project. As for the NPP Belene, the Russian builder Rosatom fought an arbitration battle for four years which resulted in a never-ending soap opera with various Bulgarian politicians and murky investors finding solution to the Russian legal challenge.
There have always been promoters of both projects not only in Russia, which is the main benefactor, but also in Bulgaria. The Bulgarian government has every reason to try to prevent alternative to the South Stream project. If the Turkish Stream is ever built, it will most probably absorb the current gas transit via Bulgaria. Turkey and Greece now receive around 17 bcm of Russian natural gas annually which is shipped via Ukraine and then via the Trans-Balkan pipeline it reaches both countries. If these quantities of natural gas are redirected to an alternative route, the transmission operator Bulgatransgaz will lose transit fees of approximately 80 mln. Euros per year. This seems not to be a great amount of money, but the Gazprom payments are one of the most secure revenues of the cash-strapped Bulgarian Energy Holding, the company that controls the state owned energy assets. It is quite possible that Gazprom might also decide to change the natural gas supply route for Bulgaria – instead of using the pipelines from Ukraine the natural gas might begin coming from Turkey which will be resounding political slap for Sofia.
But there is one more reason for the intense lobbying in favor of the pipeline - the “extra” benefits provided by South Stream. For example, in 2014 South Stream Transport, the company that was established with the idea to build the sea part of the pipeline bought a 165 ha of coastal property near the Bulgarian Black Sea town of Varna for the whopping 100 mln. Euros. This made 606 Euros per
However, if the South Stream and NPP Belene are ever built, their reanimation will certainly look like some kind of energy necromancy
sq. m., a price tag that is significantly higher than most of the deals during the property boom in Bulgaria in 20052008. There are serious doubts that the Russian company wanted to grease its way in Bulgaria, buying a property owned by a local bank, known as politically well connected. The situation with NPP Belene is similar. The International Court of Arbitration ruling requires NEK to pay 620 mln. Euros to Rosatom for equipment that was ordered, but unpaid. The ICA awarded additional 167 thousand Euros a day to the Russian company in the case NEC delays its payments. The mounting financial burden pressures the government to find a quick solution – to sell the redundant reactors or to restart the project. As with the South Stream, the NPP Belene has its own sweeteners. The contract of the NEC’s consultant for the duration of the construction was supposed to reach 400 mln. Euros, almost 10% of the initial over-night price of the nuclear power plant offered by Rosatom in 2006.
Bulgarian authorities diminished its ambitions and now would be happy to accept even one pipeline of 15 bcm annual capacity, instead of the initially 63 bcm that were planned for the South Stream
Can Zombies live another life?
For almost year and a half, immediately after the cancellation of the South Stream, the Bulgarian government promotes the creation of a gas hub in the country. The idea is to use Bulgaria’s cross-road position in South East Europe and relatively well developed gas pipeline system to distribute natural gas from various sources to different consumers in South East and Central Europe. But that is a very thin veil for the real reason for the ambitious plan. The hub idea came as a possible solution to South Stream’s problems with EU energy regulations. The reformed South Stream (or rather what is left of it) will stretch between Russia and Bulgaria and will end up at the gas hub near the town of Varna. It will not deliver gas to final consumers and because of that it should be qualified not as a “transmission“, but as an “upstream pipeline network“. The traders will buy the Gazprom delivered natural gas from the hub and then transported it to its respective markets. According to the promoters of the plan, this means that the new gas pipeline project will fall outside the requirements
of third party access or unbundling, the main obstacles that Gazprom tried to evade. Similar regulation exists in Italy with its existing pipelines through the Mediterranean Sea. Bulgarian authorities diminished its ambitions and now would be happy to accept even one pipeline of 15 bcm annual capacity, instead of the initial 63 bcm that were planned for the South Stream. The gas hub idea was communicated with Russian authorities, but they showed limited enthusiasm. Moscow insists on 100% guarantee that Gazprom will not face another legal challenge from the EC. As president Putin declared following his meeting with his Turkish counterpart Recep Tayyip Erdogan on August 9th, Moscow wants iron-clad legal guarantees for the project to go ahead. Something that the European Commission doesn’t seem to be ready to do. Additionally, it will be very difficult for Bulgaria to convince Putin to give the South Stream another chance, because
he probably feels personally affected by the cancelation of the project. The construction consortium which was supposed to build the South Stream in Bulgaria was lead by OAO Stroytransgaz, owned by Gennady Timchenko. According to the US Treasury, Timchenko used to manage Putin’s personal investments in the oil and gas business. Following the ICA ruling, the Bulgarian government hastily organized a high level visit to Tehran with the intention to offer NPP Belene equipment to Iran. The planned Iranian NPP Busher will probably use the same reactor model as NPP Belene. But the initial enthusiasm was cooled down, because Iran is not in a hurry to buy any equipment. At the same time the transaction could only take place if Rosatom cooperates. The Russian company, however, declared that it wants its money first. The immediate answer of the government was to start mulling over possible privatization of the project that will allow a private investor to complete it. Names of possible investors were
not given. The only investor willing to appear is the Chinese company SPIC (for the alternative project – the expansion of NPP Kozlodui with Westinghouse supplied equipment) or CGH (shareholder in NPP Hinkley Point, but they want to sell their own technology, not to use Russian one. The rest of the “investors” that come from time to time could be described only as dubious. One of those – Global Power Consortium turned out to consist of several people, one of whom was convicted in Italy for investment fraud. The answer for this lack of investors’ interest is simple – Bulgaria doesn’t need new power plant, it now has an excess capacity. At the same time, building a NPP with the expectation to export its electricity would be very risky undertaking. Most probably none of the projects will ever be built. But for the Bulgarian government to have chance to solve the problems with NPP Belene, it needs to soften the Russian stance with support for the South Stream. Such a support however needs mustn’t annoy neither the European Commission, nor the US.
The EU doesn’t seem to relax its stance on the South Stream, while Washington will not be particularly happy by any proRussian moves in Bulgaria or the return of any Russian nuclear power plant project, while the US Westinghouse has its own project in Bulgaria.
* Ilin Stanev is editor at Capital Newspaper in Sofia who covers energy policies and domestic politics. He can be reached at ilin. firstname.lastname@example.org
Overview Atanas Georgiev *
IS THE BULGARIAN GAS GRID FOR SALE? What would be the outcome of the DG Competition’s case against the Bulgarian Energy Holding and why is the divestiture of the national transmission grid a real option?
At the end of June, the Bulgarian Prime Minister Boyko Borissov announced that the EU antitrust regulators have told the Bulgarian authorities that they should sell the state-owned gas transmission system operator (TSO) Bulgartransgas. Otherwise they risk paying a fine of up to 300 million EUR, government sources said. Even if this came as “breaking news”, a similar development was expected and should not be treated as a full surprise. In July 2013, the European Commission’s DG Competition opened proceedings (Case 39849 BEH gas) to investigate whether the Bulgarian Energy Holding (BEH) may be abusing its dominant market position in gas markets in Bulgaria. In March 2015, the EC sent a statement of objections to BEH, informing it of the Commission’s preliminary view that “BEH may have breached EU antitrust rules by hindering competitors’ access to key gas infrastructures in Bul0garia”. As the message noted, BEH is vertically integrated and supplies gas through its subsidiary Bulgargas, while the other subsidiary Bulgartransgas owns the domestic gas transmission network,
the only gas storage facility in Bulgaria and the capacity on the main gas import pipeline into Bulgaria.
The Background – Article 102 of the TFEU The European Commission’s DG Competition has been successfully implementing the provisions of Article 102 of the Treaty on the Functioning of the European Union (TFEU). As Article 102 stipulates, “[a]ny abuse by one or more undertakings of a dominant position within the internal market or in a substantial part of it shall be prohibited as incompatible with the internal market in so far as it may affect trade between Member States.” The key to understanding Article 102 is to have in mind that its goal is to prevent the use of a dominant position which may impair the trade between the EU Member States (Frenz 2016). As other scholars (Lorenz 2013) point out, this Article does not prohibit dominance as such, but merely places specific restrictions on companies that have a dominant position. Failure to comply with Article 102 – if confirmed by the European Court of Justice (ECJ) – may lead to fines of up
to 10% of the respective group’s global turnover, as well as possible actions from third parties, which may be able to prove that they have suffered loss as a result of the anti-competitive behavior. This may explain Prime Minister Borissov’s words regarding the 300 million EUR fine – this corresponds roughly to 10% of BEH’s annual turnover.
company is to avoid ECJ proceedings. However, if the commitments are not observed, the EC may impose a fine of up to 10% of the company’s global turnover without asking the ECJ. There are three main types of commitments accepted by the EC: 1) divestitures; 2) structural remedies; and/or 3) behavioral commitments.
Bulgaria’s BEH is well-acquainted with such procedures – in December 2015 the European Commission announced, that it had adopted a decision that renders legally binding the commitments offered by BEH to end competition restrictions on Bulgaria’s wholesale electricity market with relation to another Case – 39767 BEH Electricity, which started in the end of 2012.
According to the EC’s experience, divestiture – i.e. privatization or sale of the asset – are the best way to eliminate competition concerns resulting from horizontal overlaps. Also, in general, divestitures are a preferred structural remedy by the EC as they bring “an immediate and clear-cut change in market structure and their fulfillment can be monitored at relatively low cost” (Lorenz 2013). For example, in Case 39767, BEH Electricity the Bulgarian Energy Holding and the EC have negotiated the divestiture of the Independent Bulgarian Energy Exchange (IBEX): the transfer of 100% of its shares from BEH to the Ministry of Finance before a specified deadline.
Remediation and Commitments
During such procedures, the companies under EC scrutiny may offer some commitments to evade fines. If the EC accepts the proposed remedies, a conditional decision follows and specific commitments and obligations are attached to it. The logic of such decisions by the EC and the investigated
Other similar commitments by energy
companies across Europe include the sale of assets through a special procedure, managed by a “Monitoring Trustee” – an independent company or individual, who has to organize the divestiture under transparent rules and procedures. For instance, Italian ENI has sold shares in international pipelines, RWE has divested from the German gas transmission network (more than 4000 km of high pressure pipelines), and E.ON sold some of its generation – 5000 MW. Other commitments may include “structural remedies” – i.e. granting access to key infrastructure, as well as “behavioral commitments” – i.e. the company promises to refrain from a particular market conduct.
