A group backed by anonymous donors launched a campaign on Monday to promote the benefits of cheap, abundant natural gas against what it called “radical” proposals like the Green New Deal that would phase out use of the fossil fuel.
The Empowerment Alliance, or TEA, will fund advertising and research to advocate the use of natural gas, which burns cleaner than coal, in the runup to the U.S. presidential election in November of 2020, Terry Holt, a spokesman for the group, said on Monday.
Most of Republican President Donald Trump’s challengers for the White House are pursuing aggressive policies to fight climate change.
The nonprofit group would not disclose its donors, saying they prefer to remain anonymous because of fears they will be harassed by environmental activists. The group also declined to comment on its budget.
Holt said, however, he expected his group’s budget would be smaller than those of anti-fossil fuel organizations funded by billionaire activists like former New York City Mayor Michael Bloomberg and Democratic presidential hopeful Tom Steyer that advocate for a transition away from gas, oil and coal due to their impact on climate change.
TEA’s launch comes as environmentalists and some Democratic presidential candidates have called for urgent measures to reduce the nation’s reliance on natural gas, and move more quickly to renewable resources like solar and wind power. Several U.S. cities and states are also looking into ways of curbing natural gas consumption.
The Green New Deal, a nonbinding resolution introduced by two Democrats in the U.S. Congress earlier this year, calls for a 10-year, government-driven effort for the United States to move away from carbon-emitting fossil fuels through investments in clean energy.
The resolution has become a political target of Republicans who call the plan radical and too expensive.
In its statement, TEA said such a policy would devastate the U.S. economy. Natural gas plants, the group argued, save consumers money and are helping to lower carbon emissions by replacing dirtier coal-fired generators.
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The Republic of Moldova could become a sticking point in negotiations between Ukraine and Russia over the signing of a new transit contract as the country is bracing for a major supply crisis from 1 January 2020.
Speaking to ICIS, regional and EU sources said the former Soviet state had no access to alternative sources of supply or stored gas, being entirely reliant on volumes imported from Russia via Ukraine.
Ukraine is pushing to sign a long-term transit contract with Gazprom based on EU law so that capacity at all its interconnection points in the east and in the west is offered for third party access after the existing legacy transit contract with Gazprom expires on 31 December 2019.
It is working to unbundle the transmission operations of Naftogaz and has ramped up efforts to store over 20 billion cubic metres (bcm) of gas ahead of winter to minimise any risk of gas shortages that could occur if Russia’s Gazprom decides to curtail supplies should there be no transit agreement.
However, it could come under pressure from Russia as well as the Energy Community, an EU institution working with non-EU states such as Moldova, to make concessions in ongoing negotiations.
“They [Moldova] have no storage, no money, no interconnection agreement, no contracts with alternative suppliers,” a source close to negotiations told ICIS.
“They need some 1.6bcm of gas for the first quarter [of 2020]. Both heating and electricity are gas-based. […] This is as crazy as the situation in Ukraine in 2014 [before the Maidan revolution].” the source explained.
The Romanian connection
Moldova reportedly has an annual supply contract with Gazprom, although this has not been confirmed. The country consumes an estimated 3bcm of gas annually, of which 1bcm is needed in Moldova itself and 2bcm are consumed in the adjacent breakaway republic of Transnistria. The region is considered by the UN to be part of Moldova.
Most of its electricity generation and heating comes from natural gas.
Historically, it has been supplied by Gazprom via the Trans-Balkan pipeline which crosses Ukraine, its territory, Romania and Bulgaria before heading east into Turkey and southwest into Greece and Northern Macedonia. Its own transit contract with Gazprom for the Trans-Balkan pipeline also expires on 31 December 2019.
Although Transgaz, the transmission system operator of Romania has been expected to complete a key piece of infrastructure to transport Romanian gas to the Moldovan market , this project is likely to be delayed until at least the second half of 2020. This is because Transgaz through its Moldovan company, Vestmoldtransgaz, cancelled a tender for the construction of a segment along the Iasi-Ungheni-Chisinau corridor.
Romania already has a 1.5bcm interconnector between Iasi and Ungheni in Moldova. However, as consumption is concentrated in Chisinau, Transgaz, as the operator of the interconnector needs to build an extension to link it to the Moldovan capital.
Nevertheless, speaking to ICIS, Sergiu Ciobanu, former head of the Moldovan regulator ANRE and currently a regional consultant, said it was a “fantasy” to think that Romanian supplies could be made available on the Iasi-Ungheni-Chisinau line from 2020.
The Ukrainian transmission system operator, Ukrtransgaz, has reached out to Moldova , offering to store gas for it and deliver it this winter.
However, the situation is complicated by two factors.
Firstly, the Moldovan vertically-integrated incumbent, Moldovagaz is majority-owned by Gazprom. The country, as a contracting member of the Energy Community is under pressure to unbundle its transmission operations and establish an independent grid operator from 1 January 2020. This entity would have to sign an interconnection agreement with Ukraine for any future supplies from that date onwards.
An EU source told ICIS that Gazprom may condition the separation of the transmission operations on the new Moldovan operator paying for a stretch of 247km transit pipelines which are included in the Trans-Balkan corridor.
The overall nameplate transit capacity crossing Moldova is 34.6bcm/year. This includes a 20bcm/year pipeline and two other lines with a 7.3bcm/year capacity each, according to Ciobanu.
The EU source said Moldova, one of Europe’s poorest states, would simply struggle to pay off the transmission assets to ensure it abides by the 1 January unbundling calendar set by the Energy Community.
As a result, Moldova may miss the deadline, raising questions about the operator that will be asked to sign an interconnection agreement with Ukraine and possibly a new transit contract for the delivery of gas to southern Europe and Turkey.
Secondly, since Moldovagaz is majority-owned by Gazprom, the Russian producer may frown on any competing companies such as Ukraine’s Ukrtransgaz selling volumes into Moldova.
An important factor that could sway negotiations would be price.
According to local press reports quoted by Ciobanu, the Russian gas price to Moldova is expected to drop from $241.6/kscm (€20.08/MWh) in Q4 ’19 to an estimated $223.00/kscm (€19.30/MWh) in the final quarter of 2020.
Even with the reduction, the expected Q4 ’19 Gazprom price to Moldova is still likely to be more expensive than the closest Austrian VTP Q4 ’19 price, which was assessed by ICIS on Friday at €16.23/MWh. The Ukrainian October ’19 VTP price was assessed by ICIS at €14.31/MWh.
Ciobanu said Gazprom may reduce the price by another $40.00/kscm for the first quarter of 2020, although he insisted that forecasting the price was notoriously difficult.
If granted, the discounted Gazprom Q1 ’20 price to Moldova would be $183.00/kscm (€15.73/MWh), placing it at an estimated €3.60/MWh discount to the Austrian VTP equivalent assessed by ICIS.
However, Ciobanu said: “Forecasting the gas price to Moldova depends on economic and political factors. While the economic factor may be inferred from a contractual annual formula, the political factor remains an enigma.
“One thing is certain, the final price will depend on discussions between the Russian Federation and Ukraine related to transit from 1 January 2020 as well as the political context in Chisinau. In fact, we [Moldova] pay a political price for natural gas,” Ciobanu said.
Gazprom did not respond to questions from ICIS by publication time.
The market specialist said there were several scenarios that were being considered by Moldovan authorities for this winter.
In a status quo scenario, Ukraine and Russia would conclude a new transit agreement and volumes would be delivered from Russia to Moldova via Ukraine, as is currently the case.
In a second scenario, the delivery point would be moved from the Ukrainian-Moldovan border to the Ukrainian-Russian border and Moldovan suppliers would off-take volumes directly from there.
In a third scenario, Moldova would be buying gas from Ukraine’s storage.
“Ukraine is ready to offer gas from storage and this could be a temporary solution” he said.
Much, however, will depend on what will be discussed during Ukraine-Russian transit talks which are due to resume in October.
The post ICIS: Moldova’s gas supply may impact Ukraine-Russia transit talks appeared first on EnergyWorld Magazine.
Romania’s Government will have to merge the lignite power plants of CE Oltenia and the hard coal plants of CE Hunedoara with hydropower group Hidroelectrica, unless the European Commission approves the state aid envisaged for CE Oltenia, which is on the verge of insolvency since it can’t pay for the CO2 emission certificates related to last year’s power production, Economica.net reported.
Upon the merger, the resulted entity would supply some 50% of the country’s electricity.
The idea was mentioned by state secretary Doru Visan, who heads the Energy Ministry in the absence of a proper minister. He thus confirmed rumors circulated by media over the weekend.
Consolidating the power generation sector is a long-term goal, but it won’t be pursued if the EC approves the recovery plan for CE Oltenia.
The merger of Hidroelectrica with the power plants that meet the environmental standards at CE Oltenia and CE Hunedoara will most likely be opposed by investment fund Fondul Proprietatea, a minority shareholder in both Hidroelectrica and CE Oltenia.
Under these circumstances, the state will have to compensate FP for its stakes held in Hidroelectrica and the coal and power companies, prior to the merger.
As regards the recovery plan for CE Oltenia, the ministry envisages three stages: an emergency aid for the payment of last year’s CO2 emission certificates, a longer-term state aid scheme (to be paid by end-users), and a mechanism to help the company operate independently including by building coal stocks during the summer season (possibly financed by the state, although Visan has not mentioned this).
The post RO Govt. considers merging Hidroelectrica with ailing CE Oltenia coal and power group appeared first on EnergyWorld Magazine.
By Dr Lorenc Gordani*
Albania is a small country in South Eastern Europe with many valuable natural resources, including the possibility to produce abundant electric energy from wind power. Although wind energy technology, as an energy resource, is distributed throughout Europe and total licenses in the country amount to approximately 2548 MW, with an energy generation potential of around 5.7 TWh/year, today no wind farm project is in pipeline or already completed. Therefore, it is fundamental to face the main challenges that obstruct their deployment and the implementation options of these projects.
Starting with the fundamentals, the energy from wind has been used for centuries for pumping water, windmills, etc., and in recent decades the focus has shifted on the production of electricity. Machinery operated by wind energy operates successfully in isolated areas with its capacity varying from several kW to seven MW. Windmills can be quickly installed and used in a small area of land. However, in most countries, windmill installations face a common fundamental concern, such as the lack of continuous measurements of wind velocity spanning several years.
This is the case in Albania, as in many developing countries, the lack of continuous long lasting measurements of local wind speeds. Notwithstanding that approximately 2/3 of the whole of its territory is hilly and mountainous (east of the country) and the coast line is in the direction of North-South, various companies interested to invest in this sector have encountered difficulties to estimate whether it is worth doing without the right estimations.
However, Albania has historical data obtained from different metrological stations in the country, which refer to an average annual wind speed of 6-8 m/s and energy density of 250-600 W/m2. Therefore, even while being conservative, because the data are not gathered with the specific purpose of measuring wind energy potential, as identified by the Albanian Agency of Investment Developments – AIDA there is an untapped wind power potential of at least 20 electricity plants, in particular along the Adriatic coast.
Despite the limitations and accuracy of the above, there are already several domestic and foreign licensed investors exploring wind power production in Albania. According to the Ministry of Energy and Infrastructure, a series of zones have been identified with high potential of wind energy. Interest followed up to 2015 with a significant number of proposed big projects by investors reaching an approximate capacity of 2548 MW.
The first tranche of big projects came in early 2009, which saw a significant total licensed wind capacity of 1367 MW. Their technical studies showed promising potential between 5,8 m/s to 7 m/s, with load factors typically varying from 22% to 25%. The positive outcome was followed by the continued licenses granting process during the period 2009-2015. It all resulted, based on the information provided by the Ministry of Energy and Industry, to a rough total of 2548 MW, with a generation potential close to 6 TWh/year.
Notwithstanding the above plans for big wind projects, a further obstacle has been the intake of the energy produced. Since wind is an intermittent source, there is a need to consider load balancing for the system. The data of the Ministry of Energy and Industry indicated in the referred period that based on the grid structure, the capacity of the Albanian power system to absorb and dispatch wind energy was only about 180-200 MW.
The change of the situation can lead to huge investment, as well as being part of an integrated European network and the developing of power exchanges options. A further aspect of interest for the investors is related to the openness of the market, and the possibility offered today through the adoption of a balanced approach on a regional level since wind is an energy resource of low probability. A further even more economic option is also the integration with big hydropower resources offered by the national market as an excellent balancer of wind power plants.
The opening of the market has also brought the possibility of a reform of the remuneration mechanism. Until recently, Albania had a lack of supportive regulatory framework for the deployment of renewable energy sources other than hydropower. However, the situation has changed over the past two years with the introduction of feed in tariffs for projects up to three MW or three pillars. The feed-in tariff is aligned with the RE target set in the National Renewable Energy Action Plan adopted in January 2016. Also, today there are tariffs already in place of 76 Euro/MWh. Each company can pursue more than one project for a total of 70 MW.
Furthermore, in June 2019, Albania’s Ministry of Infrastructure and Energy announced its final approval of a net metering scheme for renewable energy. The scheme is open to renewable energy systems, including wind and solar projects, not exceeding 500 kW in capacity.
