By Dr Lorenc Gordani, Independent Energy Lawyer*
An overview of the latest updates on renewable energy sources in Albania.
The Albanian energy market is undergoing a full restructuring process and the country, similar to the transition taking place in the region, is increasingly entering an emerging market of distributed renewable energy (DER), alternative traders and deregulated supply.
One of the more evident aspects of this deep renovation, regarding renewables has to do with approving measures for the connection to the distribution system of small photovoltaic installations for self-producers of solar electricity, that allow a full return of energy delivery without any cost for the use of the grid.
A few months ago, there was an insisting request for opening business opportunities, in particular for photovoltaic self-consumption. Latest changes were made towards the factual situation where the actors (the most prominent photovoltaic companies) have already delivered the first projects in practice.
Related to net metering, the ministerial regulation that will determine the price of surplus is still expected (based on new RES law). However, this renewed positive season toward renewables has pushed ahead more and more significant projects even with the completion of the power plants up to 600 kWp photovoltaic such as the one in the city of Korça, developed under the supervision of the prestigious companies Enerparc Energy and brands like is the SunPower, SMA, etc. Installations above 500 kWp surpass the threshold level – as admitted recently by the minister of energy Bellinda Balluku – for being connected in net metering.
In practice, photovoltaic installations are embraced more and more by all prestigious companies, Today, the power panels are becoming preferred for installations in parking like Coca-Cola Bottling Albania or on roofs of headquarters e.g. the Statkraft Albania, ProCredit, and itself Ministry of Energy, KESH, etc.
Factual evidence that is also confirmed by statistics, reveal that loan credits to the Res projects already reached the level of 200 Mil/Euro along 2019, with growth for the private sector by 43%.
A new tendency was preannounced first by the important developments related to the approval of the criteria for the licensing of Energy Managers and afterwards to those for Energy Auditors, during April and June 2019. A framework followed with capacity building of the first experts as graduates with the completion of the course of European standards in the energy managing.
A change of approach about renewables aims in diversification similar to the development in the rest of the Balkans. There is a tendency against hydro in the region that has also made Albania to take a big step away from harmful small hydropower and abandon especially the construction of small hydropower’s (SHPPs) with a capacity below 2 MW.
The above were finalised in Albania with the approval of the new National Consolidated Action Plan on Renewable Energy Sources, 2019-2020 in August and it was put in force on September 19, raising PV planned capacity from 120 MW to 490 MW, wind from 70 MW to 150 MW, and biomass from 8 MW to 41 MW.
One of the most critical aspects of this reform is the commencement of a formal procedure for the net-metering scheme that has found a relevant echo in international magazines. A decision not merely on paper, but already finalised with the first agreements from August to October of 2019 creating a good working practice and a streamlined procedure for further requests.
The above are followed closely with a lot of new opportunities and open challenges for their realization. First, there is the implementation of the first smart meter: up to now a pilot project, that foresees the enrollment of around 3700 in the area of Tirana-Durres.
The last few months were dominated by the updates on the delivery proposals for wind projects in the ministry of energy. The latest was the passing of the project to build a wind farm with an installed capacity up to 3 MW in Topoje village, near the south-western part of the country.
Furthermore, the transition is also reflected in an ambitious plan that will revolutionize transport in Tirana, with the removal of registration taxes for electric cars, etc. Also, it regards the quality of air as scheduled by the Tirana Green City Action Plan or the activation of different events and conferences.
Last but not least, regarding transport there is a new law initiative that establishes that 5% of the amount of fuel consumed for transportation in-country should consist of biofuels, while by 2020, this amount should reach 10% of the total, which opens the way for the first time for the production and use of biofuels, with the aim of achieving the 38% target by 2020.
The transition will, however, continue to rely upon traditional big hydropower plants. A top priority project for the Ministry of Energy of Albania and one of the most important hydropower projects in Europe is the Skavica HPP project. A project linked to the EC initiative Sustainable Hydropower Development in the Western Balkans.
Its Feasibility Study and ESIA include four principal phases: Project mobilisation and inception, Site investigations, Prefeasibility study and Regional Impact Assessment, Feasibility study and ESIA.
A further regional project is the Ionian Adriatic Gas Pipeline in Albania and Montenegro. The project has passed Preliminary Design and beneficiaries are the Government of Montenegro, Albania, B&H and Croatia. Total WBIF grant is € 2.500.000 for main deliverables, preliminary designs and updated Environmental and Social Impact Assessments.
However, we should also remind the delay of the Akerni PPVP project that even after one year the signing of the contract has not been finalized. The most relevant concern has to do with uncertainty related to the upcoming Albanian PXs so-called APEX.
The new market configuration is the deep reform that was foreseen by the “Strategic Plan for the Reform of the Energy Sector in Albania approved by the Albanian Council of Ministers with DCM Nr. 742, dated 12.12.2018”.
A project that considers the economic interest of the issues is deal by the politician, putting a paragraph in all the public discussions. The last in order is the newly elected primer of Kosovo that has put the coupling (i.e. the putting together through a power exchange) of the energies markets, in focus of the review to strengthen agreements with Albania.
Economists focus more on the need for diversifying and removing the obstacles to growth like in the dry years of 2019. Furthermore, in the last few months, energy production is strongly related to the discussion of GDP growth. These statements are confirmed in the World Bank’s position.
A very pressing problem has been the continuation of drought accompanied by high imports of electricity. Low production of hydro energy has reduced growth by around 1%, making the activation on the risk mitigation of renewables an emergency.
There is a fact preannounced by regional reports, such the last one of the EU, which states that despite vast resources, Albania is a net importer of electricity; inefficiencies in the energy sector hamper Albania’s competitiveness; and the dependence on hydropower for electricity generation makes the economy vulnerable.
It is an aspect, which is mitigated only by imports. Up to now there have been 170 Mil/Euros of imports and a forecast of 40 mil/Euro of direct support from the budget for OSHEE. In this regard, there is the notice in Albanian about the call for tender of the start of a high voltage interconnection between Albania and N. Macedonia.
Mitigation will be possible only with the launch of Albanian Power exchange. In this direction, after the decision to found the power exchange on May 16, followed the announcement of the call for the stockholders interested to participate in the Albanian Power exchange.
Due to the reform and the situation, Albania has two options by the beginning of next year, to realise a function PXs or be part of regional ones. The choice seems to go to Belen, but its action aims to the larger regional ones related to the interconnection Me-Ita, Macedonia’s electricity interconnection with Albania. Then, very soon, there will be a really great change.
This will be complete through the unbundling process of OSHE. After the transitory period of 1 year taken by Albanian DSO (OSHEE) to proceed with the reform and remove any plan of reintegration by the government of Albania in May 2019, follow the two agreements signed by the Ministry of Finance and Economy with the Government of the Federal Republic of Germany and the French Government.
Arrangements based at the Memorandum of Understanding on financial cooperation between Albania, Germany and France concern the program “Supporting the reform of the energy sector in Albania” and “Investment program for distribution of electricity I”.
Also, a cooperation agreement between OSHEE and USAID was signed earlier. An assistance programme that aimed primarily at strengthening management to further improve indicators in the Shkodra region. It is one of the 12 areas that will serve as a pilot to gradually extend to other parts of the country.
What is considered fundamental for any development of the Albanian energy market is the complete reform of the OSHEE for the upcoming period that is foreseen through the reform. Very soon there will be a definite unbundling plan as well as the strategy for the market retail opening for the strategic reform of the Albanian energy market plan.
We should also not forget the deployment of Natural Gas in Albania. The TAP project is proceeding and Albania is forecast to use at least 1.7 Bcm a year from TAP.
The above also concern the timeline of IAP. Recently the last multilateral meeting on was concluded, following up the feasibility study for the Ä618 million gas corridor between Albania, Bosnia and Croatia, which has full support of the EU and the US. The completion of the TAP project paves the way for the 511 km pipeline, which aims to link the Trans-Adriatic Pipeline (TAP) with Montenegro, Bosnia and Croatia, for following further up to the European hub of gas in Baumgarten (Austria).
Meanwhile, there has been a temporary stop to the CCGT Korça project of 480 MW following feedback by some civil representatives and environmental organisations and above all the local authority’s decision and the ministry of environment. This shows there is a need for better thinking about the procedures and to join a dialogue in order to benefit the country through this strategic project that links Albania with the main energy strategies of the European Union.
It is a situation similar to the action against carbon in the region. There is a tendency to stop carbon projects, and in Albania we should consider the lack of any carbon power plant as reflected in the preparation of the National Energy and Climate Plan (NECP). In this regard, the latest development is about the Tendering consulting services to design a carbon tax for Energy Community Contracting Parties.
We should also note that Albania is already one of the main exporters of oil in the region. Its production and exports are relatively low at around 1 billion tones per year (in years ‘70 up to 2,7 billion). However, we should consider that its needs make the country fully self-sufficient. In this context, and based on the fact of gasification of the country due to the TAP and IAP projects, the hydrocarbon sector is one to keep attention on. Relevant updates, such are the ones related to Shell, confirm high oil reserves in Shpirag.
About future perspectives, among the most important are the plans of EBRD for the regional orientation of EBRD on a new strategy for the next 5 years. In this regard, there is action again related to the economy as referred by the meeting of Minister of Economy and Finance Anila Denaj with representatives of EBRD. They discussed the second tranche of over 100 mil euro for KESH in order to reform the energy system.
In the direction of Technical Dialogue, the Albania Investment Council is working , that is part of EBRD, as well as other international organisation such as IRENA, aiming to put particular focus on improving the investment business climate.
IFC has signed an agreement with the Ministry of Finance and Economy to help Albania modernise its investment policies. Under the agreement, IFC will advise the Albanian government to better align its investment policies with those in the European Union (EU) and improve its investor services.
It is a partnership that has made possible a financial contribution by the European Commission. The EU funding is part of €2.5 million programs to help prepare the economies of the Western Balkans for EU accession and support economic development in South-Eastern Europe. Furthermore, particular attention is going to be given to service delivery in Albania through effective PPP monitoring.
In conclusion, based on the above, what remains is to find the way to better support all these energies. The main obstacle remains in the opening of the market where the right tools and clear rules will raise transparency, upgrade professional capacities, support small SMEs and education, in the way to make the things happen and not remain just a list of good wishes and finding just shortcuts of the immediate needs that will vanish without any sustainable long result.
*Dr Lorenc Gordani, Albanian Coordinator of the International Renewable Energy Agency (IRENA) and Independent Adviser in Energy Policy & Law, Regulation & Infrastructure in Albania.
RWE’s CEO, Rolf Martin Schmitz, delivered the German power giant’s proposal to prime minister K. Mitsotakis for a collaboration in renewables.
During his meeting with the Greek PM, Mr. Schmitz proposed to focus on renewable projects, but also on the sharing of knowhow to PPC for the process of decommissioning its lignite power plants.
Clean energy investment
It should be noted that the German group operates power plants of 25 GW in Germany, the UK, the Netherlands and Turkey, using natural gas, coal, lignite, hydropower and biomass as fuels.
The company has already proceeded in a significant drop of its coal portfolio, reducing its CO2 emissions by 60 million tones (around 30%) in the years between 2012 and 2018.
At the same time, RWE has pledged to further reduce emissions in the future with continuous decommissioning in order to achieve a neutral carbon footprint by 2040. As part of this effort, the company realizes annual investments of 1.5-2 billion Euros in renewables and energy storage. Besides, Germany has announced the full decommissioning of coal plants by 2038.
It should be noted that PPC and RWE have a lot in common when it comes to their course, since the two companies were close to cooperating 12 years ago.
Specifically, the two power groups had the knowhow and a wide portfolio in lignite plants, which is the least efficient and hardest to exploit of all kinds of coal.
As to their cooperation, which was not concluded in 2007 during Takis Athanasopoulos’s tenure as CEO of PPC, the two groups had signed a memorandum for the construction of 2 giants hard coal plants of 800 MW each. Said plan was pioneering in its time, but did not progress because of political and union resistance.
Now, the prime minister’s announcement to decommission PPC’s lignite plants by 2028 creates a wide spectrum of cooperation for the two groups, with decarbonization as their common goal.
Green Tank welcomes Mitsotakis’s statement for lignite
“The country’s energy policy turns a page”, noted Green Tank, while welcoming Kyriakos Mitsotakis’s statements about the lignite transition.