Possible Effects of the Bulgartransgas Divestiture While in 2010 RWE did sell Thyssengas, its German supra-regional gastransmission network, to infrastructure funds managed by Macquarie Infrastructure and Real Assets, a similar divestiture in Bulgaria may lead to unexpected results. Even in Germany now, 6 years later, the situation is quite
interesting – Reuters reported on June 15th, that the Dutch investment fund DIF and the French multi-utility EDF may buy Thyssengas, paying roughly 1.5 times the book value of the company. Selling a TSO to pension funds is one thing, but vertically integrating local gas grids with foreign energy traders may be quite different. Who would be the candidates for the Bulgarian gas grid, if the Case 39849 BEH gas is closed with commitments from BEH including divestiture and/or behavioral remedies? Can we expect Western European gas companies to purchase minority or majority stakes in the Bulgarian gas TSO? Possible buyers may be gas majors, who operate in adjacent countries. However, such interest has not been explicitly expressed.
According to the EC’s experience, divestiture – i.e. privatization or sale of the asset – are the best way to eliminate competition concerns resulting from horizontal overlaps
We have to keep in mind, that the Bulgarian gas grid was built in the 1970s mainly to solve a logistical task for Russia – connecting the Russian gas system with a consumer of roughly 1015 bcm p.a.: Turkey. Gazprom has been negotiating the purchase of the Bulgarian grid very actively about 20 years ago and would have been the first foreign coowner of some of the local transmission grids, if the South Stream was built. At present, 100% of the Bulgarian transit pipelines’ capacity is reserved for Gazprom and there is still no other source or supplier of gas with the exception of some test virtual supplies through the existing Bulgaria-Greece gas interconnector. If someone wants to solve several issues at once – a landing point for both the South Stream and the Turkish Stream (if any of them is ever built), a gas storage in a promising regional market, and a TSO at the entrance of the Southern Gas Corridor, the Bulgarian TSO looks like the perfect option. Unfortunately, this someone would most probably be Gazprom – the very same user of the network, whose contracts were the reason for starting the EC’s case against BEH in the first place. So let us explore another option – is it possible to transfer the gas TSO’s shares to the Ministry of Finance as well – just like the IBEX case? This will remove Bulgartransgas from the gas and electricity conglomerate BEH, while still keeping the ownership for the Bulgarian state. It remains to be seen whether the EC would accept such an option.
The decision would not be easy. Divesting strategic assets in South East Europe – especially on the doorstep of the Southern Gas Corridor –may not be as straightforward as divesting national gas grids in well-connected Germany, for example. Maybe this would be one of the first tests for the compliance of the Energy Union Strategy with existing EU rules and institutions. Literature 1) Frenz, Walter (2016) Handbook of EU Competition Law, Springer, pg. 829 2) Lorenz, Moritz (2013) An Introduction to EU Competition Law, Cambridge University Press, pg. 188
* Dr. Atanas Georgiev is Assistant Professor in the Faculty of Economics and Business Administration of Sofia University, Bulgaria, where he teaches Regulatory Economics and Utilities Management to grad students. Atanas is also a lecturer at the “Energy Diplomacy” courses, organized by the Diplomatic Institute in the Bulgarian Foreign Affairs Ministry. He is the publisher and chief editor of the Bulgarian “Utilities” magazine and the online portal Publics.bg, as well as a frequent author of articles in other energy-related publications. Atanas is also member of the Management Board at the National Committee of Bulgaria for the World Energy Council (NCBWEC), member of the International Association for Energy Economics and of the Scientific Committee at the Turin Sc
Electricity Vladimir Spasic
ONE YEAR OF EPS RESTRUCTURING IN SERBIA In the first quarter of this year, the Electric Power Industry of Serbia (EPS) had a profit of 13.6 billion dinars (111 million Euros), which is several times more than planned, and a good signal that a record profit could be achieved for the entire year. Last year, EPS had recorded a profit of 2.5 billion dinars (20.7 million Euros), in spite of projected losses.
Results of measures to improve the organization and efficiency of EPS are already seen in profit and payments to the state budget. In the first quarter of 2016, as company stated for EnergyWorld, EPS paid 24.5 billion dinars (200 million Euros) in various tax contributions and in part of the profit from last year. “EPS profit in the first three months of this year amounted to 13.6 billion dinars which is several times higher than planned. This shows continued trend of business results improvements having in mind that in 2015 EPS contributed to state budget with 67 billion dinars which is seven percent of the total budget revenues, and achieved profit of 2.5 billion dinars instead of the projected loss for last year”, EPS said adding that savings under the reorganization program paved by the Government of Serbia contributed in a significant extent to good financial results. In the first quarter of 2016, through increased efficiency and better organization EPS has saved 6.2 billion dinars (51 million Euros). Measures
reduced costs in almost every part of the business. The purchase cost of electricity decreased by 2.1 billion dinars (17 million Euros) compared to planned, and the centralization of the procurement system has saved about 300 million dinars (2.4 million Euros). Shifts are perhaps most evident in the production segment. Compared to last year, EPS produced 5.6 percent more electricity, which contributed to the profitable electricity trade. From January to April EPS exported electricity for 51.7 million Euros and imported for only for 9.3 million Euros. In the end EPS earned 42.4 million Euros. The mining Basin “Kolubara” also produced three percent more coal than planned. - This is a confirmation of our business efficiency. EPS didn’t stop reforms. We are constantly working on reducing costs, but it is necessary to plan longterm investment in a system which was underinvested for decades especially in the fulfillment of environmental standards. We will invest one billion Euros in environmental protection over the next 10 years - says EPS CEO Milorad Grcic.
New life for one of the two biggest thermal power units A significant investment for EPS is also a major overhaul of one of the two biggest thermal power units; block B2 with 620 MW in Thermal Power Plant “Nikola Tesla B”. EPS will be investing around 70 million Euros to get the block power increased by 30 megawatts and life-time for another 30 years. There are ongoing revitalization of aggregates in hydropower plants “Derdap 1” and “Zvornik”.
One of the environmental projects is “green credit” for the modernization of equipment and better quality management in Mining Basin “Kolubara”, with a total value of around 180 million Euros. EPS has recently launched construction of the third block of 350 MW in Thermal Power Plant “Kostolac B”, which will be the first large capacity for electricity production in Serbia after almost three decades. The project is implemented in cooperation with Chinese partners and will enable Serbia to get a thermal block built by the latest technologies, which will increase the energy security of the system. In the first phase of the project EPS revitalized with Chinese partners the two blocks in TPP “Kostolac B”, and
this year will see end of desulphurization facility construction. The company assures that no part of the system is left out in the current investment cycle to improve the quality of service that EPS provides. Company announces investment of 24.5 billion dinars (200 million Euros) in better management and modernization of the distribution network this year. “Elektroprivreda Srbije is constantly decreasing losses in the distribution network and one of the measures is Action Plan for reducing losses. Non-technical losses are reduced primarily by discovery of unauthorized use of electricity and EPS is constantly
working on detecting illegal connections to the electricity grid and theft of electricity. EPS estimates that about 40 percent of total losses in the network come from the theft of electricity. Special teams were established to detect this theft, consisting of the most experienced electricians from all parts of Serbia. Date and place of large scale field controls with fifteen teams are kept strictly secret until the last moment. All this gave results as from July 2015 to June 2016 teams of ‘EPS Distribution’ revealed usage of around 95.5 million kilowatt-hours of electricity without authorization, worth about 1.26 billion dinars (10.4 million Euros)”, EPS stated. In addition to large scale field controls, among the measures taken are detailed analysis of consumer consumption, the relocation of the meters to more visible and accessible places of households, the implementation of new technologies for more efficient detection of thieves and the promotion of advanced meters. In 2015 EPS filed more than 11,440 criminal charges against those who used electricity unauthorized.
Electric Power Industry of Serbia - Owner 100% Republic of Serbia
- Production of coal and electricity, supply and distribution of electricity
• “EPS Distribution”
- Employees 36.000 - Electricity production 35,600 GW/h - Installed capacity of power plants 8,359 MW* • in 6 lignite-fired thermal power plants 5,171 MW • in 3 gas-fired and liquid fuel-fired combined heat and power plants 353 MW • in 12 hydro power plants 2,835 MW • EPS operates three power plants of total 461 MW capacity which are not in the Company ownership
• “EPS Trading” Ltd. Ljubljana, company for trading abroad in electricity • Company for cogeneration of thermoelectric power and heating energy “Energija Novi Sad” JSC Novi Sad, founded with Novi Sad City, in the amount of 50 percent of shares in Company’s equity
- Results can already be seen. EPS operates stably and has a bright future. We have a clear plan. Every produced kilowatt-hour is important, but greater savings and efficiency are necessary. EPS intends to remain the backbone of the Serbian economy - said Grcic.
• “Ibarske hidroelektrane” ltd. Kraljevo, founded with “Seci Energia S.p.A”, Italy, with 49 percent of shares in Company’s equity
He pointed out that restructuring is a complex process that will last and should bring benefit to EPS, Serbia and consumers.
• Company “Moravske hidroelektrane” ltd. Beograd, founded with “RWE Innogy”, Germany, with 49 percent of shares in Company’s equity.
- Coal production* • 37 million tons of lignite production • coal basins of Kolubara and Kostolac are in the direct vicinity of thermal power plants
A year ago, EPS started major changes in its organization model in which production and supply were placed under a cap and five distribution companies integrated in a distribution system operator “EPS Distribution”. Both entities are part of EPS holding.
*As of 1 June 1999, EPS does not operate with 2 thermal power plants and one mine basin on the territory of Kosovo in Metohija. *2015.
- A huge system as EPS cannot be reorganized quickly, in a day or a month. We continue to implement the decisions and policies of the Serbian Government and the IMF. Reorganization runs towards plan approved by the Government. EPS’s priority remains ensuring a continuous electricity production and stable supply of all customers - Grcic said.
Oil & Gas Cristina Bucureasa
INSPECTIONS AT ROMANIAN GAS COMPANIES BY THE EU “The Commission has concerns that the companies involved may have violated EU antitrust rules that prohibit cartels and restrictive business practices and/or the abuse of a dominant market position,” reads a statement of the European Commission, regarding the three Romanian energy companies.
