The wind farms complex is supported by 20 year power selling contracts that have been signed with the Operator of the Electricity Market (DAPEEP).
A monumental project in renewables is completed and expected to enter commercial operation within 2019. It is a series of seven wind farms with a total capacity of 154.1 MW in Kafireas, SE Evoia, an investment by Enel Green Power Hellas (100% subsidiary of Italian group Enel) of 300 million Euros.
The wind farms complex is supported by 20 year power selling contracts that have been signed with the Operator of the Electricity Market (DAPEEP).
The project will produce around 480 GWh per year, covering the needs of 130,000 Greek households. The project will greatly contribute towards power production from renewables, substituting production using imports or fuels harmful to the environment and health. The selection of Kafireas was made according to the special land use framework of the country for renewables, which specifies the areas with a high wind potential and environmental constraints.
The project’s planning has been made in such a way as to protect and improve the natural environment, as well as to promote economic activity in the region and sustainable development. Enel Green Power Hellas will provide each year 3% of its net sales for the backing of local communities and environmental protection. The annual sum for supporting local communities is calculated at least at 1.2 million Euros.
Helping local community
In general, during the construction phase and the operation phase of the project, the company, following its goal to enhance local community, hired and hires many people from the wider region, while materials mainly come from Karysia, while the regional economy is improved significantly through the renting of houses and offices for the staff.
Last, the company, apart from its contribution in widening the local economic chain, has also developed a parallel action plan that enhances sustainability. An emblematic project is the reforestation of Kastanalogo, a forest with centuries old chestnut trees in an altitude of more than 1,000 meters in the side of Ohi. The reforestation plan is already in operation under the supervision of the forestry service and is expected to be completed by 2021.
The sustainable development model
Kafireas, the wind complex under construction in Greece, is another example of a “sustainable construction site” with advantages for the region and local community ranging from the environment to the economy.
Enel Green Power’s presence in Greece has brought a breath of fresh air with many social, economic and environmental benefits. The various wind farms where EGP’s flag stands in Greece, the least of who is Kafireas in the southern part of Evoia, are opportunities for sustainable development.
At the time of Kafireas’s operation, the total capacity in 2019 will be 154 MW and it will be the biggest in the country. Kafireas will contribute not just to increasing green energy produced in Greece, but also to bring a series of benefits for the local community, while it is an important incentive for local economy.
At the construction site, around 200 people from the region have found employment to build the wind farm and relative infrastructure. They began with the road that was needed to reach the construction area and which will allow residents and tourists to visit remote places and admire natural beauty in this part of the island.
A “sustainable construction site”
Small businesses and professionals from the region are also taking advantage of the presence of the project. There have been collaborations with restaurants and hotels for covering the needs of the staff at the construction site.
EGP’s presence in the construction site guarantees income for the city of Karystos and for all local municipalities that host wind farms or small hydro plants thanks to a compensation mechanism.
A sum equal to 1% of total annual sales from each wind farm is credited to local residents’ power bills. The municipality where each wind farm exists receives significant income annually, specifically 1.7% of sales of each wind farm, which is set aside by LAGIE from the producers, while another 0.3% is credited to the Green Fund.
There were also sponsorships to athletic and cultural events, such as the creation of a small clinic with experienced medical staff, a landmark for the people of the region.
For all these reasons, Kafireas is truly an example of a “sustainable construction site” in Greece, included in the model of creating common value that combines corporate needs with those of the residents where we provide energy.
A total look at environmental sustainability
The project of Kafireas follows the paradigm of the sustainable construction site that set in motion EGP’s approach based on the model of creating common value.
Through the approach of creating common value, environmental and social sustainability provides support to the company for every choice and approach in development, planning, construction and operation of projects, focusing on environmental protection, rational use of resources, attention to health and security, innovation, circular economy and benefits for all involved.
During the construction phase, we set concrete goals to measure the seven sustainable fields connected to the 17 goals for sustainable development of the UN (SDGs) that are measured according to global sustainability standards.
It should be added that all wind farms built in Greece are inside areas characterized by the government as Areas of Wind Priority and Areas of Sustainable Wind. All projects passed environmental assessment, which carefully examines their repercussions on the environment and set all phases of their life duration: Construction, operation and pause of activity.
Today, energy is one of the most important human goods and many times, from many sides, it is considered a given. The rise of societal dependence on energy led to a new energy geopolitical trend. However, it is not enough for the economy of one state to determine its relationship with the buying and selling of energy, but an even more important role is played by the policy of each state. Energy, apart from covering the needs of each state, is now a point of strategy and political pressure. Targeting energy, many alliances and synergies (political, economic) have formed for the best coverage and supply.
Thus, Europe quickly formed its own energy policy based on two pylons: On the one hand, the operation of the internal energy market and on the other hand, the security of energy supply. Today, Europe is all the more dependent on Russia, which is why it seeks other ways/routes to receive energy and cover its constantly rising needs. One of these ways is to promote a Mediterranean policy, since the Mediterranean is an important crossroads and a powerful energy route. More specifically, the EuroMed Partnership has been formed, initially because of its geographic position, but also because of the significant energy deposits held by many Mediterranean countries, in contrast to European ones. In energy, Mediterranean countries maintain an important position and this is because they are neighbouring countries to the EU (apart from the already European Mediterranean states) and cooperate with them. Also, they are importers of energy, but they also have the responsibility of securing the supply routes in the region.
East Med pipeline
As we know, energy brought a new interest in the political relations of the international community. And very quickly, states developed their own energy policy by forming cooperation and economic relations. They moved to commerce and energy supply primarily through the construction of necessary energy pipelines, which hold an important role in the geostrategic policy of countries in the energy political landscape of the global community.
Lately, with recent discoveries of energy reserves, a new breeze was given to the importance of Mediterranean space both in energy and security, as well as the political antagonisms of international “players”. Europe and primarily Greece, Cyprus and Israel, took responsibility and made the decision to create the EastMed pipeline, in an effort to advance their cooperation and their position in the energy politics canvas. This pipeline, will begin in Israel, will follow a route to Cyprus and then to Crete and continental Greece, where it will connect to Otranto, Italy and will supply the rest of Europe.
After the recent discoveries in fields inside blocks of Israel and Cyprus (Leviathan and Aphrodite-Calypso correspondingly), Europe reserved a large sum (to reach 100 million Euros) for the necessary preparations and studies of the project. Their results appear to be positive and consider EastMed as viable. This does not mean, of course, that the project does not face many challenges, leading to worry about its realization schedule. Initially, the EastMed project annoyed Russia, but primarily Turkey, which increased its provocations in the Eastern Mediterranean. It sends Turkish ships in Cyrpus’s marine blocks for its own exploration and drilling, defying the notifications and sanctions of Europe. Furthermore, another challenge faced by EastMed’s project are its own implementation plans. This is because the Mediterranean Sea is deep and has an anomalous geomorphology, which creates uncertainty in the installation and operation of necessary materials.
East Med is included in the PCI list of the EU (Projects of Common Interest). Of course, Europe does not rest just on the idea of this pipeline, but also seeks other individual solutions and routes for its energy supply and the covering of its needs. It appears that the realization of the pipeline is a long term project, considering the geopolitical antagonisms. One solution that is being studied is to use Egypt’s LNG plants or build a new one in Cyprus. It is a move that will enhance the role of these two nations.
It is noteworthy that at the beginning of the year (January 2019) the EastMed Gas Forum (EGF) organization was formed in Cairo (its headquarters). Its purpose is the creation of a peripheral gas market, the drop of infrastructure cost and the offering of competitive prices. During EGF’s formation, the energy ministers of Cyprus, Greece, Israel and Egypt took part, as well as representatives from Italy, Jordan and Palaistine. Turkey did not participate, being displeased about it. This forum will also help create a smooth and successful corporate relationship between gas producers and gas consumers.
Indeed, during the last few days (July 24-25, 2019), the new energy minister, Mr. Chatzidakis, travelled to Cairo in order to participate in EGF’s second conference. Other participants include the energy ministers of Cyprus, Israel, Jordan, Palaistine and the US, undersecretary of energy of Italy, as well as representatives from the EU, France and the World Bank. During this second conference there will be talks about advancing peripheral cooperation, organizing the forum, as well as studies made by international organizations for optimizing the methods of extracting current and potential gas quantities in the SE Mediterranean basin. Furthermore, in EGF’s conference, Mr. Chatzidakis has scheduled bilateral talks with the energy ministers of the US, Egypt and Israel about Greece’s energy relations.
After the two day EastMed Gas Forum, all parties agreed to turn the forum into an international organization in SE Europe. They also moved with the formation of a Business Council, which is responsible for carrying out EGF’s works. They also created a consultation committee along with the gas sector and the participation of public and private enterprise. Last, the first study was approved on behalf of the EGF in cooperation with the World Bank about the region’s gas potential and its better exploitation and export.
International reactions. Which global players lose and who wins?
Of course, Greece sees in the East Med project a great chance of playing an important role in the energy landscape. This pipeline will turn it into an energy power and will enhance its position both in the Mediterranean Basin, as well as in Europe. Moreover, Greece attains a strong presence in the Mediterranean, forming strong alliances with other Mediterranean states (Cyprus, Israel and even Egypt), providing a resounding answer to Turkey’s provocations. With EastMed, Greece is estimated to acquire an active role in the Mediterranean in energy and security. For now, of course, we cannot say it has reached this position, at least until there is a concrete framework and the pipeline gets the green light.
Israel heavily invests on the EastMed pipeline. This, of course, is due to the fact that through the pipeline, Israel acquires an immediate and strong connection to Europe. This automatically means that Israel’s position in the Mediterranean is enhanced, both in energy and security, while relations with Europe are strengthened. Israel (with the Leviathan field) will have the opportunity to extract gas, both to cover its own needs and to export to Europe. The only negative element is that the operation of this pipeline suggests cooperation and dependence on an Arab nation, such as Egypt, no matter how friendly. It is a collaboration whose development holds great interest when it comes to the two countries’ approach. Of course, the important thing is political will to create a cooperative relationship.
Egypt, during the last few years, has set the goal of strengthening its position on the Mediterranean energy map. Of course, even though there are no official reactions, we can certainly say that on the one hand, it benefits from East Med, but on the other hand will have certain concerns, since there are issues of competitiveness. This is because Egypt promotes and significantly depends on the operation of its two liquefied natural gas plants in Idku and Damietta correspondingly. Furthermore, as was mentioned before, Egypt (as an Arab country) has to face the prospect of depending on Israel. What is certain is that Egypt will benefit much more, since it is the cheapest route for transferring gas.
