Japan’s Nuclear Energy Revival Facing Public Resistance

By Haley Zaremba - Mar 19, 2024

• Japan aims to increase nuclear energy production but faces challenges due to public opposition and a complex restart process.
• 
  
• Restarting nuclear reactors could significantly reduce reliance on fossil fuels and help Japan meet its decarbonization targets.
• 
  
• There is a growing debate between nuclear power and renewable energy sources for Japan's clean energy future.

The Japanese government is trying to kickstart a nuclear renaissance 13 years after the Fukushima Daiichi nuclear disaster, but a return to nuclear energy is proving difficult for the nation that was once the world’s biggest nuclear power producer. While the government continues to make lofty pledges about revitalizing the industry, which would shore up Japan’s energy independence as well as its decarbonization trajectory, nuclear power generation has stagnated between 5 to 8 percent of the country’s energy mix for years now. 

Japan’s goal to generate 20-22% nuclear energy by 2030 is feeling increasingly far-fetched as that deadline grows closer, and its recent pledge to triple its nuclear energy by 2050 also seems relatively unlikely unless the country seriously alters its approach. As the Asia-Pacific news outlet The Diplomat recently reported, “the yawning gap between vision and policy reality jeopardizes important energy policy goals such as energy security and decarbonizing energy supply.”

Japanese policy and public opinion have largely shunned nuclear energy since the 2011 Fukushima nuclear tragedy, when the most powerful earthquake ever recorded in Japan sent a tsunami crashing into the Fukushima nuclear power plant. The result was the worst nuclear disaster since Chernobyl, and an ensuing sea change in Japanese energy policy. The Japanese public converged to condemn nuclear power production in their communities, while the Japanese government promised to permanently leave nuclear energy in the rear-view mirror. But now, more than a decade later, the fear generated by Fukushima is fading and the myriad benefits of nuclear power are once again beginning to outweigh the trade-offs in the Japanese energy landscape.

Japan, once a climate leader, has now fallen far behind in the clean energy transition. Through the course of Japan’s anti-nuclear decade, the country has become extremely dependent on imports of foreign fossil fuels to keep the lights on. As a result, the nation has seen a worrying decrease in energy independence and energy security, and a major uptick in greenhouse gas emissions. The country’s increasing reliance on coal over the past 13 years has been a particularly big problem for the nation’s carbon footprint. Nuclear, a carbon-free energy alternative, therefore presents a major opportunity for the country to establish its place at the helm of the decarbonization movement. But it has a long way to go.

So far, just 33 of the country’s fleet of 55 commercial nuclear reactors are in working order, and just 27 of those are undergoing a permitting process to restart operations. If those 27 are successful, they could soon provide about 14% of Japan’s energy. While that’s a considerable contribution, it’s a far cry from the country’s espoused nuclear energy targets. 

While some see this as a rallying cry to double down on nuclear in a hurry, others feel that these figures illuminate the fact that nuclear is the wrong approach for Japan, and that instead a pivot toward rapid renewables expansion is in order. As the Diplomat argued in its recent op-ed, “Japan’s nuclear energy revival is supposed to increase energy security and drive decarbonization. Chasing unattainable goals, however, has the exact opposite effect as the yawning implementation gap is continuously filled with fossil fuel imports.” 

Japan is far from the only nation currently betting big on nuclear, however. Nuclear energy is experiencing a renaissance on a global level as memories of disasters like Fukushima fade and the urgent need for carbon-free energy alternatives continues to swell. While nuclear is still divisive due to issues of safety and because of issues around managing spent nuclear fuel, its proponents are growing in number and influence. And nuclear does have a lot of benefits. It’s a proven technology with existing supply chains and established blueprints, and, critically, it’s a base load power source, meaning it’s not variable like wind and solar power. 

By Haley Zaremba for Oilprice.com 

Private Equity Cashes In After $30 Billion Shale Exit Deals

By Tsvetana Paraskova - Mar 20, 2024

• Buyout firms with oil and gas assets sold an estimated $30.55 billion worth of these last year.
• 
  
• Private equity saw the perfect opportunity to exit some oil and gas assets amid rising valuations of drilling locations in 2023.
• 
  
• U.S. oil and gas exploration and production companies spent as much as $234 billion on M&A last year—the highest such spend in real dollar terms since 2012.