European Commission officials carried out unannounced inspections at the offices of Romgaz, Transgaz, and OMV Petrom, key players in the Romanian natural gas sector, which are suspected of having participated in an agreement to block the gas export from Romania to other EU member states. Three of the main actors involved in the supply and transport of natural gas in Romania have raised suspicion that they have violated anti-trust rules and have been subject to the inspections of the European competition authorities, at the beginning of this summer. Thus, officials from the European Commission’s Directorate General for Competition and the Competition Council in Romania conducted unannounced inspections at the premises of Romgaz, OMV Petrom and Transgaz, key players in the natural gas sector. The controls targeted Romanian gas producers Romgaz and OMV Petrom, and gas transporter Transgaz. “The Commission is investigating potential anticompetitive practices in
the transmission and supply of natural gas in Romania, in particular relating to suspected anticompetitive behavior aimed at hindering natural gas exports from Romania to other Member States,” the European Commission says. The European Commission’s inspections aimed at gathering proof related to the three Romanian companies’ anticompetitive practices. However, the EC said that the unannounced inspections are just a preliminary step into suspected anticompetitive practices and this doesn’t automatically make the investigated companies guilty. The three companies have confirmed the inspections and said they were cooperating with the investigators. Romania’s Competition Council has also been helping with the investigation, which is the first such operation carried out by the European Commission in Romania. DG Competition’s inspection is an unprecedented action in Romania, but the issue of blocking gas exports is an older one. For many years,
a government policy aimed at delaying exports, and this was reflected in the lack of investments for Transgaz, the state-owned company managing the gas transmission network in Romania, in interconnections. Moreover, Romania is aimed by an infringement procedure in this regard. In October 2012, the two largest gas producers, Romgaz and Petrom had made a commitment to the Government not to export gas during the price liberalization period. Then, Romgaz and OMV Petrom, had agreed in principle with the state authorities, not to export gas during the price liberalization period. Last summer, the European Commission decided to refer Romania to the EU’s Court of Justice because it has not adopted an emergency plan on the security of natural gas supply, an obligation that should have been met three-and-a-half years ago.
“The investigation is extremely serious” The European Commission’s investigation on the gas market in
Romania is extremely serious, and the allegations against the three local companies investigated, Romgaz, Transgaz, and OMV Petrom are very serious in the eyes of the Commission, said Valentin Mircea, the head of the Prime Minister’s Control Body and former deputy president of the Competition Council. If the EC sent its inspectors to Romania, there were surely indications about the allegations, Mircea said. The allegations refer to blocking gas sales to EU’s internal market. According to the head of the Prime Minister’s Control Body, the EC will probably send these companies a preliminary evaluation in a couple of months, and they could seek an amicable settlement of the case with the Commission, Mircea added.
EC inspection, brought by a complaint from Hungary According to sources in the energy sector, the European Commission’s General Directorate for Competition (DG Competition) started its investigation
into Romania’s gas market following a complaint lodged by a company in Hungary. “The European Commission has turned against Transgaz to a large extent because, for many years, it delayed investments that would render possible exports of gas from Romania to Hungary (i.e. via Arad-Szeged pipe). The investigation started further to a Hungary complaint on the fact that Romania does not export the cheap gas it produces to this country, which would mean blocking the movement of goods within the community area,” according to sources. At the moment, the Arad-Szeged pipeline only allows gas imports from Hungary to Romania, not the other way around. Romanian gas carrier Transgaz plans to make investments to allow gas transit in both directions.
Interview Maja Turkovic* Stevan Veljovic
TIME FOR A DIFFERENT ENERGY MIX IN SERBIA The national energy strategy sends confusing messages, where renewable energy sources have a purely declarative support, but in the essence it envisages a carbon future for us. It doesn’t send the signal to investors that renewable energy is a priority, thereby reducing investment risk and the cost of capital.
Serbia faces significant challenges in accomplishing the mandatory targets of 27% of renewable energy in gross final energy consumption by 2020. A recent study you worked on as co-author, “A Roadmap for Deploying Renewable Energy Sources in Serbia and the Regional Perspective”, confirms the view that this target is out of reach within the agreed deadline? Utilization of renewable energy sources (RES) in Serbia and the region is far below the level projected and agreed within the Energy Community. Since the adoption of the Renewable Energy Directive 2009/28/EC in 2012, only 53 MW of new renewable energy capacities have been put into operation in Serbia, which is less than 5% of the targeted 1,092 MW by 2020. There are less than four years left to fulfil the targets and unlike EU, the region has not even started considering the 2030 targets. The lack of projects is not due to a lack of interest among investors and independent power producers. On the contrary – the interest is there and money has started flowing into the sector, but a result is still lacking,
because of a number of different barriers – economic, political and social – which hamper the construction of most renewable energy projects. What are the main reasons behind the sluggish development of renewable energy sources (RES) in Serbia, despite the huge interest from investors and mandatory obligation? Firstly – the national energy strategy sends confusing messages, where RES have purely declarative support, but in the essence it envisages a carbon future for us. It doesn’t send the signal to investors that renewable energy is a priority, thereby reducing investment risk and the cost of capital. Serbia was among the first within the Energy Community to implement fully harmonized energy law, but despite that has not made any progress with respect to RES deployment. Declaratory action plans for RES are being enacted, but we never conformed to them. On the other hand, a set of key secondary regulation was lagging, blocking financing and construction of large RES projects. As a consequence, some large wind
projects may become too expensive to be financed and constructed ultimately. Finally – we had to pass through the shallow learning curve lasting more than seven years, which resulted in the first bankable PPA model, being adopted in June this year. The regulatory framework has improved over the past few years, with new Law on Planning and Construction and Energy Law with bylaws. However, the issue of the PPA for large RES project remained inadequately solved. The Government has finally adopted the package of decrees relevant for RES projects, with a 6-months delay, as the previous versions of the PPA model decree were not acceptable for the creditors. The new PPA model decree brought important positive changes compared to the previous versions of the document, but has yet to be tested in practice. It replaces the “preliminary PPA” concept with the “single PPA” concept; it introduces several advanced mechanisms to resolve the issues of the force majeure events (including political force majeure and change-in-law clause); it prescribes the PPA termination clause
allowing the producer to terminate the PPA if the off-taker is in delay with payments; and – most importantly – it introduces a step-in agreement between the lender, the producer and the off-taker, for projects above 30 MW, allowing the lender to name a different entity as a producer, if the previous producer defaults on his obligations or loses the privileged producer’s status. Finally, for disputes arising from the agreement, the decree provides options between Serbian Court and an arbitrage in Wien (VIAC) or in Paris (ICC). What do you consider now as a realistic target for 2020 and does the structure of the targets need to be readjusted in the future, as well as the incentives? Increasing the share of RES in gross final energy consumption to 27% by 2020, from a starting point of 21.2% in 2009, is a mandatory target that can’t be changed. The way and the timeline to reach this target are up to us. The 2013 National Renewable Energy Action Plan failed to bring Serbia close(r) to its 2020 target in all three
sectors (electricity, heating/cooling and transportation), and it is highly unlikely that the country can catch up during the next four years and meet its obligations. However, this gap could be narrowed down significantly if large wind projects are constructed and made operational. In that case, in aggregate from wind projects and small RES projects, we could have around 500 MW from RES operational by 2020 – which is around half of the electricity target for 2020.
“The national energy strategy sends confusing messages, where RES have purely declarative support, but in the essence it envisages a carbon future for us”
Does Serbia’s actual Energy Sector Development Strategy until 2025 need to be adjusted, having in mind delays in construction of new TPPs, non-realization of RES and energy efficiency targets and new challenges in the gas sector? Absolutely, yes. There is an impression that the new “old” energy strategy was enacted because of the time pressure and/or because nobody wanted to deal with it thoroughly. This document is outdated. Do we follow the old path because we are afraid to change the course? Unfortunately, the participation of professional public in drafting the strategy paper was marginalized. It is very difficult to understand why Serbia is adopting an energy strategy dominantly based on the exploitation of coal - nowadays when the world is turning away from fossil fuels towards a non-carbon energy future. Furthermore, even in that event we should be prepared to import coal in the foreseeable future, as 76% of our coal reserves are in Kosovo. A sustainable energy strategy has to be driven by climate changes and energy security, reflected in creating an energy market with competitive prices, ensuring security of supply, reducing CO2 emissions and saving energy. How do you see Serbia’s future in terms of desirable the energy mix? Reserves of coal are highly regarded as the main source of energy for future decades, while some studies show that the RES potential is bigger than officially recognized. This is the most important question
on which the national energy strategy should provide an answer. Firstly, it is important to understand that with the current level of electricity price, regardless the RES share in the energy mix, we will not have investments in new power plants of any kind – coal, hydro or any other. For this reason no power plant was constructed in Serbia for decades, despite all the MOUs being signed with potential investors. Secondly, electricity produced by “clean” fossil fuel technologies today (e.g. with carbon capture storage) – and which are the only ones that can be built today due to strict environmental regulations – costs as much as electricity produced in solar photovoltaic power plants and wind farms. Thirdly, Serbia has nine plants that fall under the scope of the EC Large Combustion Plants Directive, with a total installed capacity of 4,679 MW, which require either modernization or replacement by new capacities. There are no new power plants built nor under construction to replace the capacity that needs to be shut down – and it typically takes 7 to 10 years to construct the utility-scale power plant. Fourthly, the RES potential in Serbia is greater than the officially recognized, specifically the potential of wind and solar power, which is limited by grid constraints. However, the grid is subject to further development and enhancement, and even now substantial
capacity from wind and particularly solar energy can be reached through distributed generation, avoiding investments in grid extension. Any future energy mix in the Serbian power sector will continue to have a significant share of electricity coming from thermal power plants, the ones based on “clean” fossil fuel technologies. Modernization of thermal power plants, which will “survive” the Large Combustion Plants Directive, in order to comply with environmental standards, will drive the electricity price up. With the upward correction of the electricity price, we can expect new investments in large hydro power plants, exploiting unused hydro potential. What does this mean for using RES potential? Renewable energy will have a significant role in the future diversified energy mix – despite all the hurdles the sector is facing today. We can expect a significant capacity from utility-scale wind farms, which is the fastest and cheapest way to ensure new production capacity on the grid. There is also a huge potential for distributed generation, especially in solar photovoltaic technologies, combined with energy storage systems for households, businesses and industry. They are becoming more efficient and affordable day by day. Distributed generation is supported by smart grids, whose role is to enable consumer engagement and demand-side management – adapting consumption
“Increasing the share of RES in gross final energy consumption to 27% by 2020, from a starting point of 21.2% in 2009, is a mandatory target that can’t be changed. The way and the timeline to reach this target are up to us”
to fluctuations in electricity production from renewables. These technologies are already available and can be applied, for example, instead of new peaking plants or storage capacity. They achieve the same benefits as, for example, gas-fired power plants, but do so at a lower cost. Another aspect of energy security is the existence of local industry and know-how. Could Serbia develop capacities for producing and maintaining RES technologies instead of just importing it quickly enough? Local industries could seek opportunities in the production of equipment for renewable energy generating technologies, as demand increases for machinery, parts and knowhow. Major industrial complexes could produce equipment such as steel towers for wind turbines or solar photovoltaic panels, demand for which is expected to grow alongside the growth in demand for renewable energy. This development entails an increased workforce, with significant changes in the structure of the labour demand as a result of the green transformation of the economy.