Lately, discoveries in the marine blocks of Cyprus (Aphrodite, Calypso and Glaucus as estimated) provide Cyprus with the opportunity to become a significant energy force in the Eastern Mediteranean political landscape. Cyprus seeks to improve its economy through EastMed, to cover its internal needs and to advance gas exports. Moreover, Cyprus enhances its position in the Mediterranean Basin through EastMed and provides an answer to Turkey’s continuing provocations. However, EastMed’s project is anything but easy, as it needs stability and security in the region, which is not true in the case of Cyprus when it comes to its conflict with Turkey and its internal division (between Greek Cypriots and Turkish Cypriots). This will lead to the delay of realizing the pipeline and the need to find a route in order not to trespass on Turkey’s marine borders. EastMed, as it appears, heightened geopolitical issues in the region instead of bringing all sides together for a common solution.
Of course, it should be mentioned that no matter how much the pipeline’s realization is delayed, Cyprus has another chance to play an important role in energy since there are plans to build an LNG plant on the island.
Turkey regards energy cooperation between Greece-Cyprus-Israel (and Egypt) as negative when it comes to EastMed. Turkey has realized its isolation from European energy plans and does its best (despite European reactions and sanctions) to acquire a share in the Mediterranean energy field. Turkey is dependent (at 70%) on Russia’s and Iran’s energy supplies. Watching its own energy needs rising, it seeks a new cheap route of supply. It knows well that its efforts are affected by negative relations with all parts of this new project. Turkey does what it can to maintain a strong presence in the Mediterranean as an energy force and to acquire benefits from recent discoveries in the Eastern Mediterranean. Thus, knowing the need for stability and security for realizing the project, it enhances its presence with continuous provocations, by sending ships for its own exploration and drilling, destabilizing the region.
Russia is definitely against EastMed, since it is a rival energy player. Russia supplies the greatest part of Europe’s energy needs through its own cheap natural gas, which is something that European powers want to avert by fracturing this relationship of dependence. Europe has provided a large sum for the pipeline’s planning and studies, a positive fact for energy deposits and EastMed’s viability. Moreover, Europe wants to avoid Turkey’s participation, since already existing pipelines already traverse its ground. They want to find an alternative route of cheap supply in order to avoid being dependent on the Turkish route.
On behalf of the US, we also have willingness to support the building of EastMed. This is because for the US, the pipeline means a direct and concrete connection of Israel to Europe, but also the weakening of Russia’s energy role in European territory. This US position was enhanced by foreign secretary, Mike Pompeo’s participation in the trilateral meeting of Greece, Cyprus and Israel last March in Jerusalem. This move was a sound answer particularly to Turkey and its provocations. It should be noted that lately, the US and Turkey do not have the best relations, especially after Turkey’s decisions on the issue of the Russian S-400 missiles.
The importance of energy in international and especially Mediterranean geopolitics is evident. Through new reactions brought by the EastMed project, a new dynamic is given to countries of the Mediterranean Basin and geopolitics of the region in regards to cooperation, energy and security were advanced.
George Stassis, an engineer and executive of the multinational energy group Enel, is the new chairman and CEO of PPC.
Former head, M. Panagiotakis, a product of PPC, with intense political and union activity, strong views and a history within the company, will be replaced with the dynamic young man, who has international experience, but apart from a multinational group, also knows the specifics of the Greek market when it comes to PPC itself with which he had relations from his time at Tellas, as well as the balance and trends in the sector (through his tenure at Enel Green Power Hellas).
The proposition to Mr. Stassis was formally made by the Hellenic Corporation of Assets and Participations (HCAP) board during PPC’s general meeting of shareholders.
Associates of the energy minister, Kostis Chatzidakis, mentioned that “George Stassis is an energy manager, has a carrier in a big multinational company, he has experience in restructuring energy businesses, he is young and he is a Greek who returns from abroad to help with the government’s effort”.
PPC’s new manager is expected to face a series of challenges that include among others negative financial results, the high cost of old production plants, the opening of the power market, the precipitation of investments in renewables etc.
As for the background of his selection, it turns out that only a close circle knew about the decision, even though ministry associates had described his profile: A young manager who climbed one of the biggest European companies ladder. According to information, Mr. Stassis was shortlisted along with three other candidates, whose CVs were chosen by energy minister K. Chatzidakis for the chair of PPC.
Mr. Stassis himself was notified a few hours before the ministry’s official announcement, of HCAP’s decision to nominate him and until the last minute, the timing of the announcement was an open issue. The ministry decided that a possible delay would break the positive momentum around the company and it wanted to give its own message about PPC’s future.
What Stassis’s choice means
On a symbolic level, the case of the 45 year old manager is the most fitting: He has years of experience in the power sector in one of the largest multinational European companies, where he distinguished himself with constant promotions, while having extensive knowledge of green and conventional energy in a tough market, such as Romania’s that has similarities and differences to the Greek market.
But the case of Enel is an example of lost opportunities for PPC, in the sense that the Italian company recently sold a large market share in Italy, transformed into an international group by taking advantage of the injected capital for its expansion, but also for the rapid growth of renewables, where it is considered to be among the top players globally. The new head of PPC has lived through this example and the restructuring of the Romanian market.
And, of course, after his return to Greece after a seven year carrier abroad, he sends another message of a successful businessman who returns home to act on the “brain regain”, that is the reversal of the brain drain that many notable Greek professionals did during the crisis.
“The right man at the right position”
What is interesting about Mr. Stassis’s case is that he is currently in his best professional phase and in that sense he does not enter PPC to finish his career and receive a good compensation bonus, but to make work of the expertise that he acquired in a difficult undertaking.
But how is he described by those who have close experience of him and what are their views about his decision to undertake the hard and demanding task of PPC?
His associated from his telecom days speak of the right man at the right position. His personality is described as simple, with multi year experience in a huge group, a man who during his tenure in Romania managed a company of similar or bigger size than PPC.
It is indeed interesting that like Enel’s CEO, Fransesco Starace who passed from the renewables arm to the mother company, Mr. Stassis transitioned from conventional power production to a market that lived through sales, privitizations, listings etc.
A manager from the green energy market who cooperated with him in ELETAEN speaks of a capable manager, both in economics and in development. The fact that he climbed rather quickly the ladder of a multinational is not random, he says.
Who is who
George I. Stassis was until now CEO of Enel Romania Srl, the greatest energy company in Romania.
Mr. Stassis worked in Italian group Enel SpA, where he was head of Enel Green Power for SE Europe and Middle East, responsible for countries like Greece, Bulgaria, Romania, Turkey and Egypt. He holds more than 13 years of experience in the energy market and has taken important positions in organizations and bodies of the sector.
From 2001 to 2006 he worked in Tellas Telecommunications S.A as a member of the executive team and as an Executive Director of Strategic Projects and Procurement.
He also holds the position of vice president of the board of the Foreign Investments Council in Romania, he is the chairman of the Coalition for Romania’s Development, while he is a member of the board of the Association of Utilities, the board of Trustees of Αspen Institute Romania and the board of CRE.
He was also a member of ELETAEN, a member of the Greek-American chamber’s energy committee and chairman of the energy committee of G20Y.
Mr. Stassis studied as a civil engineer in the Kingston University in the UK and he holds an MBA in Construction Management. He has taken part in executive programs for sustainable development in ELIS Management Academy, as well as Executive Leadership at Harvard University.
He is married with two children
Enel is a multinational energy company and a top player in global energy markets of natural gas and renewables. It is one of the biggest utilities and is included in the top power producers of Europe in terms of capacity and EBITDA. The group is present in 34 countries and it has power plants of 89 GW, while it sells power through a network of more than 2,200,00km with around 73 million residential and commercial consumers globally, the biggest number among its European peers. Enel Green Power, the renewables arm of Enel, manages more than 44 GW of wind, solar, geothermal and hydro plants in Europe, America, Africa, Asia and Australia.
Australian oil, gas and metal exploration company ADX Energy reported that it discovered hydrocarbons in several zones after drilling the Iecea Mica-1 (IM-1) well in Romania, according to globuc.com.
The report says that the potentially valuable commercial project exceeded expectations before drilling. The Pa V reservoir section represents a discovery containing a total gross hydrocarbon section of approximately 30 meters and contains at least 5 meters of a net reservoir with high-quality sandstone layers.
Another additional exploratory success is two relatively shallower Pa IIIinterval sandstones which are also associated with mud log gas shows and petrophysical pay. This discovery is of substantial significance for the proposed follow up IMIC-2 well, which is planned to drill 1.8 km NE of the IMIC-1 discovery.
The Pa V reservoir, which was not included in the predrill resource assessment, is assessed to be a gas-condensate discovery. A well IM-30 just 2.5 km further north and approximately 70 meters deeper at Pa V level tested 126 BPD of oil, ADX Energy reported.
The post ADX Energy has found hydrocarbons in Romanian well Iecea Mica-1 appeared first on EnergyWorld Magazine.
Romanian Black Sea: What should the government do to ensure the success of the current bidding round?
With the new long-awaited licencing round announced in Romania many questions and discussions arise. Globuc spoke to the President of Romanian Petroleum Exploration and Production Companies Association (ROPEPCA) – Saniya Melnicenco to see what this would actually mean for the Romanian upstream sector.
In Romania, the long-anticipated 11th concession round was announced for the exploration, development and production operations of 22 onshore and 6 offshore blocks within Romania’s territorial waters of the Black Sea. This latest round has especially been long- awaited by the upstream investors, as it opens up the sector to the new players and enhances its development.What do you expect from the new onshore bidding round in Romania?
The 11th licensing round for petroleum exploration blocks has been announced at a national level at the end of July and was long time expected by the oil and gas companies already present in Romania and abroad, since the previous round took place 10 years ago. The round represents an opportunity to put our country back on the investors’ map and to discover Romania’s under-explored potential, especially in the deep onshore. As it was stated last year by Government representatives in the public space, it is expected for Romania’s deep onshore potential to be higher than the already made discovery in the Black Sea.
Nevertheless, we believe that the round may represent a possibility for Romania’s economic development and for the diversification of the energy market, under condition of attracting new investment and entrance of more players in the sector. It can be a new breath for contractors and service providers, supporting titleholders’ activity, consequently bringing more business growth horizontally and creating new workplaces. Romania needs more investors, big and small, more know-how and new technologies, attracting and retaining talents and highly qualified specialists into its own industry. The state budget and the communities will be the first beneficiaries of new oil and gas projects. Every euro invested in oil and gas reflects in the national GDP, with a multiplication factor of 3.2.
However, for this round to be more successful than the previous exercise and to maintain a long-term investment climate, urgent stimulative measures need to be taken, having in mind the current operational context.What should the government & regulatory institutions do to ensure the success of the current round?
Without the right measures, Romania risks to remain noncompetitive and unattractive compared to other countries in the region. Several aspects need to be considered when investing in the petroleum industry, from both a national and global perspective. When it comes to stability and regulation, there is certainly a need for improvement in Romania, especially since in recent years more decisions have been made with negative effects on the industry.