As a further step, the country has already introduced feed-in-premium tariffs or Contract for Difference (CfD) for renewable projects of over 3 MW of installed capacity. The tariffs are granted through a competitive auction process and will have a duration of 15 years. The first auction for a 50 MW solar PV plant was launched in August 2018 with the support of the Energy Community Secretariat and EBRD. More than 40 companies expressed their interest with three developers shortlisted and a contract was awarded to India Power Corporation Limited, to build a large-scale PV project with a total capacity of 100 MWp.
Additional support mechanisms for renewable energy producers with an installed capacity higher than a certain capacity level (around 0,5 MW) consist of customs duty exemptions for machinery and equipment used for the construction of new capacity. Based on this scheme, the developers also are entitled to benefit from tax exemptions from excise products.
Last but not least, a relevant contribution came from the possibility to acquire the terrain for a symbolic price of 1 euro and the support by the National Business Centre, which aims to operate as a one-stop-shop for shortening procedures and increasing the transparency of the licensing process (however, there are still several administrative steps, which have not been integrated).
Notwithstanding the importance of all the above developments, the opening of the market is fundamental and the integration with the regional and European one, which also leads to other options that make projects feasible even without direct incentives. Based on the spread between the cost of development of energy production in Albania and the EU, and the high profitability by the combination with hydropower potential, wind energy offers today a surplus value to markets that makes it competitive, especially if combined with the upcoming opportunities of a green certificate scheme.
Albania offers a very attractive wind energy potential for the market. The last development related to the opening of the power exchange and the approval of tariffs, offers the possibility for further studies to enhance available data, which could be a further chance for comprehensive wind potential, at least at the most promising sites. Nerveless, considering the constant reduction of cost shown by the available preliminary studies of international organisations, such as IRENA, untapped cost-competitive potential for the deployment of wind is calculate to be 987-2,153 MW in 2016, 5,201-6,990 MW in 2030 and 7,238-7,414 MW in 2050.
*Dr Lorenc Gordani, Professor of Public Law in Marin Barleti University and Independent Adviser in Energy Policy & Law, Regulation & Infrastructure in Albania
The shareholders of Romanian natural gas producer Romgaz (SNG) approved in principle the purchase of a 20% stake in Greek LNG terminal operator Gastrade, according to a statement of the company submitted to the Bucharest Stock Exchange (BSE).
The price to be paid for the stake is nearly EUR 0.4 million but Romgaz is also supposed to contribute EUR 12.5 mln to the development of the project, Bursa daily informed. The LNG terminal is estimated to cost over EUR 370 mln, but it will be partly financed by the European Union.
Greek company Gastrade is the sole promoter and owner of the project for the construction of an offshore liquefied natural gas (LNG) terminal in Alexandroupolis, a city on the Aegean coast.
In addition to approving in principle the acquisition of 20% of Gastrade, Romgaz shareholders also approved the purchase of legal consulting, assistance and / or representation services for participating in the gas terminal project. The construction of the terminal is conditional on obtaining a derogation from the European regulations regarding the common rules for the internal market in the natural gas sector (the unbundling rules, more precisely), the company shows in a document. Gastrade estimates that the derogation decision from the provisions of the directive will be issued in November this year, and the final investment decision in the project is planned for December 2019, a decision that must be taken unanimously by the project shareholders.
Electricity giant Public Power Corporation is scanning the market with a view to issuing an international corporate bond, following the introduction of streamlining measures that have averted the risk of the utility’s collapse, chairman and chief executive Giorgos Stassis told analysts yon Wednesday while presenting PPC’s first-half financial results.
The newly appointed manager said that the process the utility’s previous administration had started but froze due to PPC’s financial problems will now resume. Stassis did not put a time frame on the power company’s return to the markets, but suggested that the fact streamlining measures were introduced at a time when Greece’s borrowing costs have fallen has paved the way for a market return.
The PPC chief informed analysts and investors that 120 million euros from the increase in power rates will got into the utility’s coffers this year, plus another 532 million in 2020.
As for the securitization of unpaid bills, Stassis said that investors have expressed an interest and are examining the data before submitting offers.
He also made it clear that the power auctions – which in recent years have contributed in PPC’s losses – planned for October will not take place.
As the world responds to climate change, energy systems are evolving, and fast. The past 10 years have seen the rise (and dramatic cost reduction) of renewables such as wind and solar, to the extent that they are no longer considered ‘alternative’ energy.
What will be the next big thing as we shift to a low-carbon future? So far, indications point towards hydrogen.
The combustion of hydrogen with oxygen produces water as its only byproduct, a better result than fossil fuels, such as coal or natural gas, which produce carbon dioxide (CO2) and other pollutants such as sulfur dioxide and nitrogen oxide. Hydrogen can be used directly as fuel in power generation and other heat applications, and can be blended with natural gas in pipeline networks. In particular, hydrogen used with fuel cells (a device that converts chemical potential energy into electrical energy) is most promising for heavy duty transport applications (such as trucks, rail, and ships) and industrial applications that require both electricity and heat.
The Hydrogen Council, a global initiative of energy, transport and industry companies, envisages that by 2050 hydrogen may power more than 400 million passenger cars worldwide and up to 20 million trucks and 5 million buses. It expects hydrogen technologies to provide 18% of the world’s total energy needs by that time, with the annual sales generated from the hydrogen fuel cell market reaching $2.5 trillion and creating 30 million jobs globally. The broader “hydrogen economy” could be much larger.
However, before this can happen, energy industries have to answer one crucial question: Where will all this hydrogen be coming from?
How hydrogen… works
Currently more than 95% of the world’s hydrogen is produced from fossil fuels such as natural gas via the steam methane reforming process. Unfortunately, this is a carbon intensive process, with emissions of seven kilograms (kg) of CO2 on average when producing one kg of hydrogen. The steam methane reforming process can be coupled with carbon capture and storage technology to cut CO2 emissions but the cost of producing hydrogen carbon capture and storage is about 45% higher. And the cost of CO2 avoidance is also high, at about €70 per ton. This is not financially viable and would require technological breakthroughs in carbon capture and storage to become a sustainable solution.
As an alternative, hydrogen can also be produced by electrolysis, which uses electricity to split water into hydrogen and oxygen, using zero-carbon and low-cost renewable energy. Hydrogen produced from renewable electricity also could facilitate the integration of high levels of variable renewable energy into the energy system by using surplus renewable output for electrolysis, storing hydrogen for long periods of time, then using hydrogen to produce electricity in fuel cells.
This overall cycle is somewhat similar to pumped hydropower storage in terms of the ability for long-term storage and time-shifting of renewable output. The oxygen produced by electrolysis also has market value for industrial and medical applications (it is important to keep in mind that for each kg of hydrogen produced there are eight kilograms of oxygen produced). Developing countries can maximize the development of their renewable energy potential by participating in the global hydrogen economy.
The world needs pioneers who are willing to take the lead and bear the cost of “first movers” for hydrogen energy, just like Germany did for solar photovoltaic technology. In Japan, as part of its “3E+S” (energy security, economic efficiency and environmental protection, plus safety) energy policy, the government formulated the world’s first 21st century hydrogen strategy in December 2017, with the aim of establishing a “hydrogen economy” by 2050.
The economy based on hydrogen
The hydrogen economy is premised on the use of hydrogen as a fuel, particularly for electricity production and hydrogen vehicles; and using hydrogen for long-term energy storage and for the long-distance transportation of low-carbon energy. The key to achieving such a hydrogen economy is to bring the cost of hydrogen down from more than $10 per kg to about $2 per kg, which would then be competitive with natural gas.
Developing countries would be the big winners from the move toward a hydrogen economy. First, on the supply side, developing countries could tap their renewable energy resources to produce hydrogen and export it to other countries, as is already done with liquefied natural gas.
For example, renewable energy (including hydropower, wind, biomass and solar) in Laos may represent a potential of about 50 gigawatts (GW). The country and its neighbors need about 20 GW to meet their electricity demand, so the unused renewable energy potential could be used to produce hydrogen with zero CO2 emissions. So potentially, Laos could become a significant exporter of renewable energy through the hydrogen supply chain.
Second, on the demand side, developing countries could start using hydrogen technologies in specific areas. For example, fuel cell vehicles can be charged fully with hydrogen within five minutes for a driving range of 500 kilometers and more, with zero CO2, sulfur dioxide or nitrogen oxide emissions.
In recent years, due to transmission bottlenecks, China has been curtailing its renewable energy (wind, solar and hydro) power generation by about 100 terawatt hours annually. This curtailed energy output could be used to produce about 1.5 million tons of hydrogen, enough to power about 10 million hydrogen-based fuel cell cars for one year. This avoids about 30 million tons of CO2 emissions. In line with national air quality objectives, The Asian Development Bank has supported fuel cell buses in Zhangjiakou City in Hebei Province, the site of next Winter Olympic Games.
What are the next steps? Development finance institutions such as ADB can do more by supporting its members in five specific ways:
- Share information on hydrogen energy so policy makers and industry players are aware of the latest trends and technologies
- Help governments to develop a strategy, roadmap and regulatory framework for hydrogen energy development
- Enhance the carbon trading platform to cover the extra cost of fossil fuel-based hydrogen production with carbon capture and storage
- Pilot hydrogen technologies and business models for scaling up
- Finance hydrogen energy projects, including production, transportation and distribution infrastructure, as well as market applications.
Adopting these initiatives will make developing countries “hydrogen ready”. For the good of the environment and the development of new and dynamic industries, the world is undergoing a low carbon energy transformation. No country should be left behind.
How hydrogen can offer a clean energy future
General Motors built its first vehicle powered by hydrogen in 1966. But instead of revolutionising the auto industry, the GM Electrovan ended up in a museum. Half a century later, we’re still waiting for hydrogen to live up to its promise as a clean energy technology.
The industry joke is that hydrogen is the fuel of the future — and it always will be. But that could be wrong. The huge challenges of climate change as well as the rise of the wind and solar industries are giving it new momentum, attracting fresh interest from governments and businesses well beyond the auto industry.
Most hydrogen produced now is not clean, but the technology to change that already exists. To understand how hydrogen can go from hype to reality it’s important to grasp the situation our energy system faces.
Right now, the world is moving away from the goals of the Paris agreement on climate change that aim to reduce carbon emissions quickly. To reverse that trend, renewable energy sources such as wind and solar will have to make up a far greater share of global supply, and fast. But they face difficulties, not least that the amount of electricity they produce can vary depending on the weather or the time of day or year, so it might not be flowing when people need it.
Hydrogen is one of the few ways of storing that variable energy. Other options include lithium-ion batteries — which power smartphones and electric cars — but they can’t compete with hydrogen in terms of scale. A big hydrogen storage facility in Texas, for instance, can hold about 1,000 times as much electricity as the world’s largest lithium-ion battery complex, in South Australia.
Clean hydrogen can do a lot more than just fuel cars. It can power trucks and ships and be a key raw material for refineries, chemical plants and steel mills — all of which now have few alternatives to today’s polluting processes.
Fortunately, these sectors tend to cluster at major industrial ports, offering great opportunities to build combined infrastructure. And hydrogen is already produced at ports to feed local chemical factories and refineries.
So, hydrogen offers tantalising promises of cleaner industry and emissions-free power: turning it into energy produces only water, not greenhouse gases. It’s also the most abundant element in the universe. What’s not to like?
One of the biggest issues is that by far the most common way to produce hydrogen is from fossil fuels. The amount generated from coal and natural gas this year for industrial uses would be enough, in theory, to power roughly half the cars on the road worldwide. But hydrogen production releases about the same amount of carbon emissions as the UK and Indonesia economies combined, according to an IEA report to be released next week.
Cleaning up these industries by capturing and storing their carbon emissions or supplying them with hydrogen from renewable sources represents a considerable challenge, but it’s also an opportunity to start building a global clean hydrogen industry for the future.
Another big difficulty is cost. Hydrogen from renewable electricity is two to three times more expensive than that produced from natural gas. But solar and wind costs have plummeted in recent years, and if they continue to fall clean hydrogen will become more affordable. Still, the technology that turns water into hydrogen (without producing carbon emissions) needs to be developed on a much greater scale to cut costs.
Governments will be crucial in determining whether hydrogen succeeds or fails. Most of the more than 200 projects under way still rely heavily on direct government funding, according to International Energy Agency analysis. But smart policies should encourage the private sector to secure long-term supplies of clean hydrogen and give investors the incentives to back the best businesses.
We also need to kick-start the international hydrogen trade with the first shipping routes. There are encouraging signs: Japan has several important pilot projects to figure out the best way to ship hydrogen over long distances.
Meanwhile, the EU has backed an initiative to make hydrogen a significant part of Europe’s efforts to decarbonise its economies.
The IEA will help governments craft the right policies. At the request of the Japanese presidency of the G20, we have carried out an in-depth study on the state of play of clean hydrogen, recommending immediate practical steps to foster its development. The report will be released next week at the meeting of the G20 energy ministers.
The world should not miss this unprecedented chance to make hydrogen a serious part of our sustainable energy future, rather than leaving it parked in a museum.
During a time when the power market is shocked by PPC’s turbulence and the effort of the dominant player to recover from wrong strategic choices and the new global reality in the sector, the private sector shows the strong investing and growing potential that exists.