During a special climate summit organized by the UN general secretary, Greek PM, Kyriakos Mitsotakis, pledged to decommission all lignite plants by 2028 at the latest.
“The PM’s pledge to shut down lignite plants by 2028 constitutes an historic decision. Our attention must now focus on the just transition of lignite regions”, said the environmental think tank.
“It is an historic decision since lignite has been our main fuel for more than six decades. At the same time, though, between 1990 and 2017, it was responsible for 34% of CO2 emissions, one of the highest percentages in the EU. Therefore, lignite is the main culprit for the fact that Greece is among the countries with the worst climate performance in Europe.
Beyond the indisputable negative effects of burning lignite for public health and the environment, progress in renewables together with European environmental law and European energy policy have made lignite economically unprofitable in recent years”, said Green Tank in its announcement.
In Green Tank’s recent report, it was highlighted that during the last 3.5 years the total damages from lignite plants’ operation reached 683 million Euros, while if PPC’s lignite portfolio remained as it currently is, damages would reach 1.3 billion in the next 3.5 years.
“Congratulations to the Greek government for its historic decision of full independence from lignite by 2028. It is absolutely necessary that this decision is mirrored in the revised National Energy and Climate Plan, while it also forces a change about the new PPC lignite plant “Ptolemaida 5”. Now that the lignite landscape becomes clear, attention must be given to these regions of the country with a high dependence on lignite. Greece’s transition to the post-lignite period must be viable and just for local communities that burned for decades in order for us to have power”, said Nick Mantzaris, policy analyst of Green Tank.
The popularity of Innovation Hubs is growing rapidly in recent years. It’s no surprise considering that they provide subject-matter expertise on technology trends, knowledge and strategic innovation management and are focal points for the Innovation Communities’ activity within the areas of focus. And although we saw Innovation Hubs in several industries in our region, we have never seen one in ports. Until now. Read all about the PoWER project – Ports as Driving Wheels of Entrepreneurial Relm – from the perspective of its coordinator Marco Padula.
Let’s start from the beginning.
What’s the PoWER project all about?
Marco: The PoWER project aims at developing and testing a new methodology and strategy supporting the evolution of Adriatic-Ionian ports into so-called “Innovation Hubs”. According to the project concept, the state of “Innovation Hub” is basically an attitude of a port towards change which implies the commitment to a three-steps methodology to address topic-specific needs, i.e. a) needs mapping; b) ideas and solutions scouting; c) scenarios foresight. This methodology – once validated – can possibly be applied to any topic. At the moment, the PoWER project is testing it in 6 pilot ports (Bari, Brcko, Durrës, Igoumenitsa, Ravenna and Rijeka) on the energy efficiency topic.
Adriatic-Ionian (ADRION) region is specific because of cultural borders and political rifts that are causing a lack of cooperation. Is that the reason why you chose this area?
Marco: Since the second post-war period, this area and especially the ports we chose underwent a progressive loss of their role of lively places of commercial and cultural exchange, which caused a lack of investments, cooperation, innovation and development, as well as a weaker application of EU policies. As a result, they suffered from low modernisation rates, inadequate smartness level and unsolved issues related to sustainability and urban regeneration needs despite being complex ecosystems and possible actors of a new development phase.
What we are trying to do, is to bring back Adriatic-Ionian port cities to their ancient pivotal role, but in a new way, set within the contemporary age. We imagine ports where the main innovation is the process through which innovation is designed and activated. This process brings back together all the stakeholders involved in the port’s “innovation supply chain”, which shall cooperate at the local level, but also at a transnational level so to achieve both vertical and horizontal innovation goals.
Can you describe how does the project work?
Marco: As I already mentioned, we are trying to regenerate port areas according to three factors: a) commercial and entrepreneurial activity, b) cultural heritage and c) surrounding territorial areas of the ports. In other words, we are leading ports to the ancient role which was a connection, cultural exchange and entrepreneurial focus. How are we planning to do that? Well, the main objective of the PoWER project is the dissemination of the PoWER methodology across the ADRION port cities and to guarantee the replicability of the PoWER Strategy by supporting the implementation and the sustainability of the activated innovation process. For that, we needed to make three main steps:
1. Mapping of needs (it provides geo-referenced information on PoWER ports, their smartness level and their needs).
2. Ideas and solution scouting (scouting sections are dedicated to C4S proposals submission, Ideas & Solutions storing and to matchmaking events).
3. Scenarios foresight (we offer to the wide public the PoWER methodology’s and strategy’s documents, the developed scenarios, as well as follow-ups on the implementation activities and results).
The main indicator of the environmental sustainability of a port is energy (EcoPorts, 2017) and that is the project’s topic. Nevertheless, it is possible to apply the PoWER methodology to any other topic of strategic interest for ADRION ports.
At what stage are you now?
Marco: This summer, we activated the last step of the project, the foresight activities. Our foresight methodology is based on the approach proposed by the European Parliament Research Service (EPRS), which has been adapted and applied to the maritime and port sector for the first time by the PoWER consortium. This methodology foresees 5 main phases, which are 1.) preparing the ground, 2.) Horizon scanning, 3.) Envisioning, 4.) short-mid-term scenarios development, 5.) Long-term scenarios development.
Currently, our piloting partners are implementing either phase 3 or phase 4, thanks to the involvement of STEEP experts gathered in local panels applying the Delphi method.
The whole point of the process is to provide local authorities and decision-makers with a clear view of actions to carry out in the short-mid-term at the local level, as well as with a more structured strategy to be implemented at the transnational level. By the end of the project, our aim is to have local entities sign a protocol, a memorandum of understanding where they agree on being interested on putting their effort in the actual implementation of the local and transnational strategy.
You said that the main topic of the project is energy. What are the main drivers for increasing energy efficiency, and what are the main obstacles?
Marco: Main driving forces for increasing energy efficiency in ports definitely are:
• Different countries regulations and requirements to implement energy efficiency measures, e.g. international, national or local legislation for increasing energy efficiency.
• Reduction of fuel consumption which will result in financial savings for ports.
• Reduction of harmful emissions and improvement of air quality which is a major issue for most countries.
• Introducing measures such as energy management system in ports and using renewable energy can mean fulfilment of strategic plans (national/local).
As for the barriers, unfortunately, there are more of these such as:
• High investment cost.
• Lack of funding for highly efficient technologies (economic barriers).
• Lack of professional staff or capacity to carry out these tasks in ports (inner organizational barriers).
• Also, different regulations can, instead of the driver, be the barrier and obstruct. For example, infrastructure projects (policy barriers).
• Lack of policies and incentives, depending on the case, can be the barrier towards these improvements.
• Lack of awareness in various ports towards energy-efficient technologies and measures that can in the long term completely transform the port and instead focusing solely on short term and absolutely necessary day to day measures.
Connected to the previous question, what would you say is the most important aspect of this project?
Marco: In general, I would say that it actually is the people living in the port. The untapped potential is their needs, their ideas, the infinite chances of cooperation that can be built, the possibility to share and to find private and public entities supporting you and to do the same for someone else, discovering that on the other side of the Adriatic Sea, some port is facing the same issue yours is facing and it’s looking exactly for the solution that you have in mind.
For example, a huge success for us was the meeting in Rijeka, where we managed to gather more than 100 people interested in a project. That is more than any other similar project succeeded to do. Also, our piloting process related to energy efficiency has brought us to the detection of 14 needs. To these needs, we gathered a total of 29 solutions from independent professionals, SMEs and researchers through our Call 4 Solutions, as well as 31 ideas drafted by high-school and university students during the gaming sessions we organized. Ideas and Solutions underwent both a local and a transnational assessment, out of which 17 solutions and 10 ideas were awarded as the best ones.
Thinking of people, how does this kind of ports development affect the locals? To their prosperity and that of the wider region?
Ports are Tools, endowed with the complexity required to encompass multi-layered and integrated supply chains and to become promoters of the regional innovation system.
Ports are Goals, as their demanding metabolisms show a need for requalification/regeneration; a condition which allows for rethinking the meaning of ports for people.
Ports are Case-studies offering a perfect background of problems, opportunities & structural conditions for identifying case-study areas, where to implement on-field activities on all possible levels of the smart innovation, to find & test solutions to urgent challenges.
Ports are the House of the enterprises linked to the Blue Growth.
They are an integral component of a city and their state affects the city and the community directly, both socially and economically.
The ports of the Adriatic-Ionian area must implement strategies that aim at innovating and internationalising the territory. Globalization and containerization’s rapid development led to bigger ships, more powerful infrastructures and supporting technologies as same as the stronger cities. Mentioned ports in this area haven’t changed since WW2 and lost their role of lively places of commercial and cultural exchange. That’s why they need to establish a permanently ongoing, collaborative and immaterial innovation process – a goal that this project is trying to accomplish with the PoWER Innovation Hub, and by clustering such IHs into a transnational network. We are sure that you are going to hear more of this project. Their next and final steps are the finalization of the foresight process and therefore, of the PoWER Strategy drafting, and the organization of the PoWER final event in Bari, at the beginning of December 2019, where our Innovation Supply Chain actors will be invited to officially sign their Memorandum of Understanding for the strategy implementation. People behind the project are giving the tool and people have to answer the call for implementation and make ports in this area better.
By Ramez Naam
Building new solar, wind, and storage is about to be cheaper than operating existing coal and gas power plants. That will change everything.
When the history of how humanity turned the corner on climate change is written, we’ll look back and see that clean energy – specifically clean electricity from solar, wind, and storage, went through four distinct phases.
Phase 1 – Policy dependent
From the 1980s until roughly 2015, there was virtually no place on earth where new solar, wind, or energy storage was cheaper than generating electricity from coal or natural gas. This was the first phase of renewables, one where they scaled entirely because of government subsidies and mandates. And in this time, renewable growth was paltry. Solar reached 1% of global electricity. Wind reached perhaps 4%. The world spend hundreds of billions of dollars subsidizing clean energy, and seemingly got nothing.
Phase 2 – Competitive for new power
Except that the world didn’t get nothing. As I’ve written often, the most important aspect of clean energy policy has been to drive down the price of clean energy by scaling it, and thus kicking in the learning-by-doing that continually lowers the unsubsidized price of new solar, new wind, and new energy storage. The policies of the 80s, 90s, 2000s, and 2010s finally drove down the cost of new solar and wind electricity by more than a factor of ten. That finally paid off around 2015, when, for the first time, building solar or wind power was, even without subsidies, sometimes cheaper than building new coal-or-gas fired electricity.
You can see this in IRENA’s graph showing the price of new solar PV, on-shore wind, off-shore wind, and solar CSP – Figure ES.2.
Phase 3 – Disruptive to existing fossil electricity
Now, after decades of subsidizing solar and wind, we’re on the verge of a new, radically different point in history – the point at which building new solar or wind power (or new energy storage systems, in some cases), is cheaper than the cost of continuing to operate existing coal- or gas-fueled power plants.
Dubious? Consider the following:
NextEra CEO: Cheaper to Build Solar & Wind Than Operate Existing Coal by the Early 2020s: In January 2018, NextEra CEO Jim Robo told investors that by the early 2020s, it would be cheaper to build new solar and wind power than to operate the utility’s fleet of existing coal power plants.
NIPSCO: Cheapest Option is to Go from 65% Coal-powered to Zero – and Replace it With Solar, Wind, and Storage. In October of 2018, a utility in Northern Indiana, NIPSCO, reached Jim Robo’s prophesied point years ahead of schedule, when it submitted a 5 year resource plan that would take the region from being 65% coal powered in 2018 to just 15% coal powered in 2023, and 0% coal powered in 2028, and replace virtually all of that coal power with a mix of solar, wind, storage, and flexible demand. Bear in mind that NIPSCO is in a region with mediocre sun, pretty good but not amazing wind, and which voted for Donald Trump by 19 points. Admittedly, this is with prices of solar and wind which are still somewhat subsidized in the US. But not tremendously so, as the US federal solar and wind tax credits (the ITC and PTC) are winding down in exactly this same period.
2019: Florida Power and Light: Cheaper to Build New Solar + Storage Than Operate Existing Gas Plants. In March of 2019, Florida Power and Light said it would retire two aging natural gas plants, and replace them with a combination of energy efficiency and the world’s largest (so far) battery, which it will use to charge with solar power during the day to deliver during the evening peak.
