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

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

by Gaurav Sharma, March 22, 2019

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(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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Virtual power plants: a story of market rules and smartgrids

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Virtual power plants: a story of market rules and smartgrids

by Eric Marx, March 14, 2019

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Access to the grid-balancing market is competitive and carefully regulated. Green electricity from distributed and behind-the-meter renewable assets is already being traded on wholesale and balancing markets. The assets come in all shapes and sizes: roof-top solar, farmyard biofuel installations, EV and home battery systems, community energy projects, wind installations and heat pumps to name but a few. When they are pooled, by aggregators, they can be presented as one, utility-scale, virtual power plant (VPP). Green competition for traditional power plants you might say. VPPs success will depend on consistent rules, the roll-out of smart controls – at both distribution and transmission levels – and price competitiveness. According to Eric Marx they are being squeezed on all fronts…

As the European power system transforms to rapidly integrate more renewables, regulators can empower VPPs to develop flexibility platforms that enable producer/consumers (“prosumers”) to play a more central role. An EU-level agreement passed in December combined with the increased penetration of renewables should help in this regard.

Nonetheless, VPPs are busy merging or expanding internationally and across Europe whilst they are being held back in some regions by a patchwork of inconsistent regulatory policies, lack of digital infrastructure and fierce competition.

Next Kraftwerke, a VPP based in Cologne, for example, recently successfully licensed its virtual power plant software to a solar energy company in South Korea. Furthermore, following the addition of storage to its portfolio last year, it is now offering enhanced frequency control to the Belgian grid operator. But on its home turf the story is quite different. The company has seen its business model upended since the cost of primary control reserve prices went plummeting.

Next Kraftwerke put this down to the fact that, under current rules, coal-fired power stations can also bid for grid reserve. Unwelcome competition for Next Kraftwerke’s CEO, Jochen Schwill, who noted that allowing them into “the balancing market contributes to their preservation [and] is absolutely not in the spirit of the energy transition…”. But there are other factors that may come to their help.

Analysts expect better times ahead for companies like Next Kraftwerke on their own soil, when old coal-fired units and nuclear power stations are taken off line and whenever smart meters are rolled out and market access rules clarified – although they will probably still have to contend with relatively cheap, gas-fired power at least. In the meantime they are faring better in regions and markets where conditions are more favourable.

New Energy Companies and Virtual Power Plants (VPPs) – explainer

The electricity grid needs to be kept in balance. Just like a water system where the network needs to be maintained at a constant workable pressure, the electricity grid needs a certain voltage to be maintained throughout.

New energy companies, including VPPs, that use software controls to provide energy on short notice to the electricity system come in many shapes and sizes. There are demand-response (DR) aggregators which manage flexibility of industrial energy users and those on the Virtual Power Plant (VPP) side which typically control generation units. The business model consists primarily of pooling and marketing generation facilities, flexible consumers and storage systems.

By sending signals to participating members, a VPP can save them money by lowering their energy costs while they also get paid by the grid operator for providing energy on short notice to the electricity system. Direct VPP operators – sometimes called “direct marketers” – scale small plants to a tradeable volume.

Utility companies and grid operators are also considered VPP operators. The distinction is that they manage their own generation units – be they biomass and wind to solar and various cogeneration facilities – for sale into grid-balancing and spot (electricity as a commodity) markets.

The Kombikraftwerk experiments carried out in 2008 showed that renewables could provide an adequate supply of constant energy and ensure a stable voltage frequency – in real-time and even when compensating for changes in output from geographically-distributed generators.

Yet not until 2012 did theory translate into full-scale market reality. That’s when Germany amended its Renewable Energy Law (EEG) to allow the direct sale of green energy by producers themselves. And in the last three years EU countries began specifying aggregator frameworks that gave legal certainty about the relationships and responsibilities among aggregators, Balancing Responsible Parties (BRPs) and suppliers, and the consumer.

Ultimately, VPPs are simply another type of platform business (like Über or Airbnb) bringing buyers and sellers together in an electronic marketplace.

Regulatory obstacles and regional inconsistencies

The introduction of variable “dynamic” pricing could help extend the business model to the lower-voltage distribution network – where smart consumer devices and distributed renewables, like rooftop solar panels and electric vehicles, reside.

