natural gas

East Mediterranean gas finds: EU energy bonanza or geopolitical headache?

March 22, 2019 by Gaurav Sharma

East Mediterranean gas finds: EU energy bonanza or geopolitical headache?

by Gaurav Sharma, March 22, 2019

(l-r) Cyprus Energy Minister Yiorgos Lakkotrypis, the energy ministry's Stelios Himonas and ExxonMobil's Tristan Aspray

Some of the world’s largest natural gas reserves have been discovered off Cyprus. One of the questions being addressed at this year’s CERA Week is, could these massive finds (totalling more than 70 trillion cubic feet!) be the answer to any perceived over-dependency on Russian gas imports to the EU? Maybe, maybe not. Geopolitical tussles could scupper the realization of these much-needed resources for Europe. Whilst the potential is there, it may be a case of “keeping calm and carrying on importing from Russia” for the time-being. Gaurav Sharma reports from Houston…

On the surface there is little to dislike about mammoth natural gas finds in the Eastern Mediterranean. The expected bonanza is largely underpinned by Glaucus, Aphrodite and Calypso gas finds in Cyprus, Israel’s Leviathan field, and Egypt’s Zohr field.

The three Cypriot finds could well tally up to 15-20 trillion cubic feet (tcf) even by the most conservative of estimates. Leviathan could yield the first proceeds of its expected 22 tcf potential in November and Egypt’s 30 tcf Zohr field is already onstream. On paper, it is a bonanza Europe could well do with. More so, as diversifying away from Russian natural gas imports seems to be a hot topic in European capitals these days.

But instead of an imminent bonanza, expect lengthy bottlenecks coloured by Cypriot disunity that has existed since the island was split into the internationally recognized Republic of Cyprus, a member of the European Union, and Northern Cyprus, following the Turkish invasion of 1974.

Unsurprisingly, Turkey wants in on the act and does not recognize Cyprus’ economic exclusion zones (EEZ). The country’s President, Recep Tayip Erdogan, has warned international oil and gas companies against any hydrocarbon exploration in Cyprus, labelling them “pirates” and “bandits”.

And last October, Erdogan sent Turkey’s own drilling ship to hunt for oil and gas in the Eastern Mediterranean off Northern Cyprus, much to the chagrin of Cyprus and Greece over jurisdiction matters. Among those labelled as bandits by the Erdogan is ExxonMobil, which has a 60% stake in Glaucus’ Block 10. Qatar Petroleum, the state-owned firm of Qatar, deemed an Erdogan ally, holds the rest.

It is by no means the only tension linked to regional maritime borders and EEZs. Lebanon is staking a claim to waters Israel is drilling in. Given its growing clout in the region, Russia wants in on the Eastern Mediterranean tussle as well.

In February, Moscow’s state-owned giant Rosneft inked a 20-year agreement to manage and upgrade an oil storage facility in Lebanon’s second city of Tripoli. Financials of the deal were not made public. Tripoli is around 30km from the Syrian border when Russia is backing the regime of Bashar Al-Assad, and less than 60km from the Russian-controlled port of Tartus, deemed Moscow’s only maritime Mediterranean hub.

In 2018, Russian gas producer Novatek bagged a 20% stake in two offshore hydrocarbon exploration blocks in Lebanese waters. Further blocks will be auctioned in 2019 and few would discount incremental Russian involvement, with Israel reportedly unhappy about the move.

Nonetheless, the main protagonists attempted to put as positive a spin as possible on the “Eastern Mediterranean renaissance” at the recently concluded IHS Markit’s CERA Week 2019 conference; a week-long energy sector jamboree held in Houston, US every year in March.

Yiorgos Lakkotrypis, Minister of Energy, Commerce and Industry, Republic of Cyprus, hailed ExxonMobil’s Glaucus Block-10 find as the “biggest so far in Cyprus.”

“Based on some official data it is also one of the biggest finds worldwide in the past two years, and will have a transformative impact on European energy security,” he added.

George Stathakis, Minister of Environment and Energy, Greece, talked of opening up a natural gas corridor “through to Europe” supported by potential Cypriot and Israeli supplies; i.e. the Eastern Mediterranean Pipeline. “Opening up of the Balkans is to be naturally expected, via a vertical corridor between Greece and Bulgaria with an extension to Serbia.”

Stathakis omitted to mention that the move – first revealed in March 2017 – alongside the Trans Adriatic Pipeline plans, is projected to cost €5.8 billion, a figure most analysts deem as too low an estimation of project costs.