The challenges faced by an investor in our industry are related to the three important components of the exploration strategy: accessibility of geological data, application of technologies and capital allocation. The regime of classified data puts the Romanian projects in the disadvantaged situation of under-funding and isolation from the globalised and digitally connected world. Also, bringing high performance technologies is closely linked to the existence of some qualified and experienced personnel in the field, assuming a considerable financial effort. The allocation of capital to exploration projects follows an adequate legislative and fiscal framework, as well as a reasonable rate of investment recovery, provided by the mechanisms of a functioning market.
Therefore, the vision for positive measures should revolve around three key elements: a predictable and stable regulatory and fiscal environment, modernisation of the relevant legislation to create more efficiency in operations and functional market mechanisms. In order for the energy sector to become truly competitive and diversified, functional market mechanisms and measures for the real protection of vulnerable consumers must be integrated. It is also necessary to stimulate the production activity by updating the legislation for streamlining petroleum operations, removing bureaucratic barriers and modernising the data regime.
ROPEPCA, in collaboration with state authorities and other market players, has developed a balanced proposal to amend the governing act for petroleum operations in Romania, the Petroleum Law, in a way that will bring it up to date.
Our expectation is that the Romanian authorities will shift views in a positive way: according to the draft Energy Strategy, is intended to stimulate long-term investments in the field of oil production, the document showing the importance of hydrocarbons in the entire energy picture for the next 30 years.
In the same time, the infamous Government Emergency Ordinance 114/2018, which has capped the price of gas for the producer and introduced a new contribution of 2% of the turnover, which has been in effect for 4 months, generated negative consequences in the market, such as the artificial increase of the unregulated price and the reduction of investments. Last week, the aforementioned provisions were called to be repealed by the Romanian Parliament.
This would be an important step forward and it is our expectation that more measures for incentivising investment and creating a functional, well balanced market will be taken in the near future. Such measures will have a significant impact on the national economy, new investments can be attracted, production would increase and ensure security of consumer supplyHow does Romania score in comparison to the other Black Sea countries in terms of opportunities for onshore producers?
In Romania, hydrocarbons account for 68% of the primary energy resources. In 2017, the crude oil production covered almost 32% of the demand, while the domestic natural gas production, resulted only from onshore deposits, covered 90% of the demand.
Despite the very good situation in terms of energy independence, Romania still has a great unexplored potential. Currently, approx. 400 oil and natural gas deposits are being exploited in the country. Most of these deposits are mature, with an operating life of over 25-30 years. In order to achieve increased production and a better understanding of Romania’s under-explored subsurface, large investments are necessary.
Since Romania did not offer new exploration blocks for 10 years, countries with a much lower geological potential have managed to attract investors over the past five years. We are talking about Hungary, Slovakia, Croatia, and now there are opportunities in Ukraine and Turkey.
In terms of the fiscal and regulatory framework in which the industry operates and which represent a prerequisite for the decision of entering the market, Romania still has room for improvement. Unpredictability of regulation represents an important concern for investors, as well as the rigid data regime and complex permitting process.
In this context our association decided to step in and to raise awareness of the authorities about the need for improvement and proposed functional solutions for the industry.
The outlook for the global wind market is on the upswing. According to Wood Mackenzie’s latest global wind power market update, global wind power capacity is expected to grow by 60 percent over the next five years.
The latest forecast shows a 5-gigawatt upgrade in the global offshore sector alone, yielding 129 gigawatts of new capacity and a compound annual growth rate of 26 percent for the burgeoning segment.
In the report Wood Mackenzie provides a comprehensive analysis of the global wind market and dive into key upgrades and downgrades by region, for both offshore and onshore segments. Below are a few highlights from this quarter’s edition.
Life beyond the U.S. PTC
Eligible offtakers are rallying to capitalize on the Production Tax Credit for wind before the full-value incentive expires in 2020 and then phases down. Developers qualifying wind facilities in 2017 are eligible for 80 percent of the full credit amount, incentivizing U.S. wind market growth.
New state-level targets in the U.S. and the strengthening of renewable portfolio standard mechanisms across the country are expected to support post-PTC demand.
As a result, Wood Mackenzie has upgraded its outlook for the U.S. market by 16 percent quarter-over-quarter, highlighted by a 3.8-gigawatt upgrade in 2021 alone.
A modest upgrade of 1 percent from last quarter in Latin America is driven by near-term upgrades in Brazil and Mexico. Demand in Brazil’s free market should positively impact expectations from 2020 to 2022, while an uptick in commercial and industrial demand in Mexico will support a record year in 2019.
European outlook dismal as subregions downgraded
The outlook in Northern Europe has been upgraded in the forecast by 6 percent. This should offset an otherwise dismal outlook update in Europe, as the other subregions combine for a 2.2-gigawatt downgrade.
Permitting challenges and undersubscription of onshore tenders in Germany and France have impeded growth. However, an increasing appetite for unsubsidized projects and a proliferation of demand from the C&I segment across Northern Europe both support a modest 0.6 percent upgrade for Europe over last quarter.
A challenge to Africa’s wind market
Slow project development due to political instability, immature support mechanisms and increasing competition from solar results has led to a slight downgrade in our forecasts for wind in Africa.
Clean energy ambitions in Africa are more prevalent than ever before, however. Renewable energy is attractive within the region, as wind and solar projects can be built much more quickly than other sources of energy. But as solar is becoming increasingly economical, Africa’s wind market faces stiff competition.
Policy deadlines boost near-term outlook in China
Onshore and offshore policy deadlines in China underpin a 2.9-gigawatt boost in the country from last quarter’s projections.
Onshore developers are rushing to comply with a new policy that requires projects to be commissioned by the end of 2020 in order to capitalize on feed-in tariffs (FIT) before a subsidy-free era begins. Offshore developers must commission projects before the close of 2021 if they are to utilize the current level of offshore FIT.
The story is not entirely positive in the Asia-Pacific region, however. Current market conditions in India have bruised the region’s near-term outlook, resulting in a 4 percent downgrade since last quarter’s report. The government-imposed auction ceiling prices and delays in commissioning awarded projects have slowed near-term growth expectations in India considerably — a decrease of 24 percent from 2019 to 2022.
Additionally, reliability concerns in Thailand have led to a 37 percent downgrade over the 10-year outlook, as the government’s focus has turned to other technologies.
Offshore wind farms may ultimately help Europe achieve its climate goals
According to an association of European grid operators, using a network of artificial energy islands as wind power hubs in the North Sea is a technically and economically feasible concept. The consortium, which includes TenneT, Energinet, Gasunie, and the Port of Rotterdam, proposed the project to meet the climate targets established by the Paris Agreement.
The North Sea Wind Power Hub (NSWPH) could play a major role in transitioning the UK, Denmark, the Netherlands, and Germany to a low-carbon energy system.
The NSWPH partners have been studying technical, environmental, and market perspectives to investigate the potential for the large wind collection hub. Last week, the consortium announced that their project assessment results showed that the concept is achievable.
“The North Sea holds a large potential for offshore wind power,” said the grid operators. Their research suggests that a series of smaller islands would be better than the initial vision of one large island.
Kees van der Leun is a sustainable energy expert and the director of Navigant, an international energy and climate consultancy that contributed to the research.
“It would be very transformative,” said Van der Leun. He explained that the proposed scale of wind farms is “completely beyond” what is operating off the coast of the UK and Germany today.
The first island hub could be developed by the early 2030s. For each individual hub, the goal is to have a network of wind farms with up to 15 gigawatts of capacity, which is enough energy to power more than 12 million homes across the UK. The biggest wind farms that are operating in the region today have a capacity of just over one gigawatt.
Van der Leun told New Scientist that the project’s success will primarily depend on whether it gets enough support from governments.
“Whether the project will happen depends largely on policy makers. If they set the right targets, appoint sufficient clustered offshore wind areas, set the right boundary conditions from a market and regulatory perspective the project is likely to go through.”
Romania has traditionally been an electricity exporter in the region over the last couple of decades, as its Communist-built power industry was large and diversified.
But commentators warn the situation is about to change due to output troubles generated by lack of investment, poor management and bad regulations.
Last year, Romania was still an electricity exporter, but the amount of exports was much lower than in previous years. But in the first quarter of this year the country became a net importer, left reliant on large imports to ensure the power needed by its businesses and households.
According to official data, Romania imported 1,125.5 million kWh over January-March 2019 and exported only 862.6 million kWh, putting the country’s electricity balance into the red. Electricity exports halved (down by -52.9 percent) in the first three months of this year, while imports rose by 78.5 percent.
This reliance on imports was due to a slump in power output, which was down by 10.8 percent compared with January-March 2018, associated with a slight decline in consumption, of 1.6 percent, during the same period. But the situation remains tense as Romania continues to rely on imports to cover its electricity needs.
Transelectrica data seen by BR show that even on a calm day like May 28, Romania imports electricity due to weak wind power output. Experts blame regulatory and tax measures.
“Romania has bigger problems with ensuring its real power production capacities. Causes? The regulatory and tax framework. We must quickly drop the obligation to trade energy produced by new capabilities on the stock exchange futures market. This regulation creates major problems with the financing of new investments,” said Razvan Nicolescu, a former energy minister and now energy consultant at Deloitte.
Large electricity imports are due to output troubles and to the electricity production structure. Romania has a diversified output structure but its coal electricity producers – all state-owned – are generating losses and need investments to stay in business. At the same time, almost all coal power capacities built during the communist era are outdated and need to be modernized.
Due to these problems, Romania relies heavily on its hydropower and nuclear energy suppliers, Hidroelectrica and Nuclearelectrica, both state-owned. But the two electricity sources cannot meet the whole consumption. The other available sources are gas-based power and wind and solar power.
The total power of the local wind turbines is 3,029 MW, but production from this type of power sources is very volatile in a country located far from the planet’s oceans and prevailing winds.
In eastern Romania, close to the Black Sea coast – where most of the local wind turbines are installed – wind is not constant, which means that wind power could fall from a peak to nothing in a couple of hours. However, some experts say that doubling the production capacity of wind power could solve some of the problems Romania is now facing.
The most stable and profitable energy producers in Romania, Hidroelectrica and Nucleaelectrica – which produce the cheapest electricity in the system – have been hit this year by the emergency ordinance 114/2018, which imposed a special tax of 2 percent on turnover and capped the profit margin at 5 percent for the energy supplied to households. Both companies need investments valued at billions of euros in order to ensure long-term electricity output.
But beyond taxes, Romania’s power producers, almost all state-owned, have faced other challenges. Running out of revenue sources, the government has forced the energy companies to pay extra dividends over the last couple of years to curb its large budget deficits, leaving the firms without money for investments.