Private equity firms have rewarded investors handsomely in recent months after divesting more than $30 billion worth of oil and gas assets in the U.S. shale patch in a blockbuster year for American upstream mergers and acquisitions.

Buyout firms with oil and gas assets sold an estimated $30.55 billion worth of these last year, and consequently, they paid billions of dollars to the investors of their oil and gas-focused funds, The Wall Street Journal reports.

As oil and gas producers, flush with cash from the 2022 record profits, started scouring the U.S. shale patch for additional drilling inventory, private equity saw the perfect opportunity to exit some oil and gas assets amid rising valuations of drilling locations.

Unlike in the late 2010s boom in acquisitions and production, this time around private-equity holders haven’t been selling entirely undeveloped assets to large public companies. They have developed at least part of the assets to get production and cash flow rising enough to attract the buyers, which are now looking to snap up drilling inventory that would begin yielding cash flows and shareholder returns almost immediately.

The most recent trend of private equity selling billions of dollars worth of assets to public producers began in the second quarter of 2023. Out of the six deals that topped $1 billion during Q2 2023, four were buyouts of exploration and production companies funded by private equity that operated entirely in the Permian by public companies, data from Enverus Intelligence Research (EIR) showed last summer.

The biggest deals involved EnCap Investments selling its portfolio companies Black Swan Oil & Gas, PetroLegacy Energy, and Piedra Resources to Ovintiv in a cash and stock transaction valued at around $4.275 billion. Another major deal was private equity firm NGP Energy Capital Management divesting Hibernia Energy III and Tap Rock Resources, portfolio companies of funds it manages, for $4.7 billion. The buyer, Denver-based Civitas Resources, thus entered the Permian basin with premium low-breakeven inventory, which is set to boost Civitas’ production by 60%.

“The formation of new private-equity-backed E&Ps hit its peak in 2017 and now, six years later, those investments are being unwound via sales to public companies,” Andrew Dittmar, director at Enverus, said.  

“For those that invested in the Permian Basin, the returns are likely substantial.”

Investors in oil and gas funds managed by private equity groups did indeed receive substantial returns.

EnCap Investments, for one, distributed a record-high $7.8 billion to investors in 2023, also thanks to the Ovintiv deal, according to an investor letter viewed by WSJ Pro Private Equity.

NGP Energy Capital Management also paid a record distribution to oil and gas-fund investors, exceeding a previous record of $1.5 billion from 2021, sources with knowledge of the matter told the Journal. 

Quantum Capital Group paid around $3.1 billion to oil fund investors in 2023, down from a record-high of $3.8 billion in 2022. But then in January 2024, Quantum Capital paid another $900 million to investors, thanks to a $2.7-billion deal it completed in December to sell Rockcliff Energy II LLC to TG Natural Resources LLC, according to Journal sources with knowledge of the matter.

With the current merger and acquisition wave in the U.S. oil and gas sector not over yet, private equity firms have more opportunities to sell assets at high valuations.

For example, U.S. oil and gas exploration and production companies spent as much as $234 billion on M&A last year—the highest such spend in real dollar terms since 2012, the Energy Information Administration (EIA) said in an analysis this week.

Private equity also continues to raise and deploy capital in buying assets. Over the past two years, private equity firms have announced about 20 new commitments, excluding groups investing in minerals and royalties, Enverus said earlier this year.

But the game for the specialist buyout firms has changed, the intelligence company said.

“Rather than buying promising exploratory acreage and hoping to prove it up before selling to a public operator, the firms will likely be looking to buy relatively developed assets cheaply and generate dividends for their private investors.” 

By Tsvetana Paraskova for Oilprice.com

 

Israel's Gas Exports to Egypt Soar Despite Political Tensions

By ZeroHedge - Mar 20, 2024

• Israel's natural gas exports to Egypt increased by 28% in 2023, with projections for a significant rise in production by 2026.
• 
  
• The new agreement is expected to benefit both nations economically and strengthen Israel's geopolitical standing.
• 
  
• Political tensions over Israel's Gaza plans persist, with Egypt building a "security zone" amid concerns about potential Palestinian refugees.

Via The Cradle

Israel’s NewMed Energy reported on Tuesday that natural gas exports from the Leviathan field to Egypt increased by 28 percent in 2023. The company reports that the exports jumped from 4.9 billion cubic meters (BCM) in 2022 to 6.3 BCM in 2023. 

