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Nord Stream Nr. 2: The Project’s Implications in Europe

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Russia, Germany and a consortium of Western European companies have re-activated the Gazprom-led Nord Stream Two gas pipeline project. Parallel to the existing Nord Stream One pipeline on the Baltic seabed, Nord Stream Two would double the system’s total capacity to 110 billion cubic meters (bcm) annually, all earmarked for direct delivery to Germany.

Nord Stream is billed as the world’s biggest natural gas transportation project, in terms of pipeline length and throughput capacities. Initially announced in 2011–2012 through non-binding agreements of intent, Nord Stream Two had to be shelved for the duration of Europe’s economic slump. The project agreement signed on September 4, 2015, however, is binding. Gazprom’s management anticipates economic-financial recovery in Western Europe and, consequently, gas demand recovery by 2019, the target date for completing Nord Stream Two. It also expects gas extraction to decline in Norway after having been capped in the Netherlands, thus boosting European import demand (Gazprom.com, accessed September 14).

The project’s other role is to bypass Ukraine’s gas transit system, its continuation through the Slovakian and Czech transit corridors, and potentially Poland’s. Those transit routes are beyond Gazprom’s control. The Kremlin intends to re-direct the lion’s share of its gas exports to the “old” European Union into the Gazprom-controlled Nord Stream route. This would not merely deprive Ukraine and those other countries of transit revenue. Strategically, it would result in Gazprom controlling gas transportation as well as the supply to Western European customers.

Gazprom claims that it would, in due course, deliver “new gas”—i.e., gas sourced from newly developed fields—through Nord Stream. But it has not identified those resources; its barely disguised near-term intent is to switch the flow from Ukrainian pipelines into Nord Stream. For years to come, gas volumes diverted from Ukraine will be Nord Stream’s main resource.

In the short and medium term, Nord Stream Two strengthens Russia’s hand against Ukraine and a number of Central-Eastern European countries. Gazprom will henceforth be able to bypass or cut off these countries—or extort concessions under such threats—before these countries would have made arrangements with non-Russian suppliers.

As a bypass project, Nord Stream Two is potentially more effective compared with South Stream (in its various configurations). Bypassing Ukraine, South Stream would have changed Gazprom’s export route but would have targeted basically the same markets. Nord Stream Two, however, aims to break into new, highly lucrative markets in northwestern and western Europe. Or by words of prof. Anis Bajrektarevic: “This arching pipeline network eliminates any transit barganing premium from Eastern Europeans and poses in effect a joint Russo-German pressure on the Baltic states, Poland, Ukraine, and even as far as to Azerbaijan and Georgia.”

The European Commission finally blocked South Stream on the legal level at the end of 2014; and the other southern bypass option, Turkish Stream, looks no more convincing in 2015, even to Moscow, than its closely resembling predecessor Blue Stream Two had looked a decade ago. Thus, Moscow has turned to Nord Stream again in the new circumstances and based on its forecasts of medium-term market demand (see above).

If completed as designed, Nord Stream Two could cement the Russo-German special partnership in the energy sector for the long term, with ramifications in the financial sector and foreign policy.

Germany is the exclusive designated recipient of Nord Stream gas. This evolution casts Germany in a new role, on top of Germany’s familiar role as Europe’s leading importer of Russian gas. Nord Stream Two promises the much-coveted status of an “energy hub” for Germany. It opens the prospect for Germany to become the main center for the transit and storage of Russian gas and its onward distribution in Western Europe. This would mean higher sales revenues for German energy companies, as well as a potential windfall from transit fees and taxes accruing to the German federal and state budgets. Even if Nord Stream One and Two operate (as seems likely) below their combined capacity of 110 bcm per year, the volumes carried into Germany could be staggering in magnitude. The prospects of transit and tax revenue on such a scale must be a significant consideration behind the German government’s support for Nord Stream Two.

Designating Germany as the privileged “hub” country is not an entirely novel idea in Moscow. In 2006, President Vladimir Putin had publicly offered to select Germany as the distribution center for Russian gas in Western Europe. Counting at that time on the development of Russia’s supergiant Shtokman field, Putin proposed to export Shtokman gas through the then-planned Nord Stream One pipeline to Germany, for onward distribution to other EU countries. The Shtokman project, however, turned out to be unfeasible and was abandoned in 2012.