CarbonTracker – New Wind and Solar Cheaper than Existing Coal and Gas in the US, China, and India by the mid-2020s. Meanwhile, think tank CarbonTracker has been quietly pumping out reports showing that in country after country, new solar and wind are headed for prices cheaper than the operational cost of existing coal and gas. Consider the following chart (slightly modified by yours truly) of new solar and wind cost in the US vs coal operational cost:
See CarbonTracker’s report on the disruption of Coal in the US for more: No Country for Coal Gen. Or, more importantly, consider what CarbonTracker forecasts for China: That new solar and wind will be cheaper than the operating cost of existing Chinese coal power plants by the 2020s.
McKinsey: New Solar and Wind Cheaper than Existing Coal and Gas… Pretty Much Everywhere by 2030.
Finally, if reports from CarbonTracker, or announcements by actual utilities aren’t enough, consider McKinsey’s assessment from its Global Energy Perspective 2019. In the chart below (with a bit of help from me), McKinsey shows that on almost every continent, and particularly in China and India, where energy demand has the most to grow, new solar and wind are cheaper than existing coal and gas by 2030. And often much sooner.
We’ve gone from Phase 2 to Phase 3 much more rapidly than we went from Phase 1 to Phase 2. Why? Because solar and wind power had to drop by a factor of nearly 10 in price – from 60 cents / kwh for new electricity to roughly 6 cents / kwh for new electricity – to move from their early days to being competitive for new power. But they only have to drop by another factor of 2 or 3 to move from being competitive for new power to being cheaper than the operating cost of existing coal and gas. The “competitive zone” is much narrower and faster to pass through than the long history of subsidized prices leading up to the first fair market competition.
Phase 4 – Slowed by headwinds
Finally, there will in fact be a Phase 4 of renewables, when their penetration has grown so high that they become limited by headwinds of their own creation: Value deflation, where renewables create so much supply at certain hours that they drive down wholesale prices; Depletion of the best sites in some regions; Seasonal intermittency and the unsolved problem of seasonal storage.
But these problems are distant. Renewables will start to encounter them in earnest when solar makes up >20-30% of electricity and when wind makes up >40-50% of electricity. Today, worldwide, solar is only 2% and wind is only perhaps 6% of global electricity. Cheap multi-hour storage will arrive before that (indeed, in the next few years), lowering the price of using solar to meet the evening peak, and of dealing with intermittency on the order of minutes to several hours. Only seasonal storage (and perhaps the political challenges of long-range transmission) seem to be truly difficult problems. And we have time before they begin to impair the growth of renewables.
What the third phase means for renewable growth rate
I’ve said often that renewables have grown exponentially. But the truth is that wind power growth rates around the world have slowed substantially. And solar power, once growing rapidly in Europe, has stagnated there over the last several years (at least, until a recent growth spurt spurred by solar entering Phase 2 in parts of Europe in the last year.)
But growth rates up until now are largely irrelevant. The whole point of growing renewables has been to drive down their cost. The actual amount of solar and wind that policies have deployed up until now is almost immaterially small. It just isn’t enough to matter. What matters is that policies up until now have driven down the cost of solar, wind, and energy storage by more than an order of magnitude.
If those policies – and the fact that renewables are now competitive for new power even without subsidies in the sunny and windy parts of the world – continue for long enough for renewables to drop another factor of 2 or 3 in price – on top of the factor of 10 or more that they’ve fallen already, then we’ll enter a new domain where renewable growth rates aren’t determined by fickle policy. Instead, they’ll be limited only by the pace at which renewables can be deployed – the pace at which factories for solar panels, wind turbines, and batteries can be built; the pace at which labor forces can be trained to deploy them; the pace at which capital can be deployed to pay for their installation.
How fast is that? I have no idea. But there’s good reason to believe that in this second and third phase of renewables, the growth rate will accelerate rather than slowing. We will look back and see that the growth of renewables is an S-curve to be sure. But we may also look back and find that, as of 2019, we had not yet hit the first upward swing in that S-curve.
In a continued effort to reduce Europe’s carbon footprint and to make energy bills cheaper for European consumers, the Commission today adopted new eco-design measures for products such as refrigerators, washing machines, dishwashers and televisions.
mproving the ecodesign of products contributes to implementing the ‘Energy efficiency first’ principle of the EU’s Energy Union priority. For the first time the measures include requirements for repairability and recyclability, contributing to circular economy objectives by improving the life span, maintenance, re-use, upgrade, recyclability and waste handling of appliances.
European Commission Vice-President for Jobs, Growth, Investment and Competitiveness Jyrki Katainen said: “Whether it is by fostering repairability or improving water consumption, intelligent eco-design makes us use our resources more efficiently, bringing clear economic and environmental benefits. Figures speak for themselves: these measures can save European households on average €150 per year and contribute to energy savings equal to annual energy consumption of Denmark by 2030. It is with concrete steps such as these that Europe as a whole is embracing the circular economy to the benefit of citizens, our environment and European businesses.”
European Commissioner for Climate Action and Energy, Miguel Arias Canete said: “Together with smarter energy labels, our eco-design measures can save European consumers a lot of money, as well as help the EU reduce its greenhouse gas emissions. Eco-design is therefore a key element in the fight against climate change and a direct contribution to meeting the goals set in the Paris Agreement. As we move towards our long-term goal of a fully decarbonised EU by 2050, our energy efficiency and eco-design strategy will become ever more important”.
Commenting on the adoption of the measures, Monique Goyens, Director general of BEUC, the European Consumer Association, said: “The new repair requirements will help improve the lifetime of everyday appliances that currently fail too quickly. It is crucial we bin the current ‘throwaway’ trend, which depletes natural resources and empties consumers’ pockets. It is excellent news that consumers’ health will be better protected, thanks to fewer flickering light bulbs and the removal of harmful flame retardants in TV screens. The EU has started with five products that most consumers own at home and we strongly encourage legislators to make more product categories repairable.”
Paolo Falcioni, Director General of APPLiA, the European home industry appliance association, said: “The new, ambitious, ecodesign requirements on improving resource efficiency are a tool to ensure that all actors play by the same rules and advance the Circular Culture concept. Provided that market surveillance authorities could have enough resources and coordination to face new difficulties in verifying the compliance with the law.”
Chloé Fayole (Programme & Strategy Director at the environmental NGO ECOS) commented on behalf of the Coolproducts campaign, led by ECOS (European Environmental Citizens Organization) and the EEB (European Environmental Bureau): “Ecodesign continues to be a European success story, in terms of energy savings and now repairability of products. Giving Europeans the right to repair products they own is common sense, and we therefore welcome the decisions that the EU has made.”
The Commission estimates that these measures, together with the energy labels adopted on 11 March, will deliver 167 TWh of final energy savings per year by 2030. This is equivalent to the annual energy consumption of Denmark and corresponds to a reduction of over 46 million tonnes of CO2 equivalent. These measures can save European households on average Ä150 per year.
These savings come on top of those achieved by the existing eco-design and energy label requirements, which are expected to deliver yearly energy saving of around 150 Mtoe (million tonnes of oil equivalent) by 2020, roughly equivalent to the annual primary energy consumption of Italy.For consumers, this already means an average saving of up to Ä285 per year on their household energy bills.
Following today’s adoption, the texts will be published in the Official Journal of the European Union in the coming weeks and will enter into force 20 days later.
After a consultation process, the Commission has adopted 10 ecodesign implementing Regulations, setting out energy efficiency and other requirements for the following product groups: refrigerators; washing machines; dishwashers; electronic displays (including televisions); light sources and separate control gears; external power supplies; electric motors; refrigerators with a direct sales function (e.g. fridges in supermarkets, vending machines for cold drinks); power transformers; and welding equipment.
The new ecodesign measures explained
What has the Commission adopted?
The Commission adopted 10 ecodesign implementing regulations, setting out energy efficiency and other requirements for the following product groups:
Electronic displays (including televisions)
Light sources and separate control gears
External power suppliers
Refrigerators with a direct sales function (e.g. fridges in supermarkets, vending machines for cold drinks)
Eight of these regulations revise already existing requirements, whereas refrigerators with a direct sales function and welding equipment are regulated for the first time.
What are the overall benefits of the Ecodesign and Energy Labelling Package?
The European Commission estimates that this package of measures will deliver 167 TWh of final energy savings per year by 2030. This is equivalent to the annual energy consumption of Denmark.
These savings correspond to a reduction of over 46.million tonnes of CO2 equivalent.
More importantly, through these measures European households save on average 150 EUR per year.
These savings come on top of the savings achieved by the existing ecodesign measures and energy labels.
How are these measures linked with the new EU energy labels?
Six of the product groups that are subject to new and revised ecodesign requirements, are also covered by new energy labelling rules, i.e. Refrigerators, Washing machines, Dishwashers, Electronic displays (including televisions), Light sources and Refrigerators with a direct sales function.
In particular for consumer products, ecodesign and energy labelling go hand in hand providing European consumers with valuable information and thereby enabling them to make an informed choice and eventually drive the market towards more energy efficient products.
How do these measures help contribute to the circular economy and the protection of the environment?
The Ecodesign Working Plan 2016-2019 identified the potential of ecodesign measures to contribute significantly to circular economy objectives. Preparatory and review studies for product specific measures now systematically consider resource efficiency aspects.
Decisions made at the design phase greatly influence what happens during the use and end-of-life phases, not only in terms of energy consumption, but also in terms of life span, maintenance, repair, reuse, upgrade, recyclability and waste handling.
These measures also bring benefits at macroeconomic level, by reducing Europe’s energy bill through energy savings and by reducing greenhouse gas emissions. In this way, they represent a direct contribution to the implementation of the Paris Agreement.
This set of ecodesign measures is a concrete contribution to our circular economy and climate objectives. In particular, measures are included for the first time under ecodesign to support the reparability and recyclability of products. Moreover, existing requirements on durability (for lighting), water consumption (for dishwashers and washing machines) and marking of chemicals were also revised and adapted as appropriate.
What improvements have been proposed on reparability and durability of appliances?
In order to promote reparability, and therefore to increase the lifespan of appliances, several ecodesign measures aim at facilitating products repair by ensuring the availability of spare parts, in particular that:
– spare parts are available over a long period of time after purchase, e.g.:
• 7 years minimum for refrigerating appliances (10 years for door gaskets);
• 10 years minimum for household washing-machines and household washer-dryers;
• 10 years minimum for household dishwashers (7 years for some parts for which access can be restricted to professional repairers);
• moreover, during that period, the manufacturer shall ensure the delivery of the spare parts within 15 working days.
– spare parts can be replaced with the use of commonly available tools and without permanent damage to the appliance;
In order to enhance the repair market, manufacturers have to ensure the availability of repair and professional maintenance information for professional repairers.
What improvements have been proposed on better water use?
Ecodesign measures for washing machines, washer-dryers, and dishwashers set a maximum use of water per cycle.
At the same time, a minimum of washing efficiency and rinsing effectiveness are required so that the reduction of water use is not achieved to the detriment of washing and rinsing performance.
For household washing machines and household washer-dryers, the impact assessment of the new measures estimates that 711 million m3/year water savings can be achieved by 2030. As for dishwashers, water savings should amount to 16 million m3/year by 2030.
Are other non–EU countries adopting these ecodesign measures?
No. EU ecodesign measures only apply to products placed on the Union market, independently of where they are manufactured. However, many other countries look to the European Union for inspiration when developing their own policies in this area.
What is the legislative framework in place for ecodesign and energy labelling?
In the EU, the Ecodesign Framework Directive sets a framework requiring manufacturers of energy-related products to improve the environmental performance of their products.
The Energy Labelling Framework Regulation complements the ecodesign framework directive by enabling end-consumers to identify the better-performing energy-related products.
The energy label is recognised by 93% of Europeans and 79% have been influenced by it when buying an appliance, according to a recent Eurobarometer survey.
The legislative framework builds upon the combined effect of the two aforementioned pieces of legislation. The ecodesign framework directive and the energy labelling framework regulationare implemented through product-specific implementing and delegated regulations.
As an alternative to the mandatory ecodesign requirements, voluntary agreements or other self-regulation measures can be presented by the industry (see also article 17 of the ecodesign framework directive). If certain criteria are met the Commission formally recognises these voluntary agreements.