Romania defers once again the EUR 1 bln coal fired power plant project
The shareholders of the Oltenia Energy Complex (CEO), more precisely the Romanian Government that holds the majority stake, refused to mandate the company’s management for starting negotiations for the construction of a new coal-mining group in Rovinari, Economica.net reported. The project is supposed to be developed under a public-private partnership with a Chinese group.
This is not the first postponement. China Huadian Engineering won the tender to build a 600 MW coal-fueled power plant in Romania, at Rovinari, in 2012. The cost of the project is estimated at EUR 1 billion. The first negotiations began in 2012, the talks were interrupted in 2016 and resumed at the end of last year.
The European Commission has recently urged Romania to revise the integrated energy and environment plan sent in its first form to Brussels and increase from 27.9% to 34% the targeted share for renewable energy in the country’s energy consumption in the horizon of 2030. However, the case for renewable energy does not invalidate the need for replacing the thermal power plants, a recent forecast by global consulting company ICIS suggests.
Romania’s thermal generation capacities will decrease rapidly toward the middle of the next decade, due to the high emissions costs and the capacities approaching the end of their lifetime. ICIS forecasts a 60% drop in installed capacity in coal-fired power stations and 45% in gas plants in Romania. Renewable generation capacities will develop slowly, given that the Government has set a low target, ICIS warns at the same time.
What will the liquefied natural gas (LNG) market of tomorrow look like? Today, a number of newer business models have emerged due to rapidly changing dynamics that have impacted the market, including increasing resource availability, new technologies and new sources of demand. According to Deloitte’s report, “Remodel, reinvent: How technology and changing business models are impacting the future of LNG”, the LNG market of tomorrow will be more flexible, liquid and accessible, shaped by new business models and technologies.
Over the last decade, the global natural gas supply industry has begun to move away from its traditional integrated model where major producers developed large, often stranded gas fields, built large liquefied natural gas (LNG) facilities and sold the cargoes to mainly large utilities.
Today, a number of newer business models have emerged due to the rapidly changing dynamics that are impacting the market, including increasing resource availability (e.g., US shale gas), new technologies (e.g., floating liquefaction – floating liquefied natural gas (FLNG), and floating storage regasification units (FSRUs)) and new sources of demand (e.g., China and India). While long-term contracts still make up the bulk of current trade, portfolio companies, tolling liquefiers, and networks of smaller buyers and sellers have grown substantially. Deloitte analyzed these new business models in 2016 report, “Work in progress: How can business models adapt to evolving LNG markets”. In this report Deloitte expands on that framework to address the impact of new technologies, new business models and changing supply and demand conditions.
To assess this impact, Deloitte conducted a survey of LNG market executives from around the world and across the value chain, including major producers, traders and buyers along with interviews with industry thought leaders. This report includes an overview of the LNG landscape with a focus on current supply and demand, and an analysis of how the industry’s business models have changed in the last few years and how they could continue to evolve. The report then highlights several major technologies driving the evolution including small-scale LNG, floating liquefaction and regasification, new gas-on-gas trading hubs, digitization (e.g., blockchain, data analytics and the Internet of Things) and more flexible financing. Lastly, the report outlines how different business models and new technologies could shape the LNG market of tomorrow – one that is likely to be more flexible, liquid and accessible.
Sources of near-term LNG supply and demand growth
While there are a number of high profile LNG projects in Asia, Europe, the Middle East and Africa, survey respondents expect more rapid supply growth from the Americas. This is likely driven by the number of high profile projects currently under construction in the US, combined with the LNG Canada project sanction (survey responses collected before the final investment decision (FID) was announced). East Africa, Qatar and Russia were also top of mind for respondents.
In contrast to supply, respondents see the most rapid demand growth in the Asia Pacific region over the next five years, with split expectations for other parts of the world. This appears to be driven by both demographic and economic growth as several countries including China, India and Pakistan were cited as the greatest sources of new demand over the next five years. China’s push to reduce environmental emissions and dependence on coal seems to have led to a recent increase in natural gas imports, including LNG. Other countries heavily reliant on coal, such as India, might pursue a similar strategy.
Short-term contracts, tolling models and technology
The LNG market is evolving and becoming increasingly dynamic and diverse. Recent demand trends support the responses from the survey, suggesting countries like China, India and Pakistan will play an outsized role in LNG demand growth compared to historically important buyers in Japan and South Korea. Moreover, as the number of buyers increase, new buyers may have more challenging credit ratings than traditional buyers, resulting in greater counter-party credit risk. This means small-scale, modular and floating technology will likely become increasingly important to offset new commercial risks not seen with larger, more traditional buyers. To that end, Deloitte asked respondents for their views across a range of technological, financial and market questions. Three key findings stood out:
- Between 2008 and 2017, spot and short-term LNG offtake contracts grew from 20 percent to 30 percent of volumes exported. Seventy six percent of respondents believe that these contracts will grow faster than overall LNG trade. This trend has important implications: • It could become more difficult to build new capacity as companies will not be able to rely on traditional long-term contracts to collateralize projects. • Buyers could see sales opportunities for trading houses, portfolio players and liquefiers with spare capacity as more attractive than LNG from yet-tobe sanctioned projects. • Brownfield and smaller or modular projects might become more appealing. Absent new financial products (e.g., a long-term, liquid LNG-focused futures market), our respondents also suggested that producers and financiers might need to be willing to accept higher market risk.
- In all cases, shorter contracts could mean slower supply of new capacity despite expectations. We could see the number of new, project-debt driven developments reaching FID decline as investment becomes more challenging. A pivot towards equitybased financing may only partially offset that decline, as seen with the recently sanctioned LNG Canada project. Equity financing however, is limited to those larger players who have access to sufficient capital to support these types of projects.
- US natural gas production has grown dramatically, from roughly 55 billion cubic feet per day (Bcfd) a decade ago to more than 80 Bcfd in 2018, and continued growth is projected. That has facilitated significant LNG export growth; from essentially zero a few years ago to 3 Bcfd in 2018. Based on current projects, exports could grow to more than 10 bcfd in the next five years. Combined with the emergence of accessible natural gas supply with transparent pricing (e.g., Henry Hub), a new business model that relies on tolling agreements rather than traditional oil-linked offtake contracts, has in part driven the growth of US LNG exports. These agreements rely on liquefaction as a service with specific per volume costs, rather than the all-in free on board or ex-ship LNG prices seen in other projects. This style of contract tends to provide flexibility to the buyer allowing them to procure their own natural gas and decouple LNG prices from liquids pricing (e.g., Brent or Japanese customs-cleared crude). Despite this, less than 20 percent of respondents think that companies could develop US-style tolling projects elsewhere. They cite a range of reasons including regulatory, market and project scale challenges. In particular, other countries face challenges in developing the large, liquid domestic natural gas markets to provide the security of supply needed for these types of contractual arrangements. However, these doubts may be short sighted – Canada has a large resource base driven by unconventionals, which could underpin tolling-style agreements for future projects. Similarly, Woodside and the Northwest Shelf LNG partners, several who are involved in the Browse project, are considering the use of tolling agreements in Australia. However, the business model is expected to remain challenging for those attempting to monetize stranded natural gas fields.
The industry appears to be unsure about how to best adapt and deploy new technologies. Approximately 60 percent of respondents say that digitization through big data analytics, machine learning and blockchain applications could have an impact on the LNG industry, with a particular interest in deploying blockchain to facilitate trade. A considered approach to execution will be critical due to both technical complexity and the difficulty in building consensus around a single system. When effectively implemented however, these types of systems could increase transaction price and volume transparency and reduce the time required to settle trades. The international consortium, VAKT supported by a number of producers, traders, and banks have been developing a digital ecosystem using blockchain to enable secure and transparent post trade transacting. However, with limited blockchain deployments to date, mainly in small-scale renewable power markets, application to the LNG markets seems far off. This space continues to evolve as market participants’ needs are evaluated and technologies are developed. Based on Deloitte’s 2018 Oil, gas and chemicals executive survey and The Industry 4.0 paradox report, blockchain appears to be a longer-term aspiration. Blockchain could provide integrated digital trading infrastructure that allows cargo to be traded and tracked more easily. This would enable the use of smart contracts to simplify the trading process, which could deliver significant value to the industry. However, in the shorter-term, big data analytics seem to be a high priority which provides the opportunity to optimize the timing of LNG shipping and reducing energy usage in the liquefaction and regasification process. This, unlike blockchain, will likely be a series of smaller incremental projects rather than an industry-wide disruptor.
A combination of opportunities and threats
In 2016 report LNG at the crossroads: Identifying key drivers and questions for an industry in flux, Deloitte outlined seven factors that could shape the LNG market. Some factors, such as the cost of shipping, are cyclical, while others, such as economic growth, appear to be secular. Two years on, several of these factors still affect the industry and are contributing to rising demand. – Table 1
The survey respondents agreed that these trends matter, with 70 percent of survey takers expecting that Asia Pacific LNG demand will rise by more than six percent over the next five years, with 50 percent saying the same for Europe, the Middle East, and Africa. This is driven by several factors including global growth, which has been robust and is projected to continue at almost four percent per year for the next five years, barring a recession or similar. The sharp rise in 2010 is due to increased capacity that came onstream due to newly-commissioned liquefaction trains in 2010 as well as from the ramp-up in output from trains commissioned in 200912. Due to the discreteness of LNG supply as well as project size and timing, the relationship between LNG and the macro-economy is not quite as clear.
LNG demand and economic growth are not well correlated. Secondly, more than 35 countries import LNG today, compared to roughly 20 only a decade ago. Thirdly, new markets like LNG as a transport fuel are growing, adding new sources of demand alongside more traditional applications. Environmental concerns are also driving these trends. For example, China’s demand for natural gas is due not only to the need to provide energy, but also to displace higher polluting energy sources like coal by increasing the share of gas in the primary energy mix to 10 percent by 2020 (up from six percent today). Similarly, LNG bunkering provides an alternative to high sulfur fuel oil that will not meet new IMO 2020 regulations.