In July, Mytilineos’s deal with General Electric for the purchase of machinery (gas turbines) for its new CCGT (Combined Cycle Gas Turbine) plant was completed. The 300 million Euros investment is the first in power production with gas in the last 10 years and seals the dramatic changes in the power market on an international level, as part of the policy to decarbonize.
Mytilineos’s investment decision, but also the interest from other market players to build new gas plants, show the market’s expectations that on the one hand, measures to remediate the sector will proceed and on the other hand that we have already entered the post-lignite era, at least in terms of competitiveness of power production. In any case, it is not random that the deal concerning Mytilineos’s investment was signed after the elections.
The biggest center
Construction works for the new plant will begin in September and will be completed by November, 2021, as the head of the group, Evangelos Mytilineos, announced, in order for it to enter the system at the beginning of 2022. The plant, which will have a capacity of 826 MW, will be the largest in the country’s power system and will be installed in the energy center of Ag. Nikolaos, Voiotia, turning the area into Greece’s largest energy and industrial center.
Already, Protergia’s CCGT plant of 444 MW operates in Aspra Spitia, but also Alouminion’s cogeneration plant of 334 MW. This means that together with the new plant, Mytilineos’s center in Voiotia will be the largest energy center of the country with power producing plants of 1,604 MW, while Agios Dimitrios of PPC with old lignite plants constructed in 1983 has a capacity of 1,456 MW, while Kardia that will be decommissioned in two years, has 1,110 MW. Of course, apart from Agios Nikolaos, Mytilineos has the largest share in Korinthos Power’s plant (395.9 MW).
A modern plant
Contrary to the old and ineffective PPC’s lignite fleet, the new gas plant will be among the most modern not only in Greece, but globally. According to announcements concerning the supplier (General Electric), the class technology air turbine will have a thermal efficiency of over 63%, while a similar PPC plant in Ptolemaida is expected to have 40.5%. The cost of Mytilineos’s investment is 300 million Euros, about one fifth of the investment in the Ptolemaida 5 lignite plant (1.4 billion with 660 MW). High efficiency plays a special part for the plant’s competitiveness, since it emits less CO2 per MWh, which means a lower cost, especially during a time when CO2 prices rally at almost 30 Euro/tonne.
Included for the first time in the FTSE4Good index
Mytilineos is now included in the recognized sustainable development stock index FTSE4Good (Emerging Index), that targets promoting investment in listed companies with a significant contribution to society, the environment and corporate governance, after the positive evaluation it received in June, 2019, from the international organization FTSE.
According to its evaluation, Mytilineos scored high in all three segments, thus satisfying the high standards of the FTSE4Good Emerging Index. With a total score of ESG:3.9 out of 5, the company managed in its first inclusion to achieve a score better than 79% of the evaluated companies in the sector of industrial products and services. More than 540 companies from 24 developing markets are included in this index.
Mytilineos’s presence in more and more international sustainable development indexes is a recognition of the group’s significant efforts in Corporate Governance, as well as its commitment to ensure sustainable development values in its operation.
The FTSE4Good indexes have been designed and developed by FTSE Russell, which specializes in corporate evaluation according to the best global practices in social, environmental ans ESG issues. They are an important tool to evaluate listed companies in sustainable development with the target of socially responsible investment.
- Mytilineos: The crisis helped Greeks open the windows to the world
German newspaper Frankfurter Allgemeine Zeitung presented E. Mytilineos as one of Greece’s biggest and most successful businessmen, who after years of dealing with the crisis, now has a reason to face the future with optimism.
The liberal and reform friendly new head of the government brings hope to Greek businesses that the country will finally make an economic step forward, after the loss of over one quarter of GDP, says the newspaper and notes that contrary to the Greek economy, Mytilineos had significant growth during the years of the crisis.
Starting with the crisis outset in 2009, the group’s sales was 662 million Euros, while net profit was 14 million Euros. In 2018 it closed with sales of 1.53 billion Euros and net profits of 141 million. During all this time there were years with wide programs of austerity and restructuring, however the group never reported any damages.
The report features statements by Mr. Mytilineos, who underlines that the group was saved thanks to its differentiation and the synergies between its different activities. “In hard times, the different arms support each other, while in good periods they make strides”.
The German newspaper presents Mytilineos’s activities which include one of Europe’s largest aluminum producers with its own bauxite mines, power production through natural gas, which is imported by the group itself and also construction. For power production, Mytilineos imports gas and is not dependent on the old public monopolies. In this way, it can bring to the Greeks not only power, but also gas.
The newspaper flashes back to the 65 year old businessman’s course, who created the group out of a middle size family business. In contrary to the children of large family dynasties, Ev. Mytilineos did not study in American schools or worked in international banks. He completed his studies with a postgraduate degree in the London School of Economics and took over his family business, formed in 1908, at the age of 24. 21 years later, in 1995, followed its listing and afterwards the construction of power plants, in 2005 the aluminum company and the next year the entrance in the renewables market with wind farms.
As for the company’s course during the crisis, FAZ notes that Mytilineos acquired multiple benefits: On the one hand, Spanish energy group Endesa wanted to leave the Greek market in 2010 and sold its energy subsidiary. On the other hand, Greece’s creditors insisted on the opening of the power and gas market, according to the remediation measures. The opening of the market and the purging of union establishment led in turn to the offering of more competitive prices on behalf of Mytilineos. “We are good, we are economical and we have the know-how”, is the businessman’s most liked phrase.
Even when – or especially when – business people in Greece are successful, they are not well liked. This happens because a part of Greeks retains a negative stance against businessmen for ideological reasons, while others remember the era of “oligarchs”, when during the 70s and 80s businessmen conspired with politicians to achieve advantageous conditions for control of the small market.
As the newspaper mentions, Evangelos Mytilineos does not want anything to do with this picture: “One should understand that this is not just about the local market. One must accommodate to the global market and attract foreign capital with his company”. Mytilineos considers a positive thing that apart from his family’s share of 26% there is also a 39% share belonging to foreign investors. In order for a foreign investor to be interested for a Greek company, “corporate governance” must be first implemented. For Mytilineos, this means that the board of eleven is not constituted solely by family members, but also by seven independent members.
The newspaper notes that Evangelos Mytilineos gives the attention of an economist rather than a manager that focuses on the details. His vision saved the group from problems during the economic crisis, when bank lending ended, since he acted in time.
The report also focuses on the previous government, saying that Mr. Mytilineos pinpointed the deviations of SYRIZA’s partly extreme left policy with the same vigor. “Some of them do not like businesses and feel bad even during the latest stage of a new industry’s licensing”.
According to FAZ, even though Evangelos Mytilineos made the effort to cooperate constructively with the SYRIZA government, he now feels relieved and turns his gaze on the future of the Greek economy: The crisis helped Greeks open the windows to the world. They had to learn to seek success not just as individuals, but where necessary, through common action.
Closing its report, FAZ noted that the successful Greek businessman and his group look forward. This is true because during the term of the new liberal prime minister, Mitsotakis, the old monopoly will be likely dissolved as well as power market distortions. This means that the new government does not have another option, since the left spoiled state group is now in danger of bankruptcy. The hope is clearly reflected on the share price. Since the day of the European elections, which hurried national elections and gave victory to the reformers, the value of Mytilineos shares was increased by 27%, ends the report of the German newspaper.
To date, the Black Sea has no LNG terminal. Romania and Ukraine each harbored plans to build the first LNG terminal in the Black Sea: Romania at Constanta (land based) and Ukraine at Odessa (FSRU). However, there has been little progress in practice since these plans were first announced. Romania’s project (Constanta/AGRI LNG) has a potential start-up date in 2026, at best, since Romania’s priority is to complete the BRUA corridor and kick start its own gas production in the Black Sea.
Paradoxically, Romanian officials still say that AGRI is on the table, although it is all but officially declared dead. Ukraine’s project is not under any development, having been frozen five years ago with no expected date in sight for its possible start. In essence, both LNG projects have quietly faded into oblivion. The super charged Black Sea geopolitical climate, as well as Turkey’s refusal to allow LNG tanks to pass through the Bosphorus Strait make the prospect of building an LNG project in the Black Sea a very distant one.
Europe’s LNG reality
Europe has 28 large scale LNG terminals, all of which are import terminals (regasification). Only Russia and Norway have export terminals (liquefaction). Only twelve countries in Europe have import LNG terminals: Belgium, France, Greece, Italy, Lithuania, Malta, the Netherlands, Poland, Portugal, Spain, Turkey and the UK. Of these 28 large scale terminals, 24 are located in EU countries and 4 are in Turkey. Moreover, of these 28 LNG terminals, 23 are land based, 4 are floating storage and regasification units (FSRUs) and one (in Malta) has both a Floating Storage Unit (FSU) and onshore regasification facilities.1 There is a substantial imbalance in the way these LNG terminals are distributed in Europe, in favor of Western Europe. Thus, the biggest regasification capacity belongs to Spain (61.9 Bcm/year in 6 operational terminals), followed by the UK (42.7 Bcm in 3 operational terminals), and France (34.65 Bcm/year in 4 terminals). In South East Europe (SEE) we have only an operational Greek LNG terminal at Revithoussa, and two planned: one at Alexandroupolis (In Greece) and another at Krk (in Croatia).
In North Eastern Europe, Lithuania opened its LNG terminal (Klaipeda) in 2014 and Poland inaugurated Swinoujscie LNG in 2016. Estonia (who currently has no LNG terminal) plans to build two: Padalski LNG (2.5 Bcm) and Muuga/Tallinn LNG (4 Bcm). Latvia too plans to build an import LNG terminal – Riga LNG (5 Bcm) and so does Russia (Kaliningrad LNG).
At the far Eastern end of Europe, in the Black Sea, we have no LNG terminals at all. Turkey (a Black Sea country) has 4 LNG terminals (2 onshore, 2 FSRUs), but none of them are located in the Black Sea. The closest – Marmara Ereglisi is located in the Marmara Sea – which connects the Black Sea with the Aegean Sea. Back in 2010, Romania dreamed to build the first LNG project in the Black Sea at Constanta, but the plan has yet to see the light of day. The AGRI LNG project is considered by ENTSO-G as “delayed” and its maturity “less advanced”, with a potential date for construction start in 2022 and commissioning in 2026 (optimistic scenario). Ukraine too has announced back in 2011 that it wants to build a 10 Bcm LNG terminal in Odessa (5 Bcm in stage 1, and an additional 5 Bcm in stage 2), but those plans were completely derailed by subsequent developments in Ukraine starting with 2014 and by Turkey’s opposition to an increased traffic through the already congested Strait of Bosphorus. Both LNG terminal projects (Odessa and Constanta) were therefore looking at Azerbaijan as a potential source of gas.
The low utilization rates of the existing LNG terminals is another issue worth taking into account. Europe’s existing LNG capacity is underutilized. Of the total European LNG import capacity (200 Bcm) only a quarter (50 Bcm) was utilized in 2014. A follow-up study conducted for the European Commission in 2017 re confirmed the “low utilization rate of LNG terminals (0-36% in 2016)” with LNG having a “significant role in the Northern route (provides cca. 18% of missing volumes)” and helping “mitigate the risk of African pipeline route disruption (38% of missing volumes)”, but with a “limited contribution in SEE Europe”.2 EU’s LNG Strategy presented in 2016 called for a more efficient use of existing LNG infrastructure and gas storage, before building new regasification terminals. Nevertheless, the EU has co-financed or committed to co-finance new LNG infrastructure projects worth over Ä638 million for 14 LNG projects, which will increase capacity by another 15 Bcm by 2021, in addition to the 150 Bcm of spare capacity that currently exists.3 However, all these 14 projects are located mostly in the Baltic, Mediterranean and Adriatic Seas, with not even one in the Black Sea.
Romania’s LNG dream
Azerbaijan-Georgia-Romania Interconnector (AGRI) was supposed to build the first LNG project in the Black Sea and diversify gas supply by creating an alternative route for Azeri gas to Europe. First proposed in 2010, it would have transported Azeri natural gas by pipeline from Azerbaijan to the Georgian port of Kulevi (in Georgia) – and from there (as LNG) –across the Black Sea to the port of Constanta (in Romania), where it would be regasified and shipped via the Romanian gas transport system to European markets (via Hungary). British consulting company Penspen completed the feasibility study for the project back in 2014 and provided 3 scenarios to consider for AGRI LNG development: 2 Bcm (at a cost of Ä1.2 Billion), 5 Bcm (Ä2.8 Billion), and 8 Bcm (Ä4.5 Billion).
The first edition of the EU’s Project of Common Interest (PCI) list in 2013 included the Romanian project in section 6.22 – AGRI (with the LNG terminal in Constanta as subproject 6.22.2), but also in the Priority Corridor Southern Gas Corridor (7.2) with minimum 8 Bcm/year from the Caspian (Azerbaijan or Turkmenistan), not with LNG, but the “submarine solution” – a pipeline linking Georgia and Romania (White Stream).4 If the AGRI project could be found on the first Project of Common Interest in 2013, it was nowhere to be found on the latest – 3rd PCI list (November 2017).5 In fact, it has already vanished from the second PCI list (November 2015), where both projects (6.22 – AGRI LNG solution and 7.2 – AGRI submarine pipeline solution) appeared as “No longer considered a PCI”.6 This could mean any of the following reasons:
• either that “according to the new data the project does not satisfy the eligibility criteria”;
• or “a promoter has not re-submitted it in the selection process for this Union list”;
• or “it has already been commissioned or is to be commissioned in the near future”;
• or “it was ranked lower than other candidate PCIs in the selection process.”