But the “starting point” right now is on the industrial side, said Patrick Adigbli, a vice president for Regulatory Affairs at REstore, a demand side management firm which sells flexible energy from large production processes to Transmission System Operators (TSOs). In most countries, aggregators are restricted to the higher voltage levels – to the transmission, rather than distribution networks – because their technical infrastructure allows a close monitoring of their use.

But even there, where several studies indicate there’s significant peak demand that could be covered with demand response (upwards of 15 GW in Germany alone) it comes mainly from the industrial sector which, according to Adigbli, has yet to be allowed in to the German market.

In Europe, France is probably the best country when it comes to demand-response policy. It currently has the highest number of independent aggregators, and yet it doesn’t allow independent parties to bid into the market through pooling of different assets.

In fact, the country risks a “stalemate” if no further steps are taken to open up its balancing market, according to a new report issued by smartEn, a trade association promoting digital energy efficiency solutions.

Switzerland is one of Europe’s leading countries, write the authors of the smartEn Map, which analyses the opening of balancing markets in 16 EU countries. Switzerland procures bids in all three power reserve markets, allows aggregators to pool assets, and is technologically agnostic in a way that does not de facto exclude new participants.

The biggest flaw, write report authors, tends to be in the area of transparency, owing to procurement methods and capacity payments which place reserves outside the market, and thereby create a barrier to entry for new participants.

“What’s problematic – and what the report points to – is the fact that tech rules still differ among member states,” says Adigbli. “Are all assets allowed to participate in a given market? Can you combine different, smaller assets to build larger ones which are able to satisfy all technological criteria? How are prices determined and is it tech-neutral and transparent?…None of this is harmonised on the EU scale” he added.

But that may soon happen, thanks to new European Network Codes for cross-border electricity-balancing, and owing to the Clean Energy for all European Package finalised in December, an EU-level agreement which sets a framework for independent aggregators and dynamic price contracts for consumers.

EU harmonisation

Both Italy and Spain are said to be aligning themselves with the new network codes. Compliance is foreseen by 2021, alongside several initiatives for standardised European products which have already helped prod countries like Belgium, Germany and Estonia to further lowering entry barriers.

As for the Clean Energy Package, which was agreed to in December after two years negotiation, analysts say it could very well enable aggregators to enter the electricity market en masse.

Incumbent suppliers can no longer block aggregators. Doing away with prior consent was “key,” said Michael Villa, a senior policy adviser at smartEn.

Another important rule concerns bidding size. The threshold for participation in day-ahead and intraday markets is now 500kW or less.

Last, is the provision on dynamic price contracts allowing consumers to react directly to price signals based on information provided by smart meters. These kinds of flexible contracts are already widely offered in Spain and Scandinavia, but in actuality, most European countries are still far from implementing real-time price signals. Germany, for example, hasn’t yet started its smart meter rollout.

Still, the very idea that a customer can choose an independent provider is a fundamental starting point. “It re-orientates the system towards customer choice”, said Villa “and for that, you need to open the market to different providers and allow competition”.

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Oil and gas giant Shell certainly thinks a customer-focused energy system is coming. In February it announced plans to buy German home battery storage company sonnen, which claims to have built, with rooftop solar customers, the world’s largest platform for power-sharing. Could a platform for auctioning electricity flexibility services on congested distribution networks – say, with heavy concentrations of electric vehicles and battery-connected solar panels – be far behind? It’s the kind of bet that made platform operators Über and Airbnb hugely successful once they established massive scale. Watch this space…

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Green Oil: second wave of investment in low-carbon assets is substantial but hardly tidal

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Green Oil: second wave of investment in low-carbon assets is substantial but hardly tidal

by Mike Scott, March 8, 2019

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Equinor's Hywind floating wind installation, Scotland

Oil majors are under significant pressure from investors to develop climate-friendly business areas but less than 1.5% of their combined investment budgets is expected to go into low-carbon assets globally this year. However, 70% of that is set to come from European oil companies who are reacting positively to market signals by participating in coordinated industry schemes designed to help meet Paris targets. Here is an overview of some of the more significant investments which, according to Mike Scott, are indicators of a permanent, growing green shift in the portfolios of these household-name giants.

The oil and gas sector has embarked on a second wave of green investment, a decade or so after abandoning a push into renewables that was spearheaded by BP’s Beyond Petroleum campaign, as the financial crisis hit and the oil price plunged.