Putin’s stillborn offer to Germany in 2006 would not have affected the Ukrainian transit of Russian gas to the European Union, given that Shtokman gas would have been “new gas,” not diverted from the Ukrainian transit system. Now, however, Russia is at war in Ukraine and is enlisting Germany into this anti-Ukrainian project. It can also be viewed as an anti-EU project, insofar as it enables Gazprom to replace a transportation route beyond its control with a route under its control.

Part Two

Within Germany, Nord Stream has spawned a system of gas transmission pipelines and storage sites, dedicated to handling Gazprom’s gas en route to German and other countries’ markets. That system’s ownership and operation pose serious challenges to the European Union’s energy market and competition norms. Those challenges will mount, if and when Nord Stream Two adds another 55 billion cubic meters (bcm) to Nord Stream One’s 55 bcm in annual capacity. From 2012 to date, Nord Stream One has operated at about half-capacity.

The dedicated infrastructure on German territory includes the OPAL and NEL transmission pipelines and the Rehden and Jemgum storage sites, all intended to operate in conjunction with Nord Stream One and Two. Gazprom and other Nord Stream stakeholders in various combinations also own and operate OPAL, NEL, Rehden and Jemgum. Alongside that dedicated system, Gazprom and Wintershall jointly operate another gas transmission network that can also be fed with gas volumes from Nord Stream One and Two.

The European Commission had, all along, viewed those plans as aiming to create vertically integrated monopolies. The Commission used its authority and legal powers to resist such arrangements (e.g., restricting Gazprom’s use of OPAL to one half of that pipeline’s capacity). For their part, the German government and regulatory agencies allowed Gazprom to expand its pipeline and storage assets in Germany through joint ventures with German companies. A flurry of such takeovers were agreed upon in 2013 and early 2014, linked with the completion of Nord Stream One and the expected agreement to build Nord Stream Two. Russia’s military intervention against Ukraine in February 2014, however, made it politically impossible for Germany to complete those transactions.

Germany’s time-out is now over. On September 4, Gazprom’s buyout of Wintershall’s gas trading and storage was finalized, and the Nord Stream Two shareholders’ agreement was signed. The agreement has created the New European Pipeline AG project company to build and operate Nord Stream Two. The companies’ press releases stopped short of identifying the chief executive of the New European Pipeline AG project company. Gazprom’s photo of the signing ceremony, however, shows an uncaptioned Matthias Warnig signing the Nord Stream Two agreement, alongside the presidents/CEOs of the stakeholder companies (Gazprom.com, accessed September 14). As managing director of Nord Stream One since that project’s inception, Warnig will apparently hold the same position in Nord Stream Two. Nord Stream Two’s shareholding largely overlaps with that of Nord Stream One and with the shareholdings of the dedicated onshore pipelines and storages in Germany.

These actions are already accompanied by pressures from the interested companies and the German government to override EU energy market and competition legislation. German Finance Minister Wolfgang Schaeuble apparently proposes transferring some of the European Commission’s anti-trust competencies to other authorities, not publicly specified as yet. Germany’s own anti-trust and regulatory agency, the Bundesnetzagentur, does not object to Gazprom’s monopolistic use of the OPAL and (in prospect) NEL pipelines (Naturalgaseurope.com, September 3).

According to the European Commission, the offshore Nord Stream One was implemented in line with EU law at that time, but “the Commission will ensure that Nord Stream Two, if implemented, fully complies with the EU’s Third Package of energy legislation.” And “any pipelines, whether northern or southern, on EU member countries’ territories must be fully compliant with EU legislation (Bloomberg, UNIAN, September 11). This official statement alludes, first, to the fact that the Third Package was not yet in force when Nord Stream One was built, but has entered into force since then. It further alludes to the European Commission’s effective use of EU law to block South Stream—that other Gazprom-led project in Europe.

The European Commission’s vice-president for the Energy Union, Maros Sefcovic, has announced “a host” of questions to be raised on Nord Stream; e.g., Does it correspond with the EU’s supply diversification strategy? What does it mean for Central and Eastern Europe? What conclusions should be drawn, if this project aims practically to shut down Ukraine’s transit route? “All projects of this magnitude would have to comply with EU legislation,” he declared (Politico.eu, September 7, 11; UNIAN, September 11; BTA, September 15).