How are decisions on ecodesign measures taken?
First, priority product groups are selected based on their potential for cost-effective reduction of greenhouse gas emissions and following a fully transparent process culminating in working plans that outline the priorities for the development of implementing measures.
Secondly, a preparatory study, involving extensive technical discussions with interested stakeholders, is undertaken by an independent consultant.
Thirdly, the Commission’s first drafts of ecodesign and energy labelling measures are submitted for discussion to the Consultation Forum, consisting of Member States’ and other stakeholders’ representatives.
Hereafter, the Commission publishes draft implementing measures.in the WTO notification database.
Once this phase is completed, the two procedures follow different paths. The draft energy labelling delegated acts are discussed in a Member State expert group where opinion(s) are expressed and consensus is sought but no vote is taken. The draft ecodesign measures are submitted for vote to the regulatory committee.
The European Parliament and Council have the right of scrutiny for a period of up to four months is foreseen. If no objection is received, the measures are published in the Official Journal and enter into force.
The founding stone for the great 350 million Euros industrial investment to build a gas plant was set in October by prime minister, Kyriakos Mitsotakis.
During the inaugural ceremony for Mytilineos’s new plant, Mr. Mitsotakis delivered a call to the business world to trust the country once more as an investment destination.
“The project is founded at the beginning of a government that believes in green development and shortly before the new development law’s submission. It is a concrete sample of business trust to the government and proof for our decisiveness to unravel the developmental knot that stops investments”, said the PM and added: “Obstacles are removed, processes are simplified, this country has paid for a long time fixations that demonized private initiative. All that are behind us, we removed capital controls, we reduce heavy taxation, no one will be able to recall insurmountable obstacles, Greece is turned into a land of political stability and incentives, while it is recognized as an investment friendly land”.
“This new investment is compatible to the government’s three central choices, namely the gradual decommissioning of lignite, the liberalization of the energy market through creating new jobs and reducing power tariffs and the reduction of power imports causing economic hemorrhage”, also noted the PM.
He specifically mentioned the government’s plan to withdraw from lignite by 2028, which as he said, is an ambitious target for the country, when others, such as Germany, plan to withdraw by 2038.
As part of that, Mr. Mitsotakis underlined that the national council for energy and the climate is formed, which will produce the transitional program. He noted that especially for the lignite regions of Western Macedonia and Megalopolis there will be a special master plan with balancing benefits and environmental measures.
Ev. Mytilineos: Clean energy investments are a national choice
Mytilineos chairman and CEO, Evangelos Mytilineos delivered the group’s commitment to uphold the government’s effort in order “for the current 20% green energy target to become 35% by 2030”, during his speech in the founding ceremony.
As Mr. Mytilineos said while addressing the PM: “I carefully listened to your speech in the UN climate summit and specifically the new national strategy based on which the share of renewables will reach 35% by 2030 versus 20% today. The target you set is not just ambitious. It is necessary and I applaud you for your decisiveness. This should be our national guideline. This will be our legacy for the next generations”, he said while adding: “I take this chance to declare before you that Mytilineos stands by this national effort. And in its own share, it commits so that its industrial activity will also become green. By the end of 2030, the group’s metallurgical arm, the historic Aluminum of Greece, and other plants abroad will be supplied exclusively by renewables, thus eliminating their environmental industrial footprint”.
Mr. Mytilineos mentioned the group’s collaboration with American General Electric for the equipment of the new gas plant and said that “GE’s modern technology used in this new plant will make it the most efficient in Europe at the moment. At the same time, power production from natural gas with this high an efficiency, will reduce CO2 emissions by 70% compared to conventional lignite plants”.
Rechsteiner: Mytilineos is top class globally
GE Electric Power Europe’s CEO, Michael Rechsteiner, said that Mytilineos’s new plant using H Class technology is among the top class of industries globally. He also noted that the plant is a milestone for GE since it is the 100th gas turbine produced by the company, while he expressed his appreciation to Mr. Mitsotakis and Mr. Mytilineos for their efforts to decarbonize the market.
Benroubi: The new plant is natural evolution
“We hope that the Agios Nikolaos energy center will continue to be even more a climate positive energy pole for Greece and an important economic nucleus for the whole region. The energy center aims to be the heart of our energy system”, noted general director for energy of Mytilineos, Dinos Benroubi and added: “It is the natural evolution of our strategy. Mytilineos is the largest private producer with 1.2 GW of thermal plants and 225 MW of renewables that cover 15% of energy demand. With the new plant, Mytilineos will surpass 2 GW and together with the ever expanding renewables it will contribute to the country’s energy security and exports towards neighboring countries”.
By Anastasios Chrysochoos and Alexandros Lagakos*
LNG’s use in shipping is expected to gather interest from the sector in the next few years for reasons associated to the new fuel requirements as well as the need to reduce emissions.
It should be noted that since the beginning of 2020, there will be a new limit on sulfur content in shipping fuels globally, set at 0.5% compared to 3.5% currently.
The issue concerns 3.5 million bpd, with shipping companies looking into ways of conforming to new requirements and stricter CO2 emissions rules in the near future, whose possible enforcement is already under discussion.
An advantageous choice
LNG is one of the more appropriate and advantageous solutions, since its use brings environmental benefits and fuel cost savings.
Specifically, LNG provides 25% fewer CO2 emissions compared to diesel, 85% fewer NOx emissions and 99% fewer SOx and microparticle emissions.
At the same time, the International Maritime Organization – IMO – has set a very ambitious goal for reducing the rate of “CO2 emissions to shipping work” by 70% until 2050 compared to 2008 with a parallel target of reducing CO2 emissions by 50% within the same timeframe.
Energy analysts consider the repercussions of these initiatives to be significant, since High Sulfur Fuel Oil (HFSO) today represents 80% of shipping fuels and 2 mboe of this fuel are expected to be replaced with cleaner alternatives, such as diesel and Very Low Sulfur Fuel Oil (VLSFO).
The possibility of sparsity
The transition to these fuels may possible create sparsity in the oil market from 2020, with balance returning shortly. At the same time, it is estimated that during 2019-2021 the installation of scrubbers (emission cleaning systems to reduce SOx emissions of ships) will rise.
When it comes to the numbers, around 155 ships are currently using LNG globally and a similar number has been ordered, while many harbors around the world already develop LNG supply infrastructure.
LNG is not expected to uniformly be applied to all types of ships, since this solution’s commercial viability has to coincide with the particular attributes of each ship.
For example, it seems that cruiseships and coastal ships turn towards LNG, since they follow frequent set paths to harbors that have – or will soon have – the necessary supply infrastructure.
At the same time, it is necessary that these ships function with the best possible green footprint, in favor of their clients and in favor of the connecting cities.
We should consider the taken decision by many European cities to “persecute” diesel off their urban space and realize how the image of a cruiseship or any other ship consuming tons of polluting diesel ties to that.
LNG does not only ensure fewer emissions (mentioned previously) but also constitutes a cheaper fuel compared to diesel. Therefore, it is an ideal solution for these ships.
Moreover, for similar reasons, LNG has significant economic and environmental benefits for other types of ships such as tugs, ferries, Ro-Ros and contains ships, even oil tankers under certain conditions.
The case of Russian Sovcomflot is enough, who has already constructed its first Aframax that will operate mainly in the ECA zone in the Baltics and the North Sea.
We should also note that first class container or CMA companies already operate ships with LNG.
In any case, IMO’s goal to reduce the “CO2 emissions to shipping work” ratio requires the use of alternative fuels in the future, such as hydrogen, methane and also electricity. These technologies are currently non competitive, either because of “commercial immaturity” of each technological solution, or because of taking much of the ship’s useful shipping capacity.
When it comes to LNG, concerns are present, since a restricting factor is the possible complexity of converting an older ship or the comparatively higher cost of constructing a new one, as well as methane slip or the dissimilar regulatory framework around the globe. However, the market and technical solutions mature over time. Therefore, offered value for shipping and the environment is obvious and LNG will certainly continue to expand its market share in the global shipping fuel market.
Last but not least, the European banking sector appears interested in “green shipping” with a given financial support by European programs and investing institutions.
In any case, IMO’s target to reduce the ratio of emissions to economic viability of LNG projects in shipping is further advanced by possible synergies from the use of small scale LNG. The Madeira island in Portugal may show the way for our case, since a storage unit supplied by ISO LNG containers, gasifies up to 12,000 c.m. per hour and supplies a small distribution network with a power plant as the main consumer.
In the Greek reality, the promotion of using LNG as a shipping fuel has been included in the Natural Gas Road Map 2017-2022, which is approved by the Governmental Council of Economic Policy (Decree 78/2018).
At the same time, the Poseidon Med II program is fully under way, which immediately concerns the country, since it includes studies for ship conversions or construction, for building infrastructure and for means of supply (bunker/feeder vessels), as well as studies about the regulatory framework and probing synergies that will constitute necessary investment ready for funding.
On its behalf, DEPA has made a step forward by developing a plan to build an LNG vessel of 3,000 c.m. in order to supply the port of Piraeus, as well as other Greek ports. Through the project, which is funded by the EU, DEPA aims to enhance the use of LNG as a shipping fuel in the country.
The vessel, according to DEPA, will be the first of its kind in Greece and the Eastern Mediterranean. The ship will be part of the Poseidon Med II project, as well as the new BlueHUBS project which is jointly forwarded by Greece and Cyprus.
As a result, LNG is still on the radar of shipping companies and necessary infrastructure, supply hubs and regulatory frameworks are globally in development, while the ambition for new, more innovative fuels remains.
After all, the issue is high in IEA’s priorities and the organization hopes to develop the necessary framework for dialogue between interested parties.
An international supply base
What remains is for Greece to take advantage of its place in global shipping, the dynamic of the Piraeus harbor and the national shipbuilding sector, the abilities of the Revythousa LNG terminal, as well as programs such as Poseidon Med II, in order for the country to become immediately a base of supplying LNG ships in the Eastern Mediterranean.
* Anastasios Chrysochoos is a staff member of the Greek energy ministry and doctoral candidate of the AUEB.
Alexandros Lagakos is the founding chairman of the Greek Energy Forum.
The Intergovernmental Agreement for the IGB pipeline (Interconnector Greece-Bulgaria) was signed in October in Sofia, Bulgaria, by the Greek energy and environment minister, Mr. Kostis Chatzidakis and his Bulgarian counterpart, Mrs. Temenuzhka Petkova.
“I am personally connected to the IGB pipeline that will soon connect Greece and Bulgaria, since I commenced the project in 2009 when I was still energy minister. It took as 10 years to reach the signing, but I am glad that once again, through my contribution during the last three months, all remaining obstacles were cleared and we move from theory to action. IGB enhances Greece’s geostrategic importance and supports energy security in the region”, said the Greek minister during the signing ceremony.
Bulgarian minister, Temenuzhka Petkova, said that “this project is vital for the country’s energy strategy and our security of supply with natural gas. The pipeline’s realization is now irreversible”.
What was signed
Afterwards, in presence of the two ministers, followed the signing of a series of deals such as:
– The revised Shareholders Agreement between companies of the ICGB consortium tasked with realizing and operating the project, that is Bulgarian BEH (50%) and IGI Poseidon holding the rest 50%, equally divided between DEPA and Italian Edison.
– Expanding ICGB’s shareholding capital.
– A 110 million Euros loan agreement from EIB.
– The deal to transfer gas with Bulgartransgaz.
Commercial operation in 2021
The first construction contracts were also signed for a total pipeline length of 182km and a total cost of 250 million Euros, running from Komotini (where it will be connected to TAP) through to Stara Zagora, Bulgaria.
Its initial capacity is 3 bcma with the option to expand to 5 bcma. Works are expected to begin immediately and be concluded within 18 months. IGB’s commercial operation is expected in July, 2021.
It should be noted that IGB has been included in the list of Projects of Common Interest (PCI)by the European Commission and its funding has already been approved with an extra 84 million Euros through the EEDR program and EU structural funds.
The intergovernmental agreement is a significant milestone for Greek energy strategy, since it upgrades the country in natural gas transfer from Caspia to Bulgaria and onwards to Serbia, Romania and other countries of Central and Eastern Europe.