Greenfield investments in renewables don’t just employ local labour and increase tax revenues during the construction period. It creates a totally new industry that generates wealth by exploiting naturally abundant resources that would otherwise be wasted. Renewable energy resources are local by nature and thus impossible to delocalize and they result in new local technological (e.g. technical maintenance, service) and non-technological jobs once the construction is complete.
* Maja Turkovic is an expert for renewable energy and co-author of the study “A Roadmap for Deploying Renewable Energy Sources in Serbia and the Regional Perspective” published by Belgrade-based Center for International Relations and Sustainable Development, CRISD.
Renewables Emilia Damian
ROMANIA TURNS TO THE... GREEN MODE The Romanian Government launched two programs in order to encourage and help the potential consumers to buy electric cars and renewable energy equipment for their houses.
There is high demand for subsidies for electric car purchases. About 7,500 Romanians have submitted applications to take part in the state-backed program for acquiring electric cars.
cars or hybrids. It will provide funds of EUR 15.4 million this year alone. Municipalities with over 50,000 inhabitants, public institutions, and companies can apply to the program.
The list with the authorized car producers and dealers within this program will be published this week, said Istvan Jakab, chairman of the Environment Fund Administration (AFM). The program may start at the end of the month.
Cora, Kaufland and Auchan, three of the largest local retailers, have already opened charging stations for electric cars at some of their stores.
People who want to apply for the program can benefit from a ticket of RON 5,000 (over EUR 1,100) for buying a hybrid car and a ticket of EUR 4,400 for acquiring an electric car, without having to give in an old car.
The Environment Ministry launched a Green Home and a Green Home Plus program in late July for public debate, designed for those in need of funding to equip homes with non-polluting energy production systems and to isolate them with ecological materials.
The average price of an electric car amounts to EUR 30,000, higher than an average car that uses gas. The total funds allocated for this program reach approximately EUR 1.1 million.
The programs were up for public debate for ten days and officially launched in August. Thus, for 2016, the Green Home programâ€™s budget reaches 138 million lei, out of which 60 million lei for individuals.
The Environment Fund Administration is also trying to create a national infrastructure for recharging electric
â€œAn individual can receive up to 6,000 lei in funding to purchase solar panels securing hot water for the household,
namely 100 percent of the costs. For the purchase of a heating pump, the funding reaches 8,000 lei, namely 70-80 percent of the total costs,” Environmental Minister Cristiana Pasca Palmer said at the conference launching the program, an event organized at an energy efficient house, namely the Solaris House of Voluntari, near Bucharest. For public buildings, funding can be obtained for up to 90 percent of the project costs, capped at 500,000 lei for religious establishments and two million lei for public institutions. For mayoralties, the subsidy is capped at four million lei for cities of over 100,000 inhabitants, decreasing gradually to 500,000 lei for places with less than 3,000 inhabitants.
“This year, we are launching as a first the Green Home Plus program. The total budget for this year is 45 million lei, out of which 12 million lei for individuals and 33 million lei for legal entities,” the minister said. The projects funded under the Green Home Plus program will include, besides
heating systems, energy optimization by employing low carbon print materials, namely weatherization of the walls using ecological materials such as wool, hemp or basaltic stone, green roof systems, systems making resource consumption more efficient and green lighting systems.
“This year, we are launching as a first the Green Home Plus program. The total budget for this year is 45 million lei, out of which 12 million lei for individuals and 33 million lei for legal entities,” – Cristiana Pasca Palmer
An individual can receive up to 40,000 lei under this program, an amount that can fully cover weatherization with ecological materials of a house with a ground print of 90 square meters (material plus labour costs). Legal entities can receive up to 500,000 lei for buildings of public interest. The Solaris House, where the press conference took place, can produce four times more energy than it consumes, with the aid of photovoltaic panels mounted on the roof, the heating and air conditioning of the house is done through the walls, ceiling and floor, using water pumped from a nearby well. The owners of the house pay no housing costs and receive money for supplying electricity to the national grid.
Electricity Kostas Voutsadakis
THE APPROPRIATE ISLAND ELECTRIFICATION MODEL IS REQUESTED The production of the necessary energy for the islands is based on outdated diesel-operated units, with a cost multiple of the average production cost in the mainland (it is indicative that in Antikythera in 2012 the production cost was... 1748 Euros per megawatt/hour while on the large islands it stood at 200 Euros compared to approximately 83 Euros, which was the price on the interconnected grid).
The PPC, as well as the Energy Ministry and the Regulatory Authority for Energy (RAE) are at a “crossroad” regarding the selection of the power model of the noninterconnected islands of the Aegean as the environmental EU legislation will lead in the coming years to the withdrawal of the most polluting units while alternative options of interconnection, upgrading of the existing facilities and/ or the creation of new ones with liquefied natural gas remain open without any decisions having been made. Given that these investments are time consuming and often encounter several reactions from locals leading to further delays, the danger that decisions are made under extreme time pressure is visible, with whatever this may mean for the cost and quality of the choices that will be made. Already this scenario applies in the case of Crete, where the emergency withdrawal of units coupled with years of delay in the island’s interconnection with the mainland necessarily leads to the selection of constructing of two interconnectors: a “small” one to ensure the electrification of the island and a “large” one that
will lead to cost savings and the development of renewable sources. The electrification of the islands is an extremely expensive activity. The difference (since the PPC’s tariffs for the islands do not differ from those of the interconnected system) is covered by the Utilities Services paid by consumers through their electricity bills, with the annual cost standing, according to the latest calculations of RAE for the period 2012-2013, at 800 million Euros. The Utilities Services’ account is (along with the Special Duty of Greenhouse Gas Emissions Reduction (ΕΤΜΕΑR)) a fuse for higher tariffs for electricity, while the PPC is retroactively claiming 600 million Euro for the 20122015 period when the revenue received from consumers fell short of the islands electricity costs. It is noted that the dip in oil prices reduced the cost for fuel on the islands on one hand; however, the difference in the cost of electricity to the mainland grid remains as a corresponding decline was recorded in the cost of generating electricity with natural gas. According to the PPC: “Although the considerations were set by the RAE
for the Utilities Services of the years 2012 and 2013, for the determination of the new unit charges per customer group and particularly the inclusion in the electricity bills, a legal provision is required which until today has not been promoted resulting in the corresponding income falling below the of the consideration approved by the RAE. The PPC has submitted the question to the competent ministry. The total additional amount payable for the PPC (for the years 2012 & 2013) amounts to € 445.3 million and the approved consideration for the Utility Services has not yet determined by the RAE for 2014”. The current figure for the electrification of the islands is as follows: –The Total capacity of the units is 1784 MW, of which 1046 are units of Crete (813) and Rhodes (233 MW). In 2015, thermal units covered for 82% of the demand with renewable sources limited to only 18% despite the rich wind and solar potential. –For The current summer (2016) when the consumption is increased due to tourism, PPC analyzes show that there is
a problem of adequacy in Crete; Rhodes has a 20 MW deficit to be covered by power generators while in nine islands (Anafi, Othoni, Kythnos, Donousa Erikoussa, Amorgos, Astypalea, Limnos and Karpathos) there is smaller or larger reserve deficit will shall also be met with generating pairs, owned or rented. The largest surplus reserve (over 10 MW) is in Santorini, where apparently they learnt their lesson well. The PPC’s medium-term planning includes the new power 115 MW unit in Rhodes constructed and is expected to be operational in 2017, a new 120 MW power unit in Lesvos and installation of a generating pairs of a total 150-160 MW power in other islands to meet the needs until 2019. Problems arise however from 2020 onwards, further to the implementation of environmental EU directives (2010/75 and 2015/2193 for large and small, above and below 50 MW and small power plants respectively). The Directive sets stricter emission limits. According to the analysis of the PPC’s competent departments there is a serious problem for 20 units in Crete (11 in Linoperamata, 4 in Atherinolakkos
and 5 in Chania), 16 in Rhodes and 21 in Kos, Lesvos, Paros, Samos and Chios. Furthermore, more than 200 units in the Aegean Sea have to be modernized. The options if the upgrading of the units does not proceed, is the use of natural gas, the interconnections and the use of renewable sources (geothermal, storage) or a combination of the aforementioned solutions. The Community framework, however, favors the interconnections providing that the authorities “during authorization or tendering for new capacity within a given isolated network of non interconnected islands, systematically consider the alternative of interconnecting of the isolated network part of which is the given non interconnected island. No license is granted for a new capacity if the creation of an interconnection is more cost-effective”. The PPC points out that the framework (strict environmental requirements, high cost of any solutions decided and short time limits) does not allow for patchy solutions but requires the formulation of a long-term energy plan for the non interconnected islands.
Oil & Gas
CHEAPER NATURAL GAS FOR HOUSEHOLDS AND INDUSTRIES As it appears, households and industries using natural gas from next year, will be the big winners as of 2017 by reducing the cost and other household and industrial tariffs.
The new multi (austerity) bill recently passed, shows a significant reduction in the Special Consumption Tax (SCT) as for natural gas a reduction is provided from 01/01/2017 reduction for the excise tax for domestic use. Furthermore, for industrial use as of 01/01/2017 the SCT is reduced incrementally according to consumption. More specifically, the Special Consumption Tax on domestic invoice will be reduced to 0.11 cents per kilowatt hour (0,00108 € / KWh) from 0.54 cents per kilowatt hour (0,00540 € / KWh) with a direct impact in formulating the final value of gas from the date of its application. For example, applying the reduced tax rate today on the current price for the domestic tariff of EPA Attica (May 2016) would result in an additional reduction of 10% of the price of gas (from 4.8 to 4.3 minutes per kWh). Similarly, the competitiveness of natural gas compared with heating oil will increase even more, and indeed given the impending increase of SCT on oil.
In the same example and with April prices for heating oil, the savings of gas compared to heating oil would reach 36% and furthermore, without taking into account the increase in oil taxes.
Further to constant negotiations with its international suppliers, DEPA has managed to achieve significant reductions in fuel supply rates, which the company has passed on to final consumers
A significant relief is also foreseen for other consumer categories and for industries as there will be scaling down of the tax rate according to consumption. It is worth noting that natural gas prices since the beginning of this year’s heat period until today, rose to levels significantly lower compared to 2015, by a decrease in domestic use of 24% and 39% for industrial use. These reductions are due to the reduction of gas purchase costs as a result of international oil prices and the reduction in prices achieved by DEPA from its suppliers. As it is well known in recent years, DEPA, further to constant negotiations with international suppliers has managed to achieve significant reductions in fuel supply rates, which the company passed on to final consumers.