Adapting existing business models
In the report, “Work in progress: How can business models adapt to evolving LNG markets?”, Deloitte identified six major LNG market participants: large scale integrated producers, portfolio companies, tolling or contract liquefiers, traders, large utility buyers and consortiums, and small-scale utilities. These companies span the global gas value chain: drilling wells, operating producing fields, gathering systems and pipelines as well as liquefaction, trading, transport and natural gas consumption. – Table 2
These six company types are well represented in our survey’s respondents. They believe that short-term trading will play an increasingly significant role in LNG. Additionally, they do not see companies developing US-style tolling projects in other countries (with the potential exception of Canada) and the potential benefits from digitization remain uncertain. These trends could potentially slow capacity growth and delay the construction of new greenfield plants as markets rely on shorter-term, more flexible and potentially more volatile contracts. The challenge could be to square the circle, with LNG buyers seeking flexible, shorter-term contracts while potential sellers are typically looking to develop conventional liquefaction projects. If LNG producers are exposed to increased market risk in both the short and long term, then producers have an incentive to reshape how these projects are designed, financed and executed. Traders and buyers may have less incentive in the short term, but the benefits of a more efficient, transparent market could be worthwhile pursuing. Reshaping the markets would present different business models with alternative risks and rewards. While respondents may not be sure how the LNG market will evolve, it is clear there are opportunities for business model transformation. Companies with historic ties to the industry including integrated producers, portfolio players and large-scale utilities will need to adapt as the market becomes more flexible. If larger buyers are unwilling to sign multidecadal, fixed-term sale and purchase agreements, operators of major liquefaction projects may be exposed to increased market risk. As mentioned previously, this could reduce access to limited-recourse financing. If project level debt is less accessible than in the past, these companies seem to have two options: corporatelevel debt or project equity financing. Neither the idea of using corporate debt to fund large project nor cargo buyers investing equity in a liquefaction project is new, but could be a challenge.
Looking further into the future, there is an opportunity to push LNG industry financing further. An offtake agreement, like a contract, guarantees certain payments in exchange for either tangible goods (e.g., LNG cargoes) or intangible rights (e.g., access to capacity) with an array of caveats and conditions. While not widely discussed within the industry today, there is an opportunity to separate certain parts of sales and purchase agreements from the corporate entities that are part of a transaction. Although not necessarily common in oil and gas outside of overriding royalty agreements or perhaps petroleum service contracts, other industries have made similar shifts. For example, commercial or residential property can be sectioned into economic interests (e.g., real estate investment trusts or mortgage-backed securities), facility management contracts and tenant leases (or sublease in the case of shared workspace companies). This way multiple parties can share various costs, benefits and obligations of using property, while not necessarily being responsible for all aspects. In the case of LNG, a project could be structured with an operator who develops the project but has limited or no equity in the project and is compensated through an ongoing management fee. Using that structure, it would be possible for small increments of offtake capacity from one project, or a portfolio of projects without destination restrictions, to be sold through either an auction-type system or direct negotiation. These shares would entitle the holder to a certain number of cargoes per year in exchange for an ongoing payment, similar to an option premium, thus mimicking features of a take-or-pay clause in a traditional contract. By securitizing LNG capacity, projects could be financed by those who may only have short-to-medium term interest in the project, because they could later re-sell their shares while assuming market risk due to shifts in value of the underlying asset. Undoubtedly, new (or even existing but atypical) financial structuring will likely face challenges during adoption.
However, even if these companies are not currently interested in corporate debt or equity financing for LNG projects, they may not have much of a choice going forward, unless the market tightens significantly and contract durations begin to lengthen. Otherwise, greenfield facilities could have trouble securing capital to reach the final investment decision. There is an incentive to innovate if the alternatives are unavailable. If larger companies tend to lack flexibility, smaller market participants could lack access. For a regional utility providing natural gas to a city or a power utility that derives the bulk of their energy from intermittent or variable sources like hydro, wind or solar, LNG could provide an appealing alternative to cope with the intermittency issues. However, with a typical large offtake contract running 20 years and sometimes requiring the purchase of two million tonnes per annum (roughly 260 million cubic feet per day) under take-or-pay terms, would likely prove too onerous to be feasible. Thanks to FSRUs, a cyclically soft market over the last few years and increased activity from trading houses, smaller, shorter and spot contracts have been available to non-traditional buyers, though credit-worthiness could remain an issue. However, if markets tighten, and there are signs that they have already, these smaller buyers could face challenges procuring spot or short-term contracts at affordable prices. Trading organizations could provide liquidity (for a price) and a futures market could provide some price-risk mitigation. However, respondents were split on the timing of future markets, unsure whether we would see a major futures hub develop in the next couple of years, over the next six years or beyond. More specifically, half of respondents thought that if a hub develops it would likely be in the Asia Pacific region in countries like China, Japan or Singapore. For a power company in Brazil, Asian LNG futures may prove a poor hedge for market risks in the Atlantic basin as gas prices have diverged in the past. Like larger companies, smaller ones could also benefit from securitization. If a buyer is not a creditworthy counterparty, they could struggle to secure capacity via a traditional contract, particularly if they are seeking to purchase relatively small volumes. A tradable equity share in a project, however, could provide the flexibility of a shorter-term contract with an asset that could be used as collateral for debt financing. There would be some equity-type risk associated with project ownership, but trading houses could be willing to assume asset and LNG price volatility risk in exchange for either payment or a portion of offtake volumes. These structures would have to evolve in line with both market needs and as companies better understand their own energy needs and appetite for financial risk. If companies look to novel financing structures and more flexible terms to transform their business models, the existing physical assets will not change. In the future, however, the physical and digital process used to transport, liquefy and market natural gas in the form of LNG may need to change to better match the changing industry, perhaps by deploying relatively new technology.
Technology as a catalyst for business model transformation
What opportunities are there for technology to bridge the gap between buyers and sellers as LNG markets evolve? It typically comes down to flexibility, transparency and efficiency. While respondents were unsure how exactly technology could be used, three key points came to the forefront: modular projects, blockchain and big data. Whether it is trading spot contracts or the execution of a LNG-backed equity agreement, the LNG market is likely to become increasingly flexible. FLNG and FSRUs should play a role as companies can deploy them more quickly and at smaller scales than traditional facilities. Similarly, small and microscale LNG appear to make sense in a world where demand is increasingly fragmented, whether due to demand from shipping or to supplying a number of intermittent buyers. In both cases, reducing unit costs might be the biggest challenge as they may be a good fit for where the market is heading. The survey respondents expect smaller-scale LNG to grow faster than the overall market. The next few years may prove that to be correct. Blockchain could pose more of a challenge, which organizations like the digital trading platform VAKT are working on. Respondents said that it could be used to improve transparency and optimized LNG trading, but other studies looking more broadly at oil and gas technology deployment, have found that blockchain is often viewed as longer-term opportunity. That being said, as LNG becomes increasingly securitized and the number of cargoes traded increase, there could be a need for increased transparency and access to a global transactions platform. Particularly in the case of multiparty LNG project-backed equity structuring, smart contracts could provide a means to simplify execution. Moreover, the lack of legacy systems could mean greater opportunities for novel solutions. While the specific technology used to underpin the system could be up for debate, greater collaboration around the financing and financial structure of the LNG market will likely be needed. Big data is a buzzword that applies to a range of projects crossing multiple industries including oil and gas, broadly including the use of large data sets (potentially sourced from IoT-type sensors) and high-powered analytics to generate novel insights and drive innovation. The potential benefits seen elsewhere in the industry apply in part to LNG as well. There are opportunities to cut energy and materials waste, increase operational uptime with predictive maintenance and improve the design of supply chains. In the case of the latter, it would need to be considered on a case-by-case basis. Many projects still include significant volumes exported under long-term contracts with fixed destinations. Optimizing routing and procurement processes may therefore be limited. Spot volumes, portfolio players and trading houses, however, might find new analytical tools useful in executing trades in an efficient manner.
Population growth, increasing economic prosperity in developing nations, government regulation and actions focused on improving air quality will drive demand for lower-carbon energy globally. As a result, LNG will command an increasing share of the global fuel mix given its lower-carbon footprint and its ability to flexibly supply increasingly diverse markets, customers and applications – ranging from power generation to marine and land transportation. Based on the survey, respondents expect consumption to increase in the Asia Pacific region over the next five years, most notably in China, India and Pakistan, with the bulk of new supply coming from the US among others. However, with respondents expecting spot and short-term contracts to grow (along with small-scale and floating LNG), the market could become increasingly fragmented and difficult to finance. Why is that? Many recent projects have been financed by project-level debt that required long-term sales and purchase agreements. We have seen some equityfinanced projects announced (e.g., LNG Canada), but it remains to be seen if that will be replicated elsewhere. Additionally, US export growth has been driven by tollingstyle agreements that may not be readily adaptable to other countries. Now is the time for companies to evolve and adapt to keep pace with market changes. Moreover, new technologies ranging from big data to blockchain could be used to reduce costs, improve logistics and simplify transactions. The next five years will be a challenging and dynamic period for LNG producers, traders and buyers as they navigate a rapidly evolving market and adapt new technologies and business models. One thing is certain, the global LNG industry will continuously remodel and reinvent itself in order to deliver energy to a rapidly growing and changing world.
US-based energy investment company Trident Acquisitions has announced that it has won a public competition to explore and produce oil and gas from Ukraine’s offshore Dolphin block at the northwestern corner of the Black Sea’s continental shelf. Ilya Ponomarev, company CEO talked to Globuc about the oil & gas industry prospects in Ukraine and his company plans.
The first question is about the overall situation in the Ukrainian oil and gas production in the context of the situation in other countries of the Black Sea region with a focus on the advantages and disadvantages of investing in this industry.
The current legal structure and business practices in the oil and gas sector of Ukraine has become better not just in the entire Black Sea basin, but in Europe as a whole. The country enjoys low royalty rates while authorisation procedures work very fast, if not always transparent.
The loose legal framework is Ukraine’s main problem. The country was formed not long ago and decisions can often be revisited as a result. Some people can sue you out of the blue, and you’re going to have to stand trial, wasting time and energy. A local council, for one, might throw a spanner in the works over environmental or other commitments.
Everything is resolved in the final run but plain vanilla Western investors can be at a loss sometimes, as this is not what they are used to. That’s the downside.
These things, however, do not dampen our company’s positive outlook on investing in Ukraine.
Romania has traditionally been seen as the leader in the region. Ukraine is now increasingly hitting the news, but there is still ambiguity about what exactly should be produced there.
Romania has been thought of as leader in Romania, but in Ukraine it is Ukraine that has been considered the leader. Romania is rich in oil whilst Ukraine is rich in gas.
According to our geology experts, doubling this volume with the modern technology should not be a problem at all.
The technological capacity in Ukraine is not up to scratch and there is a shortage of personnel because qualified geologists and reservoir engineers have been leaving for Russia over the past 30 years to work on larger projects and better salaries. Therefore it is hard to source qualified staff within Ukraine now. Lots of people have to be recruited elsewhere. And it’s a challenge.
Ukraine is not a country for large companies, it seems. It is better suited to small and medium-sized companies with a production under 5 MBOE. An ExxonMobil would not work there, but several successful players can handle a few million tons of production.
What challenges and difficulties can the development of the Dolphin block present?