There is so much happening, it is difficult to keep up. Here is a snapshot of recent activity:

  • Shell recently announced it wanted to double its investment in renewable energy to up to $4bn annually, having recently invested in solar power, wind farms, electric car infrastructure and even a utility, the UK’s First Utility. In the first two months of 2019, it has invested in Autogrid, which uses artificial intelligence to make energy systems more flexible; US electric vehicle charging group Greenlots; Nordsol, a producer of bioLNG; autonomous driving company Aurora; Makani, a company aiming to generate wind power using kites; a demonstration project for a floating wind turbine; and sonnen, an energy storage company. And most recently, it bought UK-based Limejump, a virtual power plant company that will boost its position in demand response.
  • BP’s joint venture with DuPont, Butamax, has developed technology that converts sugars from corn into an energy rich biofuel known as bio-isobutanol. It has more than 1GW of wind power capacity in the US, and in 2018, it bought solar power developer Lightsource, and UK EV charging company Chargemaster. (image: BP’s Butamax biofuel investment)
  • Total has been involved in solar power since 1972. It bought SunPower in 2011 and covers the entire solar value chain, from manufacturing solar cells to installation. In 2016, it bought Saft, a leading provider of energy storage solutions. It has also been involved in biofuels since the 1990s and has opened France’s first biorefinery at La Mède.
  • Italy’s Eni is investing €1.2bn to install 1GW of renewable capacity by 2021, and it aims to have installed capacity of 5GW by 2025, mainly in PV and wind, but also in concentrated solar power, biofuels and green chemistry.
  • Equinor plans to devote 25% of its R&D budget to renewables by 2020 and to invest $1bn a year in renewables to 2030. It is one of the biggest players in offshore wind and is developing the world’s first floating offshore wind turbine project, Hywind. It has been storing CO2 in its Sleipner gas fieldsince the 1990s and it is one of the world leaders in CCS research. In solar, it has invested in Oxford PV, a leader in perovskite technology, which could lead to greater efficiencies, and Convergent Energy + Power, which develops solar and storage projects.
  • Exxon has a $500m joint venture with Synthetic Genomics to genetically engineer photosynthetic algae to produce renewable crude from sunlight and carbon dioxide, but even though it has been investing in this area for decades, there have so far been few results.It is part of a $1bn a year programme of basic research in low-carbon technologies. Last year, it signed the biggest renewable energy power purchase   agreement of any oil and gas company, to buy 500MW of wind and solar in Texas, which it will use to produce oil.

  • Chevron has invested in solar, wind and geothermal, as well as renewable diesel but only at a small scale to evaluate the technologies.

The summary League Table above presents headline company findings. It is based on detailed analysis across a range of carbon and transitional indicators which could have a significant impact on company performance. The League Table is designed to serve as a proxy for business readiness in an industry which will undergo significant change as governments increase efforts to implement the Paris Agreement. Companies placed towards the bottom are deemed less prepared for a low-carbon transition

 

A number of firms, including Total and Equinor, have their own venture investment units. In addition, the Oil and Gas Climate Initiative (OGCI), an industry scheme that includes most of the oil majors, has a $1bn investment fund that is investing in areas such as reducing methane leakage, cutting CO2 emissions and recycling CO2.

The fund has made a number of investments in start-up companies working in areas ranging from low-emissions cement and catalyst technology that enables CO2 to be used as a raw material, to data-providers monitoring methane leakage and CO2 emissions using satellites and aerial surveys, as well as more fuel-efficient and less polluting petrol engines.

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So, is this different from the last time Oil majors dipped their toe in the water of renewables investing, and if so, why?

There are a number of reasons to believe that what is going on now is a more lasting change. Firstly, cost and technology developments such as the growth of the energy storage sector have made renewables much more viable for power generation and transport than they were a decade ago.

Second, the science is much firmer than it was in the early 2000s, when the last wave of investment kicked off, buoyed by the birth of the European Emissions Trading Scheme and Al Gore’s Oscar-winning turn in the film An Inconvenient Truth.

Subsequent reports from the Intergovernmental Panel on Climate Change (IPCC), backed up by a growing body of anecdotal evidence, have shown with much greater certainty that climate change is happening and it is man-made. At the same time, advances in analysis and research have made it much clearer who is responsible for greenhouse gas emissions. The US Environmental Protection Agency reported that in 2016, more than three quarters of US emissions came from burning fossil fuels for the transportation (28%), industry (22%) and electricity (28%) sectors.