What do households gain?
All the basic needs of a house can be met with the use of natural gas and save energy and costs exceeding 50%: – Cooking Many households in Greece already cook in ovens and hobs linked to the gas
supply of the building they are in and notice the difference in cooking. It is a completely secure method of cooking. The hobs do not require preheating and cooking speed is impressive. The difference in the economy with respect to the electric power supply is huge, while the difference in taste of the food reaches 100%.
water supply 24/7. Usually natural gas supplies water heaters are used or wallmounted natural gas boilers that are used both for heating and for hot water and savings of up to 40% are achieved compared to an oil boiler and up to 60% compared with a simple electrical water heater.
– Heating The use of natural gas for domestic heating (condensing boilers, etc.) reduces heating costs by 40% and yields reach 110%. The application/ use of natural gas is now a must in the selection of a home’s heating method, over all other polluting and wasteful solutions such as oil boilers, Pellet boilers, wood boilers and biomass. As for the technical part, it is usually not necessary to replace old heating radiators. However, the technician during the relevant check can advise customers depending on the state of the radiators for the best possible solution.
Businesses and industries that select an ecological fuel such as natural gas, actually contribute to the struggle against pollution of the environment by improving the company’s image towards the community and the market in general.
– Warm water The latest domestic hot water production machines allow for hot
The benefits of using natural gas for the cogeneration is economical, environmental and energy saving.
What do industries gain?
The natural gas used in Cogeneration of electricity and heat – CHP (cogeneration is the combined production of electricity and heat from the same original source of energy. With the cogeneration technology the same device can produce both electricity and heat by the combustion of natural gas).
With the conventional manner of electricity production, large amounts of heat are released into the environment, either through the refrigerant circuit (condensers, cooling towers, etc.) or through gas exhaust (air turbines, etc.). With the cogeneration method, much of this heat is recovered and used beneficially. Thus savings are achieved in both energy and costs. The CHP systems can be considered as integrated energy systems, in the sense that that they can cover all final energy uses (electricity, hot water, steam, hot air, cooling). The efficiency of cogeneration systems can reach 85%. Furthermore, in the coproduction natural gas has a high energy efficiency and low emissions of air pollutants.
Electricity Emilia Damian
THE... DARK (AND BLACK) SIDE OF COAL IN ROMANIA Half of the thermal power plants in Romania are among the most pollutant in Europe, said Greenpeace, in its study “Europe’s Dark Cloud: How coalburning countries are making their neighbours sick”
Five of the eleven thermal power plants currently operating in Romania rank in the Top 30 with highest impact upon health, says a report carried out by several environmental NGOs, released by Greenpeace Romania. According to the document, the five countries whose thermal power plants cause the highest number of premature deaths across borders are Poland (4,690), Germany (2,490), Romania (1,660), Bulgaria (1,390) and Great Britain (1,350). The five Romanian plants with the highest impact upon health are Oradea II (240 premature deaths), Rovinari (250), Drobeta (430), Mintia (340) and Govora (230). The report shows that shutting down even one such thermal power plant would substantially improve the health conditions of the population nearby and in neighbouring countries. The report was drawn up by Health and Environment Alliance (HEAL), Climate Action Network (CAN) Europe, WWF
European Policy Office (the European Policies Office of WWF) and Sandbag.
Romania has two big energy complexes, Oltenia and Hunedoara, which both have thermal power plants and coal mines. One of them, Hunedoara Energy Complex, is in insolvency since the beginning of the year and it needs to be restructured. The Jiu Valley Lonea and Lupeni coal mines will enter the closing down program until 2018 and only the Livezeni and Vulcan mines will still be part of the Hunedoara Energy Complex, Energy Minister Victor Grigorescu announced in a press conference. He added that only an energygeneration group will be maintained at the Paroseni thermal power plant and another group at Mintia-Deva, with the two facilities having an aggregate capacity of 400 MW. The discussions with the European Commission on approving the state aid for Hunedoara Energy Complex (CEH) are lengthy, and solutions do not come
from a man’s pen or changes to the legislation, as it occured in the previous years, Energy Minister Victor Grigorescu told a Monday’s debate on national energy strategy. Asked whether it is possible for the DG Competition delegation of the European Commission, which will come to Romania to analyze granting potential state aid to CEH, to reject the reorganization plan, Grigorescu replied: “The discussion with the European Commission is lengthy”.
the approval of the DG Competition in Brussels. Earlier this year, the Competition Council Chairman Bogdan Chiritoiu told a press conference that the authorities in Brussels had demanded the separation of energy production activity from the mining one of CEH.
“It also happens in other companies that are in similar situation to us. We do nothing else than take it step by step. When we reach the end of this process, after a fair and a well-substantiated analysis, we will have a conclusion”, added Grigorescu.
“The discussion with the European Commission about Hunedoara Energy Complex is lengthy” – Victor Grigorescu, the Romanian Energy Minister
In late May 2015, the Government approved an emergency ordinance for granting individual state aid totaling 167 million lei to save CEH, which needs
“At the end of the restructuring period, the complex will remain much smaller, but it will be functional, it will operate on its own”, added Chiritoiu.
The minister could not give a timeframe for completing these discussions.
The official receiver of CEH, GMC SPRL, is proposing in the report on the causes of insolvency, offsetting the debts to the Romanian state, through the Ministry of Public Finance, by taking over the mines in the account of the liability, to an amount resulting from an evaluation report. CEH debts amount to 1.5 billion lei, including 1.2 billion lei to the Ministry of Public Finance, according to the aforementioned report. The Hunedoara Tribunal pronounced the company insolvent on January 7th. CEH has some 6,000 employees in four coal mines and two thermal power plants.
The other energy complex, Oltenia Energy Complex, has approved a series of major projects to be implemented by the company in the period immediately ahead, including a mining strategy for 20162030, a plan for making the company more efficient and streamlined as well as a plan of redundancies for 2016-2017, Spokesperson Elena Zamfir said.
“Oltenia Energy Complex, has approved a series of major projects to be implemented by the company in the period immediately ahead, including a mining strategy for 2016-2030” – Elena Zamfir, spokesperson for Oltenia Energy Complex
“The projects reflect a mining strategy for 2016-2030, which aim is to decrease production costs per tonne of coal and get 2.4 billion lei in savings in 2016-2020, taking into account an almost constant energy quota and the closure of some mines as a result of lignite deposits having been depleted, the absence of selling markets for captive quarries or huge operation costs; an efficiency and streamlining plan for the company in 2016-2020 that has been approved by the Supervisory Board, as well as a lay-off plan in 20162017 starting on June 1st, 2016, that provides for 2,000 redundancies in 2016, 1,067 of whom are pensionable workers by December 31st, 2019. Oltenia currently has 15,168 workers”, said Zamfir. Zamfir also said that at a meeting of the Oltenia management and trade unions, CEO Manager Laurentiu Ciobotarica unveiled the financial state of the company in the year 2015 and the first quarter of 2016. Because the company reported an aggregate two-year loss of 1,655 million lei and a Q1, 2016 profit of 144 million lei, measures are
needed to improve CEO’s efficiency and streamline it. The company’s 2015 lignite output stood at 22.405 million tonnes of coal. Its 2015 losses were standing at 895 million lei, up 30 percent from net losses in 2014 of 693 million lei.
Overview Emilia Damian
NEW WAYS FOR PIPELINES IN ROMANIA The new oil and gas pipelines in the country will be able to cross peoples’ lands even without their permission, according to the new rules adopted by the government.
Projects of national importance in the field of natural gas can be implemented without the agreement of the landowners whose property would be crossed. These include the project that aims to interconnect the gas transport systems of Romania, Bulgaria, Hungary and Austria, namely the BRUA project, report local media. The project’s infrastructure elements can cross peoples’ property, even if they don’t agree with it. Moreover, if the landowners refuse the companies’ access on their land, then the firms that carry out the work can ask the police to help. The provisions are part of an emergency ordinance drafted by the Economy Ministry. State-owned gas carrier Transgaz will develop the Romanian section of the BRUA pipeline, which is 528 kilometers long and will cost some EUR 560 million to build. The European Commission has already approved a EUR 179 million financing for this project and the work should start early next year.
The gas pipeline, which is to link Romania and Bulgaria under the Danube River, will be ready by the end of the current year. It would contribute to the improved energy security for both countries, said Romania’s Energy Minister Vlad Grigorescu. “After several years of hindrances, this project will finally be accomplished. We and the Bulgarians as well will benefit through increased energy security,” said the Energy minister. “Romania has one of the most important energy grids in the region; the system is solid, strong, with an improving situation. (...) We ensure our own energy safety and, even if we encounter troubles, we face them, we are a positive example to the region,” said Grigorescu.
In Mid June, Klaus Iohannis, the President of Romania, together with the delegation of the Romanian Embassy of Romania in Sofia, visited Marten Site, Bulgaria, were the HDD works for the Danube undercrossing were initiated.
“Romania has one of the most important energy grids in the region, the system is solid, strong, with an improving situation. We ensure our own energy safety and, even if we encounter troubles, we are a positive example to the region,” – Victor Grigorescu, the Romanian Energy Minister
Klaus Iohannis met the representatives of the companies involved in the project: Transgaz, Bulgartransgaz and the constructor Habau. The Interconnection Bulgaria - Romania is the only project ensuring gas transmission on the southern gas route Azerbaijan-Turkey-Greece to Austria, through the Romanian section. The gas pipeline from Bulgaria to Austria via Romania and Hungary (BRHA - PCI 7.15, Project of Common Interest on the first list of PCIs) is significant at the regional level since after commissioning the pipeline will provide integration of gas sources from the Southern Corridor with the Central and Western European markets. According to a press release issued by Transgaz, the implementation of this project ensures gas supply from the Southern Corridor (the TANAP and TAP projects), the LNG terminals and other potential sources to the Balkans, Southern European and Central European countries, thus completing the Vertical Corridor between Greece-Bulgaria-Romania,
to Hungary and Central Europe. The project benefits from EU funding through the EEPR, according to Funding Decision C (2010)5962-06.09.2010, the maximum value of the grant amounting to EUR 4.5 million for the Romanian section and to EUR 4.1 million for the Bulgarian section. The date of project completion according to the EC Funding Decision is December 31st 2016. The project includes the building of two gas metering stations (at Giurgiu in Romania and at Ruse in Bulgaria), enabling gas flow in both directions.