Since construction did not start and the project was eligible before, a possible reason is that either it was not re-submitted (promoter lost interest in it) or it was ranked lower than other projects (not considered commercially viable). The fact that it has not re-surfaced on the 3rd PCI list (in either form – LNG or submarine pipeline) confirms the lack of commercial attractiveness or signal difficulties related to transport across the Black Sea. These challenges can relate to the liquefaction part. As rightfully observed by British energy security expert John Roberts, countries that possess gas resources (in this case, Azerbaijan) never build LNG terminals in other countries (in this case, Georgia).7 The challenge has to do also with the deteriorating geopolitical climate in the Black Sea after 2014.
In either case, it adds an extra layer of complexity to the AGRI LNG project. Friendship among countries (Azerbaijan, Georgia and Romania) is not enough to make a gas infrastructure project a reality. A commercial project has to be underpinned by sales contracts. And, in AGRI’s case we have seen only political statements, Memorandum of Understanding, feasibility studies and discussions among the SPV shareholders. No sales contracts. Without a firm buy commitment, who will put money in building the infrastructure? Especially, when LNG remains more expensive than pipeline gas, especially in an oversupplied European gas market, and especially in a place where the geopolitical climate has worsened. Since the annexation of Crimea by Russia in 2014, the geopolitical risk in the Black Sea went up. Such a project could face harassment/sabotage from Russia, especially since the LNG ships/underwater pipeline would have to pass by Ukrainian waters that are controlled by Russia. This could further strain already tense relations between Black Sea countries. In the post-2014 climate, such a project carries a higher geopolitical risk, making the securing of finances and related insurance costs more expensive than in a business as usual case.
Add to this, Romania’s drive to develop its own Black Sea resources which undermines the urgency of an LNG project. To put things in context, the talks related to the AGRI LNG project started in 2010 (2 years before the discovery of the Neptune gas field in Romania’s offshore waters) which changed the optics and calculations in Bucharest. Since 2012, the priority in Romania has been the development of its Black Sea gas and related gas infrastructure (to bring this gas onshore, to export it to Moldova or further on to Austria). Romania is not particularly great at promoting several projects simultaneously. Also, it has learned that being on a PCI list is not in itself a guarantee of success, since the project promoters have to be very active in lobbying for the project, securing finance, conclude pre-sales contracts, etc.
Moreover, Romania’s haphazard policy making in the past 2 years raises a big question mark even regarding its Black Sea gas developments with only one company (Black Sea Oil and Gas) taking a FID in early 2019 meanwhile the two other big players (OMV Petrom and Exxon) adopted a “wait and see” strategy.
Finally, it is clear that Azerbaijan’s priority investment destination is Turkey, not Romania. Azerbaijan does have the resource base to supply the Constanta LNG project, but in the near future its number one priority is gas supply through the TANAP/TAP system. Should its capacity be expanded (from the current 16 Bcm to 32 Bcm in stage two), this would allow Azerbaijan to sell more gas to Europe (20 Bcm instead of the current 10 Bcm via TAP) than the volume it would sell across the Black Sea as LNG to Romania (8 Bcm).
Romania’s efforts in early 2019 to explore new cooperation possibilities with Azerbaijan by involving SOCAR in Romania’s Black Sea gas developments (through a partnership with Romgaz) signals the attempt to secure Caspian gas for transport through the Eastring pipeline – a project which, although equally distant in time (2023-2028), seems to have better prospects than AGRI LNG does at the moment. Add to this the fact that there will be four elections held in Romania in the next two years: European parliamentary and Romanian presidential elections this year, Romanian local and parliamentary elections in 2020. In effect, judging by how fast Romania has been moving on its priority projects so far (Black Sea gas development, BRUA, interconnectors), and for all the reasons explained above, I am very skeptical about the chances of Constanta LNG project happening anytime soon.
1 LNG in Europe 2018: An Overview of Import Terminals in Europe, King&Spalding, 2018, p. 2.
2 Follow-up study to the LNG and storage strategy written by REKK, Tractebel, Energy Markets Global (2017).
3 EU-U.S. Joint Statement of 25 July: European Union imports of U.S. Liquefied Natural Gas (LNG) are on the rise, August 9, 2018: http://europa.eu/rapid/press-release_IP-18-4920_en.htm
4 https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32013R1391&from=EN , see page 14-15 of pdf 5 https://ec.europa.eu/energy/sites/ener/files/documents/memberstatespci_list_2017.pdf , see pg. 21-22 (Romania’s PCIs)
6 https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32016R0089&from=EN, see page 15-16 of pdf
7 John Roberts lecture on Black Sea Energy Security, ROEC Bucharest Talks, March 12, 2019.
Closed-door Congress, co-hosted with Hellenic Petroleum, took place in Thessaloniki earlier this week. The event was supported by both Greek and international media with reporters taking exclusive comments and interview from top-managers.
The keynote speakers of the Congress covered both the business and technical sides of the two developing regions: the Mediterranean and West African offshore. Among honorable speakers were:
- Dr Abdelarahim Mohamed – Board Director for Exploration & Production of National Oil Corporation of Libya
- Yannis Bassias – President & CEO of Hellenic Hydrocarbon Resources Management
- Kees Jongepier – VP Exploration of Aker Energy AS
- Chijioke Akwukwuma – CEO of Ocean Deep Drilling ESV Nigeria Limited (ODENL)
- Dr. Jörg Köhli – Senior Expert – Head of Upstream Oil and Gas of European Commission
- Christophe Souillart – BD Director Africa, Mediterranean and Southern Europe of Subsea 7
- Henry Okolie-Aboh – Founder & CEO of Westfield Energy Resources Limited
The first day started with the presentations highlighting new challenges, opportunities and strategies across Mediterranean region while the second day’s plenary session was devoted to the overview of the West African offshore region and its current performance.
During two days major players of the upstream industry, representing E&P companies, EPC contractors, drilling contractors, service providers & equipment manufacturers, shared their experience and views on the current situation in regions, and presented solutions, cases and technologies to overcome these challenges.
Not only did the delegates take part in the discussions, but also found new business contacts and started the discussion for further cooperation.
More about the Congress: https://bit.ly/2kR7ERN
The post Delegates from more than 100 companies met at EPOCH Congress appeared first on EnergyWorld Magazine.
The Saudi oil attacks have triggered the steepest crude market price surge in 30 years and stoked fears for the global economy.
The attacks on Saudi Arabia’s oil infrastructure led to the biggest jump in global prices since 1988 by wiping out 5.7m barrels of production a day – 5% of the world’s oil supply.
The price of Brent crude surged by more than $12 (£9.60) a barrel within seconds as trading began in London, quickly climbing to highs of $70.88 – a rise of more than 19% – before settling lower in a day of record-breaking oil trading. By Monday evening oil was trading at nearly $69, up 15% on the day.
Oil futures trading reached a new all-time record on the Intercontinental Exchange as traders placed more than 2m bets on the future price of oil as a hedge against more market volatility.
Meanwhile, the energy price shock reverberated through global markets, driving up shares in energy companies on the prospect of higher profits, while stock exchanges across Europe plunged into the red as investors took fright over rising geopolitical tensions.
Oil market analysts claim prices could surge towards $100 a barrel in the coming weeks if Middle East tensions lead to renewed disruption in the strait of Hormuz, a key transit route for the world’s oil tankers.
Geoffrey Smith, a director at the market data firm Refinitiv, said Saudi Arabia has “resumed loading oil from its storage reserves to make up for the break over the weekend – but in the longer terms its exports are in doubt.
“The question is how long Saudi Arabia can maintain export levels and quality while the damage is fixed. The most likely effects are to be felt from November onwards as storage might start hitting critical levels if the processing facility has not been repaired,” Smith said.
A Middle East energy crisis could be a boon for the US fracking industry, but threatens to tip the stumbling global economy into a recession by stemming supply to Asian economies. Rising oil prices also threaten consumer spending – a key growth factor for economies – because they could force up prices and depress demand for goods.
Donald Trump said the US was “locked and loaded” to retaliate and could authorise the release of US oil reserves to help balance the market. But energy experts cast doubt on whether US fracking companies – who produce oil by breaking up shale rock formations underground – would be able to fill the gap left by Saudi oil production plants.
Bjørnar Tonhaugen, the head of oil markets at the research firm Rystad Energy, said the world was “not even close” to being able to replace Saudi exports.
“The market’s reaction to Saudi Arabia’s importance, in the new era of US shale, will now be put to the test,” he said.
The global economy has been faltering against a backdrop of rising trade tensions between the US and China. Demand for oil had been falling in recent months as industrial production slowed while the world’s two biggest economies imposed punitive tariffs on one another’s goods.
Economists said higher oil prices could compound the pressure on manufacturing output, which had already plunged into recession territory as a result of the trade war, serving as a further brake on global growth.
Philip Shaw, the chief economist at the City bank Investec, said: “Against a background where you have global trade on a downward trajectory because of the tariff war between the US and China, it’s not helping at all.”
The spike after the Saudi attacks returned the oil price to levels last seen in July, which analysts said could mitigate some of the impact on global growth. However, Shaw said growth around the world could slip below 3% this year, marking the weakest expansion since the depths of the global financial crisis in 2009.
Some energy experts believe the global oil price shock may even help efforts to shift economies from fossil fuels to green energy alternatives.
Artur Baluszynski, the head of research at investment firm Henderson Rowe, said Europe may “feel the pain of higher energy prices” in the short term, “but in the long term, more expensive fossil fuels will accelerate Europe’s already leading position in renewables like wind and solar”.
Callum Macpherson, the head of commodities at Investec, said: “Only time will tell, but we may look back on this incident as a critical development in motivating the energy transition.”
A spokesman for the RAC, Simon Williams, said the steep market price hike for petrol and diesel will not necessarily hit drivers at the pumps unless oil prices are allowed to remain high in the long-term. “The wholesale prices of both petrol and diesel look set to increase by 3p a litre, [but] this doesn’t necessarily mean higher prices at the pumps because retailers only just began to pass on overdue wholesale price savings at the end of last week,” Williams said.
Supermarkets cut fuel prices by around 3p on Friday to127.77p a litre for petrol and 131.26p for diesel. Williams added: “If the barrel price remains high for a sustained period however, it could easily lead to several pence a litre being added to the average price of both fuels.
“We are hopeful the fact the US is releasing emergency oil stocks and that Saudi Arabia operates a global storage network will mean that drivers here in the UK will not be too harshly affected.”
The post Saudi oil attacks push prices up by highest amount since 1988 appeared first on EnergyWorld Magazine.
The wind farms complex is supported by 20 year power selling contracts that have been signed with the Operator of the Electricity Market (DAPEEP).
A monumental project in renewables is completed and expected to enter commercial operation within 2019. It is a series of seven wind farms with a total capacity of 154.1 MW in Kafireas, SE Evoia, an investment by Enel Green Power Hellas (100% subsidiary of Italian group Enel) of 300 million Euros.
The wind farms complex is supported by 20 year power selling contracts that have been signed with the Operator of the Electricity Market (DAPEEP).
The project will produce around 480 GWh per year, covering the needs of 130,000 Greek households. The project will greatly contribute towards power production from renewables, substituting production using imports or fuels harmful to the environment and health. The selection of Kafireas was made according to the special land use framework of the country for renewables, which specifies the areas with a high wind potential and environmental constraints.
The project’s planning has been made in such a way as to protect and improve the natural environment, as well as to promote economic activity in the region and sustainable development. Enel Green Power Hellas will provide each year 3% of its net sales for the backing of local communities and environmental protection. The annual sum for supporting local communities is calculated at least at 1.2 million Euros.
Helping local community
In general, during the construction phase and the operation phase of the project, the company, following its goal to enhance local community, hired and hires many people from the wider region, while materials mainly come from Karysia, while the regional economy is improved significantly through the renting of houses and offices for the staff.
Last, the company, apart from its contribution in widening the local economic chain, has also developed a parallel action plan that enhances sustainability. An emblematic project is the reforestation of Kastanalogo, a forest with centuries old chestnut trees in an altitude of more than 1,000 meters in the side of Ohi. The reforestation plan is already in operation under the supervision of the forestry service and is expected to be completed by 2021.
The sustainable development model
Kafireas, the wind complex under construction in Greece, is another example of a “sustainable construction site” with advantages for the region and local community ranging from the environment to the economy.
Enel Green Power’s presence in Greece has brought a breath of fresh air with many social, economic and environmental benefits. The various wind farms where EGP’s flag stands in Greece, the least of who is Kafireas in the southern part of Evoia, are opportunities for sustainable development.
At the time of Kafireas’s operation, the total capacity in 2019 will be 154 MW and it will be the biggest in the country. Kafireas will contribute not just to increasing green energy produced in Greece, but also to bring a series of benefits for the local community, while it is an important incentive for local economy.