The Science Based Targets Initiative has worked out the contribution of individual companies to emissions, creating a baseline of what is acceptable if companies are to do their bit in limiting the effects of climate change. A growing number of companies have signed up to the initiative and through their own efforts to cut their impact, they are putting pressure on their energy providers to be more sustainable.

The Carbon Tracker Initiative has set out the risks of the transition to a low-carbon economy to the oil and gas sector in reports with titles such as 2020 Vision: why you should see the fossil fuel peak coming; Mind The Gap: the $1.6 trillion energy transition risk; and Expect the Unexpected: The Disruptive Power of Low-carbon Technology. And the Taskforce for Climate-related Financial Disclosures (TCFD) is gaining increasing traction with investors, who are demanding answers from companies on how they are dealing with climate risks.

As a result, and most importantly, investors are firmly on board this time. The clearest illustration of this has come outside the oil and gas sector in recent days, with the announcement from Glencore, the world’s biggest exporter of thermal coal and one of the companies most bullish on the case for coal, that it will cap production at current levels, align its business with the goals of the Paris Agreement and prioritise investment in commodities that support low-emissions technology.

It is testament to the success of shareholder pressure in changing behaviour, especially the impact of the relatively new group ClimateAction 100+, which also recently persuaded Shell to halve its net carbon footprint by 2050, with a 20% cut by 2035, and to link executive remuneration to these targets. The group, which is targeting the biggest emitters, is also asking BP to align its business strategy with the Paris Agreement in a shareholder resolution, and, significantly, BP is recommending that investors approve the move.

The group is planning to target other large polluters and is likely to have significant success, given its recent achievements and the fact that it represents more than 300 investors and over $33 trillion in assets under management.

Another key driver is a wave of climate lawsuits targeting oil and gas companies, filed by cities such as New York and San Francisco, along with a group of 21 young people, with ExxonMobil a particular target. It’s unclear how successful these suits will be, but even if they ultimately fail, they cost time and money to defend and if oil companies are found liable, the costs would likely run into billions of dollars.

And if oil executives want to see which way the wind is blowing, they need only watch thousands of schoolchildren skipping school to protest against climate change every week or hear the latest developments in the Green New Deal.

All of these developments suggest that the sector is moving towards an acceptance that they need to change. The moves they have made so far are significant, but it’s important to remember that the $3.38bn the world’s largest oil firms spent on climate change reduction initiatives in 2018 was just 1.3% of their combined budgets, according to climate researchers CDP. And most of that spending, some 70%, is by European oil groups, suggesting that companies in other regions, including many national oil companies, may struggle to cope with a changing market.

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Energy majors grab blockchain “multi, multi-billion dollar opportunity”

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Energy majors grab blockchain "multi, multi-billion dollar opportunity"

by Gaurav Sharma

January 23, 2019

Shell CEO, Ben van Beurden announcing stake in Applied Blockchain

Blockchain is being used to optimise performance across all energy sectors where wholesale digitalisation of trading processes, asset management and demand response is now standard. Its adoption by sector operators is clearly visible but will its wide range of possible applications help deliver a leaner industry resulting in reduced costs and a more efficient transition or is everyone jumping on an untested bandwagon for fear of missing out? Gaurav Sharma reports…

Use cases for the deployment of blockchain in the energy sector seem to be growing by the day with practically every segment from natural gas trading to fuel procurement up for grabs. An entire industry, often deemed old fashioned by technologists, now appears smitten by blockchain in its quest for efficiencies in an era of relatively low oil prices and shifting consumer behaviour.

In simple terms, a blockchain is akin to a digitally distributed ledger that can be replicated and spread across many nodes in a peer-to-peer network, thereby minimising the need for oversight and governance of a single ledger. It is the platform underpinning cryptocurrency Bitcoin.

For a sector infamous for copious amounts of paperwork from bills of lading to tender submissions, a tool to securely digitize and save is an enticing one. Energy blockchain streams could be split three-ways: process applications (energy trading, grid management, payments and supply chain solutions), end-user deployment, and component (including service platform) solutions.

While many of the concepts are coming out of North American and Asian markets, unmistakably the UK and Germany are leading the way. London in particular is buzzing, with multiple technology incubation hubs or shared workspaces between Shoreditch and Moorgate – areas conventionally home to start-ups – counting several energy blockchain enthusiasts in their ranks.