Legal wrangles are still on going around it. Our company has been nominated the preferred provider alongside San Leon (Ireland) and GSP (Romania). The [Ukrainian Energy and Coal Industry Ministry] Interagency Commission submitted its conclusion on the winners of the bidding process but the Cabinet of Ministers has not yet approved the results. There is still time to do this, two months till the end of September.
The new Ukrainian government believes that large companies like ExxonMobil may resume working in Ukraine, although the said ExxonMobil has just withdrawn from Romania where it developed a field just a few kilometres from the Dolphin.
The block contains three areas licensed to Chernomorneftegaz seized in the run-up to Crimea’s forceful annexation by Russia. We believe that these areas will become available after Ukraine wins the case against Russia over the annexation of Crimea. The case has been submitted to an international tribunal, and the adjudication of Naftogaz’ 5-billion-dollar claim against Russia has begun
We want to include these areas in the overall development scope; they can have quite a significant yield.
Do geopolitical challenges play an important role then?
They play virtually the primary role. We suspect that some participants of the tender, which was rather intense and competitive, were backed by Russia, attempting to prevent Ukraine from starting the development of this block.
We are insured against war risks by the United States government, and we believe that the Russian Federation can be into some funny business in that area. This block is beyond Russia’s claims even theoretically, as it is closer to Romania than to Crimea, but you never know. The events of the last five years demonstrate that it’s all very complicated.
What are your company’s strategic plans for the near future?
We were established three years ago. A little over a year ago, we got a listing at the NASDAQ stock exchange, pulled off an IPO, raising 200 million USD in the process.
The original strategy was to acquire a core company in Eastern Europe, most likely in Ukraine. The next step would be to inject American oil and gas production technologies into this company and to invest into the development of the Black Sea shelf. We have followed this strategy so far and are in takeover negotiations with several Ukrainian and American companies.
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This year the 3rd Hydropower Balkans Summit takes place in Belgrade, Serbia, 7-8 November. The Summit is held with the official support of national power utility Elektroprivreda Srbije. EPS is the owner of major part of generating capacities in the country. It also operates numerous investment projects including overhaul of Djerdap 1, 2 HPPs and modernisation of Zvornik HPP.
Advantages of investing in hydropower in Serbia:
- Serbia has the highest installed hydropower capacity in South-Eastern Europe: current installed capacity is totalling 2,835 MW;
- In Serbia’s energy mix 21,2% is covered by hydropower plants where 2831 MW is installed hydropower capacity;
- 29% of the total electricity produced in Serbia is generated from hydro;
- 500 million euros will be invested in modernisation of hydropower plants by 2025 to prolong their service life for the next 30 years;
- Serbia plans to install 438 MW of new hydropower capacities in order to achieve the energy target to cover 27% of its gross final energy consumption through the use of RE. Still and all unharnessed hydropower capacity is about 7000 GWh;
- 39 small HPPs with 49MW total capacity are now under operation in Serbia. Moreover, 856 potential locations for SHPPs were identified in Serbia;
- In Serbia the most promising big, medium and small investment projects are located, including construction of 3 hydropower plants on the upper Drina river, construction of SHPP Celije and SHPP Rovni, overhaul of Djerdap 1, 2 HPPs and many other.
One of the investment projects from Serbia:
OVERHAUL OF DJERDAP 1, 2 HPPS
At the end of 2017, EP S announced its intention to overhaul 10 units of HPP Đerdap 2 over 10 years, to help ex tend the plant ’s lifespan and boost its capacity by 50 MW. EPS and Siloviye Mashiny are cooperating on the overhaul of HPP Đerdap 1. The overhaul began in 2009. In Jul y 2018, the t wo companies signed a contract on the modernization of the A2 and A3 units in or der to complete the revitalization of the entire HPP in 2021.
This and other investment projects will be discussed at Hydropower Balkans 2019. It is a professional platform, bringing together chief ministers, major investors, decision-makers of power utilities, leading hydropower plants, project initiators, regulators, with the aim to consolidate efforts focused on efficient development of key projects for construction and modernisation of HPPs across the Balkan region.
Romanian natural gas transport system operator Transgaz and Black Sea Oil & Gas (BSOG) have signed the contract for building a 24.37 km pipeline. It will transfer gas from Midia offshore perimeter to the national gas transport system, the economy ministry said.
The Midia project consists of 5 offshore production wells — 1 subsea well at Doina field and 4 platform wells at Ana field. The Doina well will be connected through an 18 km pipeline with a new unmanned production platform located over Ana field.
A 126 km gas pipeline will link the Ana platform to the shore and to a new onshore gas treatment plant in Corbu commune, Constanta county. The treated gases will be delivered through the gas measuring station to Transgaz. It is estimated that gas production will begin in the first quarter of 2021.
Energy minister Nicolae Badalau and prime minister Viorica Dancila attended the ceremony for the signing of the contract.
BSOG is controlled by US investment fund Carlyle International Energy Partners and EBRD. It’s a Romania-based independent oil and gas company, targeting exploration and development of conventional oil and gas resources.
Mark Beacom, CEO of BSOG, will share the details of the pipeline construction project at the Black Sea Oil and Gas Conference in Bucharest on 23 and 24 October.
The post Transgaz to build gas pipeline for the Midia project in the Black Sea appeared first on EnergyWorld Magazine.
Romania’s energy market regulator ANRE drafted new regulations requiring natural gas producers and suppliers to build up higher reserves ahead of the cold season, quoting risks of “reduced” transfer of natural gas through Ukraine and limited capacities of the interconnectors with other states (Hungary and Bulgaria), according to a release published on August 27.
In a revised version of the release, ANRE erased the note on the possible interruption of imports from Russia through Ukraine, although this is likely the main reason behind the decision, Hotnews.ro reported.
It was for the first time Romanian authorities mentioned the imminent termination of the natural gas imports from Russia through Ukraine.
Gas transport system operator Transgaz has constantly stated Russian gas producer Gazprom has not informed it about discontinuing the deliveries as of January 2020. The contract between Ukraine and Russia expires at the end of this year and it hasn’t been renewed due to the political tensions between the two countries.
Moldova, facing the same problem (although at a larger scale) has set up an emergency committee to deal with the situation.
The new regulations are published by ANRE for public consultations by September 6. Local companies already met the required reserves as per existing regulations, which were set at a level 10% higher than in the previous season. It may still occur that the natural gas resources might not be enough for all consumers [during the winter season], ANRE argued. The reserves provisioned under the revised regulations should be large enough to cover local consumption over the winter period (by the end of March).
The post Romania: Market regulator wants higher natural gas reserves appeared first on EnergyWorld Magazine.
Italian Carlo Pignoloni took over as country manager of utility group Enel’s operations in Romania, replacing Georgios Stassis. The change became effective as of August 22, the group announced in a press release.
Carlo Pignoloni was previously head of Enel Green Power’s operations in Italy.
“We are very pleased to have Carlo Pignoloni as the new country manager of Enel’s operations in Romania. His knowledge of the conventional part of the business coupled with his experience in renewables makes him an ideal candidate for the job,” said Simone Mori, Head of Europe and Euro-Mediterranean Affairs at Enel.
Pignoloni graduated in Mechanical Engineering at the Polytechnic University of Milan, and joined Enel in 1990. He is not new to Romania, as he ran Enel Green Power’s operations in the country from 2008 to 2011.
Enel has been active on the Romanian market since 2005, with operations in power distribution and supply as well as renewable energy generation. Enel Energie and Enel Energie Muntenia are leading suppliers of energy nationwide, serving 3.1 million customers.
A total of 13 companies have sent letters of interest to Bulgaria’s energy ministry for the relaunch of the project to build the Belene nuclear power plant (NPP), Energy Minister Temenuzhka Petkova said on August 20.
Plans to build the Belene NPP were scrapped in 2012, but Sofia was forced to reconsider after Bulgaria was ordered to reimburse over €600mn to Atomstroyexport (a unit of Russia’s Rosatom), which had won the contract to build the power plant and had already started work.
In May, Bulgaria called a tender for strategic investor for the project. The government in Sofia hopes to finish the project within 10 years at a cost of up to €10bn.
Seven of the letters were from companies interested in becoming strategic investors in the project. Rosatom, China National Nuclear Corp. (CNNC) and Korea Hydro & Nuclear Power were already known to have been interested in the project. The other four interested parties were German-registered Bektron-Liaz-Engineering, and three Bulgarian-registered entities.
France’s Framatome and US General Electric sent letters expressing their interest in supplying equipment and securing the funding for the project.
Neighbouring North Macedonia said it was interested in acquiring a minority stake in Belene and signing an electricity purchasing agreement. An interest in minority participation in the NPP was also received from Bulgarian companies Atomenergoremont AD and Grand Energy Distribution EOOD.
Within 90 days, a working group with representatives from the Ministry of Energy, Bulgarian Energy Holding EAD, National Electric Company EAD and Electricity System Operator EAD will prepare a shortlist of companies interested in participating in the Belene NPP project as strategic investors, the ministry said.
The procedure is flexible and allows the selected strategic investor to have conversations with companies that have a minority interest in the project or an interest in purchasing electricity, it added.
Source: bne Intellinews
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Natural gas for power generation should be expected on the island late in 2021, the head of the natural gas public company (Defa) said on Tuesday.
Symeon Kassianides briefed President Nicos Anastasiades on Tuesday on the successful completion of the tender procedure for the construction of the infrastructure necessary to import gas for power generation.
A multinational consortium made up of China Petroleum Pipeline Engineering, Aktor and Metron S.A., with Hudong-Zhonghua Shipbuilding, and Wilhelmsen Ship Management has ranked first in the evaluation for the construction of the infrastructure.
Kassianides said the procedure was now in its final stage when other bidders can appeal the decision.
If it all goes well, the contract with the successful bidder could be signed by mid-October, starting the process of having natural gas for power generation by December 2021, Kassianides said.
The LNG terminal will include a floating storage and regasification unit (FSRU), a jetty for mooring the FSRU, a jetty borne gas pipeline, and related infrastructure.
The €300m project is co-funded by the European Commission to the tune of €101m. The electricity authority (EAC) will put up another €40m while Defa is seeking financing from the European Investment Bank, the European Bank for Reconstruction and Development, and local lenders for the rest.
Kassianides said the project is “considered of the highest strategic importance so its not an interim solution.”
Provisions have been made so that the infrastructure can be used in the future if Cyprus manages to have its own gas, he added.
Initially, the plan is to import gas for power generation, not only for the EAC, but for other licenced organisations. Later on, it could be used in industry and transport, as well as ship refuelling, the Defa chairman said.
Defa is already running a separate tender for the provision of the gas.
The company intends to procure its LNG requirements through a combination of medium and long-term supply via one or more LNG sales and purchase agreements and supplemental cargos via multiple master sales agreements and a bidding process.