Oil & Gas Emilia Damian
ROMANIA FREEZES GAS PRICES UNTIL NEXT YEAR The Romanian natural gas price will be frozen until March 2017, because the international gas prices are at very low levels. Imported natural gas will be 20 per cent cheaper than domestic stocks this winter.
The Romanian Government announced that, as of July 2016, the price of the domestic natural gas will be frozen for nine months at 60 lei per MWh, to address some “particular market conditions”, Energy Minister Victor Grigorescu said. “We took all necessary measures to make sure that this winter we will have enough gas stored so that we avoid this traditional debate on whether the stored amount is enough to get through the cold season”, he added. Not freezing the price might have resulted in prices for the domestic consumers on the regulated market exceeding the free market price, the minister explained. The government also set up an “explicit legal framework” to reconfirm that the Regulatory Authority for Energy (ANRE) is the body that decides on the storage obligations. “We implement harsh fines if the market actors do not build natural gas stocks as required by the ANRE”, added Grigorescu.
The problem of the early liberalization of the gas market in Romania came online with the lower gas price levels in the region. The price of natural gas has dropped on international markets to the level of Romania’s domestic production; thus, a calendar of liberalization of the gas market for households is no longer necessary, Regulatory Authority for Energy (ANRE) President Niculae Havrilet said during a specialists’ debate. “Now is a good moment for the early liberalization of the natural gas market. In my opinion, when price convergence is reached, a liberalization calendar is no longer justified where prices are above the market ones”, Havrilet explained. Imported natural gas will be 20 per cent cheaper than domestic stocks this winter, he also added. Addressing the 2016 Regional Energy Forum (FOREN) in June, Havrilet mentioned possible losses for this industry, resulting from expected prices of 70 lei/MWh for imports, and
80 lei/MWh for the natural gas from the domestic production stored by July 1st, and 86 lei/MWh for the amounts stored after this date. According to the price liberalization calendar, natural gas prices should have increased by 10 per cent on July 1st. Havrilet nevertheless pleaded for continuing the liberalization, without setting up production prices. “The end price of gas will definitely not increase by 10pct”, he insisted. The gas pool for households includes quotas of the current domestic production, stored gas, and imports. The ANRE sets these quotas to obtain the minimum end price. Energy Minister Victor Grigorescu asked that a technical analysis is necessary before halting the liberalization, to avoid useless debates.
Ready for liberalization?
The natural gas market of Romania is not ready for liberalization yet, because there is no competitive environment and the current prices are conjunctural, said the commercial director of the Romgaz (Romania’s biggest producer of natural gas – author’s note) Vasile Ciolpan. “We are not ready yet to experiment this. We still don’t have a competitive environment. The Romanian gas market is closed; look at it, there is nobody to consume the natural gas. Should we modify the current law depending on conjuncture, when the
conjuncture changes, we’ll have to modify it once again”, said Ciolpan. The Romgaz official showed that the current market prices are not determined by supply and demand, as they should. In addition, he reminded that the OPEC and the large oil and natural gas producers are going to change their prices.
Romania has a strong position in Europe in terms of independence from external sources of natural gas, having the largest natural gas reserves in Central and Eastern
“We took all necessary measures to make sure that this winter we will have enough gas stored so that we avoid this traditional debate on whether the stored amount is enough to get through the cold season” – Victor Grigorescu
Europe, with proved reserves of about 150 billion cubic meters and geological reserves of 615 billion cubic meters. With an annual average production of 11 billion cubic meters and a 5 per cent constant annual decline of secure reserves of natural gas, in conjunction with an 80 per cent replacement rate of natural gas reserves, it can be estimated that the Romanian current natural gas reserves may run out within a period of about 14 years.
Last year, the Romanian Government and the European Commission agreed on a new liberalization graphic for the gas price paid by the population for the period July 1st, 2015 – July 1st, 2018. Price increases will be made annually, not quarterly. According to the Memorandum of Understanding between the Romanian Government and the Monetary International Fund (IMF) that contains the new liberalization schedule of prices for domestic natural gas for households, the gas price will increase from RON 53/MWh in July 2015 to RON 72/MWh in 2017. In the case that in 2018 prices on the free market will be more than RON 78/MWh, a new timetable will be scheduled by 2021. For each new price, the Ministry of Energy will have to prepare a draft Governmental Decision that will be published for public debate at least 10 days.
Legal insight Yannis Kelemenis, Managing Partner, Kelemenis & Co., & Konstantina Karveli, Associate, Kelemenis & Co.
THE LATEST BILL ON THE FRM IN GREECE The increased share of intermittent (i.e. variably operating) Renewable Energy Sources (RES) in the energy mix, leads to the assumption that power generation adequacy is not only about capacity margin. As the output of these resources is variable and not fully predictable, both adequate and flexible capacity to produce electricity is needed to avoid black-outs and ensure that electricity supply meets demand at any time.
Generation adequacy (the availability of sufficient resources capacity when needed, including activation of demand switching) and flexibility (the ability to adapt production or consumption to the system needs within a given timeframe) constitute the cornerstones of a reliable power system. 1. The interim report of sector inquiry on electricity capacity mechanisms by European Commission On 29 April 2015, the European Commission initiated a sector inquiry on electricity capacity mechanisms adopted by the Member States. A year later, on 13 April 2016, the Commission invited the public to submit their views on the preliminary results of this state aid sector inquiry into electricity capacity mechanisms in the EU. The inquiry has found 28 past, existing or future capacity mechanisms in eleven examined Member States (Belgium, Croatia, Denmark, France, Germany, Ireland, Italy, Poland, Portugal, Spain and Sweden). Almost two thirds of the capacity mechanisms identified are targeted mechanisms, which benefit only specific types of capacity providers. On the contrary,
most of the mechanisms in planning are market-wide, in which all classes and categories of capacity providers can participate (for instance the French, Irish and Italian planned schemes). Currently the most common capacity mechanisms are: (a) the maintenance of ‘a strategic reserve’, within which governments pay providers for keeping power plants operational. These plants can be called upon by the network operator in emergency situations. (b) the so-called ‘interruptibility schemes’, in which industrial customers are asked by the system operator to reduce their demand in scarcity situations. Such schemes are also considered a form of ‘reserve’, as they provide capacity that is only activated when a supply shortfall occurs. Furthermore, tenders for new capacity were found in France, Ireland and Belgium. All three tenders were very specific on the size, technology type and location of capacity tendered out. Tenders may be an appropriate
temporary measure to incentivize investment in electricity generation capacity (including potentially in a specific location). However, a tender does not effectively address longer term generation adequacy problems, and should be combined with reforms to address underlying market and regulatory failures.
2. The background of the Capacity Mechanisms in Greece In accordance with the provisions of statute 4001/2011 (the Greek energy statute), Greek state designed in 2005 a decentralized ‘Capacity Assurance
Mechanism’ (‘permanent CAM’). The mechanism was supposed to be based on the bilateral trading of capacity certificates. These were to be issued by dispatchable power plants in proportion to their capacity and were
Targeted capacity payment schemes were found in Italy, Poland, Portugal, and Spain. The schemes typically cover one or more types of electricity generation (coal, gas, hydro with storage and sometimes oil). The price paid for capacity in these schemes is set administratively, rather than through a competitive tender process. In general, the beneficiaries of targeted capacity payments must make their capacity available during peak demand periods or face financial penalties. Targeted capacity payments also do not address the underlying issues that caused the capacity problem. An additional drawback of this model is that the administrative price setting process increases the risk of overcompensation of the beneficiaries.
Belgium** Belgium Italy France Denmark** Poland Ireland** Germany*** Portugal*** Poland Spain*** Sweden Germany (Interruptibility Scheme) Ireland (Interruptibility Scheme) Italy (Interruptibility Scheme)*** Poland (Interruptibility Scheme) Portugal (Interruptibility Scheme) Spain (Interruptibility Scheme) Central buyer De-central obligation Market-wide cap. payment Ireland* France* Ireland Italy*
Tender for Strategic reserve new capacity
* Planned Mechanism (or being implemented) ** Past Mechanism )or never implemented) *** Multiple capacity mechanisms of the same type Source: European Commission, Capacity mechanisms sector enquiry
Targeted capacity payment
held by electricity suppliers and selfsupplied consumers. Such certificate holders were under the obligation of holding a sufficient amount of capacity certificates to cover their load at peak times. However, the ‘permanent CAM’ has never been implemented because of the asymmetry between the vertically integrated incumbent (PPC) and the small independent generators which have not achieved direct load serving business. According to the Greek authorities, the mechanism would have allowed the incumbent to acquire capacity certificates internally, with the consequence that there would be no demand for capacity contracts addressed to the independent generators. In this scenario, the Greek authorities applied instead, a transitory capacity assurance mechanism consisting of direct remuneration of capacity availability of plants, which was in force until December 2014. This transitory mechanism provided for regulated remuneration based on a fixed payment for all eligible plants, excluding hydro power generation and natural gas generation plants. Hydro and natural gas plants received payment based on the real availability of capacity However, pursuant to the rationale of decision no 338/2013 of RAE, the reform of the existing CAM was deemed necessary for ensuring capacity availability and security of supply; it highlighted that the existing CAM should be reassessed in line with the principle of proportionality and should be adjusted to the market rules and conditions taking into account the potential financial returns of each unit
arising from its participation in DayAhead Energy Scheduling (DAS). Following the above decision, RAE put forward two consultations for the reform of the Capacity Remuneration Mechanism (CRM) in Greece, on 29.7.2014 and on 7.1.2015. RAE’s final proposal refers to the establishment of two mechanisms: a new permanent mechanism which shall operate on the basis of auctions for the purchase of necessary flexibility services for the System, and a transitory mechanism for the remuneration of flexibility (FRM). The final proposal is focused solely on one element of the initially proposed mechanism, namely the flexibility pillar. 4. Transitory Electricity Flexibility Remuneration Mechanism (‘transitory FRM’) On 27.5.2016, statute 4389/2016 was published and amended the Energy Statute 4001/2011, with the aim to ensure electricity generation adequacy in the Greek interconnected system and system reliability through the establishment of a ‘transitory FRM’. Such remuneration scheme will operate for a maximum period of 12 months, during which time the level of remuneration will be defined by RAE. The new statute interrupted the implementation of the permanent CAM, as provided for by the “Code on the Operation of the Greek Electricity Transmission System”. The ‘transitory FRM’ compensates certain electricity generators in the Greek interconnected
electricity system for the provision of ‘flexibility services’ to the Greek Electricity Transmission System Operator (TSO – ADMIE SA). In particular, according to the provisions of the transitory flexibility remuneration scheme, on instruction from the TSO and subject to specified notice period, beneficiaries increase or decrease the amount of electricity injected into the electricity system at a specified minimum rate on a multi-hour timescale. More specifically, any individual plant which is eligible for remuneration under the measure, should be capable of increasing electricity generation (ramping) at a rate greater than 8 MW/ min with three hours’ notice (starting from hot conditions), while remaining available to follow ramping instructions continuously for a minimum of three hours. Therefore, the envisaged beneficiary generators must be located in Greece and be connected to the interconnected transmission system of the mainland. The above prerequisites can be satisfied by the following technologies: Combined Cycle Gas Turbine (CCGT), Open Cycle Gas Turbine (OCGT), Combined Heat and Power (CHP), and Hydro. As provided for in the statute 4389/2016, in order that interested power generators participate in the new transitory mechanism, they shall first submit application to RAE. The template of such application is expected to be published by RAE following proposal from ADMIE SA. The applicants must declare the
capacity available for participation in the transitory mechanism. The declared capacity available can be lower than the real capacity of the generators. Furthermore, they must declare the nominal capacity of the plants and the compensation desired as incentive for providing ramping services. Finally, the generators must also declare the operating and maintenance (O&M) costs evaluation associated with the provision of ramping services. Within one month from the time of the said applications, RAE shall approve the registration of eligible units to the “Register of Flexible Generation Units” following proposal from ADMIE SA. 5. Compensation and Penalties Remuneration for flexibility under the said scheme consists of a ‘capacity premium’, which is a fixed payment based on available capacity to provide ramping services, set administratively by RAE, at a level of €45/kW/year. In addition, the TSO will ensure that capacity premium revenues shall not exceed 15 million Euros per eligible power generation installation. The maximum total budget, amounting to 225 million Euros, shall be covered by ‘Load Representatives’ (electricity suppliers) and will be paid to the beneficiaries proportionally, according to the historical availability of their power plants, measured in MW, over the previous three years. In case the ‘eligible’ power plants are unavailable to comply with the obligations arising from their participation in the transitory FRM in real time, penalties will be imposed. In this case,
RAE, following proposal from ADMIE SA, can even claim the repayment of 10% to 100% of the remuneration, depending the severity of violation. 6. Financing of the measure The measure will be financed by a special levy, set by RAE, imposed on Load Representatives, according to the provisions of the System Operation Code. The obligation imposed on each Load Representative relates to its maximum electricity demand measured during hours with increased loss-ofload-probability. The TSO (ADMIE SA) will be responsible for: (a) calculating the payments awarded under the measure, (b) issuing the settlements and (c) performing the respective invoicing. 7. Assessment of the transitory FRM as state aid Before the implementation of the discussed flexibility remuneration mechanism, on 19.1.2015 the Greek state notified the above discussed scheme to the European Commission. According to decision No C (2016) 1791 final of 31.3.2016 of the European Commission, the new transitory FRM was characterized as ‘state aid’, given that it is financed through compulsory charges imposed by the legislation of the Member State, managed and apportioned in accordance with the provisions of such legislation, even if the levies imposed are managed by entities separate from the public authorities.