The pipeline’s optional upgrade either through additional Caspian quantities or LNG imports, as long as IGB is connected to the planned Alexandroupolis FSRU, is expected to further enhance Greece’s central position in the Southern Corridor’s European strategy.
Other bilateral issues
Furthermore, Mr. Chatzidakis and deputy minister, Mr. Gerasimos Thomas, discussed a series of bilateral energy issues with their Bulgarian counterparts. Among those:
– Coordination of decisions for the Alexandroupolis FSRU.
– Progress in the power interconnection Nea Santa-Maritza.
– Looking into the prospects of greater cooperation between the Greek and the Bulgarian energy exchanges. Mr. Thomas and the exchange’s chairman, Athanasios Savakis, had a separate meeting with the chairman of the Bulgarian stock exchange, as well as the country’s energy exchange.
Xifaras: Investment horizons
DEPA was represented by chairman, Ioannis Papadopoulos, CEO, Constantine Xifaras, coordinator of international activities, trade and supply, Dr. Constantine Karagiannakos and international activities director, Mr. Dimitris Manolis.
DEPA CEO, Constantine Xifaras, said: “The interconnection to Bulgaria is a significant step that creates new prospects in energy security and adequacy of the wider region. Our vision it to contribute decisively to widening our investment horizon and to multiply business opportunities across the range of energy activities, inside and outside of Greece, since it is important to create the requirements for supplying the market safely, competitively and in the long term”.
Apart from the intergovernmental agreement, which sets construction and operation terms by ICGB, as well as other obligations, there was also the signing of:
– The revised shareholders agreement for ICGB by IGI Poseidon chairman and DEPA CEO, Constantine Xifaras, IGI Poseidon CEO, Pierre Vergerio, ICGB’s directors Mrs. Teodora Georgieva and Dr. Constantine Karagiannakos and on behalf of BEH, Mrs. Ina Lazarova.
– The loan agreement between EIB and BEH, as well as the on lending agreement between BEH and ICGB.
– Shipping contracts with natural gas users.
– Supply contract with Corinth Pipeworks for pipes and
– Construction contract with AVAX.
Greece’s role becomes strategic in energy
This is, according to DEPA’s announcement, a project creating new prospects both for DEPA and for the gas market in the wider SE Europe. The project enhances Bulgaria’s energy mix on one hand through a competitive cost and it is also a new field for the Greek gas market, highlighting the strategic role it can play in gas supply for the wider SE Europe.
Through IGB, the gas network of Greece will be connected to Bulgaria’s and other countries as well as indirectly to markets in Central and Eastern Europe (Hungary, Austria, Ukraine).
The project is included in the 3rd PCI list of the European Commission based on regulation 347/2013, while since July 2015 it is included in the priority projects list of Central and South Eastern Europe Gas Connectivity- CESEC. Its funding by the EU as part of the EEDR program has already been approved with 45 million and through structural funds with 39 million.
The pipeline has been designed to operate in two phases. During the first phase, planned to begin on July 1st, 2021, its initial capacity will be 3,0 bcma, of which 2.7 bcma will be offered for long term products and 0.3 bcma for short term.
In a second phase and depending on commercial interest, the pipeline’s capacity will be increased to the total 5 bcma through the addition of a compressor, of which 4.5 bcma will be offered for long term products and 0.5 bcma for short term. A long term product is considered to be over five years, while short term commitments are under one year.
Kelemenis & Co. is a Greek law firm providing quality legal services in key corporate and commercial areas. The firm advises a varied clientele that includes corporations, governments, large institutions and high-net-worth individuals, while it often acts on behalf of international clients in cross border transactions and regulatory matters.
During the last few years, Kelemenis & Co. has distinguished itself for providing services in complex cross border transactions and large trade disputes for corporate clients and funding institutions. The company’s specialization extends to multiple business sectors, among which energy, infrastructure, tourism, transport, health and health tech products, real estate, retail and technology.
According to Legal 500 2019: “Kelemenis & Co.” has acquired an excellent reputation when it comes to advising large companies in renewables, power and hydrocarbons. John Kelemenis has a serious and respected presence in the energy market”.
Internal and external collaborations
Even though its primary space of operations is Greece, Kelemenis & Co. also operates in the wider SE Europe and Middle East region, where it provides legal support both to international bodies as part of their cross border investments and to governments as part of including their law systems in the European acquis.
More specifically, when it comes to the energy market, the company has already gained significant fame both in Greece and in the wider region of SE Europe, where it actively participates in market liberalization and regulation. Its experience concerns both trade transactions and matters of regulatory law. IPTO, LAGIE, General Electric, DEPA, Chevron, Endesa and Statkraft are some of the most significant clients that the company provides services to on a steady basis. When it comes to regulation in the market, Kelemenis & Co. has a great history of collaborations with regulatory bodies and organizations, such as the Secretariat of the Energy Community, the regulatory authorities of Greece (RAE), North Macedonia (ERC) and Egypt (EgyptERA), as well as the governments of Romania, Moldova, North Macedonia and Albania. In 2011, Kelemenis & Co. was selected by the Greek government for composing the bill (law 4001/2011) for integrating the 3rd Energy Package in Greece.
Challenges in the energy market
In a comprehensive interview for “EnergyWorld”, Kelemenis & Co.’s CEO, John Kelemenis, analyzes all crucial issues of the Greek energy market.
“In light of our country’s environmental obligations, there is the challenge of a deeper renewables penetration and much more, the combination of this public goal with the transition of the operation and remuneration of renewables under a market regime. Furthermore, another great challenge is the liberalization of the gas market and the planned operation of a transactions hub (together with upgraded infrastructure, such as new pipelines, Revythousa’s upgrade, the construction of a FSRU in Alexandroupoli, LNG and CNG commercial utilization etc). It is clear that former inefficiencies of the power market must not be manifested here, for example the lack of boldness in creating clear, strict and fully fair terms for all participants. Potentially self-canceling, occasional and politically expedient measures will lead to a lack of long term planning and regulatory instability”, he said about legal and regulatory challenges in the Greek energy market.
Describing the peculiarities of the energy sector where his law firm is specialized, he added that “in order for someone to be useful from a legal perspective, he must have legal adequacy in specific fields (for example, competition or administrative law or law preparatory work), as well as understand the technical aspect of energy. That is not easy. It takes time and commitment that is not shared by all. In other words, the lawyer must exit what the English call his comfort zone”.
He gives special attention to the role of renewables in the decarbonization process, saying that “in this framework it is clear that the transitional fuel is natural gas, which however must be understood that it is an imported commodity. Renewable technologies are going to play a great part”. As for long renewable licensing processes, he adds: “The basic issue is the instability of the renewables regulatory framework and even more the ineffectiveness of bodies created to fast track strategic projects”.
According to Mr. Kelemenis, the energy exchange in Greece will contribute to managing the participants’ risk and realizing a pricing policy with regard to offers in favor of the consumers.
The 3rd Annual International Investment Summit and Exhibition “Hydropower Balkans 2019”, organised by Vostock Capital, received official support of JS Elektroprivreda Srbije.
The Summit was held on 7-8 November in Belgrade, Serbia and united participants from 20 countries! The event featured HPP greenfield and brownfield projects from Serbia, Montenegro, Albania, Republike Srpske, Slovenia, Bulgaria, North Macedonia, Bosnia, Greece.
Among the companies participated in the Summit: JS Elektroprivreda Srbije, European Bank for Reconstruction and Development, Albanian Power Corporation (KESH), Bulgarian Energy Holding, Elektroprivreda Republike Srpske, European Investment Bank, Hidroelektrarne na Spodnji Savi, International Finance Corporation, Power Plants of North Macedonia, Montenegrin Electric Enterprise (EPCG), Hydro Power Plants at Vrbas, PPC S.A., PPC Albania, Holding Slovenske elektrarne, Government of Republic of North Macedonia, EcoEnergy Consulting, Elektroprivreda BiH and many others.
The Summit was sponsored by: ABB Italy, Sevinc Machine Industry and Trade, Emerson Process Management.
Plenary session participants concluded, that electrification and decarbonisation process requires a significant increase of investments in clean generation and storage as well as additional grid and infrastructure investments. Nevertheless, there are political risks and regulatory complexities, social and environmental issues which are considered to be the most significant challenges for developers and investors.
Development plans and prospects as well as the flagship investment projects for new HPPs construction were presented there.
The Round table dedicated to engineering aspects of HPP construction and renovation concluded the first day of the Summit. International engineering companies and equipment suppliers discussed all project details directly with CTOs of operator companies.
The decision-makers of major financial institutions, such as International Finance Corporation, European Bank for Reconstruction and Development, European Investment Bank enlightened the participants on investment opportunities in the regional hydropower industry, challenges for developers and investors and risk mitigation.
This year special attention was paid to small hydropower potential of the Balkans. Two Round tables devoted to Serbia and Bosnia and Herzegovina concluded the Summit.
Besides, specialised technical exhibition took place at the Summit. Industry leaders presented their technical, technological and service solutions for the region: ABB Italy, Sevinc Machine Industry and Trade, Emerson Process Management, Stucky, Tor Services, Zollern, Rakurs Engineering, Polyar Steel Construction, AUMA, Alpiq AG, Tractebel Engineering, AF Сonsult, Landsvirkjun Power.
Over the course of three Summit days, more than 150 business meetings were held, which, of course, became the basis for a long and mutually beneficial future cooperation.
The post Serbia: 3rd Hydropower Balkans Summit held 7-8 November in Belgrade appeared first on EnergyWorld Magazine.
By Anouk Honore – Oxford Institute for Energy Studies
In 2018, the European market(s) represented almost 16 per cent of the global LNG market (GIIGNL 2019 Report). Volumes imported to the region vary greatly from one year to another. This is because Europe is acting as the swing market for LNG.
As a result, the region is expected to help balance the market at times of high Asian demand, as seen after 2011 following the Fukushima disaster, but also help to absorb any LNG surplus coming on to the market, as expected in the 2020s. With regasification terminals only being used at about 28 per cent of their capacity, Europe could import a lot more LNG relying only on its existing infrastructure. But is there a place for LNG in Europe, especially up to 2030?
Europe is not an LNG market per se–it is a market with a demand for gas, which can come in the form of indigenous production, imports via pipelines, or LNG. After a continuous decline between 2010 and 2014, natural gas demand in Europe started to rise again in 2015–17. This was due to a combination of colder than average months in winter (higher energy consumed for heating), economic recovery, and increasing gas deliveries to the power sector because of coal-to-gas switching.
In addition, low hydropower in the south and limited nuclear availability in France created a set of special circumstances, which enhanced the use of gas-fired power plants in the generation mix. With the normalization of these special circumstances and milder temperatures, natural gas demand in Europe (35 countries) declined in 2018 for the first time in three years and reached 536 billion cubic metres (bcm).
Gas and climate change policies
The future place of natural gas in Europe’s energy system will determine the need for imports, including of LNG. But this future faces major uncertainties as a result of climate change policies.
The decarbonization of energy systems is a major part of the European Union’s (EU’s) policy agenda; it is committed to reducing its greenhouse gas (GHG) emissions to 80–95 per cent below 1990 levels by 2050. The decarbonization of the electricity sector through the integration of renewables has been regarded as the first step in a wider strategy. Between 2007 and 2017, the share of renewables grew from 5 to 18 per cent (excluding hydro), with the largest increase in the form of onshore wind and solar. Both are intermittent sources of power generation, and one of the key challenges posed by this rapid evolution was how to integrate a large and growing share of intermittent generation into the power system.
This approach has catalysed disruptions in the traditional structure of the electricity sector, and by extension the role of gas in the electricity mix. While in the past, combined cycle gas turbines (CCGTs) were traditionally run on baseload power, they are increasingly required to provide backup for variable renewable resources. New projects involve smaller and more flexible plants; and as plants that back up renewable plants run for fewer hours, this may also result in lower and more unpredictable gas demand.
Decline of coal
Nonetheless, the role of natural gas in European power generation could increase in the late 2010s and early 2020s, thanks to the expected decline of coal in the generation mix. With tightening legislation on GHG emissions, increasing carbon prices, a ban on subsidies on all coal plants from 2025, and their prospective phase-out at the EU and/or national level, generators will soon have to make decisions about the future their coal plants. Options include retrofitting control technology and continuing to operate within the new limits, applying for derogation (if possible), limiting their operating hours to less than 1,500 annually (the threshold below which emissions limits are less stringent), and shutting down.