At the construction site, around 200 people from the region have found employment to build the wind farm and relative infrastructure. They began with the road that was needed to reach the construction area and which will allow residents and tourists to visit remote places and admire natural beauty in this part of the island.
A “sustainable construction site”
Small businesses and professionals from the region are also taking advantage of the presence of the project. There have been collaborations with restaurants and hotels for covering the needs of the staff at the construction site.
EGP’s presence in the construction site guarantees income for the city of Karystos and for all local municipalities that host wind farms or small hydro plants thanks to a compensation mechanism.
A sum equal to 1% of total annual sales from each wind farm is credited to local residents’ power bills. The municipality where each wind farm exists receives significant income annually, specifically 1.7% of sales of each wind farm, which is set aside by LAGIE from the producers, while another 0.3% is credited to the Green Fund.
There were also sponsorships to athletic and cultural events, such as the creation of a small clinic with experienced medical staff, a landmark for the people of the region.
For all these reasons, Kafireas is truly an example of a “sustainable construction site” in Greece, included in the model of creating common value that combines corporate needs with those of the residents where we provide energy.
A total look at environmental sustainability
The project of Kafireas follows the paradigm of the sustainable construction site that set in motion EGP’s approach based on the model of creating common value.
Through the approach of creating common value, environmental and social sustainability provides support to the company for every choice and approach in development, planning, construction and operation of projects, focusing on environmental protection, rational use of resources, attention to health and security, innovation, circular economy and benefits for all involved.
During the construction phase, we set concrete goals to measure the seven sustainable fields connected to the 17 goals for sustainable development of the UN (SDGs) that are measured according to global sustainability standards.
It should be added that all wind farms built in Greece are inside areas characterized by the government as Areas of Wind Priority and Areas of Sustainable Wind. All projects passed environmental assessment, which carefully examines their repercussions on the environment and set all phases of their life duration: Construction, operation and pause of activity.
Today, energy is one of the most important human goods and many times, from many sides, it is considered a given. The rise of societal dependence on energy led to a new energy geopolitical trend. However, it is not enough for the economy of one state to determine its relationship with the buying and selling of energy, but an even more important role is played by the policy of each state. Energy, apart from covering the needs of each state, is now a point of strategy and political pressure. Targeting energy, many alliances and synergies (political, economic) have formed for the best coverage and supply.
Thus, Europe quickly formed its own energy policy based on two pylons: On the one hand, the operation of the internal energy market and on the other hand, the security of energy supply. Today, Europe is all the more dependent on Russia, which is why it seeks other ways/routes to receive energy and cover its constantly rising needs. One of these ways is to promote a Mediterranean policy, since the Mediterranean is an important crossroads and a powerful energy route. More specifically, the EuroMed Partnership has been formed, initially because of its geographic position, but also because of the significant energy deposits held by many Mediterranean countries, in contrast to European ones. In energy, Mediterranean countries maintain an important position and this is because they are neighbouring countries to the EU (apart from the already European Mediterranean states) and cooperate with them. Also, they are importers of energy, but they also have the responsibility of securing the supply routes in the region.
East Med pipeline
As we know, energy brought a new interest in the political relations of the international community. And very quickly, states developed their own energy policy by forming cooperation and economic relations. They moved to commerce and energy supply primarily through the construction of necessary energy pipelines, which hold an important role in the geostrategic policy of countries in the energy political landscape of the global community.
Lately, with recent discoveries of energy reserves, a new breeze was given to the importance of Mediterranean space both in energy and security, as well as the political antagonisms of international “players”. Europe and primarily Greece, Cyprus and Israel, took responsibility and made the decision to create the EastMed pipeline, in an effort to advance their cooperation and their position in the energy politics canvas. This pipeline, will begin in Israel, will follow a route to Cyprus and then to Crete and continental Greece, where it will connect to Otranto, Italy and will supply the rest of Europe.
After the recent discoveries in fields inside blocks of Israel and Cyprus (Leviathan and Aphrodite-Calypso correspondingly), Europe reserved a large sum (to reach 100 million Euros) for the necessary preparations and studies of the project. Their results appear to be positive and consider EastMed as viable. This does not mean, of course, that the project does not face many challenges, leading to worry about its realization schedule. Initially, the EastMed project annoyed Russia, but primarily Turkey, which increased its provocations in the Eastern Mediterranean. It sends Turkish ships in Cyrpus’s marine blocks for its own exploration and drilling, defying the notifications and sanctions of Europe. Furthermore, another challenge faced by EastMed’s project are its own implementation plans. This is because the Mediterranean Sea is deep and has an anomalous geomorphology, which creates uncertainty in the installation and operation of necessary materials.
East Med is included in the PCI list of the EU (Projects of Common Interest). Of course, Europe does not rest just on the idea of this pipeline, but also seeks other individual solutions and routes for its energy supply and the covering of its needs. It appears that the realization of the pipeline is a long term project, considering the geopolitical antagonisms. One solution that is being studied is to use Egypt’s LNG plants or build a new one in Cyprus. It is a move that will enhance the role of these two nations.
It is noteworthy that at the beginning of the year (January 2019) the EastMed Gas Forum (EGF) organization was formed in Cairo (its headquarters). Its purpose is the creation of a peripheral gas market, the drop of infrastructure cost and the offering of competitive prices. During EGF’s formation, the energy ministers of Cyprus, Greece, Israel and Egypt took part, as well as representatives from Italy, Jordan and Palaistine. Turkey did not participate, being displeased about it. This forum will also help create a smooth and successful corporate relationship between gas producers and gas consumers.
Indeed, during the last few days (July 24-25, 2019), the new energy minister, Mr. Chatzidakis, travelled to Cairo in order to participate in EGF’s second conference. Other participants include the energy ministers of Cyprus, Israel, Jordan, Palaistine and the US, undersecretary of energy of Italy, as well as representatives from the EU, France and the World Bank. During this second conference there will be talks about advancing peripheral cooperation, organizing the forum, as well as studies made by international organizations for optimizing the methods of extracting current and potential gas quantities in the SE Mediterranean basin. Furthermore, in EGF’s conference, Mr. Chatzidakis has scheduled bilateral talks with the energy ministers of the US, Egypt and Israel about Greece’s energy relations.
After the two day EastMed Gas Forum, all parties agreed to turn the forum into an international organization in SE Europe. They also moved with the formation of a Business Council, which is responsible for carrying out EGF’s works. They also created a consultation committee along with the gas sector and the participation of public and private enterprise. Last, the first study was approved on behalf of the EGF in cooperation with the World Bank about the region’s gas potential and its better exploitation and export.
International reactions. Which global players lose and who wins?
Of course, Greece sees in the East Med project a great chance of playing an important role in the energy landscape. This pipeline will turn it into an energy power and will enhance its position both in the Mediterranean Basin, as well as in Europe. Moreover, Greece attains a strong presence in the Mediterranean, forming strong alliances with other Mediterranean states (Cyprus, Israel and even Egypt), providing a resounding answer to Turkey’s provocations. With EastMed, Greece is estimated to acquire an active role in the Mediterranean in energy and security. For now, of course, we cannot say it has reached this position, at least until there is a concrete framework and the pipeline gets the green light.
Israel heavily invests on the EastMed pipeline. This, of course, is due to the fact that through the pipeline, Israel acquires an immediate and strong connection to Europe. This automatically means that Israel’s position in the Mediterranean is enhanced, both in energy and security, while relations with Europe are strengthened. Israel (with the Leviathan field) will have the opportunity to extract gas, both to cover its own needs and to export to Europe. The only negative element is that the operation of this pipeline suggests cooperation and dependence on an Arab nation, such as Egypt, no matter how friendly. It is a collaboration whose development holds great interest when it comes to the two countries’ approach. Of course, the important thing is political will to create a cooperative relationship.
Egypt, during the last few years, has set the goal of strengthening its position on the Mediterranean energy map. Of course, even though there are no official reactions, we can certainly say that on the one hand, it benefits from East Med, but on the other hand will have certain concerns, since there are issues of competitiveness. This is because Egypt promotes and significantly depends on the operation of its two liquefied natural gas plants in Idku and Damietta correspondingly. Furthermore, as was mentioned before, Egypt (as an Arab country) has to face the prospect of depending on Israel. What is certain is that Egypt will benefit much more, since it is the cheapest route for transferring gas.
Lately, discoveries in the marine blocks of Cyprus (Aphrodite, Calypso and Glaucus as estimated) provide Cyprus with the opportunity to become a significant energy force in the Eastern Mediteranean political landscape. Cyprus seeks to improve its economy through EastMed, to cover its internal needs and to advance gas exports. Moreover, Cyprus enhances its position in the Mediterranean Basin through EastMed and provides an answer to Turkey’s continuing provocations. However, EastMed’s project is anything but easy, as it needs stability and security in the region, which is not true in the case of Cyprus when it comes to its conflict with Turkey and its internal division (between Greek Cypriots and Turkish Cypriots). This will lead to the delay of realizing the pipeline and the need to find a route in order not to trespass on Turkey’s marine borders. EastMed, as it appears, heightened geopolitical issues in the region instead of bringing all sides together for a common solution.
Of course, it should be mentioned that no matter how much the pipeline’s realization is delayed, Cyprus has another chance to play an important role in energy since there are plans to build an LNG plant on the island.
Turkey regards energy cooperation between Greece-Cyprus-Israel (and Egypt) as negative when it comes to EastMed. Turkey has realized its isolation from European energy plans and does its best (despite European reactions and sanctions) to acquire a share in the Mediterranean energy field. Turkey is dependent (at 70%) on Russia’s and Iran’s energy supplies. Watching its own energy needs rising, it seeks a new cheap route of supply. It knows well that its efforts are affected by negative relations with all parts of this new project. Turkey does what it can to maintain a strong presence in the Mediterranean as an energy force and to acquire benefits from recent discoveries in the Eastern Mediterranean. Thus, knowing the need for stability and security for realizing the project, it enhances its presence with continuous provocations, by sending ships for its own exploration and drilling, destabilizing the region.
Russia is definitely against EastMed, since it is a rival energy player. Russia supplies the greatest part of Europe’s energy needs through its own cheap natural gas, which is something that European powers want to avert by fracturing this relationship of dependence. Europe has provided a large sum for the pipeline’s planning and studies, a positive fact for energy deposits and EastMed’s viability. Moreover, Europe wants to avoid Turkey’s participation, since already existing pipelines already traverse its ground. They want to find an alternative route of cheap supply in order to avoid being dependent on the Turkish route.
On behalf of the US, we also have willingness to support the building of EastMed. This is because for the US, the pipeline means a direct and concrete connection of Israel to Europe, but also the weakening of Russia’s energy role in European territory. This US position was enhanced by foreign secretary, Mike Pompeo’s participation in the trilateral meeting of Greece, Cyprus and Israel last March in Jerusalem. This move was a sound answer particularly to Turkey and its provocations. It should be noted that lately, the US and Turkey do not have the best relations, especially after Turkey’s decisions on the issue of the Russian S-400 missiles.
The importance of energy in international and especially Mediterranean geopolitics is evident. Through new reactions brought by the EastMed project, a new dynamic is given to countries of the Mediterranean Basin and geopolitics of the region in regards to cooperation, energy and security were advanced.
George Stassis, an engineer and executive of the multinational energy group Enel, is the new chairman and CEO of PPC.
Former head, M. Panagiotakis, a product of PPC, with intense political and union activity, strong views and a history within the company, will be replaced with the dynamic young man, who has international experience, but apart from a multinational group, also knows the specifics of the Greek market when it comes to PPC itself with which he had relations from his time at Tellas, as well as the balance and trends in the sector (through his tenure at Enel Green Power Hellas).
The proposition to Mr. Stassis was formally made by the Hellenic Corporation of Assets and Participations (HCAP) board during PPC’s general meeting of shareholders.
Associates of the energy minister, Kostis Chatzidakis, mentioned that “George Stassis is an energy manager, has a carrier in a big multinational company, he has experience in restructuring energy businesses, he is young and he is a Greek who returns from abroad to help with the government’s effort”.
PPC’s new manager is expected to face a series of challenges that include among others negative financial results, the high cost of old production plants, the opening of the power market, the precipitation of investments in renewables etc.
As for the background of his selection, it turns out that only a close circle knew about the decision, even though ministry associates had described his profile: A young manager who climbed one of the biggest European companies ladder. According to information, Mr. Stassis was shortlisted along with three other candidates, whose CVs were chosen by energy minister K. Chatzidakis for the chair of PPC.
Mr. Stassis himself was notified a few hours before the ministry’s official announcement, of HCAP’s decision to nominate him and until the last minute, the timing of the announcement was an open issue. The ministry decided that a possible delay would break the positive momentum around the company and it wanted to give its own message about PPC’s future.
What Stassis’s choice means
On a symbolic level, the case of the 45 year old manager is the most fitting: He has years of experience in the power sector in one of the largest multinational European companies, where he distinguished himself with constant promotions, while having extensive knowledge of green and conventional energy in a tough market, such as Romania’s that has similarities and differences to the Greek market.
But the case of Enel is an example of lost opportunities for PPC, in the sense that the Italian company recently sold a large market share in Italy, transformed into an international group by taking advantage of the injected capital for its expansion, but also for the rapid growth of renewables, where it is considered to be among the top players globally. The new head of PPC has lived through this example and the restructuring of the Romanian market.