Furthermore, this financing scheme allows beneficiaries to receive an additional compensation beyond which they would obtain in the Greek electricity market, therefore will confer an economic advantage to these undertakings in one sector of the economy (electricity production). Therefore this advantage is selective, affecting trade within the internal European market. In line with the Commission’s demands, in order to be found appropriate, this State aid should: (i) only compensate the service of availability of capacity (ii) be open and provide adequate incentives to both existing and future generators and to operators using substitutable technologies, and (iii) take into account the extent to which interconnected capacity can contribute to remedy the generation adequacy concerns. Under said conditions, the Commission has authorized the transitory FRM scheme for 12 months following the date of its adoption.
Legal insight Senior Associate Petar Mitrovic and Counsel Andrea Wilson, Karanovic & Nikolic
A NEW RENEWABLES INCENTIVE SCHEME FOR SERBIA This summer, the Government of the Republic of Serbia finally adopted a package of decrees setting out a new incentive scheme for renewable energy in the country. These new decrees were adopted pursuant to the 2014 Energy Law, a relatively new piece of legislation aimed at harmonizing Serbia’s energy framework with the Energy Community Treaty (the ECT). One of the explicit aims of the ECT is to support the development of renewable energy in South Eastern Europe. As renewable energy remains less competitive than conventional energy, the development of such energy sources is heavily dependent on the implementation of support schemes throughout the region.
Serbia is sending a clear message with the passing of these new decrees that it hopes to increase investments in renewable energy in the years to come and to build on the successes of pioneering green energy projects in the country such as WPP Alibunar developed by Elicio (formerly Electrawinds). The decrees comprising the new package are: (i) the Decree on the Power Purchase Agreement, (“PPA Decree”); (ii) the Decree on incentive measures for the production of electric energy from renewable energy sources and from high-efficiency cogeneration of electric energy and thermal energy (“FIT Decree”); and (iii) the Decree on the requirements and procedures for acquiring the status of privileged power producer, preliminary privileged power producer and producer from renewable energy sources (“Status Decree”). These new pieces of legislation (the Decrees) aim to remove obstacles for renewable energy investments in Serbia which existed under the previous scheme by improving project bankability and making it easier for project sponsors to secure financing for renewable energy projects.
The adoption of the Decrees on 13 June 2016 represent the culmination of a long process of the energy sector reform which began in the latter half of 2009 when Serbia incorporated a support scheme for renewable energy into its legal system for the first time. The initial scheme underwent notable improvements with the adoption of the 2011 Energy Law, the accompanying bylaws which were adopted in early 2013, and a model power purchase agreement (PPA) in the summer of 2013. Renewable generators were, for the first time, given the right of priority access to the grid and the right to sell the entire quantity of electricity generated to the state-owned purchaser under guaranteed, preferential prices. However, investor confidence in the permanence and reliability of the new support scheme was not significantly improved. A sound Power Purchase Agreement (PPA) between a renewable generator and state-owned purchaser is an important starting point for any renewable energy scheme as such an agreement guarantees the future revenue stream for a renewable project.
The PPA model adopted by Serbia in 2013 contained several flaws which limited the expansion of the renewable energy sector in the country, despite the potential of this sector. For example, the PPA model did not include reasonable deadlines for the development of a project. Additionally, the PPA did not provide generators with adequate protection against risks outside the control of the generator, such as grid constraints (i.e. interruptions to or restrictions on the export of electricity to the grid), by requiring a purchaser to pay for the volume of electricity which would have been generated had there been no such interruption or restriction. The PPA model failed to provide a mechanism allowing generators to withdraw from a PPA and to be compensated for their losses, if circumstances beyond their control made it impossible or unlawful to maintain the PPA (such as defaults and breaches of the PPA by the purchaser or changes in the law after which the generator could not substantially be put back in the same economic position as before the changes were implemented). Another shortcoming was that lenders were not given the opportunity to
step in or take over project rights and obligations alongside the generator under the PPA. Because of these shortcomings, investors were suspicious of the permanence and reliability of the Serbian renewable energy support scheme under the 2011 Energy Law.
Adoption of the 2014 Energy Law by the Serbian Parliament established a framework for the improvement of the renewables support scheme and, even more importantly, improvement of currently applicable PPAs which we now see through the adoption of the new decrees.
A sound Power Purchase Agreement (PPA) between a renewable generator and state-owned purchaser is an important starting point for any renewable energy scheme
1. PPA Decree
The PPA Decree establishes a PPA model which will be concluded between green producers and the guaranteed off-taker. The PPA is concluded for an incentive period of 12 years and is valid from the day of first reading of the metering equipment, after the day of acquiring privileged generator status and until the expiry of the incentive period for the power plant. The term of the PPA may be prolonged in the event of unplanned occurrence and action of force majeure during the incentive period, which the parties of the PPA may acknowledge by annex, before determining the new date of expiry of the incentive period. The PPA Decree introduces a significant improvement by eliminating the
concept of “Preliminary PPA” from the renewable energy framework, prescribing instead a more common concept known as “Single PPA”. The concept of a “Single PPA” stipulates that the holder of the preliminary privileged power producer status (“4P Status”) may enter into the PPA, and after fulfilling a number of statutory conditions, it may continue under the agreement as a holder of privileged power producer status (“3P Status”). The PPA also prescribes several advanced mechanisms (the real reach is yet to be tested in practice) in the Serbian energy sector regarding force majeure clauses, one of which is “political force majeure” and the other being “change-in-regulations”. Political force majeure prescribes that if any competent authority fails to issue, upkeep, amend or prolong any public authorization without the fault of the generator or the off-taker, the agreement shall remain in force, but its legal effects shall be suspended for the period of duration of the force majeure event. Another mechanism worthy of mentioning is the change-in-regulations clause. This clause outlines that a generator may submit a proposal to amend incentive measures if a new regulation comes into effect on the date of or after conclusion of the PPA which results in an increase in the cost of operations for the generator. This mechanism is designed to put the generator in the same financial position that it was in under the PPA but for the new regulation.
In the event of disputes, the PPA Decree foresees two options: resolution through a domestic Serbian Court or international arbitration, either in Vienna, at the Vienna International Arbitration Center, or in Paris at the International Court of Arbitration of the ICC. The PPA also prescribes that a generator is now entitled to terminate the PPA if the off-taker is delayed in settling any due payments, with previous notice for payment. The PPA Decree further stipulates a stepin agreement as a supplement to the PPA, between the lender or lenders’ agent, the generator and the off-taker, but only for projects exceeding 30MW in power. The step-in agreement allows lenders to name a completely different entity as a generator, if the existing generator defaults on one of its obligations or loses the status of privileged generator. For any disputes arising from this agreement, an option between resolution in a domestic Serbian Court or international arbitration is also stipulated. The only major downside of the new PPA model is that the off-taker may provide only promissory notes as collateral for the fulfilment of obligations under the PPA. Promissory notes are only effective if the debtor has the relevant level of funds secured by the promissory note in its accounts. However, given the possibility to alter the PPA with approval by the ministry responsible for energy, generators may request a more certain way to secure the obligations of the off-taker, i.e. through a bank guarantee. This fact, coupled with the possibility of a change in off-taker
every five years without the producers or the lenders having any say, is expected to be the most significant challenge for the further realisation of Serbian renewable energy projects.