All these measures suggest a sharp decline in coal generation in the early to mid 2020s. Of course, not all coal plants will be replaced, and certainly not all by natural gas; but if the closure of a large number of coal plants happens quickly, there may be no time for alternative plants or grid extensions to be built, and gas-fired plants may be called back into the mix at both peak and baseload times.
Nuclear phase-out in Germany by 2022 and in Belgium by 2025, other potential limits placed on existing (or new) nuclear plants, and delays in construction will also provide some opportunities for natural gas, at least until further low-carbon capacities are developed in Europe.
So far, the electricity sector has been the main focus of low-carbon policies; but if Europe is to meet its objectives, decarbonization efforts will need to expand to other sectors, including the heating and cooling sector. This sector is the largest energy user in Europe; in 2015 it represented about 50 per cent of the final energy demand.4 Although the sector is moving towards low-carbon energy, about two-thirds of its energy demand is still met through the direct combustion of fossil fuels, and over 40 per cent from natural gas alone. The main focus of EU decarbonization policies for heating and cooling production so far has been on two main types of measures: energy efficiency and the promotion of renewables (essentially for final energy demand, although some work is also being done on district heating systems). The implementation of low-carbon options faces critical energy challenges with few simple answers, and neither the impacts nor the time frames are likely to be uniform across Europe.
In the building sector, the main options include efficiency improvements (upgrading boilers, developing combined heat and power (CHP) and fuel cells, and switching to more efficient heating systems, all of which could potentially still include natural gas as an input), raising the renewables share (replacing fossil fuels with renewables, installing hybrid systems –which may include gas– and repurposing the gas network for hydrogen), electrifying the heating sector from a zero-carbon electricity supply, and expanding heat networks. Active policies promoting low-carbon options in buildings only started in the early 2010s, and the effects may take time to materialize in the European market, where buildings are old and not energy-efficient.
Nonetheless, some efficiency gains –through thermal refurbishments and minimum energy efficiency requirements for new buildings– may start to lower demand for space heating in the second half of the 2020s.
Reducing carbon emissions in the industrial sector and reaching the 2050 targets will essentially depend on a mix of energy efficiency, electrification of heat (and heat recovery techniques), fuel switching (to biomass or hydrogen as feedstock and/or fuel), and carbon capture utilization and storage (CCU/CCS). The heterogeneity across subsectors and energy uses will be one of the main challenges in designing a framework to decarbonize the sector and some subsectors will be more complex to decarbonize than others. For example, cement, steel, ethylene, and ammonia are characterized by high emissions from feedstock and high-temperature heat processes. Because not all technologies and fuels are capable of achieving high temperatures, fossil fuels, including natural gas, can be more easily displaced by traditional renewable energies for low- temperature applications than for high-temperature applications. As a result, only natural gas used in low-temperature applications (about 48 bcm) could realistically be replaced by low-carbon sources in the 2020s (provided that these can meet both commerciality and acceptability requirements). In addition, energy (including gas) demand in the industrial sector may increase slightly due to favourable economic conditions and fewer options to improve energy efficiency than in the residential sector, especially in energy-intensive industries.
In decarbonized form
To summarize, natural gas demand in the three main sectors which make up about 80 per cent of the European market –power, residential, and industrial– is expected to remain high at least in the first half of the 2020s and maybe up to 2030. Use of gas in the transport sector may also expand if adequate support is provided for public entities and businesses to use LNG and compressed natural gas (CNG) in road and maritime transport to improve air quality, and for the use of LNG as a bunkering fuel in European ports. Important growth rates are expected in this sector, but starting from a very low base, with limited effects on the regional total.
Following on from this, there are several reasons to be carefully optimistic about gas demand in Europe in the next five and maybe even 10 years. It will not return to the strong growth seen in the 2000s, but it is likely to remain fairly high. However, natural gas is a fossil fuel, and efforts will need to be made towards decarbonization (by developing CCS and increasing the production of green gas such as biomethane or hydrogen) sooner rather than later if it is to maintain a share in the energy mix, certainly after 2030 but potentially even before. As part of the EU long-term strategy ‘A Clean Planet for All’, gas will contribute to the decarbonization of the energy sector, but its role in the EU energy mix will increasingly be in its decarbonized form.
There will be a place for LNG in Europe in the 2020s?
In 2018, indigenous production covered about 46 per cent of Europe’s needs, while imports via pipeline accounted for 41 per cent and LNG for 13 per cent.5 One of the main uncertainties concerns the pace and scale of the region’s conventional production decline due to resource depletion and/or political decisions –especially in the Netherlands, where the government decided in March 2018 to phase out production from the giant Groningen field as quickly as possible, and no later than 2030. There are reasons to believe that, if more earthquakes occur like the one in May 2019, production could be reduced even faster than expected. This would alleviate some of the LNG glut in Europe for 2020 and 2021 and help balance the market, but it would then add to the tightening of the market in 2023/2024, when Nord Stream 2 could be needed, depending on Asian LNG demand trends.
After 2025, demand for natural gas (especially unabated gas) may start to soften as a result of decarbonization policies. Nonetheless, indigenous production of biomethane and hydrogen from electrolysis is unlikely to exceed 15–25 bcm by 2030. This will not replace the decline of conventional production which this author’s estimates at about 113 bcm in this timeframe (compared to 2018 in a Europe of 35 countries including Norway). Therefore, gas imports will be the key to meeting regional needs, and Russian gas and LNG are likely to be the main sources competing to provide these. Therefore, the main challenges for LNG in Europe in the 2020s will be the dynamics in other markets, especially in Asia, where LNG can potentially be sold more profitably, and the competition with Russian gas, but Europe will welcome the diversification of gas supply sources and routes provided by a growing and ever more flexible global LNG market.
A major Russian natural gas pipeline that bypasses Ukraine and Poland can finish construction.
Denmark gave permission for a natural gas pipeline from Russia to Germany to pass through waters in its exclusive economic zone, meaning that the project, Nord Stream 2, can be completed despite sharp criticism from the United States, Ukraine and Poland.
With nearly all of its 2,400 km of pipe already laid, Nord Stream 2, wholly owned by Russia’s Gazprom, should be completed roughly on schedule early next year. It is actually a pair of pipelines, complementing a previous pair, Nord Stream 1, and will double capacity to 110 billion cubic meters, or about 3.9 trillion cubic feet.
The pipelines are sensitive geopolitically, because they increase German and European dependence on Russian natural gas while bypassing Ukraine and Poland, cutting off some transit fees for those two economies. Some critics believe that Russia is trying to harm Ukraine’s economy in particular, especially after the 2014 annexation of Crimea and the continuing warfare in eastern Ukraine.
The pipelines have been strongly supported by the Russian and German governments. But Berlin has responded to critics of the project by promising to ensure that Ukraine continues to benefit from gas transit revenue. Europe’s demand for natural gas is increasing even as local supplies from the Netherlands and the North Sea are dwindling.
Sebastian Sass, who represents Nord Stream 2 AG, the pipeline company, before the European Union, argues that Ukrainian vulnerability is exaggerated. He contends that Europe’s need for cheap natural gas, as use of coal and nuclear power shrinks, will increase sufficiently to ensure that Russian gas will continue to travel through Ukrainian pipelines, too.
US President Trump has said the new pipeline “really makes Germany a hostage to Russia,” while Senator Ted Cruz, Republican of Texas, has said it would encourage Russian “military adventurism.” Both men have threatened to impose American economic sanctions, presumably on the companies building the pipelines.
All about Europe’s energy needs
But with construction nearly complete, analysts believe that it would be too late for any sanctions to hinder the project.
American officials say that the pipelines damage Europe’s “energy independence” and that Russia should not be trusted. They argue that some 40 percent of the Russian budget comes from oil and gas production, helping to finance Russian military spending. Gazprom, which is majority owned by the Russian government, also owns 51 percent of Nord Stream 1.
Mr. Trump and American businesses also want to sell more American liquefied natural gas, which is significantly more expensive than Gazprom’s gas, to Europe.
Germany’s minister for economic affairs and energy, Peter Altmaier, has not ruled out importing liquefied natural gas from the United States, but only to supplement Russian gas, and only if the price is right.
Given Germany’s turn away from nuclear power, it already depends more on coal than environmentalists would like. Natural gas produces roughly half the carbon dioxide of coal, so cheap gas is attractive in a country where energy prices are already very high, given big subsidies for renewables like wind and solar. But Germany’s press for the pipelines has undermined European Union solidarity, critics argue.
“Nord Stream is politically sensitive because it fractures Europe strategically between the interests of Germany and the interests of everyone else,” said Kristine Berzina, a senior fellow at the German Marshall Fund in Brussels. “That creates a lot of mistrust and tensions with Poland and Ukraine.”
But even pipeline opponents in Germany, like Norbert Röttgen, the chairman of the German Parliament’s foreign relations committee, believe that it is too late for American sanctions to stop the project.
Even worse, he said, American sanctions “would be a heavy blow to trans-Atlanticists,” who are already defensive about fierce Trump criticism of Chancellor Angela Merkel and her policies, and could set off another chapter in a trade war.
For Mr. Röttgen, a member of Ms. Merkel’s party, the pipelines are already a Russian success. “Russia is driving a wedge between Germany and its eastern neighbors, between Germany and the E.U., and between Germany and the United States,” he said.
In Berlin, asked whether any political obstacles to the project remain, a German government spokesman, Steffen Seibert, said: “We have always said that there is a political dimension to Nord Stream 2, and we have always said that gas transit through Ukraine must have a future.”
He said that Ms. Merkel had discussed the issue with Russian President Vladimir V. Putin, and that Germany continues to support three-way talks between Russia, Ukraine and the European Commission on gas transit.
The paired pipelines of Nord Stream 2 were intended to follow the route under the Baltic Sea of Nord Stream 1, which opened in 2011 and is already at full capacity. But given political pressure, Denmark refused to approve the original route through its territorial waters. Nord Stream 2 withdrew its original application on June 28, after proposing detours around the Danish island of Bornholm.
The detours avoided territorial waters, instead passing through Denmark’s exclusive economic zone, which meant that Copenhagen could deny the application only on environmental, not political, grounds. On Wednesday, more than two and a half years after the original route application, the Danish Energy Agency approved the route southeast of Bornholm, covering a section of 147 km.
Nord Stream 2 is estimated to cost 9.5 billion euros (about $10.5 billion). While Gazprom owns the pipeline, half the financing of the Ä8 billion capital cost comes from five European companies: Uniper and Wintershall of Germany, OMV of Austria, Engie of France and Royal Dutch Shell.
The International Energy Agency (IEA) cut its oil demand forecast yet again, citing the weakening global economy.
In its latest Oil Market Report, the agency predicts that demand will grow by 1 million barrels per day (mb/d) in 2019 and 1.2 mb/d in 2020, both of which are downward revisions by 100,000 bpd from previous estimates. It is the latest in a series of downgrades to demand forecasts, as the weakening economy continues to slow consumption growth. Notably, despite the downgrade, the tone from the IEA still seems relatively upbeat. The agency said that its downgrade for 2019 had more to do with revisions to its 2018 data than anything else, and it sees demand on the upswing, at least relative to earlier this year.
Global oil markets are going through a period of extraordinary change. The United States is increasingly leading the expansion in global oil supplies. Meanwhile, the production of heavier crude grades is hamstrung by sanctions and production restraint in key producing countries. All this contributes to a transformation of global oil supplies, with critical implications for energy security and market balances throughout our forecast period to 2024.
Although the United States had the largest increase in global demand in 2018, growth continues to move away from developed economies and transportation fuels, confirming a shift towards Asia and petrochemicals. These changes will have profound consequences for trade and refining. That sector will also have to adapt to new marine fuel specifications mandated by the International Maritime Organisation, which take effect in 2020, and an impending overhang in refining capacity that will require significant adjustments from refiners globally.
The US leads global supply growth
The United States continues to dominate supply growth in the medium term. Following the unprecedented expansion seen in 2018, when total liquids production increased by a record 2.2 million barrels per day (mb/d), the United States will account for 70% of the increase in global production capacity until 2024, adding a total of 4 mb/d.