Continuing the feel good chatter, Yuval Steinitz, Minister of Energy, Israel, hailed his country’s pooling of resources with Cyprus as the beginning of wider regional cooperation with “natural gas fast becoming the fuel of the future.”

Playing his part in the CERAWeek bonhomie, Tarek El Molla, Minister of Petroleum and Mineral Resources of Egypt said, “Fruits of the Egypt-Israel peace treaty are being felt 40 years later in the shape of the Eastern Mediterranean Gas Forum.”

With Steinitz adding: “It would be great for Israel and the region if our gas can be exported to Europe via Egypt.”

Some even cooed how natural gas finds could serve as a catalyst for bringing about Cypriot reunification. But a response by the Turkish Energy Ministry highlights the complexity of the situation.

When asked about its stance on the developments, a spokesperson said: “We don’t have an eye on others’ resources, but President [Recep Tayip] Erdogan has been clear we will not allow other countries to drill for gas in Turkish or northern Cyprus waters in the Eastern Mediterranean.”

Most expect Turkey to dig deep, therefore talk of European markets relying on a potential Eastern Mediterranean gas bonanza are premature at best.

“In a worst case scenario, geopolitical tensions could stop natural gas finds from being developed altogether” Laurent Ruseckas, IHS Markit

Laurent Ruseckas, Senior Advisor, Eurasian Gas at IHS Markit, says “In a lower risk scenario, geopolitical problems could stunt the pace of development, but in a worst case scenario could stop viable natural gas offshore prospects from being developed altogether.

“Turkey-Cyprus dispute has been rumbling for what is now approaching five decades, and the gas finds add another dimension. No one knows how that is going to be resolved before we start making projections on how Europe could or couldn’t benefit from it. Commercialization will not be straightforward.”

ExxonMobil, whose recent find off Cyprus brought renewed focus on the region, declined comment on political ramifications. However, the company’s Vice President of Exploration for Europe, Russia and the Caspian, Tristan Aspray, says he remains “positive” on the Glaucus find, the data from which had been sent for further analysis.

Sidestepping salvos between Turkey and Cyprus over Glaucus, the latter’s Aphrodite and Calypso prospects are far from being the done deal too. Calypso – where exploration is being fronted by Total and Eni – is in nascent stages.

Aphrodite, first discovered in 2011, is facing delays as its stakeholders Noble Energy, Delek and Royal Dutch Shell are renegotiating their production sharing agreement with the government. The concept of how to get the natural gas to market has also not been finalised, with some Cypriot policymakers torn on whether or not to send the gas to Egypt for liquefaction and export via LNG tankers.

Industry consultants Wood Mackenzie describe the Eastern Mediterranean as one of the world’s “premier exploration hotspots” with massive potential for Europe. Be that as it may, the realization of that potential is some way away; and may need refereeing by Brussels. Perhaps keeping calm, and carrying on importing from Russia looks to be about par over the short term.

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Germany: headed for an amazing energy year

November 13, 2018 by Karel Beckman

ENERGY WATCH #1 - November 13, 2018

Germany: headed for an amazing energy year

by Karel Beckman

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Germany is headed for a rather amazing energy year. According to energy market research group AG Energiebilanzen (AGEB), the country will use more than 5% less energy this year compared to last year! This is based on data over the first nine months of 2018.

The reasons for this spectacular decline, according to AGEB: higher energy prices, warmer weather, and energy efficiency. The reason is not to be found in lower economic production or a decline in population, AGEB notes.

Primary energy use in Germany has been declining since 2006 and is the lowest in over 20 years.

More remarkable findings: oil, gas and coal use all declined, the production of renewable energy and nuclear power (!) grew. As a result, AGEB expects CO2 emissions to decline by no less than 7%.

However, energy analysts said the data did not indicate that Germany was solidly on track for further emission reductions in the coming years. They warned that the drop was largely caused by one-off effects, reported Clean Energy Wire. “I would warn against calling this a trend”, said Hans-Joachim Ziesing, a member of the federal government’s independent Energiewende monitoring commission.

Hans König from Aurora Energy Research said emissions could even rise next year if energy demand and the weather returned to average levels.

In other news: according to new figures from utility association BDEW, renewables produced 38% of the power used in Germany in the first nine months, an increase of three percentage points.

GlobalData, a leading analyst company, expects that non-hydro renewables will almost entirely make up for the lost production from nuclear power when the last nuclear plant closes in Germany in 2022.