Part Three

According to the European Union’s Energy Commissioner Miguel Arias Cañete, Ukraine is a “reliable transit country,” while Nord Stream Two does not help diversify supply sources, hence “it is not a priority” in terms of EU policies (Naturalgaseurope.com, September 3). “Not a priority” was also the European Commission’s standard diplomatic phrase when blocking South Stream. The phrase implies (inter alia) no access to EU funding, which is reserved for projects of common interest in the trans-European network-energy (TEN-E) category.

Austrian OMV’s entrance into the Nord Stream Two consortium is noteworthy, both politically and from a business perspective. OMV is the majority owner of the Central Europe Gas Hub (CEGH), at Baumgarten, near Vienna. This was the planned terminus of two major, rival pipeline projects: the EU-backed Nabucco and the Gazprom-led South Stream, both defunct. The CEGH’s remaining role is that of terminus of the Ukraine-Slovakia gas transit corridor to Europe. But the transit volumes have been falling sharply in recent years in that corridor; down to some 40 billion cubic meters (bcm) in 2014. Nord Stream Two threatens to kill that corridor altogether, by switching Russian gas flows from Ukrainian pipelines into Nord Stream.

Hence, OMV has joined Nord Stream Two to keep the CEGH alive, apparently expecting to connect Baumgarten, ultimately, with Nord Stream, via the OPAL and Gazela pipelines in Germany and the Czech Republic. OMV’s new president, Rainer Seele, has indicated at this possibility (Naturalgaseurope.com, August 12). Seele was Wintershall’s president until July 2015 and is closely aligned with Gazprom. Presumably, Seele’s value to OMV is to unlock Gazprom’s doors more widely for the Austrian company, and keep the CEGH alive by connecting it with Nord Stream (Vedomosti, September 4).

If Nord Stream Two kills the Ukrainian transit route—with Slovakia as collateral victim—Hungary could be left up in the air. Ukraine is the sole existing route for Russian (or any) natural gas into Hungary.

Re-routing gas flows from Ukraine into Nord Stream would also affect Poland and the Czech Republic adversely, albeit less dramatically than it would affect Ukraine, Slovakia or Hungary.

Czech dependence on Russian gas stands at about two thirds of the Czech consumption of some 9 billion cubic meters (bcm) annually. In recent years. The Czech Republic also provides transit service for Russian gas to Germany.

The Czech Republic’s pre-existing two trunklines are traditionally sourced with Russian gas from the Ukraine-Slovakia transit corridor. The new pipeline, Gazela, is dedicated to Russian gas to be sourced from Nord Stream, which feeds directly into the OPAL pipeline in Germany, thence to connect with Gazela in the Czech Republic. According to calculations in 2014, Russian natural gas reaching Central Europe via the Baltic sea entails far higher transportation costs—and, thus end prices—compared with the same volumes of Russian gas reaching Central Europe via Ukraine.

Poland, in the last two decades, has provided transit service for Russian gas through the Yamal-Europe pipeline, with an annual capacity of 35 bcm, which runs via Belarus and Poland into Germany. New transport capacity in Nord Stream Two would enable Moscow to either re-direct gas volumes into that offshore pipeline, bypassing Poland, or threaten to do so in order to re-negotiate supply and transit terms with Poland in Russia’s favor under duress. Re-negotiations are due ahead of 2022.

In Europe’s southeast, however, Gazprom has no bypass solution available. Gazprom will have to continue using the Ukrainian transit route in order to supply Moldova, Romania (which has almost stopped importing Russian gas in 2015), Bulgaria, Greece, and western parts of turkey. That would amount to an aggregate volume of up to 10 bcm per year, transiting Ukraine en route to the Balkans.

Whether Gazprom has the gas volumes available to deliver 55 bcm annually through Nord Stream One by 2019, and a total of 110 bcm annually through both lines after that year, seems doubtful, even by switching most of the flow from Ukraine, if Nord Stream Two ultimately materializes.

 

First published by the INGEPO Consulting’s Geostrategic Pulse magazine

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Are aviation biofuels ready for take off?