Important contributions will also come from other non-OPEC countries, including Brazil, Canada, a resurgent Norway, and newcomer Guyana, which together add another 2.6 mb/d in the next five years. In total, non-OPEC production is set to increase by 6.1 mb/d through to 2024.
Among OPEC countries, only Iraq and the United Arab Emirates have significant plans to increase capacity. These gains have to offset steep losses from Iran and Venezuela, which are subject to sanctions and political or economic turmoil. As a result, OPEC’s effective production capacity falls by 0.4 mb/d by 2024.
The US is also turning
into a major player
As a result of its strong oil production growth, the United States will become a net oil exporter in 2021, as its crude and products exports exceed its imports. Towards the end of forecast, US gross exports will reach 9 mb/d, overtaking Russia and catching up on Saudi Arabia. The transformation of the United States into a major exporter is another consequence of its shale revolution.
Greater US exports to global markets strengthen oil security around the world. Buyers of crude oil, particularly in Asia, where demand is growing fastest, have a wider choice of suppliers. This gives them more operational and trading flexibility, reducing their reliance on traditional, long term supply contracts.
Global trade is not simply a story for the United States. The second-largest increase in crude exports comes from Brazil, which ships an extra 0.8 mb/d of oil by 2024. Following Brazil, Norway is enjoying a renaissance and will overtake Kazakhstan and Kuwait in the next five years a remarkable achievement.
The forecast for supply growth depends on investment. The International Energy Agency (IEA) has argued for many years that with the demand for oil increasing for the foreseeable future, continued investment is necessary to ensure adequate spare production capacity. Our analysis last year looked at the rates of decline in oil fields and found that to keep production steady, the equivalent of the output from the North Sea needed to be offset each year.
This remains true today. It is therefore reassuring that 2019 upstream investment is set to rise for the third straight year, according to preliminary plans announced by key oil and gas companies. For the first time since the 2015 downturn, investment in conventional assets could increase faster than for the shale industry. While US production growth has exceeded expectations, we cannot be complacent about investment levels towards the end of our forecast period and beyond.
Oil demand growth eases
in the next five years
Fundamentally, oil demand depends on the strength of the global economy. Recently, the International Monetary Fund (IMF) downgraded its short-term outlook, reflecting weaker economic sentiment in many countries. Ongoing trade disputes between major powers and a disorderly Brexit could lead to a reduction in the rate of growth of international trade and oil demand. But while the economic mood is not encouraging, we expect oil demand to grow in our forecast, although at a more measured pace.
A key factor underpinning demand growth is that leading developing economies will continue to expand. China and India will account for 44% of the 7.1 mb/d growth in global demand expected to 2024. Despite its recent slowdown, China’s GDP has more than doubled in real terms in the past decade and is still growing at a healthy clip. Income levels have grown sharply and the structure of oil demand is moving away from heavy industrial sectors towards consumer needs. As for India, while its GDP per capita is still only a fifth of China’s, it is growing more strongly: By 2024, India’s oil demand growth will match China.
Petrochemicals & jet fuel are stalwarts of demand growth
Around the world, more consumer demand means more plastic, which in turn means more petrochemicals. Despite efforts to curb plastics use and encourage recycling, demand for plastics and petrochemicals is growing strongly. Led by the United States and China, we have identified more than 50 major projects due to come onstream through 2024. These are expected to add 2.2 mb/d in oil consumption over the forecast period, accounting for 30% of global growth.
This supports expansions in the early part of our forecast at a rate close to today’s level. While the lack of complete visibility on new projects causes our estimate to fall towards the end of the forecast period, it is highly possible that more projects will be announced and that demand could be higher than currently anticipated.
The other major growth sector is aviation. In recent years, the air travel industry has witnessed a spectacular expansion thanks to rising passenger numbers. Demand will continue to grow strongly, supported by rising incomes in developing countries, more airports being built and growing airline fleets. Asia accounts for 75% of this increase over our forecast period. In absolute terms, while China sees the largest jump in demand, India posts the fastest rate of growth, at an impressive 8.2% a year.
At the same time, efficiency improvements and fast-expanding markets reaching maturity will tamper the increase in the global jet fuel market, according to our forecast. As for gasoline, ongoing efficiency improvements will cause the global rate of growth to slow to less than 1% per year. In developing countries, however, the rate is twice as high, as rising income levels lead to more vehicles on the road.
The IMO regulations
The 2020 IMO marine regulation change is one of the most dramatic ever seen to product specifications, although the shipping and refining industries have had several years notice. We believe that industry players are in a strong position to adjust in the medium term, with the largest incremental volumes coming from the United States, the Middle East, and China. Still, the market will initially be tight and there will be some non-compliance. Orders for scrubbers to be fitted on ships have increased, and our analysis of refiners’ plans suggests that, as demand for high sulphur fuel oil plummets, there will be enough availability of marine gasoil and, in time, a new ultra-low sulphur fuel oil to plug the gap.
Prices for gasoil could rise at first as demand from the marine sector increases, but sluggish growth from inland sources of demand will limit the pressure. Meanwhile, unwanted high sulphur fuel oil could find a home in the power sector, with the Middle East a likely market.
Refiners face twin challenges
The refining industry is facing a wave of new capacity additions in the period to 2024, with a net growth of about 9 mb/d. China will overtake the United States to become the global leader in installed capacity. Given that these new additions far exceed the increase in demand for refined products, plant closures might be necessary to rebalance the market, though questions remain as to where and when that will happen.
While the global average crude oil barrel produced remains predominantly a medium gravity sour grade, the availability of heavier crude from several countries is in doubt due to production cutbacks and geopolitical challenges. At the same time, the average global product barrel is getting lighter as fuel oil demand falls and petrochemicals grow in importance. As a result, the United States will be in prime position as a supplier of light types of crude oil that are in growing demand. Shale oil will also help meet the new IMO requirements and provide the quantities of naphtha required for the petrochemicals industry.
Radu Dudau, EPG Director
One of the major present challenges of Romania’s energy sector is the crisis faced by the coal-fired power generation plants, caused by their inability to cope with the high prices of ETS certificates. Meanwhile, the Romanian government does not have a coherent strategy for managing the short- and long-term consequences of this crisis.
With about 5 GW of installed capacity, the country’s lignite and hard coal power generators account for more than a third of the average yearly electricity production. The National Electricity Dispatcher uses 1,600-2,000 MW of lignite-fired power generation to cover the load curve. Out of Romania’s total power generation of ca. 60 TWh, coal-fueled power covers 25%. Both the Oltenia Energy Complex (OEC), the lignite company, and the Hunedoara Energy Complex (HEC), the hard coal one, integrate mining activities and thermal generation of power and heat.
However, over the past two years, the price hike of the CO2 certificates under the EU ETS trading scheme – called EU Allowances, EUAs – has imposed an unbearable financial burden on the two state-owned coal companies. In early September 2019, the EUA price was ca. Ä26, down from Ä29 in mid-July – a level that was never reached since soon after the introduction of the EU ETS system in 2008. For the better part of the 2010s, the EUA price hovered between Ä4 and Ä6. To recollect, the recent price hike was mainly triggered by the recent reform of the ETS market, agreed upon in November 2017, with the introduction of the Market Stability Reserve, which resulted in a tightened balance of supply and demand.
The current price trend on the ETS market has greatly accelerated the anticipated demise of the coal-based power generation sector in Romania and, indeed, the entire Southeast European region. In 2018, OEC booked a loss of Lei 1.1 bn, mainly because of its obligation to acquire CO2 allowances, as well as the higher costs of serving its debt, on account of a worsening exchange rate of the Leu against the Euro. OEC had to buy ca. 13 million EUAs until May 1, 2019 at a total cost of Lei 1.4 bn, which came down to 40% of downturn. To this purpose, in April 2019 it took a loan of Lei 500 million.
For its part, HEC is on the brink of insolvency. In fact, the company did declare insolvency in January 2016, following several filings by businesses whose services and goods it stopped paying. In November 2016, though, the Hunedoara Tribunal annulled the decision by a lower court to open insolvency. Subsequent fillings by HEC have been turned down. At present, the company’s assets are under the sequester of the National Agency for Fiscal Administration or serve as collateral for the state guarantees given by the Finance Ministry for a state aid that the European Commission deemed illegal in June 2015.
The latter is indicative of the degree to which the EU restrictions on state aid have been affecting the economic viability of the national coal companies by choking off the traditional subsidy channels. In November 2018, the European Commission found that HEC “received around Ä60 million of incompatible State aid from Romania through four publicly financed loans. The state now needs to recover the illegal aid plus interest.” The loan referred to was granted to HEC by the government in April 2015 with the European Commission’s approval of a state aid, according to the EU rules for temporary rescue, and was supposed to be paid back in six months. The Energy Ministry submitted a restructuring plan on the company’s long-term viability. However, HEC was unable to repay the loan, while the Commission concluded that the restructuring plan could not ensure the company’s long-term economic viability without continued state aid.
Nevertheless, continuing state aid to the coal sector is exactly what the government plans to do. In a statement by the Energy Ministry in February 2018, HEC’s Plan of development of mining and energy production activities up to 2030 was assumed to depend on continued state subsidies: “To continue activities in safety conditions, investment of Lei 168,213,000 is necessary for 2014-2024, from the state budget.” In a separate instance, in April 2019, a State Secretary of the Energy Ministry said the ministry would notify a support scheme for OEC to the European Commission by which the state would cover the EUAs costs “that the market sales cannot internalize.” This approach shows, to say the least, a poor understanding of how the EU ETS system works.
The government does not actually have a clear-cut coal phase-out strategy. In effect, since the beginning of 2017, repeated commitments were issued by the Energy Ministry about continuing coal mining and investment in lignite-based power generation assets. The paper of the Energy Strategy 2019-2030, published in October 2018, emphasizes the role of lignite in ensuring grid stability and energy security by 2030 and beyond. One of the strategy’s main investment objectives is an improbable new 600 MW supercritical lignite-fired plant in Rovinari.
As a matter of fact, though, it should have been obvious that any such plans were futile, because both of the regulatory framework and the market environment. For one thing, a bunch of stringent new EU regulations are creating a forbidding investment and operating environment for the coal-fired plants: a limit of 550g CO2/kWh for power generation units admissible on the capacity markets as of 2025, while the typical lignite-fired coal plant emits in excess of 1000 g CO2/kWh; new, restrictive BAT/BREF limits on NOx, SO2 and particulate emissions from Large Combustion Plants, that must be complied with by the end of 2020, but which are being largely exceeded by the lignite plants in Romania. Add the almost full curtailment of EU finances for coal investment – except for the Modernisation Fund which, for Romania and Bulgaria alone, allows investment in the refurbishment of existing coal plants used for district heating.
The economic conditions of the clean energy transition are making the coal industry’s long-term survival virtually impossible. As shown in a Carbon Tracker Initiative report of 2018, considering the learning curve of the renewable energy technologies, by 2025, the new wind and solar capacities will be significantly cheaper than new coal-fueled units in terms of capital and operational, and by 2030 the new renewable energy sources (RES) will be cheaper than the operational costs of the existing coal plants. Some studies point out that Romania’s coal regions have a solar PV potential of 2,000 to 5,000 GWh/year, and a sizeable wind energy potential of 5,000 to 10,000 GWh/year.
But the Romanian energy system needs a solution to the crisis of its coal power generators way sooner than the moment in time when the share of RES will be large enough and sufficiently well integrated to ensure security of electricity supply. True, Romania must start scaling up its RES capacities – beginning by creating a friendly regulatory environment, which does not deny PPAs to RES investors – and, in the process, take all the measures to ensure grid adequacy. But the lead time to achieve the necessary level of capacity, as well as the lead time of any of the “projects of national interest” in the energy strategy – two new 700 MW nuclear reactors at Cernavoda, a 1,000 MW pumped storage hydro power plant at Tarnita, and a vaguely defined “hydro-energy complex” at Turnu Magurele – are at least a decade-long, not to mention the uncertain prospects of the said “projects of national interest”.
It should be clear, against this background, that Romania needs a substantive phase-out plan for the coal-fired power generation that offers the quickest possible solution able to ensure grid stability and security of supply while also complying with the country’s EU energy and climate targets of greenhouse gas emissions reductions, RES share in the final energy consumption, and improvements in energy efficiency. The solution, at the same time, must be cost effective and aligned with EU’s long-term strategy of reaching net zero carbon emissions by 2050.