“Non-hydro renewable power capacity is expected to continue growing to establish itself as the dominant source of energy by 2030, when it is expected to account for 71.9% of total installed capacity,” said Chiradeep Chatterjee, Power Analyst at GlobalData, on CleanTechnica.

Looking forward, “GlobalData sees Germany focusing on expanding its offshore wind and geothermal power sectors, which are expected to increase at a rate of 8.7% and 9.9% respectively. Conversely, thermal capacity is expected to decline from its current levels of 38.4% to only 23.2% by 2030, due primarily to a reduction in coal-fired capacity.”

Specifically, according to GlobalData, the following table outlines the company’s forecasts for onshore wind, offshore wind, solar PV, and solar thermal (CSP) through to 2030:

“The share of coal power, which was 22.1% in 2017 in the total capacity mix, is expected to decline to 9.3% in 2030,” added Chatterjee. “The gap is expected to be filled up only partially by gas-based capacity which explains the net decline in the share of thermal power.”

All this does not necessarily mean that energy prices will go down. The German website Strom Report tracks consumer electricity prices throughout the country.

Recently it reported that although taxes and duties are expected to decline next year, prices will probably nevertheless go up.

The German renewable energy levy (EEG), the main financing instrument of the Energiewende, which makes up 23% of all taxes and duties, will be adjusted downwards by 0.39 cents to 6.404 cents per kWh in 2019. The CHP (combined heat and power) levy will go down slightly to 0.28 cts per kWh. However, the Offshore Network levy will go up from 0.037 cts to 0.416 cts per kWh. Total levies will be 7.411 cts per kWh, 1.9% lower than in 2018.

Network tariffs vary by state by will go up on average by 2%, notes Strom-Report.

Wholesale prices for electricity have risen sharply, by 54%, in the first nine months, to 5.5 cts per kWh. This is the highest in five years. The main reasons are higher prices of gas and coal and higher carbon prices in the EU ETS. Strom-Report does not see any indications that this trend will reverse itself in the coming period.

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Lazard: wind, solar beat new and old coal and gas

November 13, 2018 by Express Editor

EXPRESS #4 - November 13, 2018

Lazard: wind, solar beat new and old coal and gas

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Solar now cheaper than fossil fuels says Lazard

“Wind and solar technologies have extended their lead over fossil fuel generation on costs of new plant, and are now as cheap, or even cheaper, than existing coal, gas and nuclear power plants – even compared to existing and fully-depreciated fossil fuel generators.”

That’s the major takeaway from the 12th edition of the annual Lazard Levelized Cost of Energy Analysis, which has become one of the major global industry benchmarks, according to Giles Parkinson of Reneweconomy.com.

“We have reached an inflection point where, in some cases, it is more cost effective to build and operate new alternative energy projects than to maintain existing conventional generation plants,” said George Bilicic, the vice chairman and global head of Lazard’s Power, Energy & Infrastructure Group.

“As alternative energy costs continue to decline, storage remains the key to solving the problem of intermittency and we are beginning to see a clearer path forward for economic viability in storage technologies.”

Lazard’s figures are based on US data and in US conditions, but give an insight into global trends, notes Parkinson. “Over the past year, Lazard has seen a further 13 per cent fall in the cost of solar, and another 7 per cent fall in the cost of wind energy. This has extended its big advantage over the cost of building new coal, nuclear, or even gas plants – even in the US where the cost of gas is well below that of Australia [and Europe]”.

The new element is that wind and solar LCOE is now beating existing coal and nuclear plants, even those which have been fully depreciated.

Lazard says that the low end levellized cost of onshore wind-generated energy is $US29/MWh, compared to an average illustrative marginal cost of $US36/MWh for existing coal generators.

“The levellized cost of utility-scale solar is nearly identical to the illustrative marginal cost of coal, at $US36/MWh,” Lazard says.

In the US, tax incentives increases the advantage of wind and solar, pushing their costs to as low as $US14/MWh for wind, and $US32/MWh for solar. This compares to the cost of $US60/MWh-$US140/MWh for new coal, $US112/MWh-$189/MWh for new nuclear, and $US41-$US74/MWh for gas-fired generation (gas is comparatively cheap in the US).

“Such an outcome would have been unthinkable for many people a decade ago – around the time of Copenhagen climate conference – but Lazard estimates that since 2009 solar has fallen in cost by 88 per cent and wind has fallen by 69 per cent”, notes Parkinson.

He adds that “Lazard has also identified more significant cost declines in battery storage technologies in the 4th edition of the Levellised Cost of Storage report.”