Pharoah Le Feuvre

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Air travel is booming, with the number of air passengers set to double over the next twenty years. Aviation demand is particularly evident in in the Asia Pacific region, where growing economic wealth is opening new travel opportunities.

Aviation accounts for around 15% of global oil demand growth up to 2030 in the IEA’s New Policies Scenario, a similar amount to the growth from passenger vehicles. Such a rise means that aviation will account for 3.5% of global energy related CO2 emissions by 2030, up from just over 2.5% today, despite ongoing improvements in aviation efficiency.

This expansion underscores the need for the aviation industry to tackle its carbon emissions. For now, liquid hydrocarbon fuels like jet fuel remain the only means of powering commercial air travel. Therefore, along with a sustained improvement in energy efficiency, Sustainable Aviation Fuel (SAF) such as aviation biofuels are key to reducing aviation’s carbon emissions.

The International Civil Aviation Organization (ICAO), which governs international aviation, has committed to reducing carbon emissions by 50% from their 2005 level by 2050. Blending lower carbon SAF with fossil jet fuel will be essential to meeting this goal. This is reflected in the IEA’s Sustainable Development Scenario (SDS), which anticipates biofuels reaching around 10% of aviation fuel demand by 2030, and close to 20% by 2040.

The aviation industry demonstrates a strong commitment to sustainable aviation fuel use

The first flight using blended biofuel took place in 2008. Since then, more than 150,000 flights have used biofuels. Only five airports have regular biofuel distribution today (Bergen, Brisbane, Los Angeles, Oslo and Stockholm), with others offering occasional supply. But the centralised nature of aviation fuelling, where less than 5% of all airports handle 90% of international flights, means SAF availability at a small number of airports could cover a large share of demand.

Another indication of aviation’s commitment to growing SAF use is the agreement of long-term offtake agreements between airlines and biofuel producers. These now cumulatively cover around 6 billion litres of fuel. Meeting this demand will require further production facilities, and some airlines have directly invested in aviation biofuel refinery projects.

Still, aviation biofuel production of about 15 million litres in 2018 accounted for less than 0.1% of total aviation fuel consumption. This means that significantly faster market development is needed to deliver the levels of SAF production required by the aviation industry and keep on track with the requirements of the SDS. 

Technology development is essential to increase aviation biofuel availability

Currently, five aviation biofuel production pathways are approved for blending with fossil jet kerosene. However, only one – hydroprocessed esters and fatty acids synthetic paraffinic kerosene (HEFA-SPK) fuel – is currently technically mature and commercialised. Therefore, HEFA‑SPK is anticipated to be the principal aviation biofuel used over the short to medium term.

Meeting 2% of annual jet fuel demand from international aviation with SAF could deliver the necessary cost reduction for a self-sustaining aviation biofuel market thereafter. Meeting such a level of demand requires increased HEFA-SPK production capacity. If met entirely by new facilities, approximately 20 refineries would be required. This could entail investment in the region of $10 billion. Although significant, this is relatively small compared to fossil fuel refinery investment of $60 billion in 2017 alone.

Ongoing research and development is needed to support the commercialisation of novel advanced aviation biofuels which can unlock the potential to use agricultural residues and municipal solid wastes. These feedstocks are more abundant and generally cost less than the waste oils and animal fats commonly used by HEFA-SPK, and can therefore facilitate greater SAF production. Furthermore, synthetic fuels produced from renewable electricity, CO2 and water via Power-to-Liquid processes may offer an alternative fuel source for aviation in the long term.

Improved aviation biofuel cost competitiveness with fossil jet kerosene is also needed

SAF are currently more expensive than jet fuel, and this cost premium is a key barrier to their wider use. Fuel cost is the single largest overhead expense for airlines, accounting for 22% of direct costs on average, and covering a significant cost premium to utilise aviation biofuels is challenging.

The competitiveness of SAF depends on its production cost relative to that of fossil jet kerosene (which varies with crude oil price). For all biofuels obtaining an economic feedstock supply is fundamental to achieve competitiveness, as feedstocks are the major determinant of production costs. For HEFA-SPK economies of scale could be realised by refineries designed for continuous production.