And, of course, after his return to Greece after a seven year carrier abroad, he sends another message of a successful businessman who returns home to act on the “brain regain”, that is the reversal of the brain drain that many notable Greek professionals did during the crisis.
“The right man at the right position”
What is interesting about Mr. Stassis’s case is that he is currently in his best professional phase and in that sense he does not enter PPC to finish his career and receive a good compensation bonus, but to make work of the expertise that he acquired in a difficult undertaking.
But how is he described by those who have close experience of him and what are their views about his decision to undertake the hard and demanding task of PPC?
His associated from his telecom days speak of the right man at the right position. His personality is described as simple, with multi year experience in a huge group, a man who during his tenure in Romania managed a company of similar or bigger size than PPC.
It is indeed interesting that like Enel’s CEO, Fransesco Starace who passed from the renewables arm to the mother company, Mr. Stassis transitioned from conventional power production to a market that lived through sales, privitizations, listings etc.
A manager from the green energy market who cooperated with him in ELETAEN speaks of a capable manager, both in economics and in development. The fact that he climbed rather quickly the ladder of a multinational is not random, he says.
Who is who
George I. Stassis was until now CEO of Enel Romania Srl, the greatest energy company in Romania.
Mr. Stassis worked in Italian group Enel SpA, where he was head of Enel Green Power for SE Europe and Middle East, responsible for countries like Greece, Bulgaria, Romania, Turkey and Egypt. He holds more than 13 years of experience in the energy market and has taken important positions in organizations and bodies of the sector.
From 2001 to 2006 he worked in Tellas Telecommunications S.A as a member of the executive team and as an Executive Director of Strategic Projects and Procurement.
He also holds the position of vice president of the board of the Foreign Investments Council in Romania, he is the chairman of the Coalition for Romania’s Development, while he is a member of the board of the Association of Utilities, the board of Trustees of Αspen Institute Romania and the board of CRE.
He was also a member of ELETAEN, a member of the Greek-American chamber’s energy committee and chairman of the energy committee of G20Y.
Mr. Stassis studied as a civil engineer in the Kingston University in the UK and he holds an MBA in Construction Management. He has taken part in executive programs for sustainable development in ELIS Management Academy, as well as Executive Leadership at Harvard University.
He is married with two children
Enel is a multinational energy company and a top player in global energy markets of natural gas and renewables. It is one of the biggest utilities and is included in the top power producers of Europe in terms of capacity and EBITDA. The group is present in 34 countries and it has power plants of 89 GW, while it sells power through a network of more than 2,200,00km with around 73 million residential and commercial consumers globally, the biggest number among its European peers. Enel Green Power, the renewables arm of Enel, manages more than 44 GW of wind, solar, geothermal and hydro plants in Europe, America, Africa, Asia and Australia.
Australian oil, gas and metal exploration company ADX Energy reported that it discovered hydrocarbons in several zones after drilling the Iecea Mica-1 (IM-1) well in Romania, according to globuc.com.
The report says that the potentially valuable commercial project exceeded expectations before drilling. The Pa V reservoir section represents a discovery containing a total gross hydrocarbon section of approximately 30 meters and contains at least 5 meters of a net reservoir with high-quality sandstone layers.
Another additional exploratory success is two relatively shallower Pa IIIinterval sandstones which are also associated with mud log gas shows and petrophysical pay. This discovery is of substantial significance for the proposed follow up IMIC-2 well, which is planned to drill 1.8 km NE of the IMIC-1 discovery.
The Pa V reservoir, which was not included in the predrill resource assessment, is assessed to be a gas-condensate discovery. A well IM-30 just 2.5 km further north and approximately 70 meters deeper at Pa V level tested 126 BPD of oil, ADX Energy reported.
The post ADX Energy has found hydrocarbons in Romanian well Iecea Mica-1 appeared first on EnergyWorld Magazine.
Romanian Black Sea: What should the government do to ensure the success of the current bidding round?
With the new long-awaited licencing round announced in Romania many questions and discussions arise. Globuc spoke to the President of Romanian Petroleum Exploration and Production Companies Association (ROPEPCA) – Saniya Melnicenco to see what this would actually mean for the Romanian upstream sector.
In Romania, the long-anticipated 11th concession round was announced for the exploration, development and production operations of 22 onshore and 6 offshore blocks within Romania’s territorial waters of the Black Sea. This latest round has especially been long- awaited by the upstream investors, as it opens up the sector to the new players and enhances its development.What do you expect from the new onshore bidding round in Romania?
The 11th licensing round for petroleum exploration blocks has been announced at a national level at the end of July and was long time expected by the oil and gas companies already present in Romania and abroad, since the previous round took place 10 years ago. The round represents an opportunity to put our country back on the investors’ map and to discover Romania’s under-explored potential, especially in the deep onshore. As it was stated last year by Government representatives in the public space, it is expected for Romania’s deep onshore potential to be higher than the already made discovery in the Black Sea.
Nevertheless, we believe that the round may represent a possibility for Romania’s economic development and for the diversification of the energy market, under condition of attracting new investment and entrance of more players in the sector. It can be a new breath for contractors and service providers, supporting titleholders’ activity, consequently bringing more business growth horizontally and creating new workplaces. Romania needs more investors, big and small, more know-how and new technologies, attracting and retaining talents and highly qualified specialists into its own industry. The state budget and the communities will be the first beneficiaries of new oil and gas projects. Every euro invested in oil and gas reflects in the national GDP, with a multiplication factor of 3.2.
However, for this round to be more successful than the previous exercise and to maintain a long-term investment climate, urgent stimulative measures need to be taken, having in mind the current operational context.What should the government & regulatory institutions do to ensure the success of the current round?
Without the right measures, Romania risks to remain noncompetitive and unattractive compared to other countries in the region. Several aspects need to be considered when investing in the petroleum industry, from both a national and global perspective. When it comes to stability and regulation, there is certainly a need for improvement in Romania, especially since in recent years more decisions have been made with negative effects on the industry.
The challenges faced by an investor in our industry are related to the three important components of the exploration strategy: accessibility of geological data, application of technologies and capital allocation. The regime of classified data puts the Romanian projects in the disadvantaged situation of under-funding and isolation from the globalised and digitally connected world. Also, bringing high performance technologies is closely linked to the existence of some qualified and experienced personnel in the field, assuming a considerable financial effort. The allocation of capital to exploration projects follows an adequate legislative and fiscal framework, as well as a reasonable rate of investment recovery, provided by the mechanisms of a functioning market.
Therefore, the vision for positive measures should revolve around three key elements: a predictable and stable regulatory and fiscal environment, modernisation of the relevant legislation to create more efficiency in operations and functional market mechanisms. In order for the energy sector to become truly competitive and diversified, functional market mechanisms and measures for the real protection of vulnerable consumers must be integrated. It is also necessary to stimulate the production activity by updating the legislation for streamlining petroleum operations, removing bureaucratic barriers and modernising the data regime.
ROPEPCA, in collaboration with state authorities and other market players, has developed a balanced proposal to amend the governing act for petroleum operations in Romania, the Petroleum Law, in a way that will bring it up to date.
Our expectation is that the Romanian authorities will shift views in a positive way: according to the draft Energy Strategy, is intended to stimulate long-term investments in the field of oil production, the document showing the importance of hydrocarbons in the entire energy picture for the next 30 years.
In the same time, the infamous Government Emergency Ordinance 114/2018, which has capped the price of gas for the producer and introduced a new contribution of 2% of the turnover, which has been in effect for 4 months, generated negative consequences in the market, such as the artificial increase of the unregulated price and the reduction of investments. Last week, the aforementioned provisions were called to be repealed by the Romanian Parliament.
This would be an important step forward and it is our expectation that more measures for incentivising investment and creating a functional, well balanced market will be taken in the near future. Such measures will have a significant impact on the national economy, new investments can be attracted, production would increase and ensure security of consumer supplyHow does Romania score in comparison to the other Black Sea countries in terms of opportunities for onshore producers?
In Romania, hydrocarbons account for 68% of the primary energy resources. In 2017, the crude oil production covered almost 32% of the demand, while the domestic natural gas production, resulted only from onshore deposits, covered 90% of the demand.
Despite the very good situation in terms of energy independence, Romania still has a great unexplored potential. Currently, approx. 400 oil and natural gas deposits are being exploited in the country. Most of these deposits are mature, with an operating life of over 25-30 years. In order to achieve increased production and a better understanding of Romania’s under-explored subsurface, large investments are necessary.
Since Romania did not offer new exploration blocks for 10 years, countries with a much lower geological potential have managed to attract investors over the past five years. We are talking about Hungary, Slovakia, Croatia, and now there are opportunities in Ukraine and Turkey.
In terms of the fiscal and regulatory framework in which the industry operates and which represent a prerequisite for the decision of entering the market, Romania still has room for improvement. Unpredictability of regulation represents an important concern for investors, as well as the rigid data regime and complex permitting process.
In this context our association decided to step in and to raise awareness of the authorities about the need for improvement and proposed functional solutions for the industry.
The outlook for the global wind market is on the upswing. According to Wood Mackenzie’s latest global wind power market update, global wind power capacity is expected to grow by 60 percent over the next five years.
The latest forecast shows a 5-gigawatt upgrade in the global offshore sector alone, yielding 129 gigawatts of new capacity and a compound annual growth rate of 26 percent for the burgeoning segment.
In the report Wood Mackenzie provides a comprehensive analysis of the global wind market and dive into key upgrades and downgrades by region, for both offshore and onshore segments. Below are a few highlights from this quarter’s edition.
Life beyond the U.S. PTC
Eligible offtakers are rallying to capitalize on the Production Tax Credit for wind before the full-value incentive expires in 2020 and then phases down. Developers qualifying wind facilities in 2017 are eligible for 80 percent of the full credit amount, incentivizing U.S. wind market growth.
New state-level targets in the U.S. and the strengthening of renewable portfolio standard mechanisms across the country are expected to support post-PTC demand.
As a result, Wood Mackenzie has upgraded its outlook for the U.S. market by 16 percent quarter-over-quarter, highlighted by a 3.8-gigawatt upgrade in 2021 alone.
A modest upgrade of 1 percent from last quarter in Latin America is driven by near-term upgrades in Brazil and Mexico. Demand in Brazil’s free market should positively impact expectations from 2020 to 2022, while an uptick in commercial and industrial demand in Mexico will support a record year in 2019.
European outlook dismal as subregions downgraded
The outlook in Northern Europe has been upgraded in the forecast by 6 percent. This should offset an otherwise dismal outlook update in Europe, as the other subregions combine for a 2.2-gigawatt downgrade.
Permitting challenges and undersubscription of onshore tenders in Germany and France have impeded growth. However, an increasing appetite for unsubsidized projects and a proliferation of demand from the C&I segment across Northern Europe both support a modest 0.6 percent upgrade for Europe over last quarter.
A challenge to Africa’s wind market
Slow project development due to political instability, immature support mechanisms and increasing competition from solar results has led to a slight downgrade in our forecasts for wind in Africa.
Clean energy ambitions in Africa are more prevalent than ever before, however. Renewable energy is attractive within the region, as wind and solar projects can be built much more quickly than other sources of energy. But as solar is becoming increasingly economical, Africa’s wind market faces stiff competition.
Policy deadlines boost near-term outlook in China
Onshore and offshore policy deadlines in China underpin a 2.9-gigawatt boost in the country from last quarter’s projections.
Onshore developers are rushing to comply with a new policy that requires projects to be commissioned by the end of 2020 in order to capitalize on feed-in tariffs (FIT) before a subsidy-free era begins. Offshore developers must commission projects before the close of 2021 if they are to utilize the current level of offshore FIT.
The story is not entirely positive in the Asia-Pacific region, however. Current market conditions in India have bruised the region’s near-term outlook, resulting in a 4 percent downgrade since last quarter’s report. The government-imposed auction ceiling prices and delays in commissioning awarded projects have slowed near-term growth expectations in India considerably — a decrease of 24 percent from 2019 to 2022.
Additionally, reliability concerns in Thailand have led to a 37 percent downgrade over the 10-year outlook, as the government’s focus has turned to other technologies.
Offshore wind farms may ultimately help Europe achieve its climate goals
According to an association of European grid operators, using a network of artificial energy islands as wind power hubs in the North Sea is a technically and economically feasible concept. The consortium, which includes TenneT, Energinet, Gasunie, and the Port of Rotterdam, proposed the project to meet the climate targets established by the Paris Agreement.
The North Sea Wind Power Hub (NSWPH) could play a major role in transitioning the UK, Denmark, the Netherlands, and Germany to a low-carbon energy system.
The NSWPH partners have been studying technical, environmental, and market perspectives to investigate the potential for the large wind collection hub. Last week, the consortium announced that their project assessment results showed that the concept is achievable.
“The North Sea holds a large potential for offshore wind power,” said the grid operators. Their research suggests that a series of smaller islands would be better than the initial vision of one large island.
Kees van der Leun is a sustainable energy expert and the director of Navigant, an international energy and climate consultancy that contributed to the research.
“It would be very transformative,” said Van der Leun. He explained that the proposed scale of wind farms is “completely beyond” what is operating off the coast of the UK and Germany today.