However, Lazard cautions that while storage technology holds great promise, “alternative energy systems alone will not be capable of meeting the base-load generation needs of a developed economy for the foreseeable future.”

Parkinson does not fully agree with this point. “It is important here to note that Lazard only canvasses the various battery storage technologies, and not the cost of storage of other technologies for longer durations such as solar thermal, pumped hydro, or even hydrogen”, he writes.

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“Germany needs gas – but it does not need new gas infrastructure”

November 13, 2018 by Express Editor

EXPRESS #3 - November 13, 2018

“Germany needs gas – but it does not need new gas infrastructure”

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Germany may not need new gas pipelines any longer

The “long-term relevance of gas” in the German energy market is “vastly underrated by many”, according to a new report from German research institute EWIcommissioned by the Gas Value Chain Company. The latter is a one-man consultancy founded in 2014 by German energy expert Wolfgang Peters, who makes no secret of the fact that he is a “gas advocate”. Peters co-wrote the report with Harald Hecking of EWI.

What Peters and Hecking did was “to compare a scenario labelled “Electrons” – implying high electrification and lower use of gas – with a scenario labelled “Molecules”, the latter implying a higher degree of direct gas use in all sectors.”

Their main findings:

Gaseous molecules as energy carrier will be indispensable in both the Electrons and the Molecules scenarios all the way towards 2050.
(Fossil) natural gas demand can remain at current levels up to CO2 reduction targets of 65% to 70%. For deeper decarbonization beyond 70%, gas has to become ‘green’, i.e. nonfossil. In the Molecules scenario, demand for green gas reaches ~800 TWh in 2050 in order to achieve a -95% CO2 reduction.
There are various options presently known for ‘greening’ gas. Bio-methane is the obvious first, but its growth potential is limited. Green hydrogen blending would be the next obvious step, but its use potential is limited due to gas quality constraints. This renders synthetic methane, produced by the power-to-methane process the most likely option for greening gas in large quantities. It is pivotal in either deep decarbonization scenario (e.g. -95%) towards 2050.
Gas and the existing gas infrastructure will be pivotal for ensuring the security of electricity supply: o Peak electricity demand will increase significantly towards ~160 GW in the ambitious -95% Electrons scenario mainly due to the high use of electric heat pumps. Also gas-fired power generation capacity will have to increase strongly, namely towards 107 GW in the same -95% scenario. Gas is the main contributor to meet peak electricity demand. In the Molecules scenario particularly the higher direct use of gas for space heating alleviates the surge in peak electricity demand.
In the Electrons scenario, a tremendous rise in power demand is seen (towards ~930 TWh of final energy demand in ‘EL95’). Since such (green) power is mostly furnished by intermittent wind and solar, gas performs a double role to ensure security of electricity supply: First, it acts as a ‘permanent synchronizer’ stabilizing the power grids. Moreover, it steps in the breach in the event of a protracted period of a “Kalte Dunkelflaute”, where a prevailing cold-snap causes massive power and power peak demand but there is neither wind nor sun.

Although the report looks like a lobby for gas, the authors do not shy away from some inconvenient truths for the gas sector.

They note that: “Peak gas demand will decline in both the Electrons and the Molecules scenario, so that existing gas infrastructure by and large suffices.”

They also conclude that “seasonal demand patterns as we presently know them will largely vanish but volatility stemming from renewables intermittency will rise substantially. This implies less future need for seasonal storage and more need for short- and midterm flexibility by line-pack and multiple-cycle peak storages.”

According to the authors, one big advantage of gas-based decarbonization strategies is that they are significantly less costly than electrification based ones: “The ‘Molecules’ scenario achieving 80% CO2 reduction in 2050 causes additional costs of € 1.2 trillion, while the Electrons scenario achieving 95% CO2 reduction causes costs of € 2.2 trillion.”

This is because “a gas-based decarbonization strategy requires less investment needs in buildings, power plants, industrial appliances and the infrastructure, an advantage that prevails even though costs for energy use are slightly higher.”

It is also “far cheaper to transport energy in the form of gas than in the form of electricity due to its higher energy density. Since the existing gas infrastructure is by and large ‘up to the task’ and can continue to be used, significant costs for expensive new-built power grid expansions can be saved.”

Meanwhile, in the UK there are increasing worries about security of gas supply, in particular the adequacy of the country’s gas storage capacity. The Energy & Utilities Alliance (EUA) told the UK parliament on October 31 that the UK must urgently review the case for more gas storage in order to minimise the risk to supply and maintain flexibility, according to a report by William Powell for Natural Gas World.