In the long term, airlines may include SAF consumption cost premiums within ticket costs. At current prices and today’s fleet average energy efficiency, the additional cost per passenger for a 15% blend of HEFA may not be high in comparison with other elements that influence ticket prices, such as seating class, the time of ticket purchase and taxation. However, due to the competiveness of the aviation industry customer price sensitivity is a core consideration for airlines.

Policy measures are crucial to stimulate sustainable aviation fuel demand

Impressive progress has been made in the utilisation of SAF since the first biofuel flight ten years ago. However, to fulfil aviation biofuels’ potential to reduce the climate impact of growing air transport demand, further technological development and improved economics are needed.

There is a key role for policy frameworks at this crucial early phase of SAF industry development. Without a supportive policy landscape, the aviation industry is unlikely to scale up biofuel consumption to levels where costs fall and SAF become self-sustaining.

Subsidising the consumption of SAF envisaged in the SDS scenario in 2025, around 5% of total aviation jet fuel demand, would require about $6.5 billion of subsidy (based on closing a cost premium of USD 0.35 litre between HEFA-SPK and fossil jet kerosene at USD 70/bbl oil prices). This is far below the support for renewable power generation in 2017, which reached $143 billion.

Other policy measures that could support SAF market development include:

  • Financial de-risking measures for refinery project investments (e.g. grants, loan guarantees).
  • Measures to provide guaranteed SAF offtake, e.g. mandates, targets and public procurement.
  • Other mechanisms that close the cost gap between SAFs and fossil jet fuel e.g. carbon pricing.

Countries have more control over policy support for domestic than international aviation, and the introduction of national policy mechanisms to facilitate SAF consumption is gathering pace. The United States, the European Union, the Netherlands, the United Kingdom and Norway have all recently established policy mechanisms which will support the use of aviation biofuels. To gain the confidence of policy makers and the general public, such support will need to be linked to robust fuel sustainability criteria.

The Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA), scheduled to be introduced in 2021, will be the principal mechanism to meet the ICAO’s long-term decarbonisation targets. SAF consumption and the purchase of carbon offsets are the two principal means to achieve CORSIA compliance, with the relative attractiveness of these to the aviation industry dependent on their cost per tonne of CO2 emissions mitigated.

IEA

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A long-term view of natural gas security in the European Union

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The security of European natural gas supplies has rarely been far off the political agenda. New gas pipeline and LNG projects command high levels of attention, particularly in the context of the European Union’s growing need for imports: its own production is declining; around 100 billion cubic metres (bcm) of long-term contracts expire by 2025; and there is some upside for gas consumption – at least in the near term – as coal and nuclear plants are retired. We estimate that the EU will have to to seek additional imports by 2025 to cover up to one-third of its anticipated consumption.

At the moment, Russia is sending record volumes to Europe while LNG utilisation rates remain relatively low. Limits to European production capacity and import infrastructure (with over half of pipelines operating at monthly peaks above 80%) may contribute to market tightness over the coming years, particularly if Asia continues to absorb the ramp up in global LNG liquefaction capacity.

Over the long-term, our projections in the latest World Energy Outlook suggest that Russia is well placed to remain the primary source of gas into Europe. LNG imports are projected to grow, as new suppliers – notably the United States – increase their presence on international markets and more European countries build LNG regasification capacity. However, Russia is still projected to account for around one-third of the EU’s supply requirements through to 2040.

But import dependence is only one part of the gas security equation. Less attention is being paid to three issues that may, in the long run, have an even greater impact on gas security in the European Union: how easily gas can flow within the European Union itself; how patterns of demand might change in the future; and what role gas infrastructure might play in a decarbonising European energy system.

A liberalised internal gas market

Whether or not gas can flow easily across borders within the European Union is a key focus of the EU’s Energy Union Strategy. On this score, our analysis suggests that the internal market is already functioning reasonably well: around 75% of gas in the European Union is consumed within a competitive liquid market, one in which gas can be flexibly redirected across borders to areas experiencing spikes in demand or shortages in supply. Bidirectional capacity has been instrumental in this regard.

That said, there are a few areas where markets and physical interconnections need further development. For example, roughly 80 billion cubic metres (bcm), or 40%, of the EU’s LNG regasification capacity cannot be accessed by neighbouring states, and some countries in central and southeast Europe still have limited access to alternative sources of supply.