The first island hub could be developed by the early 2030s. For each individual hub, the goal is to have a network of wind farms with up to 15 gigawatts of capacity, which is enough energy to power more than 12 million homes across the UK. The biggest wind farms that are operating in the region today have a capacity of just over one gigawatt.
Van der Leun told New Scientist that the project’s success will primarily depend on whether it gets enough support from governments.
“Whether the project will happen depends largely on policy makers. If they set the right targets, appoint sufficient clustered offshore wind areas, set the right boundary conditions from a market and regulatory perspective the project is likely to go through.”
Romania has traditionally been an electricity exporter in the region over the last couple of decades, as its Communist-built power industry was large and diversified.
But commentators warn the situation is about to change due to output troubles generated by lack of investment, poor management and bad regulations.
Last year, Romania was still an electricity exporter, but the amount of exports was much lower than in previous years. But in the first quarter of this year the country became a net importer, left reliant on large imports to ensure the power needed by its businesses and households.
According to official data, Romania imported 1,125.5 million kWh over January-March 2019 and exported only 862.6 million kWh, putting the country’s electricity balance into the red. Electricity exports halved (down by -52.9 percent) in the first three months of this year, while imports rose by 78.5 percent.
This reliance on imports was due to a slump in power output, which was down by 10.8 percent compared with January-March 2018, associated with a slight decline in consumption, of 1.6 percent, during the same period. But the situation remains tense as Romania continues to rely on imports to cover its electricity needs.
Transelectrica data seen by BR show that even on a calm day like May 28, Romania imports electricity due to weak wind power output. Experts blame regulatory and tax measures.
“Romania has bigger problems with ensuring its real power production capacities. Causes? The regulatory and tax framework. We must quickly drop the obligation to trade energy produced by new capabilities on the stock exchange futures market. This regulation creates major problems with the financing of new investments,” said Razvan Nicolescu, a former energy minister and now energy consultant at Deloitte.
Large electricity imports are due to output troubles and to the electricity production structure. Romania has a diversified output structure but its coal electricity producers – all state-owned – are generating losses and need investments to stay in business. At the same time, almost all coal power capacities built during the communist era are outdated and need to be modernized.
Due to these problems, Romania relies heavily on its hydropower and nuclear energy suppliers, Hidroelectrica and Nuclearelectrica, both state-owned. But the two electricity sources cannot meet the whole consumption. The other available sources are gas-based power and wind and solar power.
The total power of the local wind turbines is 3,029 MW, but production from this type of power sources is very volatile in a country located far from the planet’s oceans and prevailing winds.
In eastern Romania, close to the Black Sea coast – where most of the local wind turbines are installed – wind is not constant, which means that wind power could fall from a peak to nothing in a couple of hours. However, some experts say that doubling the production capacity of wind power could solve some of the problems Romania is now facing.
The most stable and profitable energy producers in Romania, Hidroelectrica and Nucleaelectrica – which produce the cheapest electricity in the system – have been hit this year by the emergency ordinance 114/2018, which imposed a special tax of 2 percent on turnover and capped the profit margin at 5 percent for the energy supplied to households. Both companies need investments valued at billions of euros in order to ensure long-term electricity output.
But beyond taxes, Romania’s power producers, almost all state-owned, have faced other challenges. Running out of revenue sources, the government has forced the energy companies to pay extra dividends over the last couple of years to curb its large budget deficits, leaving the firms without money for investments.
Romania defers once again the EUR 1 bln coal fired power plant project
The shareholders of the Oltenia Energy Complex (CEO), more precisely the Romanian Government that holds the majority stake, refused to mandate the company’s management for starting negotiations for the construction of a new coal-mining group in Rovinari, Economica.net reported. The project is supposed to be developed under a public-private partnership with a Chinese group.
This is not the first postponement. China Huadian Engineering won the tender to build a 600 MW coal-fueled power plant in Romania, at Rovinari, in 2012. The cost of the project is estimated at EUR 1 billion. The first negotiations began in 2012, the talks were interrupted in 2016 and resumed at the end of last year.
The European Commission has recently urged Romania to revise the integrated energy and environment plan sent in its first form to Brussels and increase from 27.9% to 34% the targeted share for renewable energy in the country’s energy consumption in the horizon of 2030. However, the case for renewable energy does not invalidate the need for replacing the thermal power plants, a recent forecast by global consulting company ICIS suggests.
Romania’s thermal generation capacities will decrease rapidly toward the middle of the next decade, due to the high emissions costs and the capacities approaching the end of their lifetime. ICIS forecasts a 60% drop in installed capacity in coal-fired power stations and 45% in gas plants in Romania. Renewable generation capacities will develop slowly, given that the Government has set a low target, ICIS warns at the same time.
What will the liquefied natural gas (LNG) market of tomorrow look like? Today, a number of newer business models have emerged due to rapidly changing dynamics that have impacted the market, including increasing resource availability, new technologies and new sources of demand. According to Deloitte’s report, “Remodel, reinvent: How technology and changing business models are impacting the future of LNG”, the LNG market of tomorrow will be more flexible, liquid and accessible, shaped by new business models and technologies.
Over the last decade, the global natural gas supply industry has begun to move away from its traditional integrated model where major producers developed large, often stranded gas fields, built large liquefied natural gas (LNG) facilities and sold the cargoes to mainly large utilities.
Today, a number of newer business models have emerged due to the rapidly changing dynamics that are impacting the market, including increasing resource availability (e.g., US shale gas), new technologies (e.g., floating liquefaction – floating liquefied natural gas (FLNG), and floating storage regasification units (FSRUs)) and new sources of demand (e.g., China and India). While long-term contracts still make up the bulk of current trade, portfolio companies, tolling liquefiers, and networks of smaller buyers and sellers have grown substantially. Deloitte analyzed these new business models in 2016 report, “Work in progress: How can business models adapt to evolving LNG markets”. In this report Deloitte expands on that framework to address the impact of new technologies, new business models and changing supply and demand conditions.
To assess this impact, Deloitte conducted a survey of LNG market executives from around the world and across the value chain, including major producers, traders and buyers along with interviews with industry thought leaders. This report includes an overview of the LNG landscape with a focus on current supply and demand, and an analysis of how the industry’s business models have changed in the last few years and how they could continue to evolve. The report then highlights several major technologies driving the evolution including small-scale LNG, floating liquefaction and regasification, new gas-on-gas trading hubs, digitization (e.g., blockchain, data analytics and the Internet of Things) and more flexible financing. Lastly, the report outlines how different business models and new technologies could shape the LNG market of tomorrow – one that is likely to be more flexible, liquid and accessible.
Sources of near-term LNG supply and demand growth
While there are a number of high profile LNG projects in Asia, Europe, the Middle East and Africa, survey respondents expect more rapid supply growth from the Americas. This is likely driven by the number of high profile projects currently under construction in the US, combined with the LNG Canada project sanction (survey responses collected before the final investment decision (FID) was announced). East Africa, Qatar and Russia were also top of mind for respondents.
In contrast to supply, respondents see the most rapid demand growth in the Asia Pacific region over the next five years, with split expectations for other parts of the world. This appears to be driven by both demographic and economic growth as several countries including China, India and Pakistan were cited as the greatest sources of new demand over the next five years. China’s push to reduce environmental emissions and dependence on coal seems to have led to a recent increase in natural gas imports, including LNG. Other countries heavily reliant on coal, such as India, might pursue a similar strategy.
Short-term contracts, tolling models and technology
The LNG market is evolving and becoming increasingly dynamic and diverse. Recent demand trends support the responses from the survey, suggesting countries like China, India and Pakistan will play an outsized role in LNG demand growth compared to historically important buyers in Japan and South Korea. Moreover, as the number of buyers increase, new buyers may have more challenging credit ratings than traditional buyers, resulting in greater counter-party credit risk. This means small-scale, modular and floating technology will likely become increasingly important to offset new commercial risks not seen with larger, more traditional buyers. To that end, Deloitte asked respondents for their views across a range of technological, financial and market questions. Three key findings stood out:
- Between 2008 and 2017, spot and short-term LNG offtake contracts grew from 20 percent to 30 percent of volumes exported. Seventy six percent of respondents believe that these contracts will grow faster than overall LNG trade. This trend has important implications: • It could become more difficult to build new capacity as companies will not be able to rely on traditional long-term contracts to collateralize projects. • Buyers could see sales opportunities for trading houses, portfolio players and liquefiers with spare capacity as more attractive than LNG from yet-tobe sanctioned projects. • Brownfield and smaller or modular projects might become more appealing. Absent new financial products (e.g., a long-term, liquid LNG-focused futures market), our respondents also suggested that producers and financiers might need to be willing to accept higher market risk.
- In all cases, shorter contracts could mean slower supply of new capacity despite expectations. We could see the number of new, project-debt driven developments reaching FID decline as investment becomes more challenging. A pivot towards equitybased financing may only partially offset that decline, as seen with the recently sanctioned LNG Canada project. Equity financing however, is limited to those larger players who have access to sufficient capital to support these types of projects.
- US natural gas production has grown dramatically, from roughly 55 billion cubic feet per day (Bcfd) a decade ago to more than 80 Bcfd in 2018, and continued growth is projected. That has facilitated significant LNG export growth; from essentially zero a few years ago to 3 Bcfd in 2018. Based on current projects, exports could grow to more than 10 bcfd in the next five years. Combined with the emergence of accessible natural gas supply with transparent pricing (e.g., Henry Hub), a new business model that relies on tolling agreements rather than traditional oil-linked offtake contracts, has in part driven the growth of US LNG exports. These agreements rely on liquefaction as a service with specific per volume costs, rather than the all-in free on board or ex-ship LNG prices seen in other projects. This style of contract tends to provide flexibility to the buyer allowing them to procure their own natural gas and decouple LNG prices from liquids pricing (e.g., Brent or Japanese customs-cleared crude). Despite this, less than 20 percent of respondents think that companies could develop US-style tolling projects elsewhere. They cite a range of reasons including regulatory, market and project scale challenges. In particular, other countries face challenges in developing the large, liquid domestic natural gas markets to provide the security of supply needed for these types of contractual arrangements. However, these doubts may be short sighted – Canada has a large resource base driven by unconventionals, which could underpin tolling-style agreements for future projects. Similarly, Woodside and the Northwest Shelf LNG partners, several who are involved in the Browse project, are considering the use of tolling agreements in Australia. However, the business model is expected to remain challenging for those attempting to monetize stranded natural gas fields.
The industry appears to be unsure about how to best adapt and deploy new technologies. Approximately 60 percent of respondents say that digitization through big data analytics, machine learning and blockchain applications could have an impact on the LNG industry, with a particular interest in deploying blockchain to facilitate trade. A considered approach to execution will be critical due to both technical complexity and the difficulty in building consensus around a single system. When effectively implemented however, these types of systems could increase transaction price and volume transparency and reduce the time required to settle trades. The international consortium, VAKT supported by a number of producers, traders, and banks have been developing a digital ecosystem using blockchain to enable secure and transparent post trade transacting. However, with limited blockchain deployments to date, mainly in small-scale renewable power markets, application to the LNG markets seems far off. This space continues to evolve as market participants’ needs are evaluated and technologies are developed. Based on Deloitte’s 2018 Oil, gas and chemicals executive survey and The Industry 4.0 paradox report, blockchain appears to be a longer-term aspiration. Blockchain could provide integrated digital trading infrastructure that allows cargo to be traded and tracked more easily. This would enable the use of smart contracts to simplify the trading process, which could deliver significant value to the industry. However, in the shorter-term, big data analytics seem to be a high priority which provides the opportunity to optimize the timing of LNG shipping and reducing energy usage in the liquefaction and regasification process. This, unlike blockchain, will likely be a series of smaller incremental projects rather than an industry-wide disruptor.
A combination of opportunities and threats
In 2016 report LNG at the crossroads: Identifying key drivers and questions for an industry in flux, Deloitte outlined seven factors that could shape the LNG market. Some factors, such as the cost of shipping, are cyclical, while others, such as economic growth, appear to be secular. Two years on, several of these factors still affect the industry and are contributing to rising demand. – Table 1
The survey respondents agreed that these trends matter, with 70 percent of survey takers expecting that Asia Pacific LNG demand will rise by more than six percent over the next five years, with 50 percent saying the same for Europe, the Middle East, and Africa. This is driven by several factors including global growth, which has been robust and is projected to continue at almost four percent per year for the next five years, barring a recession or similar. The sharp rise in 2010 is due to increased capacity that came onstream due to newly-commissioned liquefaction trains in 2010 as well as from the ramp-up in output from trains commissioned in 200912. Due to the discreteness of LNG supply as well as project size and timing, the relationship between LNG and the macro-economy is not quite as clear.
LNG demand and economic growth are not well correlated. Secondly, more than 35 countries import LNG today, compared to roughly 20 only a decade ago. Thirdly, new markets like LNG as a transport fuel are growing, adding new sources of demand alongside more traditional applications. Environmental concerns are also driving these trends. For example, China’s demand for natural gas is due not only to the need to provide energy, but also to displace higher polluting energy sources like coal by increasing the share of gas in the primary energy mix to 10 percent by 2020 (up from six percent today). Similarly, LNG bunkering provides an alternative to high sulfur fuel oil that will not meet new IMO 2020 regulations.