2. FIT Decree
The FIT Decree stipulates in detail the incentives for the production of electric energy from renewable energy sources and high-efficiency cogeneration of electric energy and thermal energy. The FIT Decree explicitly regulates the amount of feed-in-tariffs (“FIT”) available to renewable energy producers by introducing a specific calculation method and a cap on purchase prices. Furthermore, and perhaps even more importantly, the FIT Decree introduces a maximum annual effective operation time for all types of generation facilities. The incentive purchase prices prescribed in the FIT Decree range from between 6 Eurocents per kWh for hydropower plants (on existing infrastructure) to 9.2 Eurocents per kWh for wind power facilities to 13.26 Eurocents per kWh for biomass plants up to 1 MW installed power. The FiTs are indexed according to the Eurozone inflation. If, during the incentive period, a generator produces electricity in excess of the maximum calculated under the FIT Decrees’ calculation method, the amount that has surpassed the maximum will be purchased at a price equalling 35% of the FIT. Up to the commencement of the incentive period (i.e. the commissioning period) the same, ‘special’ FIT is
stipulated, with the difference that the preliminary privileged producer is entitled to an incentive price in the amount of 50% of the respective FIT. Considering the fact that in this sector of industry there are a lot of large scale multi-phase projects, regulating the commissioning of projects in this way provides flexibility and security to generators. The FIT Decree also includes details on the currency of the incentive purchase price, the manner of payment for incentive purchase and the adjustment of the incentive purchase price for inflation, as well as the conditions under which projects have access to incentive measures.
3. Status Decree
The Status Decree prescribes in detail the requirements and procedures for the acquisition, duration and termination of the status of a privileged power producer, preliminary privileged power producer, and a power producer from renewable energy sources. Furthermore, the Status Decree now sets out a more comprehensive and somewhat improved set of requirements for acquiring the status of a privileged producer, which are
aligned with Serbia’s construction laws. New advanced financial security instruments for acquiring the status of a preliminary privileged power producer have also been introduced, stipulating in more detail the manner of establishing securities (i.e. via monetary deposit, or a “first call” bank guarantee), including provisions regarding the prolongation of the guarantee and the conditions for the activation and return of the financial security instrument. It is worth mentioning that the Status Decree also prescribes the traditional force majeure cases as well as “political force majeure”. The possibility of prolonging a generator’s 3P Status in the event of any unforeseeable or unavoidable event is permitted for the period necessary to remedy the effects of these unforeseeable circumstances. The Status Decree also stipulates statutory caps, i.e. the overall maximum capacity specifically applicable to wind power facilities and solar plants. In addition, the administrative procedures regulating the acquisition and alterations of the 3P Status and 4P Status, the status of a renewable energy producer,
and requests for the prolongation of the 4P Status are outlined in detail. Much needed comprehensive transitional provisions addressing the 4P Status and 3P Status have also been incorporated from previously applicable regulations.
* Karanovic & Nikolic attorneys were extensively involved in consultations and negotiations with the relevant stakeholders, including public authorities, investors, sponsors and the international lenders leading up to the adoption of the Decrees. Having been so thoroughly involved in the process, we can definitively state that this PPA Package represents a major step forward for green energy in Serbia. It will take time, however, to evaluate whether the new package will allow the green energy market in Serbia to flourish, given the novelty of some of the provisions in the Decrees to the Serbian, and for that matter regional, legal framework governing renewable energy. Karanovic & Nikolic plans to organize a panel discussion on the effects and implications of the new scheme in the fall of 2016, at a time which we believe the market will be in a better position to assess the reach of the new scheme.
Legal insight Dr Lorenc Gordani
THE DEVELOPMENT OF HYDROELECTRIC POTENTIAL IN ALBANIA The National Renewable Energy Action Plans adoption and submission is not only a legal obligation but also a tool that ensures transparency towards investors in renewable energy on the policy objectives to reach the 2020 renewable energy targets.
Over the last 25 years, Albania has experienced a difficult transition shifting from a centrally planned to an openmarket economy. During the transition process, Albania has encountered many successes and hardships. Focusing here on the renewable energy sector, Albania’s moving forward to address the objectives with an integrated approach in the energy sector and the overtaking of important institutional changes in line with the Third Energy Package of the European Union regard the introduction of private operators in the market was revealing a tough challenge.
already completed with the enactment of the new Law 138/2013 “On Renewable Energy Sector”.
The previous law no. 9072, date 22.5.2003 “On Power Sector” was been revised about 13 times in order to be further aligned with the EU general principles and the acquis on award of energy sector. Attracting investment in the sector was the rationale behind many of the above measures and actions taken. However, private investment remained far below the levels aimed. Then during 2009-2013, the new Renewable Energy Sector Law was prepared prospecting the compliance with Directive 2009/28/EC. A process that was to be considered as
The country that was once a net exporter of electricity has been forced from 1998 to import power due to the rising demand and the stagnation of new capacity installations since the transition from a centrally planned economy to an open market in the late 1980s. The energy demand is expected to increase by 60 per cent in 2020, and there is a clear need for Albania to strengthen its energy security. While efforts to develop new thermal, wind and solar capacity are ongoing, hydropower remains the nation’s largest energy resource.
Notwithstanding, the new law on the renewable sector approved, constitutes a formal decisive step forward, that revealed only the first ones on a long path of the adequate match of the expectations of investors in the sector. In this regard, Albania has missed the deadline of January 1st 2014 to fully transpose Directive 2009/28/EC, as amended by the Ministerial Council, in its national legislation.
Albania derives 98 per cent of its domestically produced electricity from hydropower. Mountainous Albania is home to eight major river systems. The Drin river, located in northern Albania, is the largest river in the country and hosts three hydropower stations: Fierzë (500 MW), Komani (600 MW) and Vau I Dejës (250 MW). This 1,350 MW cascade represents more than three-quarters of the country’s total electricity capacity and 70 per cent of domestic electricity production. The remaining 480 MW of installed capacity is distributed over some 100 hydro power plants. As the country tries to limit greenhousegas emissions in line with EU goals, it could see the increased co-generation of biomass and gas, the promotion of the development of renewable energies, remains mainly focusing on hydropower. The Western Balkan country has the largest remaining unexploited hydropower potential in Europe, as its river catchments remain largely undeveloped. Up to 60 per cent of rivers remain in near natural or unspoiled states and has an estimated 10,000 GWh technical potential, which
are concentrated in the mountainous regions neighbouring with Montenegro and Kosovo. Estimates show that only 45 per cent of Albania’s hydropower potential has been developed so far. Due to these favourable conditions, Albania’s hydropower sector remains attractive to foreign and private investors. However according to data reported from AKBN a large number of SHPP granted on concessions have not yet commenced the construction or are still under construction, showing delays of three years and more. More specifically, out of 501 SHPPs under concession, 307 SHPPs with installed capacity of 1,127 MW and forecasted energy at 5,288 GWh have not yet started the construction phase. The remaining of approximately 100 are entering in the regime and 84 SHPPs are in the construction phase. The new capacity installations are aimed at strengthening the power supply to the south of the country, and to complete the planned cascade of projects on the Drin River. Ashta (53 MW), commissioned
in 2012, was the largest hydropower project to be completed in Albania since the 1990s. Another major project is the EUR 535 million Devoll River cascade, which will consist of two hydropower stations, Banja and Moglicë. With a total installed capacity of 256 MW, these two stations will produce around 729 GWh each year, increasing Albania’s electricity production by nearly 17 per cent. Investments for a third plant in the cascade will be considered once these two are completed. Both are expected to begin commercial operation by 2018. Albania’s mid-term goal is to once again become a net importer of electricity by developing its significant hydropower potential. In this way, Albania could increase its influence in the regional energy market while simultaneously bolstering its own energy security. In this regard, the EU integration process sent a strong support towards fostering energy trade for a more efficient power market. By expanding the total market size, new interconnections would improve reliability, reduce costs and increase the possibility to trade the energy produced.
An integrated market allows for the possibility of thermal and hydropower technologies to complement each other, as well as lowering the required reserve capacity and overall balancing costs. In June 2016, the Albania and Kosovo transmission interlink 400 kV was finalised, permitting energy grids to maximise Albaniaâ€™s hydropower and Kosovoâ€™s coal-fired electricity. In 2015, the EU announced that it would invest in a number of transmission projects across the region, especially between Albania and Fyrom. A few weeks ago, the Albanian government signed an agreement for a loan of 50 million Euros with the German state-owned development bank KfW, which will open the way for the construction of a highvoltage 400kV interconnection line with Fyrom. Albania is also exploring options for an undersea electricity interconnection to export excess power to Italy. Despite the interconnection and the high-unexploited potential, the development of new hydropower projects is stalled primarily due to a lack of financing incentives. While there are many potential projects in the planning stage, it is seen that the majority are not coming to fruition. All the above are due also to the hesitation by the country in removing non-cost barriers to attract investments in small, distributed renewable energy projects. So far, the country do not meet its interim trajectories and the assessment of the submitted NREAPs shows that the
country is not on track to meet its 2020 targets if no enhanced policy initiatives are put in place as the trajectories become steeper closer to 2020. Since at this stage, the country foresees to established electricity trading platforms in the way to offer more transparency in its wholesale markets. However, at starting the removal of non-cost barriers that hinder the uptake of energy from renewable sources and the simplification and streamlining of administrative procedures and grid integration of renewable energy must be a key priority. Historically specific feed-in tariffs combined with industrial policies have proven to be the most suitable way to ensure investor confidence and to tap renewable energy potential. Currently Albania has support schemes for small hydro producers of up to 15 MW. While the capital costs are higher than in the European Union, the labour and other operational costs are lower. Implementation of measures that reduce capital costs in the Energy Community combined with policies to promote renewable energy with the lowest impact on end-user consumer prices is the only way to ensure that the renewable energy targets will be reached in the most costeffective way. These support measures must not be subject to changes and uncertainties. The frequently revised feed-in tariffs after their adoption, as a result of administrative measures or calculated on an annual basis leading to increased uncertainty for investors. The PPA
must be signed at the beginning of the development stage of a renewable energy project, to provide sufficient security to investors. Securing the support scheme valid at the time of signature of a PPA is the key to ensure investor confidence and to finance the renewable energy projects. In addition, the Administrative procedures for permit issuing, authorisation and connection to the grids have to be simplified, coordinated and streamlined to a greater degree. A great obstacle may consist of the administrative measures, which increase the risks for the potential investors willing to operate. Lastly, a reform to the compulsory jurisdiction of domestic courts of justice or the country has to provide the possibility to resolve disputes in international arbitration. Furthermore, daily experience raises awareness that a strong partnership between the public and private sector is need, to address the mistakes of the past. As a result of daily work contact, the requests of owners or permission holders of the hydropower station and investors interested to cooperate or even to share their quota due to changes in their priorities are frequent. Then a successful key is won in the restoration of new business relationship giving a new level of active cooperation regarding the liberalization and the effective integration as well as the efficient use of energy resources.
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