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CEO of Hellenic Petroleum Upstream S.A.Yannis Grigoriou gave a special interview in the 3rd episode of BGS Talks Youtube show. With Regina Chislova, Project Director of Exploration and Production Offshore Congress Hub EPOCH 2019, they talked about offshore exploration in Greece, relations between the company and the Greek government, cooperation with ExxonMobil and Total, investments during the crisis and other topics. Here are the extracts provided by our partner BGS Group exclusively for our readers. The full interview is available on BGS Talks Youtube channel.
“Regina: In general, let us list the most important projects happening in the region right now.
Yannis: I think what is going around Cyprus is very interesting, the majors are there <…>. I think that over the next days we will have some positive announcements. The licensing round of Egypt was a success for the country.<…> And in Greece we have started to sign the Lease Agreement for two huge offshore blocks around Crete together with Total and Exxon Mobil.
R: Could you give us more details on this project, since the really huge majors came to the region.
Y: We got geological concepts in our mind. It was almost three years ago, when we had in our hands some multi-client seismic data sold by PGS, we were looking at those and trying to interpret the complex geology of the area. <…> So we worked on that for 2 or 3 months and then we discussed that with Total <…>. We thought “Let’s form a joint venture to go further on that.” We did that and then we thought again “We need another one company to join us” and <…> we approached Exxon Mobil. <…> In autumn 2016 we created a very strong joint venture for the exploration in the country: Total 40% operator, Exxon Mobil – 40%, and Hellenic – 20%. <…> After negotiations and all that stuff we are about now to sign the lease agreements for these 2 blocks which are really big and very promising.”
“R: Anyway, the country suffered from a huge crisis,how the oil and gas industry was surviving when everything had happened?
Y: In Hellenic we survived because during the crisis we invested more than €3 billion in building a brand new refinery near Athens and we upgraded our refineries. Because the group is mostly the downstream oriented group this investments, first of all, created a number of jobs for the areas <…>, we had an opportunity to produce high-quality products according to the strictest EU specifications, which we exported in the nearby countries: to Italy, France, we are exporting petrochemicals to Turkey. So we overcame the Greek crisis by exporting products. And actually, the group is very proud of that the last 3 years we are experiencing high profits <…>. Our profits on an EBITDA basis are almost €800-900 million which gives us an opportunity for further growth and investing in other business opportunities like upstream or renewables. Because the export of renewables is also the next pillar for growth for the company.”
“R: The principle of your company is “we operate responsibility towards society and environment”. <…> Can you tell us more? So the Greek environment is perfect, everyone knows about it. How do you protect it?
Y: Health, safety and environment is our first principle for all the activities we have in the company. <…> So we are trying the best, we are spending for doing the best in all our activities for protecting the health of our employees, the health of the local communities, and their safety and the environment. I’ll give you an example of our recent project in Patraicos gulf where we conducted a 3D seismic survey in accordance will environmental compliance and with special attention to dolphins. <…> I can tell you that in the project of 5 mln dollars, all that we did for the environment was 400.000 dollars, it’s 8% which is nothing for the technical project. What I mean by that is that we as a company we can afford to increase a project by 5 or 8% to keep all the measures, all the restrictions all the constraints for the environment.”
“R: How do you approach your team as a senior-level manager?
Y: If I say “as a friend” perhaps there will be misunderstanding in the whole group, but the way we work is like that. We are not a kindergarten: perhaps, if you ask them, they might tell you that I’m a very strict boss and I push them to the end. But we set goals – sometimes the difficult ones – and all of us work together to achieve them.”
Watch the full interview on BGS Talks Youtube channel to know why does Yannis think it is possible to discover the fields similar to Zohr in Greek offshore, what do “seismic” and “earthquake” have in common in Greek and how to cope with failure. Learn more about EPOCH 2019 in Thessaloniki, Greece at the Congress website.
Any use of interview materials in any form is allowed only with the written permission of the publisher and the copyright holder (LLC BGS Group). Use refers to any reproduction, distribution, dissemination of materials to the public, translation and other processing of materials, as well as other uses.
The post CEO of HELPE: “During the crisis, we invested more than €3 billion in O&G segment in Greece” appeared first on EnergyWorld Magazine.
The main purpose of this article is to present the bottleneck that obstacle the wind deployment resource in Albanian – keeping in consideration the assumed technical potential and the large number of awarded projects but still not developed – and the creating a weighted opinion on the overcoming changes that will expand soon the last frontier of energy sector in Albania. A situation apparently very complex that exactly for this need a right “keys” to be read, and if assisted with the capable support by the begin offer a relevant level of profitability as the emerging markets reserves for its first pioneer.
By Dr. Lorenc Gordani (Edited by Irsida Sheshi, M.A. in Public Administration)
Albania is a small country in the South Eastern Europe with high potential in natural resources, including the possibility to produce abundant electric energy from wind power. Although wind energy technology, as an energy resource, is distributed throughout the country, with total licenses amounting to approximately 2548 MW and generation potential around 5.7 TWh/year, yet no wind farm projects have been completed or are currently in the pipeline. Therefore, fundamental become the face of the main challenges that obstruct in Albania the wind energy deployment and the implementation options that are offering in practice by the transformation of energy market in Albania.
In fact, the energy from the wind has been used in centuries for pumping water, windmills, and in recent decades the focus has shifted to the production of electricity. Today, the wind machinery for energy operate successfully in isolated areas with capacity varying from several kW to more than 7 MW. Most often, they can be quickly installed and occupied only a small portion of land. However, in most countries, these installations face a common fundamental concern, such as the lack of continuous measurements of wind velocity spanning several years.
The above is inevitable also in Albania energy market — where like in many developing countries, the issue lies on the lack of continuous long-lasting measurements of the local wind speeds. Thus, notwithstanding that approximately two-thirds of the whole of its territory is hilly and mountainous (from north to the south east of the country), and the coast line is in the direction of North-South, various companies interested to invest in this sector have found it difficult to decide whether it is worth to follow with such projects without the right estimations.
Therefore, even without being conservative, there are some issues, since there are not data gathered with the specific purpose of measuring wind energy potential in Albania. However, the historical records obtained from different meteorological stations in the Albania, shows an average annual wind speed of 6-8 m/s and an energy density up to 250-600 W/m2. Then, as identified by the Albanian Investment Development Agency (AIDA), there is an untapped wind power potential for at least 20 wind electricity centrals, especially along the Adriatic coast.
Nevertheless, the aforementioned limitations and accuracy of the above, there are already several domestic and foreign licensed investors exploring wind power production in Albania. According to the Albanian Ministry of Energy and Infrastructure, a series of zones have been identified with high, wind energy potential. An interest that up to the 2015 is followed by a relevant proposed number of big projects from investors, reaching an approximate capacity of 2548 MW in Albania.
The first tranche of big projects which came in early 2009, saw a significant number of total licensed windmills released to the capacity of 1367 MW. Technical studies showed promising potential between 5.8 m/s to 7 m/s with a load factor typically varying from 22% to 25%. This positive outcome brought a continued licenses-granting process during the 2009-2015 period in Albania. The results of the above, based on the information provided by the Albanian Ministry of Energy and Industry, showed roughly a total amount of 2548 MW with a generation potential close to 6 TWh/year (that is approximately the annual energy consumption of Albania).
Notwithstanding the above several plans for big wind projects in Albania, a further obstacle has been the intake of the energy produced. Since wind is an intermittent source, there is a need to consider load balancing for the system. The data from the Ministry of Energy and Industry in Albania, referring to the period indicated, and based on the grid structure, showed that the capacity of the Albanian power system to absorb and dispatch wind energy was only about 180-200 MW.
However, the situation is in a strong accelerated change due to big investments made, influenced by being part of an integrated European network as well as the development of power exchange options. Another aspect of interest for the investors is related to the openness of the market and the possibility offered today to adopt a balanced approach in a regional level, since wind is an energy resource of low predictability. Another even more lucrative option is to integrate with the larger hydropower resources offered by the national market as an excellent balancer of wind power plants.
The opening of the Albanian market has brought also the possibility of a reform on the remuneration mechanism. Until recently, Albania lacked a supportive regulatory framework for the deployment of renewable energy resources other than hydropower. However, the situation has changed over the past two years with the introduction of feed-in tariffs for projects up to three MW (or three pillars) in Albania.
The feed-in tariff that are aligned with the Renewable Energy (RE) target of Albania set out in the National Renewable Energy Action Plan adopted in January 2016 and further reviewed in 2018. For the contract subscribed up to now, there are in place tariffs of 76 Eur/MWh. Each company can have more than one project, for a total of 70 MW. In addition, after public notice made along the Energy Charter Conference in Tirana by the Minister of Energy Belinda Balluku it is already started with the presentations of first wind projects.
Further, on June 2019, Albania’s Ministry of Infrastructure and Energy Ms Balluku in an online meeting conference with the interested stockholders announced also the final approval of a net metering scheme for renewable energy. The scheme, open to renewable energy systems, includes wind and solar projects that do not exceed 500 kW in capacity.
Moreover, in the Albanian energy market are also introduced feed-in premium tariffs through the Contract-for-Difference (CFD) for renewable projects. The tariffs, tested up to now in large PV (the first auction for a 50 MW solar Photovoltaic (PV) plant was launched in August 2018 with the support of the Energy Community Secretariat and European Bank for Reconstruction and Development (EBRD)) are granted by a competitive auction process (more than 40 companies expressed interest and three developers were shortlisted with the contract awarded to India Power Corporation Limited) and tariffs will have a duration of 15 years.
Additional support mechanisms for renewable energy producers in Albania with an installed capacity higher than 0,5 MW consist of customs duty exemptions for machineries and equipment used for the construction of new capacities. Based on this scheme, the developers are also entitled to beneﬁt from tax exemptions from excise products (used in the build of project).
Last but not least, after the first energy project nominate a relevant contribution comes by the possibility to get the land with a symbolic price of 1 euro. As well as a support can come within the framework of procedures offered for the strategic investment but also the upgrade of structure for the e-licences or the competence of the National Business Centre, which aims to operate as a one-stop-shop for shortening procedures and increasing the transparency of the license process. However, in this regard there are still several administrative steps, which have yet to be integrated.
Notwithstanding the presence of all the above development, the most fundamental part is the opening of the energy market and its integration with the regional one. This makes possible to be open to other options that make feasible, renewable energy projects even without direct incentives. When calculating the “spread” among the cost of the development of energy production in Albania and the EU, as well as the high profitability by combining it with hydropower potential, Albanian potential offers a “surplus” value to energy markets, which makes it competitive, especially if combined with upcoming possibilities of green certificate schemes.