“A parliamentary committee is investigating the adequacy of the UK storage portfolio, given the closure of the giant Rough asset, once one of the largest in Europe and previously used for balancing demand in winter”, writes Powell.

“With Rough gone, the UK can meet only a few percent of its annual demand from its storage facilities which are all now quick-response salt caverns, unlike Rough, which was a depleted gas field that depended on seasonal price differences. Those winter-summer price differences are too small to justify the major refitting that the offshore platform would need to be serviceable. Members of parliament are asking the Department for Business, Energy and Industrial Innovation what, if anything, needs to be done to replace it.”

“One question that the committee will consider is whether the government should intervene if the market will not; or whether the array of under-used LNG import terminals and interconnector pipelines are, by themselves, a sufficient resource.”

Roddy Monroe, the former head of the operator of Rough, Centrica Storage, “told the committee that there may be serious implications for UK energy security if policy makers rely solely on the market to deliver the right level of investment to meet broader government objectives, which include making the transition to a low carbon economy and providing access to affordable energy.”

Monroe said that “energy security is underpinned by long life, capital intensive investments which require long-term financial certainty and the government has felt it necessary to intervene in the electricity market to help deliver positive changes. He said that such intervention may now be necessary for the gas market in order to provide the right level of gas security.”

He said: “We urge government to look, in detail, at the issue of gas storage, such as they did in 2013. Since then we have seen a number of material changes to the energy market which have the potential to worsen energy security and, in particular, significantly increase the exposure to extreme price volatility.”

These include the winding down of Groningen, the major swing field in the Netherlands, which creates a gap in a number of northwest countries’ supply portfolio thereby pushing up demand for other gas during winter.

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Roads to 2050: hydrogen hype runs up against electrification reality

October 30, 2018 by Sonja van Renssen

BRUSSELS INSIDER #1 - October 30, 2018

Roads to 2050: hydrogen hype runs up against electrification reality

by Sonja van Renssen

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Energy-intensive industries will become electro-intensive industries

As the European Commission prepares a new EU 2050 climate and energy strategy for late November, organisations in Brussels are putting forward their own ideas on what this should look like. A major analysis by the Institute for European Studies at the Vrije Universiteit Brussel – carried out on behalf of 11 energy-intensive industries – predicts a tripling in demand for low-carbon electricity and warns that the success of “green hydrogen” will depend on the availability of “competitively priced, abundant and reliable low-CO2 electricity”. The challenges of creating such a resource are formidable, however. Other groups still look to carbon capture and storage/use (CCUS) for salvation.

This article discusses the results of a number of new reports and papers showing roads to a net zero emissions energy system in 2050: from the Institute for European Studies, Eurelectric, Eurogas, Ecofys, The European Climate Foundation, BP and the World Energy Council Germany.

One report that is doing the rounds at the EU institutions this autumn is a study carried out by the Institute for European Studies (IES) at the Vrije Universiteit Brussel this summer. It was commissioned by 11 European energy-intensive industries and in effect forms their contribution to a new EU 2050 climate and energy strategy. The Commission is preparing this strategy for delivery at the end of November, ahead of the next round of UN climate talks in Katowice, Poland (COP24) in the first half of December.

The IES report, which was first published at the end of September, clearly points out the central role of electricity in the future energy system. This is enhanced not diminished by all the recent hype about hydrogen in the EU capital. It concludes that European energy-intensive industries are likely to triple their electricity demand as they start large-scale decarbonisation, especially through use of hydrogen as a feedstock, carbon capture and storage (CCS) and the production of fuels using electricity (power-to-X).

“Energy-intensive industries will become electro-intensive industries,” Tomas Wyns, the study’s lead author, told Energy Post. The researchers estimate that energy-intensive industries will use 2980-4430 TWh of electricity in future, up from 500-1000 TWh today. That makes “competitively priced, abundant and reliable low-CO2 electricity… one of the most important framework conditions for the transition to a low-CO2 industry in Europe”.

A lot of power

The IES study stresses that energy-intensive industries are “vital to enable a carbon neutral Europe”. They sit “at the forefront of low-carbon solutions” and “form the foundations of the European economy”. This is because they are an integral part of material value chains that produce everything from wind turbines to electric batteries. Energy-intensive industries’ emissions have come down over time – 36% since 1990, the report says – but clearly they will need to come down further if Europe wants to reduce its emissions to net zero.