On the whole, our projections suggest that targeted implementation of the European Union’s Projects of Common Interest (PCI) and full transposition of internal gas market directives can remove remaining bottlenecks to the completion of a fully-integrated internal gas market, thereby enhancing the security and diversity of gas supply. With LNG import capacity and pipeline projects like the Southern Gas Corridor increasing Europe’s supply options, the gas market in an ‘Energy Union’ case can build up its resilience to supply shocks while enabling short-term price signals, rather than fixed delivery commitments, to determine optimal imports and intra-EU gas flows.

However, this cannot be taken for granted. If spending on cross-border gas infrastructure were frozen and remaining contractual and regulatory congestion persists, then peak capacity utilisation rates would rise alongside the growth of European gas imports: around half of the EU’s import pipelines would run at maximum capacity in 2040 in this Counterfactual case, compared with less than a quarter in an Energy Union case.

Whether higher utilisation of the EU’s gas ‘hardware’ poses a security risk depends in large part on the strength of the ‘software’ of the internal market. The marketing of futures, swap deals and virtual reverse flows on hubs can allow gas to be bought and sold several times before being delivered to end-users. Along with more transparent rules for third party access to cross-border capacity, this might preclude some of the need for additional physical gas infrastructure and, in time, enable gas deliveries to be de-linked from specific suppliers or routes. Infrastructure investment decisions therefore require careful cost-benefit analysis, particularly as the debate about the pace of decarbonisation in Europe intensifies.

Security and demand

A second issue for long-term European gas security is the composition of demand. Winter gas consumption in the European Union (October-March) is almost double that of summer (April-September). The majority of this additional demand is required for heating buildings; this seasonal call is the primary determinant of gas infrastructure size and utilisation.

In the IEA’s New Policies Scenario, ambitious efficiency targets are projected to translate into a retrofit rate of 2% of the EU’s building stock each year, starting in 2021. Together with some electrification of heat demand, this would lead to a 25% drop in projected peak monthly gas demand in buildings by 2040.

This reduction in demand from the buildings sector more than offsets a 50% increase in peak gas demand for power generation, which is needed to support increasing amounts of electricity generated from variable sources, notably wind. Along with gradual declines in industrial demand, the net effect by 2040 is a reduction in monthly peak demand for gas by almost a third.

Such a trajectory for gas demand has significant commercial implications; reduced gas consumptions in buildings would lead to an import bill saving of almost €180 billion for the EU as a whole over the period 2017-2040. However, it also poses challenges for mid-stream players – e.g. grid and storage operators as well as for utilities:

For grid operators, structural declines in gas de21mand for heating means that the need for additional infrastructure is more uncertain, and what already exists may see falling utilisation (as discussed in WEO 2017). Capacity-based charges to end users typically contribute the most to cost recovery, and underpin the maintenance of the system. But, over time, higher operating costs for ageing infrastructure might need to be recovered from a diminishing customer base at the distribution level. This may further reinforce customer fuel switching over the long term.  

For storage operators, the slow erosion of peak demand for heating implies an even more pronounced flattening of the spread between summer and winter gas prices, further challenging the economics of seasonal gas storage.

For utilities, with the anticipated declines in nuclear and the phasing out of coal-fired power plants in Europe, alongside the growth of variable renewable electricity, gas-fired power plants need to ramp up and down in short intervals in order to maintain power system stability. This flexible operation means a reduction in running hours but a continued need to pay for a similar amount of fuel delivery capacity (whether or not the gas itself comes from import pipelines or short-term storage sites).

A new set of questions for Europe’s gas infrastructure

The debate on Europe’s gas security has tended to concentrate on external aspects, mainly the sources and diversity of supply. But the focus may be shifting to internal questions over the role of gas infrastructure in a decarbonising European energy system, and the system value of gas delivery capacity.

A key dilemma is that, while Europe’s gas infrastructure might be needed less in aggregate, when it is needed during the winter months there is – for the moment – no obvious, cost-effective alternative to ensure that homes are kept warm and lights kept on. The amount of energy that gas delivers to the European energy system in winter is around double the current consumption of electricity.