It is difficult to pin a figure on the size of the global energy blockchain market. However, a five-year range can be projected in the region of $7 billion to $12 billion by 2024, based on industry forecasts, number of energy blockchain start-ups, implementation projects and confidential conversations. Whether it materializes or not, even a cursory glance at the market would warm up the most sceptical of industry watchers.

Cataloguing movers and shakers

The enthusiasts’ roster includes a veritable who’s-who of the energy business. For instance, London-based trading platform Vakt, created in 2017, includes oil majors BP, Royal Dutch Shell, Equinor, and trading firms Mercuria Energy, Koch and Gunvor. Furthermore, the New Year has started on a positive footing for Vakt having signed on Chevron, Total and Reliance Industries. It is already being used to trade North Sea oil.

To quote Total’s head of trading and shipping Thomas Waymel: “We have felt a need to digitize cargo post-trade processes for some time. We view blockchain as a major step forward towards safer, faster and cheaper logistical operations and are committed to contribute to Vakt’s roll out to various markets.”

Other members of the Vakt consortium include banks ABN Amro, ING and Societe Generale. If you thought streamlining oil trading was the only game in town, think again. Shell made a significant move into blockchain last year premised on “smart-contracts” by bagging a minority stake in Applied Blockchain, another London start-up.

“We did the first product derivative trade on blockchain together with our partner Applied Blockchain.” Ben van Beurden, CEO, Shell

A Shell spokesperson said: “Blockchain applications have huge potential to shake up how we do things in the energy industry from streamlining process, to simplifying how we work with our suppliers and serve our customers. Investing in Applied Blockchain is part of our commitment to use digitalization to create value in our core business and develop new business models.”

Total, Eni, Gazprom, Mercuria, Vattenfall, Petroineos and Freepoint are all part of Canadian group Interbit’s “OneOffice” proposition aimed at facilitating natural gas trading reconciliation through to settlement and delivery of trades using blockchain to bring about “cost savings across the trade life cycle.”

“The energy companies running blockchain pilot projects [are embracing] a fundamental change that is increasingly being demonstrated as viable at a time when concerns about torrents of newly- available data, the mass deployment of sensors, increasing machine-to-machine communication, and rising security threats demand a move from legacy processes and technical debt to a scalable, automatable, and trust-less solution” Interbit, Canada and UK

Elsewhere, ConsenSys and field data management firm Amalto have a blockchain joint venture to develop a platform to facilitate the automation of ticket-based order-to-cash processes in the industry. Abu Dhabi National Oil Company (ADNOC) and IBM have successfully piloted a blockchain-based automated system to integrate oil and gas production across the full value chain.

Completing the spectrum, even sector data and market information aggregator S&P Global Platts is deploying blockchain to “facilitate submissions of weekly oil storage and inventory data”, a move it revealed in the fuel storage hub of Fujairah, United Arab Emirates, last year.

Meanwhile, European utilities including Enel, RWE and Vattenfall are collaborating with Germany’s Ponton on using blockchain to bring peer-to-peer trading to the wholesale energy market via the Enerchain project.

Rival Iberdrola believes blockchain has a vital role to play in “energy resource verification.” In partnership with Kutxabank, the Spanish company is using blockchain technology to “guarantee the energy it supplies to its customers comes from 100% renewable sources.”

A spokesperson said the blockchain pilot will help Iberdrola figure out “which assets will supply energy to a specific point of consumption.”

Demand response and blockchain

Technical University Cluj Napoca investigated the use of decentralised blockchain mechanisms for delivering transparent, secure, reliable, and timely energy flexibility to all the stakeholders involved in the flexibility markets (Distribution System Operators primarily, retailers, aggregators, etc.). They found that “blockchain based distributed demand side management can be used for matching energy demand and production at smart grid level, the demand response signal being followed with high accuracy, while the amount of energy flexibility needed for convergence is reduced”

As the plethora of examples indicates – not a single facet of the energy sphere is considered beyond the scope of emerging blockchain technology. But is it too much, too soon?

A note of caution

While the industry is raving on about the money that is being pumped into blockchain, dialogues on return on investment and security concerns seem to be relatively muted. Much of it narrows down to the fear of losing out, which partially explains incremental sector moves on blockchain since 2015.