Adapting existing business models
In the report, “Work in progress: How can business models adapt to evolving LNG markets?”, Deloitte identified six major LNG market participants: large scale integrated producers, portfolio companies, tolling or contract liquefiers, traders, large utility buyers and consortiums, and small-scale utilities. These companies span the global gas value chain: drilling wells, operating producing fields, gathering systems and pipelines as well as liquefaction, trading, transport and natural gas consumption. – Table 2
These six company types are well represented in our survey’s respondents. They believe that short-term trading will play an increasingly significant role in LNG. Additionally, they do not see companies developing US-style tolling projects in other countries (with the potential exception of Canada) and the potential benefits from digitization remain uncertain. These trends could potentially slow capacity growth and delay the construction of new greenfield plants as markets rely on shorter-term, more flexible and potentially more volatile contracts. The challenge could be to square the circle, with LNG buyers seeking flexible, shorter-term contracts while potential sellers are typically looking to develop conventional liquefaction projects. If LNG producers are exposed to increased market risk in both the short and long term, then producers have an incentive to reshape how these projects are designed, financed and executed. Traders and buyers may have less incentive in the short term, but the benefits of a more efficient, transparent market could be worthwhile pursuing. Reshaping the markets would present different business models with alternative risks and rewards. While respondents may not be sure how the LNG market will evolve, it is clear there are opportunities for business model transformation. Companies with historic ties to the industry including integrated producers, portfolio players and large-scale utilities will need to adapt as the market becomes more flexible. If larger buyers are unwilling to sign multidecadal, fixed-term sale and purchase agreements, operators of major liquefaction projects may be exposed to increased market risk. As mentioned previously, this could reduce access to limited-recourse financing. If project level debt is less accessible than in the past, these companies seem to have two options: corporatelevel debt or project equity financing. Neither the idea of using corporate debt to fund large project nor cargo buyers investing equity in a liquefaction project is new, but could be a challenge.
Looking further into the future, there is an opportunity to push LNG industry financing further. An offtake agreement, like a contract, guarantees certain payments in exchange for either tangible goods (e.g., LNG cargoes) or intangible rights (e.g., access to capacity) with an array of caveats and conditions. While not widely discussed within the industry today, there is an opportunity to separate certain parts of sales and purchase agreements from the corporate entities that are part of a transaction. Although not necessarily common in oil and gas outside of overriding royalty agreements or perhaps petroleum service contracts, other industries have made similar shifts. For example, commercial or residential property can be sectioned into economic interests (e.g., real estate investment trusts or mortgage-backed securities), facility management contracts and tenant leases (or sublease in the case of shared workspace companies). This way multiple parties can share various costs, benefits and obligations of using property, while not necessarily being responsible for all aspects. In the case of LNG, a project could be structured with an operator who develops the project but has limited or no equity in the project and is compensated through an ongoing management fee. Using that structure, it would be possible for small increments of offtake capacity from one project, or a portfolio of projects without destination restrictions, to be sold through either an auction-type system or direct negotiation. These shares would entitle the holder to a certain number of cargoes per year in exchange for an ongoing payment, similar to an option premium, thus mimicking features of a take-or-pay clause in a traditional contract. By securitizing LNG capacity, projects could be financed by those who may only have short-to-medium term interest in the project, because they could later re-sell their shares while assuming market risk due to shifts in value of the underlying asset. Undoubtedly, new (or even existing but atypical) financial structuring will likely face challenges during adoption.
However, even if these companies are not currently interested in corporate debt or equity financing for LNG projects, they may not have much of a choice going forward, unless the market tightens significantly and contract durations begin to lengthen. Otherwise, greenfield facilities could have trouble securing capital to reach the final investment decision. There is an incentive to innovate if the alternatives are unavailable. If larger companies tend to lack flexibility, smaller market participants could lack access. For a regional utility providing natural gas to a city or a power utility that derives the bulk of their energy from intermittent or variable sources like hydro, wind or solar, LNG could provide an appealing alternative to cope with the intermittency issues. However, with a typical large offtake contract running 20 years and sometimes requiring the purchase of two million tonnes per annum (roughly 260 million cubic feet per day) under take-or-pay terms, would likely prove too onerous to be feasible. Thanks to FSRUs, a cyclically soft market over the last few years and increased activity from trading houses, smaller, shorter and spot contracts have been available to non-traditional buyers, though credit-worthiness could remain an issue. However, if markets tighten, and there are signs that they have already, these smaller buyers could face challenges procuring spot or short-term contracts at affordable prices. Trading organizations could provide liquidity (for a price) and a futures market could provide some price-risk mitigation. However, respondents were split on the timing of future markets, unsure whether we would see a major futures hub develop in the next couple of years, over the next six years or beyond. More specifically, half of respondents thought that if a hub develops it would likely be in the Asia Pacific region in countries like China, Japan or Singapore. For a power company in Brazil, Asian LNG futures may prove a poor hedge for market risks in the Atlantic basin as gas prices have diverged in the past. Like larger companies, smaller ones could also benefit from securitization. If a buyer is not a creditworthy counterparty, they could struggle to secure capacity via a traditional contract, particularly if they are seeking to purchase relatively small volumes. A tradable equity share in a project, however, could provide the flexibility of a shorter-term contract with an asset that could be used as collateral for debt financing. There would be some equity-type risk associated with project ownership, but trading houses could be willing to assume asset and LNG price volatility risk in exchange for either payment or a portion of offtake volumes. These structures would have to evolve in line with both market needs and as companies better understand their own energy needs and appetite for financial risk. If companies look to novel financing structures and more flexible terms to transform their business models, the existing physical assets will not change. In the future, however, the physical and digital process used to transport, liquefy and market natural gas in the form of LNG may need to change to better match the changing industry, perhaps by deploying relatively new technology.
Technology as a catalyst for business model transformation
What opportunities are there for technology to bridge the gap between buyers and sellers as LNG markets evolve? It typically comes down to flexibility, transparency and efficiency. While respondents were unsure how exactly technology could be used, three key points came to the forefront: modular projects, blockchain and big data. Whether it is trading spot contracts or the execution of a LNG-backed equity agreement, the LNG market is likely to become increasingly flexible. FLNG and FSRUs should play a role as companies can deploy them more quickly and at smaller scales than traditional facilities. Similarly, small and microscale LNG appear to make sense in a world where demand is increasingly fragmented, whether due to demand from shipping or to supplying a number of intermittent buyers. In both cases, reducing unit costs might be the biggest challenge as they may be a good fit for where the market is heading. The survey respondents expect smaller-scale LNG to grow faster than the overall market. The next few years may prove that to be correct. Blockchain could pose more of a challenge, which organizations like the digital trading platform VAKT are working on. Respondents said that it could be used to improve transparency and optimized LNG trading, but other studies looking more broadly at oil and gas technology deployment, have found that blockchain is often viewed as longer-term opportunity. That being said, as LNG becomes increasingly securitized and the number of cargoes traded increase, there could be a need for increased transparency and access to a global transactions platform. Particularly in the case of multiparty LNG project-backed equity structuring, smart contracts could provide a means to simplify execution. Moreover, the lack of legacy systems could mean greater opportunities for novel solutions. While the specific technology used to underpin the system could be up for debate, greater collaboration around the financing and financial structure of the LNG market will likely be needed. Big data is a buzzword that applies to a range of projects crossing multiple industries including oil and gas, broadly including the use of large data sets (potentially sourced from IoT-type sensors) and high-powered analytics to generate novel insights and drive innovation. The potential benefits seen elsewhere in the industry apply in part to LNG as well. There are opportunities to cut energy and materials waste, increase operational uptime with predictive maintenance and improve the design of supply chains. In the case of the latter, it would need to be considered on a case-by-case basis. Many projects still include significant volumes exported under long-term contracts with fixed destinations. Optimizing routing and procurement processes may therefore be limited. Spot volumes, portfolio players and trading houses, however, might find new analytical tools useful in executing trades in an efficient manner.
Population growth, increasing economic prosperity in developing nations, government regulation and actions focused on improving air quality will drive demand for lower-carbon energy globally. As a result, LNG will command an increasing share of the global fuel mix given its lower-carbon footprint and its ability to flexibly supply increasingly diverse markets, customers and applications – ranging from power generation to marine and land transportation. Based on the survey, respondents expect consumption to increase in the Asia Pacific region over the next five years, most notably in China, India and Pakistan, with the bulk of new supply coming from the US among others. However, with respondents expecting spot and short-term contracts to grow (along with small-scale and floating LNG), the market could become increasingly fragmented and difficult to finance. Why is that? Many recent projects have been financed by project-level debt that required long-term sales and purchase agreements. We have seen some equityfinanced projects announced (e.g., LNG Canada), but it remains to be seen if that will be replicated elsewhere. Additionally, US export growth has been driven by tollingstyle agreements that may not be readily adaptable to other countries. Now is the time for companies to evolve and adapt to keep pace with market changes. Moreover, new technologies ranging from big data to blockchain could be used to reduce costs, improve logistics and simplify transactions. The next five years will be a challenging and dynamic period for LNG producers, traders and buyers as they navigate a rapidly evolving market and adapt new technologies and business models. One thing is certain, the global LNG industry will continuously remodel and reinvent itself in order to deliver energy to a rapidly growing and changing world.
US-based energy investment company Trident Acquisitions has announced that it has won a public competition to explore and produce oil and gas from Ukraine’s offshore Dolphin block at the northwestern corner of the Black Sea’s continental shelf. Ilya Ponomarev, company CEO talked to Globuc about the oil & gas industry prospects in Ukraine and his company plans.
The first question is about the overall situation in the Ukrainian oil and gas production in the context of the situation in other countries of the Black Sea region with a focus on the advantages and disadvantages of investing in this industry.
The current legal structure and business practices in the oil and gas sector of Ukraine has become better not just in the entire Black Sea basin, but in Europe as a whole. The country enjoys low royalty rates while authorisation procedures work very fast, if not always transparent.
The loose legal framework is Ukraine’s main problem. The country was formed not long ago and decisions can often be revisited as a result. Some people can sue you out of the blue, and you’re going to have to stand trial, wasting time and energy. A local council, for one, might throw a spanner in the works over environmental or other commitments.
Everything is resolved in the final run but plain vanilla Western investors can be at a loss sometimes, as this is not what they are used to. That’s the downside.
These things, however, do not dampen our company’s positive outlook on investing in Ukraine.
Romania has traditionally been seen as the leader in the region. Ukraine is now increasingly hitting the news, but there is still ambiguity about what exactly should be produced there.
Romania has been thought of as leader in Romania, but in Ukraine it is Ukraine that has been considered the leader. Romania is rich in oil whilst Ukraine is rich in gas.
According to our geology experts, doubling this volume with the modern technology should not be a problem at all.
The technological capacity in Ukraine is not up to scratch and there is a shortage of personnel because qualified geologists and reservoir engineers have been leaving for Russia over the past 30 years to work on larger projects and better salaries. Therefore it is hard to source qualified staff within Ukraine now. Lots of people have to be recruited elsewhere. And it’s a challenge.
Ukraine is not a country for large companies, it seems. It is better suited to small and medium-sized companies with a production under 5 MBOE. An ExxonMobil would not work there, but several successful players can handle a few million tons of production.
What challenges and difficulties can the development of the Dolphin block present?
Legal wrangles are still on going around it. Our company has been nominated the preferred provider alongside San Leon (Ireland) and GSP (Romania). The [Ukrainian Energy and Coal Industry Ministry] Interagency Commission submitted its conclusion on the winners of the bidding process but the Cabinet of Ministers has not yet approved the results. There is still time to do this, two months till the end of September.
The new Ukrainian government believes that large companies like ExxonMobil may resume working in Ukraine, although the said ExxonMobil has just withdrawn from Romania where it developed a field just a few kilometres from the Dolphin.
The block contains three areas licensed to Chernomorneftegaz seized in the run-up to Crimea’s forceful annexation by Russia. We believe that these areas will become available after Ukraine wins the case against Russia over the annexation of Crimea. The case has been submitted to an international tribunal, and the adjudication of Naftogaz’ 5-billion-dollar claim against Russia has begun
We want to include these areas in the overall development scope; they can have quite a significant yield.
Do geopolitical challenges play an important role then?
They play virtually the primary role. We suspect that some participants of the tender, which was rather intense and competitive, were backed by Russia, attempting to prevent Ukraine from starting the development of this block.
We are insured against war risks by the United States government, and we believe that the Russian Federation can be into some funny business in that area. This block is beyond Russia’s claims even theoretically, as it is closer to Romania than to Crimea, but you never know. The events of the last five years demonstrate that it’s all very complicated.
What are your company’s strategic plans for the near future?
We were established three years ago. A little over a year ago, we got a listing at the NASDAQ stock exchange, pulled off an IPO, raising 200 million USD in the process.
The original strategy was to acquire a core company in Eastern Europe, most likely in Ukraine. The next step would be to inject American oil and gas production technologies into this company and to invest into the development of the Black Sea shelf. We have followed this strategy so far and are in takeover negotiations with several Ukrainian and American companies.
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