Moreover, the importance of this function and the difficulty of maintaining it both increase as Europe proceeds with decarbonisation. As the European Union contemplates pathways to reach carbon neutrality in the Commission’s latest 2050 strategy, options to decarbonise the gas supply itself are gaining traction – notably with biomethane and hydrogen (we will be exploring these options in WEO 2019).

In order to stay relevant, natural gas infrastructure must evolve to fulfil additional functions beyond its traditional role of transporting fossil gas from the wellhead to the burner tip. Traditional concerns around security of supply of course remain relevant, but there are more things to value than volume. The security of the future gas system will increasingly depend on its versatility, flexibility, and the pricing of ‘externalities’ such as carbon emissions, air pollution or land use. Europe’s gas infrastructure is an undoubted asset. But, like many other pieces of energy infrastructure, it will need to adapt to the demands of sustainable development.

IEA

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Batteries Can Help Renewables Reach Full Potential in Africa

MD Staff

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Attractive costs for solar and wind power and cutting-edge innovations are making clean energy a compelling proposition in Sub-Saharan Africa, which faces the world’s largest gaps in electricity access. But solar and wind power are variable by nature, making it essential to find effective ways to store the electricity they produce to use when it is needed most.

Energy storage – batteries in particular – can help solve that problem.

Today, battery technology is costly and not widely deployed in large-scale energy projects. The gap is particularly acute in Sub-Saharan Africa, where nearly 600 million people still live without access to reliable and affordable electricity, despite the region’s significant wind and solar power potential and burgeoning energy demand.

Catalyzing new markets will be key to drive down costs for batteries and make it a viable energy storage solution in Africa.

A recent partner- and investor-focused conference sought to do just that.

The “Batteries, Energy Storage & the Renewable Future” event in Cape Town on Feb. 24 and 25 was attended by more than 200 participants from companies including Tesla, General Electric, Fluence, Siemens, the Southern Africa Power Pool, and national research labs and utilities from many countries.

South Africa’s Minister for Energy, Mr. Jeff Radebe, delivered opening remarks, and underscored the country’s commitment to the application of battery storage in its energy systems.

The event focused on the potential for batteries and other forms of energy storage to complement renewable energy by supporting off-grid and mini grids, which supply electricity to millions of people living in remote communities or areas that are not supported by traditional infrastructure.

It also demonstrated the tremendous demand that exists in the region today for energy solutions that do not just boost the uptake of clean energy, but also help stabilize and strengthen existing electricity grids and aid the global push to adopt more clean energy and fight against climate change.

Global demand for battery storage is expected to reach 2,300 GWh by 2030, while power systems around the world will need nearly ten times more — 22,000 GWh — of storage capacity by 2050 to integrate more wind and solar energy into the electricity grid.

The World Bank is already taking steps to address this growing need.

A new, first-of-its-kind $1 billion World Bank Group (WBG) program aims to help fast-track investments in battery storage by raising $4 billion more in public and private funds and convening a global think tank with the ultimate goal of financing 17.5 GWh of battery storage by 2025 – more than triple the 4-5 GWh currently installed in all developing countries.

“Last year, almost twice as many energy storage projects were announced globally – and the same is expected this year. The market is still small, but exponential growth has begun,” said Michael Solomon, the Chief Executive Officer of Clean Horizon.

To that end, the World Bank, in partnership with the Climate Technology Fund (CTF) and the African Development Bank, will support a large-scale distributed battery storage program in South Africa.

The WBG is also developing solar parks with 150 MW of PV and some 200 MWh battery storage each in Mali and Burkina Faso – the largest in the region. Other projects include a combined solar and battery storage project in Haiti, an emergency solar and battery storage power plant in the Gambia and mini-grids in island states to improve resilience.

In recent years, the WBG has also been working with other countries to support the deployment of batteries with solar and wind power, with projects currently under preparation in Africa, South Asia, Latin America and the Caribbean and the Pacific.

The World Bank event, “Batteries, Energy Storage & the Renewable Future,” was held in Cape Town, South Africa on Feb. 25-26, 2019 with the support of the Energy Sector Management Assistance Program (ESMAP) and the Middle East and North Africa Knowledge and Innovation Program (MENA KIP).

World Bank

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