Blockchain enthusiasts point to its secure credentials and it helps to get people on the bandwagon. Many say bitcoin’s greatest gift is not the cryptocurrency itself but rather the blockchain technology that underpins it which has become commonplace.

But if bitcoin is blockchain’s poster deployment, then it is a very poor example of implied greater security. Just consider the number of colossal hacks in recent years. Mt Gox, Coincheck, Coinrail and another half dozen examples spring to mind in the last five years alone.

Of course, blockchain’s promising future in the energy industry cannot be negated as a result of events elsewhere but caution is merited, says Deborah Byers, US Industry and Energy Leader at EY. “A secure, distributed digital ledger blockchain might well be, but nothing is 100% hack proof. As a piece of software it always remains susceptible to hacking. That realism should not be discarded.”

Perhaps the reason there hasn’t been a fiasco on the scale of Mt. Gox in the energy sphere is because deployment is in its infancy, and few wish to talk on-record about a possible hack, opting instead to emphasise how blockchain could help eliminate transaction fraud via digital logs, and how energy specific hackathons (events where systems are tested for weaknesses) are becoming commonplace to mitigate risk.

Another issue is while no single party can tamper with a blockchain ledger without the consent of all parties, no one is particularly in charge of keeping it safe either. Yet, the unstoppable energy blockchain train powers on.

If $12 billion really gets pumped into blockchain by energy companies over the next five years, expectations of return on capital should at least be twice that with negligible security breaches to support it. Given that’s a tall order by any benchmark, there will be winners and sinners in equal measure. More to the point, an operational reckoning is on the horizon for better or worse.

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Opposition to Nord Stream 2 ignores market fundamentals

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ENERGY WATCH #1 - December 13, 2018

Opposition to Nord Stream 2 ignores market fundamentals

by Gaurav Sharma

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Merkel and Putin discuss Nord Stream 2

Criticism of the Nord Stream 2 project routinely misses the bigger picture of EU’s lower carbon targets, Groningen’s impending switch-off and Russia’s own dependence on natural gas exports to Europe.

Pipeline projects by their very nature ought to be functional, reliable and crucial pieces of energy infrastructure built mundanely away from prying eyes, but Nord Stream 2 – the 1,200 km undersea pipeline project aimed at doubling Russian gas capacity to Germany, and by extension to Northern Europe – has proved to be anything but.

The project might be financed by a consortium comprising of Russia’s Gazprom and its five backers, Uniper and Wintershall of Germany, OMV of Austria, Engie of France, and Royal Dutch Shell, the Anglo-Dutch oil major, but its political ownership rests with Germany.

With the first 30 kms of the pipeline extension to the original Nord Stream having been laid, the criticism is getting louder. The primary moan – that Berlin is becoming “dependent” on Moscow for its energy needs – is not new, but the critics’ roster has changed, not least, to include US President Donald Trump, who often likes conducting international diplomacy via Twitter.

Trump belatedly joins a plethora of US senators threatening sanctions against all parties involved. Several Eastern European governments, especially Poland, and proponents of rival southern European pipeline projects have joined ranks with the Americans.

German Chancellor Angela Merkel has even been buffeted by those on her side. Manfred Weber, head of her centre-right leaning EPP group in the European Parliament, and Norbert Röttgen, chairman of the German parliament’s foreign affairs committee, have been vocal in their opposition too, preferring to send her letters of complaints rather than fire tweets.

And if all that was not enough, while the first bit of pipeline is being laid undersea, the scheduled works could not have come at a worse time with tension between Russia and Ukraine at its highest. The recent seizure by Russian forces of three Ukrainian navy vessels and their crews in the Kerch Strait at the entrance to the Sea of Azov, following Moscow’s Crimean annexation has complicated matters further.

Ukraine has always maintained that Nord Stream 2 is a Russian geopolitical tool packaged as energy infrastructure. Until the project comes onstream, much of Europe’s natural gas imported from Russia transits via Ukraine. Transit fees netted Ukraine’s Naftogaz $2.8bn (€2.5bn) in 2017, representative of 1.5% of the country’s GDP.

Despite assurances by Merkel that Ukraine will not be sidelined, few critics are buying it. Yet, for all the noise, much of the criticism seems to be low on facts and figures, especially when it comes to cataloguing Germany’s dependency.