Therefore, Albania energy market offers a very attractive wind energy potential for its investors and energy market operator. The last development related to the opening of the power exchange and the approval of tariffs offer a possibility for further studies so as to enhance the available data, which could results in opportunities for comprehensive wind potential studies, at least those regarding the most promising sites. Nonetheless, considering the continuous reduction in cost of available preliminary studies from international organisations, such as International Renewable Energy Agency (IRENA) — untapped cost-competitive potential for the deployment of wind energy is calculated to be 987-2,153 MW in 2016, 5,201-6,990 MW in 2030 and 7,238-7,414 MW in 2050.
*Dr. Lorenc Gordani is Legal Advisor in Albanian Energy Market, Professor in the Department of Justice at the UMB
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Oil prices fell on Monday, pushing U.S. crude to the lowest in more than two weeks, as an intensifying trade war between the U.S. and China undermined confidence in global economic growth.
Brent crude was down 52 cents, or 0.9%, at $58.82 a barrel by 0645 GMT, having earlier touched $58.24, the lowest since Aug. 15.
U.S. oil was down 62 cents, or 1.1%, at $53.55 a barrel, having earlier fallen to $52.96, the lowest since Aug. 9.
Concerns about an economic slowdown are being fanned by a ratcheting up of trade tensions between the United States and China.
The latest round of tariffs “will bring yet another dent to global growth,” Morgan Stanley said in a note. “We view risks of further escalation as meaningful.”
China’s commerce ministry said late last week it would impose additional tariffs of 5% or 10% on a total of 5,078 products originating from the United States, including crude oil, agricultural products such as soybeans, and small aircraft.
In retaliation, President Donald Trump said he was ordering U.S. companies to look at ways to close operations in China and make products in the United States.
“The only thing that will lift the storm clouds over oil markets this week will be if both China and the U.S. talk and decide to mutually take a step back,” said Jeffrey Halley, market analyst at Oanda. “I can’t see that happening.”
U.S. Federal Reserve chair Jerome Powell told an annual economic symposium in Jackson Hole, Wyoming that the U.S. economy is in a “favorable place” and the Federal Reserve will “act as appropriate” to keep the current economic expansion on track.”
The remarks gave few clues about whether the central bank will cut interest rates at its next meeting.
But exacerbating concern over the possibility of recession, U.S. manufacturing industries registered their first month of contraction in almost a decade.
The Brent/WTI spread was at minus $5.26, after widening 60 cents to settle at minus $5.17 on Friday. The spread blew out after China included U.S. oil for the first time in its tariff moves.
Hedge funds and other money managers raised their bullish wagers on U.S. crude to a three-month high in the latest week, the U.S. Commodity Futures Trading Commission (CFTC) said.
U.S. energy companies cut the most oil rigs in about four months last week, with the rig count falling to the lowest since January 2018, as producers cut spending on new drilling and completions.
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While the mainstream media’s attention is now focused on the completion of Russia’s two gas pipeline projects—Nord Stream 2 and TurkStream—exceptional, but under-reported changes are afoot in southeast Europe that could challenge Moscow’s regional dominance and geopolitical pressure and help establish a bidirectional north-south corridor linking Greece and Turkey to Ukraine along the Trans-Balkan pipeline.
The corridor has been the main artery for gas shipped from Russia to Bulgaria, Greece, the Republic of North Macedonia, and Turkey across Ukraine, the Republic of Moldova, and Romania for more than three decades.
Source: ENTSOG Transmission Capacity Map 2017.
However, with a long-term transit contract between the Ukrainian incumbent Naftogaz and Russia’s Gazprom expiring at the end of 2019, and Moscow pressing to divert current exports to TurkStream 1 and 2, an entirely new transport route across the Black Sea, the Trans-Balkan pipeline is expected to be freed up.
Critically, the expiry of the contract coincides with a rise in US-sourced liquefied natural gas (LNG) exports to Greece and Turkey and unprecedented transformations in the region’s gas dynamics.
This opens a rare window of opportunity for southeast Europe—historically one of the continent’s areas most reliant on Russian gas—to tap LNG and transport the fuel from south to north across the Trans-Balkan route.
To reverse flows, countries would need to boost compression, upgrade metering stations, and align transmission and cross-border trading rules. But while the costs involved in such operations are relatively small and the time required to implement them should be short, particularly when compared to building a new pipeline from scratch, the difficulty lies in countries agreeing to work fast and in concert before the window of opportunity closes and Russia’s grip is further cemented.
Since the beginning of 2019, southeast Europe and Turkey have witnessed some of the most dramatic gas sector changes in recent years.
Turkey, which has traditionally relied on Russian pipeline gas to cover more than half of its internal consumption, has succeeded in raising its LNG off-takes to be almost on par with Russia’s shares of Turkey’s total imports. According to latest reports by the energy regulator EPDK, Turkey imported 20.6 billion cubic meters (bcm) of LNG and pipeline gas in the first five months of 2019. Of these, 6.8 bcm, or 33 percent, were Russian pipeline gas, while LNG imports amounted to 6.5 bcm, or 32 percent, of the total. This is a remarkable change from the first five months of 2017, for example, when Turkey’s pipeline imports from Russia stood at 51 percent of total gas off-takes, which amounted to 24.2 bcm. To compare, the share of LNG within the total imports stood at 21 percent during that same period.
Within Turkey’s rising share of LNG imports, US deliveries have been soaring. According to the same reports, the country off-took 0.9 bcm of US-sourced LNG in the first four months of 2019, which was double the volume of US imported LNG throughout the whole of 2018.
The significant increase in US-sourced LNG now places Turkey after Spain as Europe’s second largest importer.
One vessel of 150,000 LNG cubic meters equals 90 million cubic meters or 3 billion cubic feet pipeline gas. In Million British Thermal Units (MMBTu), this amounts to 3 million MMBTu.
Source: ICIS LNG Edge.
Changes are largely due to the recent expansion of Turkey’s LNG import capacity at its onshore Aliaga and Marmara terminals and the charter of two floating storage and regasification units (FSRU), which serve its Etki and Dortyol ports on the Aegean and Mediterranean Seas. The expansion has brought its total nameplate LNG import capacity to 42.7 bcm, or 90 percent of Turkey’s total gas imports in 2018, strengthening Turkey’s position as a major global LNG importer and as an aspiring regional gas hub.
Neighboring Greece has equally expanded its importing capacity at the Revithoussa LNG terminal by adding a third tank and is in the process of commissioning an offshore terminal at the northern Alexandroupolis port.
Like Turkey, it also imported more US-sourced LNG in the first half of 2019 than throughout the whole of 2018, as shown in the graph below.
Source: ICIS LNG Edge.
Earlier in June, for the first time ever, Greece received a US-sourced LNG cargo for delivery into Bulgaria, which was due to be followed by a second delivery via the same Greek onshore Revithoussa terminal in the third quarter of 2019.
Bulgaria, which had depended almost entirely on Russian gas until recently, has been able to diversify supplies thanks to the arrival of US LNG and the increase of cross-border physical interconnection capacity at its Greek Kulata-Sidirokastro interconnection point. The interconnection capacity between the two countries is set to rise further in 2020 when the 3 bcm/year Interconnector-Greece-Bulgaria (IGB) will be commissioned and linked to the Alexandroupolis terminal in northern Greece.
From a pricing perspective, the region currently carries a premium of anything between €9.00–€14.00/MWh ($2.98/MMBTu–$4.6/MMBtu) over western Europe. In Bulgaria and Turkey’s case, this is because they operate regulated end-consumer tariffs, which reflect the price of Russian oil-indexed gas imports. As for Romania, the government reversed the liberalization process this year, capping end-consumer tariffs and introducing an import obligation despite reduced interconnection capacity with neighboring markets.
The high costs paid by these countries for natural gas makes it even more imperative for them to open up their borders and allow LNG to reach their markets, while LNG companies should be attracted to sell to this premium region at a time of globally reduced profits.
Source: ICIS data.
The milestones reached and dynamics currently shaping up are only the beginning of a wider regional transformation that could see LNG reaching markets as far north as Romania, the Republic of Moldova, and Ukraine if transmission capacity is made available on the Trans-Balkan pipeline.
In 2020, when Gazprom’s transit contract with Ukraine’s incumbent Naftogaz ends, volumes currently exported via the Trans-Balkan pipeline to Turkey may be diverted to the 15.75 bcm/year Russian-backed TurkStream 1 to serve the Turkish market exclusively.
Russia’s TurkStream 2, a pipeline of equal capacity, is expected to carry gas to Hungary via Turkey, Bulgaria, and Serbia. However, there are indications that the project—which will rely on existing infrastructure, some of which is part of the Trans-Balkan line, as well as new pipelines built inside Bulgaria—will be delayed at least until 2021 due to ongoing legal issues in that country.
This means that if the 14 bcm/year of gas exported to Turkey via the Trans-Balkan line are diverted to TurkStreamm1, then most of the existing transit infrastructure could become idle, allowing countries along the route to reverse flows and establish a bidirectional corridor.
Until the completion of TurkStream 2, Gazprom may continue to transport some smaller volumes via the Trans-Balkan corridor to countries such as Bulgariaand Greece, which hold long-term supply contracts not exceeding 3 bcm/year each.
Even so, capacity could be booked by other companies in reverse flow on the Turkish-Bulgarian section of the line following relevant upgrades last year. Spare capacity on T1, one of the three lines of the Trans-Balkan corridor that links Romania’s Bulgarian border to its interconnection point with Ukraine along the same route should also be available.
With import and transit capacity expanded in Turkey and Greece, and Ankara looking to sign an interconnection agreement with Sofia to allow Turkish exports, LNG could reach the entire region as early as January 1, 2020.
Nevertheless, there are lingering obstacles that have to be removed.
While carrying out the technical works—for example, boosting compression or introducing new metering stations—should not be a challenge in itself, the difficulty lies in stakeholders along the route working in unison to turn the Trans-Balkan pipeline into an export corridor for LNG and an alternative to Russia’s regional projects.
So far, countries such as Romania have proven reluctant partners, being accused by the European Union (EU) of hampering regional gas security by restricting cross-border trading.
Romania’s transmission system operator, Transgaz, has also failed to implement EU rules for third party access at its interconnection point with Ukraine following the expiry of the T1 transit contract in 2016, despite highinterest in capacity booking at that interconnection point.
The region may have until 2021, the likely date by which Bulgaria is expected to sort out legal issues and build its leg of the TurkStream 2 corridor, to ensure it establishes access to non-Russian supplies and infrastructure to create real change.
If that window is missed, the TurkStream 2 corridor will be commissioned and critical infrastructure would once again be blocked to serve Gazprom’s interests.
Dr. Aura Sabadus is a senior energy journalist writing about Eastern Europe, Turkey, and Ukraine for ICIS, a London-based global energy and petrochemicals news and market data provider.
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