Compelled by the facts, the government has grasped that, for practical purposes, the short-term action at hand is to replace some of the oldest lignite plants with new, natural gas turbines. And indeed, the construction of several new gas plants was announced over the past year:
• A 400 MW CCGT unit at HEC’s Mintia (Deva), to be built by Romgaz by 2022;
• A 200 MW CCGT unit at OEC’s CET Craiova 2, to be built by 2024;
• A 300 MW CCGT at OEC’s Isalnita, to replace one existent lignite group, to be built by 2025;
• A 330 MW at OEC’s Turceni, to replace one of the existent lignite group, to be built by 2025.
All these planned constructions come on top of the already progressing construction of a 430 MW CCGT at Romgaz’s Iernut, due to be commissioned in 2020, as well as a smaller-scale 73 MW cogeneration unit at Rompetrol’s Midia plant in Navodari. There is also word about a new 50 MW gas turbine at CET Titan, in Bucharest, as well as other private projects for gas units. All in all, one is likely to see ca. 2,000 MW worth of new gas-fired power generation in Romania by 2025.
Ironically though, the change of heart at the Energy Ministry from coal to natural gas has happened just as the Romanian government introduced legislation that has clearly discouraged the development of new gas fields in Romania, such as the 2018’s Offshore Law, which apparently put off ExxonMobil and OMV Petrom, the investors in the Black Sea’s main gas field, and even more so the GEO 114/2018, which effectively suspended for three years the liberalization of the Romanian gas market. Meanwhile, Exxon is reported to be seeking exit from the Neptun Deep project, which by itself may lead to a fateful delay in the development of the country’s Black Sea gas finds.
These blatant instances of misgovernance occurred on a slow yet steady trend of diminishing gas production in Romania – 4-5% yearly. The consequence is that an increasing gas consumption in the next few years could only be met by growing gas imports, which are consistently more expensive than Romanian gas production. This, in turn, is likely to impact the profitability of those new gas units, especially considering that they too will have to acquire expensive EUAs – albeit less than half per MWh than the coal plants.
Getting a grasp of how the energy markets are going to evolve in the next ten years in such a dense environment of climate and environmental regulations and considering the profound changes in terms of technology costs is paramount for the member states’ ability to manage energy systems that are decarbonizing, while being stable and well-provided. In any event, the National Energy and Climate Plans (NECPs) of the East and Southeast European member states, due to be submitted in final form by the end of 2019, ought to offer a path forward that includes both a short-term solution to the challenge of coal-fired power generation, and a long-term trajectory towards decarbonization.
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Greece and China in Athens Monday signed 16 agreements in sectors including energy, agriculture, tourism and ports.
Chinese President Xi Jinping is on an official visit to Greece for follow-up meetings with Greek officials, after Premier Kyriakos Mitsotakis visited China last week. At that time, the leaders said they wanted to expand relations between two of the world’s oldest civilizations.
China and Greece “are natural partners” for the creation of the one belt, one road initiative, Xi said after meeting with Mitsotakis. The two countries will cooperate in many sectors and “we want to strengthen the transit role of Piraeus Port to expand bilateral trade and to invest in energy, transportation and the banking sector.”
Chinese tourists gathered in Athens’ central Syntagma Square, clutching small flags from both countries as Xi laid a wreath at the tomb of the unknown soldier.
“We’re opening a road that will soon become a freeway as our cooperation will be significantly enforced,” Mitsotakis said. The common goal of both countries is for half a million Chinese tourists to visit Greece in 2021, he said.
An agreement in agriculture will see the export to China of Greek kiwi fruit as well as saffron from Kozani, a move that will boost the local economy of the small northern Greek town. In the energy sector, the State Grid Cooperation of China officially expressed interest in a tender for linking the island of Crete to the mainland’s power network while a separate deal was signed for Chinese participation in the 50-megawatt Minos solar project in Crete.Port deal
Xi and Mitsotakis will visit together later Monday Cosco’s Piraeus Port container terminal operations, the largest Chinese investment in Greece to date.
The Greek government recently approved Cosco’s 612 million-euro ($675 million) plan for the port. That will see the expansion of the cruise terminal, a new passenger terminal and a logistics zone. One of the agreements Monday was for the Greek and Chinese sides to work to overcome any obstacles to implementation of the investment.
The European Investment Bank is lending Cosco 140 million euros to partially finance the project with guarantees from the Export-Import Bank of China. Chinese lenders including Bank of China and Industrial and Commercial Bank of China are also expected to contribute. A Bank of China branch started operating in Athens on Nov. 1. and ICBC is establishing an office.
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Imagine waking up in your posh high-rise penthouse facing the Red Sea. Above the bustling city hangs a giant artificial moon that livestreams images from outer space. You call for an automated flying taxi, and it carries you to your job genetically modifying humans to make them stronger. When you return home in the evening, you find that robot maids have made a thorough cleaning of the place. Later, you decide to step out for the night at one of the city’s many five Michelin star restaurants, followed by a visit to the robot dinosaur park.
Sound like science fiction? Maybe. But believe it or not, this is the future envisioned by Saudi Arabia’s crown prince, Mohammad bin Salman Al-Saud. Everything I described above is lifted directly from his plans for a brand new city.
This “land of the future,” called Neom, is to be built on a Massachusetts-size area of barren desert along the Saudi kingdom’s northwest coastline. Its goal is not only to attract “the world’s greatest minds and best talents,” but also to lure international tourists and luxury travelers.
As ambitious (crazy?) as bin Salman’s plan sounds, it’s already moving forward. Bloomberg reports that the kingdom has awarded two Saudi construction firms with contracts to begin building housing for workers.
Altogether, the cost to bring Neom to fruition will run an estimated $500 billion—which has some investors sweating. This year the oil-rich kingdom’s budget deficit has widened further to around 7 percent of its gross domestic product (GDP), according to the International Monetary Fund (IMF).
So where does bin Salman, also known as MBS, expect to come up with this cash?
Do I even need to say it?Saudi Aramco, World’s Most Profitable Company, Going Public at Long Last
It may be no coincidence that at the same time that construction starts on Neom, Saudi Arabia is finally set to sell shares of its national oil company, Saudi Aramco. Coincidence or not, the timing is interesting.
Early last week, the kingdom’s Capital Market Authority announced that, after years of speculation, Aramco will at long last begin trading on the Saudi Stock Exchange, or Tadawul, sometime next month. The energy giant is the world’s most profitable company—in 2018 it generated a mind-boggling $111 billion in net income and some $86 billion in free cash flow. And with a valuation of between $1 trillion and $2 trillion, it’s worth more than the entire $550 billion Saudi equity market.
In fact, at the low end of that valuation, Aramco “will still be worth more than all Brazilian stocks, and the top valuation would make it worth more than Korean, Australian, Swiss or German stocks,” writes the Wall Street Journal’s James Mackintosh.
He adds: “This is an asset class all on its own.”
Indeed, there’s a lot that, on the surface, is enticing about Aramco as an investment. Consider the dividends alone. According to the summary prospectus, Aramco intends to pay out an incredible $75 billion in cash dividends next year. Not only does that amount to a potential 5 percent yield per share, but it’s almost 30 times more than the $2.6 billion Apple distributed to investors in 2018.
As for production, it has the world’s largest oil reserves for any one company, and its cost for extracting the stuff is a low, low $2.80 per barrel, far less than any of its rivals.
The IPO also comes just a few months after Saudi Arabian stocks were finally included on the MSCI Emerging Markets Index, giving a greater number of global investors exposure to the oil-rich kingdom.But Should You Invest?
Despite all this, Aramco may have a hard time convincing foreign investors to look past some of the significant drawbacks.
For one, shares will only be available to buy on the Tadawul in Riyadh—for now, anyway. Second, the public float will be in the neighborhood of 2 percent of shares, making this a relatively small public debut for such a massive company. Depending on the company’s final valuation, and depending on the percent of shares it ends up listing, Aramco could end up making between $30 billion and $51 billion in this round of fundraising. That’s according to estimates by Ellen R. Wald, author of the 2018 bestseller Saudi, Inc.: The Arabian Kingdom’s Pursuit of Profit and Power.
The rest of the shares will be owned, of course, by the crown prince and the House of Saud. This is an absolute monarchy we’re talking about, after all, and so global investors should not expect to have any shareholder rights. Aramco’s board of directors will have a fiduciary duty not to investors but to MBS and any future monarch. This has some serious implications.
In the past, the monarchy has used Aramco as a piggy bank, dipping into its vast coffers to finance any number of pursuits and projects. As Ellen Wald puts it in a recent New York Times op-ed:
“The money raised from the Aramco IPO, and any subsequent offerings, will not go to the company. It will go to Saudi Arabia—to the king and his government. And every subsequent purchase of Aramco shares will raise the value of the company just a little, further enriching the king.”
And getting him closer to realizing the futuristic city of Neom.OPEC Cuts on Deck While U.S. Shale Could Be Headed for a “Major Slowdown”
According to reports, Aramco’s growth assumptions and basis for such a generous dividend package are predicated on Brent crude prices at or above $65 a barrel, a level last seen in September. The average price for a barrel of oil for the three-year period through November 8 is just shy of $63.
In an attempt to prop up prices before its IPO, Aramco has been making production cuts for the better part of a year, and at next month’s OPEC meeting, Saudi Arabia is expected to push for additional cuts from fellow oil-exporting members. Output could collectively be lowered by some 1.2 million barrels a day.
Meanwhile, U.S. shale production has only continued to rise thanks to advances in fracking technology, helping to keep global crude prices in check. In August, the most recent month of data, American producers pumped out a record 12.4 million barrels a day, an amazing 128 percent increase from a decade earlier. Last year, the U.S. industry was producing an extra 2 million barrels a day compared to 2017.
That explosive growth, however, could be headed for a “major slowdown,” according to a new report by IHS Markit, the same people who put out the monthly purchasing manager’s index (PMI). Shale production growth next year will be only 440,000 barrels a day, the group says, down significantly from 2 million barrels a day. Output will slow even more before “essentially flattening out in 2021.”
Says IHS Markit’s Raoul LeBlanc, this slowdown could be coming due to lower oil prices and more challenging access to capital markets. (Important here to recall Norway’s complete divestiture from fossil fuel equities, not to mention the general rise of ESG investing—or “environmental, social and corporate governance”—which rules out fossil fuel companies.)
“The combination of closed capital markets and weak prices are pulling cash out of the system,” LeBlanc comments. “Investors are imposing capital discipline on exploration and production (E&P) companies by pushing down equity prices and pushing up the cost of capital on debt markets.”
This is both good and bad news for Aramco. Oil prices could surge above $65 with even more product coming offline, but at the same time, the company could run into challenges attracting investors.
Bulgaria joins the common European electricity market, the Electricity System Operator announced. Together with Croatia, the Czech Republic, Hungary, Poland, Romania and Slovenia, Bulgaria will now be involved in unifying the electricity markets.
So far, there were 14 European countries involved in the union. The first deliveries are planned for November 20 this year. An integrated market will increase competition and make more efficient use of electricity generation resources in Europe.
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Iranian President Hassan Rouhani said a new big oilfield has been discovered in Khuzestan province in southwestern Iran. “We have discovered a new big oilfield with 53 billion barrels of reserves,” Rouhani said in a speech cited by the official IRNA news agency.
The Iranian leader said the oilfield has extended from Bostan district to Omidieh with the capacity of 53 billion barrels. Rouhani said the U.S. should realize that Iran is a rich country.
“Despite animosity and cruel sanctions, Iranian workers and engineers discovered a new oilfield,” he said. The new discovery would mean that Iran’s proven crude oil reserves would be boosted by a third. Right now, Iran says it has some 150 billion barrels of proven crude oil reserves.
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Cyprus on Thursday granted the first hydrocarbon exploitation licence to the consortium that owns the Aphrodite concession, with a view to pipe gas to Egypt and export it in the form of LNG.
The licence, granted to Noble Energy, Shell, and Delek, is for 25 years.
It is based on a development and production plan agreed between the government and the companies.
The plan provides for the gas to be carried to an Egyptian liquefaction facility via an underwater pipeline and exported to Europe and elsewhere in the form of LNG.
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