Not in Moscow’s pocket

Trump’s claim that Berlin is “captive” because it imports 51% of its natural gas from Moscow is an exaggeration to put it mildly. Of course, Russia is Germany’s biggest gas supplier. However, it provides only fractionally more in volume terms than two other providers – Norway and the Netherlands.

Dissecting this down to power generation, natural gas, as of 2017, only accounts for 23% of Germany’s primary energy use and only 13.5% of the electricity generated at power plants. Not all of it comes from Russia, but near doubling of gas volumes from 53 billion cubic metres to 110 bcm via Nord Stream 2, as Berlin phases out nuclear and coal fuelled power plants is worrying many.

But much of the imported gas via the German gateway is likely to be passed on and sold on to the rest of Europe. If Trump is so concerned about Germany’s dependency on Russian gas, then perhaps he should look elsewhere on the continent too.

Austria, Bulgaria, Czech Republic, Estonia, Finland, Latvia, Poland, Romania, Slovenia and Slovakia, all imported more than 75% of their total national imports of natural gas from Russia.

How this dynamic will alter over the coming decades, after the Groningen in the Netherlands – once Europe’s largest operational gas field, is shut down by 2030 – remains to be seen but given proximity to Russia, it is only logical to turn to the neighbourhood for solutions.

A necessity that works both ways

Germany, like much of Europe, needs natural gas as a bridging fuel in its march to a low carbon economy. A cursory glance at the country’s underlying market conditions would reveal that. For instance, the UK’s decarbonisation of power generation has gone down from 900gm per KWh to about 225gm per KWh; in terms of CO2 intensity in British electricity generation.

That is largely down to coal shutdowns. But if you look at the comparable data for Germany – it has been steady at 800gm per KWh, which shows the magnitude of the task ahead.

“In order to decarbonise and meet its own high climate change targets, Germany needs natural gas. The most convenient, and economically viable, source at present for Berlin is Russia’s Gazprom,” says Ashutosh Shastri, Director at EnerStrat Consulting.

Likewise, Russia’s natural gas industry needs Germany, and by extension Europe, as much as they need it.

“Complementary, if not as cost effective, sources of LNG imports from Qatar, Algeria and US are emerging for Northern and Southern Europe, but for Gazprom, Europe remains the primary play, and its commercial mainstay,” Shastri adds.

Little surprise then that Gazprom has long ditched its past insistence on coupling natural gas prices with the oil price, and in the price negotiations of both 2008 and 2012, initiated compromises and discounts for supply contracts.

Matter of pure economics

Shuttering political rancour, the commodity business is about finding cost effective solutions and not playing supply games. While the political classes were obsessing over Nord Stream 2 last month, Qatar, the world’s largest LNG exporter, held talks with German energy firms Uniper and RWE, about cooperating on a potential local import terminal and liquefaction train.

Institutional investors pin possible location sites for the terminal at Brunsbuettel and nearby Stade, two small ports on the Elbe River close to Hamburg. Should it come onstream, as is Chancellor Merkel’s express wish, the terminal would join several others in Europe. These facilities provide complementary importation avenues, foster competition and keep the Russians on their toes.

In theory, if US LNG exports to China decline in the wake of trade tensions with Beijing, Europe could be the beneficiary of American LNG terminal projects seeking additional offtake. The country’s gas exports in first half of 2018 alone were more than double the figure posted in 2017, and total US LNG export capacity reached 3.6 bcf per day in March 2018, via Cove Point and Sabine Pass LNG projects.

But American exporters will need to sell for at least $6 per million btu in Europe in order for it to be profitable. It is a price level, Gazprom can, and in many cases does, discount by 20-25%, according to industry sources in Austria and Germany.

The Russian company has shown itself to be a very rational market player in recent years. “If you give up market share, who knows what you might have to do in order to claw that back again. Gazprom’s consistent strategy of defending market share sees Nord Stream 2 at its core, and sometimes you have to take it at face value,” Shastri says.

Little surprise it is then that Russia has labelled Trump and the US’ targeting of Nord Stream 2 as “anti competitive” and “unfair”, and aimed at furthering American LNG exports. Undoubtedly, Nord Stream 2 would foster piped gas versus LNG competition. How it gets played out in different parts of Europe remains to be seen, but both sides are likely to keep the other honest.

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Shell links executive pay to emissions goals – now follow that!

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ENERGY WATCH #2 - December 7, 2018

Shell links executive pay to emissions goals - now follow that!

by Mike Scott

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Royal Dutch Shell has kicked off the annual round of announcements that accompany the UN climate conference with possibly the most consequential initiative of all. It has said it will set short-term, binding targets to cut emissions. Not only that, but it will link executive pay to meeting these targets.

One of the biggest producers of fossil fuels has, for the first time, agreed to cut its carbon emissions – by 20% by 2035, rising to around 50% by 2050. And it is doing this in absolute terms, not per unit of production as high emitters so often do.

This is not tree huggery. It is a hard-headed business decision to position the company for the “energy transition”. “This ambition positions the company well for the future and seeks to ensure we thrive as the world works to meet the goals of the Paris Agreement on climate change,” said CEO Ben van Beurden.

The company has now set the bar for the industry.

But will other oil majors follow?

While Shell is ahead of many of its rivals, it will not be the last company to do this. This is part of a bigger trend, although everyone will do things in their own way.

The other European majors seem likely to follow suit, although US companies may react slightly differently – for example, ExxonMobil announced last week that it’s going to use wind and solar power to produce shale gas in the Permian Basin. Most of the oil majors are stepping up their investments in renewable energy and electric transport. Following Shell’s announcement, expect a race to the top.

When your product is oil, your customers’ emissions matter too

The emissions Shell is planning to reduce include those of its customers. This is another huge development – big oil is starting to realise that it has to deal with end-use emissions as well as its own operations. This is the result of the increasing focus on “Scope 3” emissions – those in a company’s value chain rather than from its direct operations – that is embedded in initiatives such as the RE100, Science Based Targets, the Greenhouse Gas Protocol and CDP’s collection of carbon emissions data. For many products and companies, their key impacts lie not in their own facilities and production but in their supply chains (e.g. food producers) or their end users (e.g. oil and gas groups).

Shell needs to consider end user emissions because other companies are looking to reduce their own Scope 3 emissions to meet their own sustainability targets. If Shell wants to keep selling to them, it has to reduce the emissions from its products.

Shareholder activism is working

This move is the result of pressure from investors, which is both increasing and becoming increasingly targeted in its focus. Shell was asked to act by Climate Action 100+, a group of more than 300 investors representing $32 trillion of assets, which targets the 100 biggest global emitters, representing up to two thirds of global emissions (plus another 61 nominated by the investors as either having significant climate risks or a significant opportunity to drive the clean energy transition.) Three quarters of the companies are either fossil fuel providers or their major customers in utilities, transportation and chemicals.

So even if the sectors ignore investors, their customers are likely to ask them to act. Mindy Lubber, CEO of investor group Ceres, said Shell’s announcement was a critically important benchmark against which other oil and gas majors will be assessed. “Climate Action 100+ will now use this commitment to raise the bar for the oil and gas industry as a whole.”

It’s easy to criticise the sector for a combination of dragging its feet and greenwash announcements that amount to little (ExxonMobil’s algae adverts, for example). But this looks like an indicator of a real change in strategy. Last year, Shell made a load of acquisitions in clean energy, and a load of announcements around climate, that were all pretty small-scale compared to its investments in its core business, and non-binding. These targets are not only binding, they are linked to senior executives’ pay.

Against a geopolitical backdrop that looks really quite pessimistic for climate action, given the prominence of Trump, Bolsonaro, Putin, MBS and others, this sends a huge message to climate-sceptic leaders that the business at the heart of it all believes the science, sees the writing on the wall and thinks now is the time to act.

It also suggests that the sector is starting to see a way through the morass of climate action, which until recently must have looked potentially deadly. It sees healthy demand for years to come in chemicals (including plastics), shipping (where diesel or natural gas could be cleaner alternatives to bunker fuel), and aviation.

The renewable age is starting to make commercial sense

The industry may also be ready to embrace carbon capture, particularly if the carbon can be used rather than stored. I recall conferences over a decade ago where the majors said that CCS was all very well, but governments were going to have to pay. With renewables increasingly cost-competitive with fossil fuels for power, industrial operations and transport, that equation may be changing.

Of course, we need to be realistic about how much difference this will make. The same day as Shell’s announcement, Wood Mackenzie published a report saying that even with oil demand peaking some time in the 2030s, fossil fuels will still comprise 77% of global energy demand. The difference, apart from the growth in the amount of renewable electricity, is that a huge amount of coal is replaced by gas. This suits the majors just fine.