Israel Katz, former energy minister, approved the increase in exports to Egypt last year. For 2026, he projected an annual production increase of six BCM – about 60 percent over the current volume. "3.5 BCM of which will be directed in favor of Egypt," the report stated. 

"The expansion of the total export quota to Egypt was increased by 38.7 BCM over 11 years," the Israeli Ministry of Energy’s August announcement read. "The export permit was granted under the comprehensive framework approved by government decisions … and in consultation with the Director of the Natural Gas Authority. In addition, an additional increase of 0.5 BCM per year is being considered."

The ministry noted that, in addition to enabling production expansion, the new exports are expected to derive billions of dollars in bonus revenues for Israel, increase energy ties with Egypt and other regional players, and strengthen Israel’s geopolitical status.

Furthermore, the report adds that "on December 14, 2023, the partners in the Tamar reservoir announced that the Ministry of Energy approved them to increase the export permit of the reservoir from 38.7 BCM … to 43 BCM. This amount will make it possible to increase the maximum amount of additional gas allowed for export to Egypt from 3.5 BCM per year to 4 BCM per year. As of the valuation date, no agreement has yet been signed. The export is subject to the aforementioned export permit."

NewMed reported that Leviathan’s partners, including Chevron, will invest $568 million to upgrade the field. In the latter half of 2025, annual production will increase from 12 BCM to 14 BCM. The company reported a fourth-quarter profit of $102 million, down significantly from $141 million the previous year.

Egypt–Israel tensions have been on the rise in recent months over Tel Aviv's plan to push Gazans into the Sinai Peninsula to continue with their plan of invading Rafah. 

Cairo has called on Washington, which has previously condemned the plan, to send a clear message to its regional ally not to move forward with the Rafah invasion. It says that "it is not enough to state opposition; it is also important to indicate what if that position is circumvented, what if that position is not respected."

However, following multiple investment deals into Egypt by other regional allies of Israel and a boost in the International Monetary Fund (IMF) loan to be granted to Egypt, the North African nation is constructing an "isolated security zone," something which local rights groups are calling Cairo's preparation for an influx of Palestinian refugees.

By Zerohedge.com

The Golden Age of Miner Dividends Might Be Coming to an End

By City A.M - Mar 20, 2024

• Rising commodity prices and potential shortages are forcing mining companies to invest in exploration and production instead of high dividends.
• 
  
• Investors enjoyed years of large payouts from mining giants, but this trend may be ending.
• 
  
• Glencore and Rio Tinto have already cut dividends, and BHP and Anglo American might follow suit.

According to a new report, after years of bumper dividends, investors will have to get used to lower cash returns from mining giants such as BHP, Rio Tinto, Anglo American, and Glencore.

Analysis from Morningstar published today said that after “many years of returning excess cash to shareholders” at the expense of expanding portfolios through mergers and acquisitions, heightened prices are now forcing a strategic rethink.

Geological deposits are finite and deplete; be it precious metals such as gold and silver, energy fuel such as coal or energy transition metals such as zinc and copper.

This recently led HSBC’s chief economist Paul Bloxham to opine that commodities are in the midst of a “super-squeeze,” and have been for some time.

Indeed, the Energy Transition Commission warned back in July that markets could be looking at a shortage of a slew of metals like graphite, cobalt, copper, nickel and lithium in the next decade.

“Large-scale mining projects can take 15-20 years, and the last decade has seen a lack of investment in exploration and production for key energy transition materials,” the report said.

Furthermore, mining companies often develop or acquire assets when prices are high, only to find out when the cycle corrects that they overpaid and the reserves are not worth as much.

All this is likely worrying news for investors in the major miners, like Rio Tinto, BHP, Glencore and Anglo American.

These have been some of the biggest dividend payers in the world in recent years, with Glencore and Rio claiming the title of the second and third biggest dividend payers, respectively, in the FTSE 100 in 2022.

However, this is now starting to change.

Shares in Glencore slumped when it reported its results in February and revealed it would be slashing its dividend from 34 cents (27p) to 13 cents (10p) to help pay for its $6.9bn (£5.4bn) buy of Teck Resources’ coal operations.

Indeed, including the $4bn (£3.1bn) buyback programme from 2023, last year’s cash return for shareholders was just 16 per cent of that in 2022.

The firm was also much more exposed than other major miners to energy transition metals, such as zinc, lead, cobalt, and nickel, that did not see price gains in 2023.

Its peer, Rio Tinto, also cut its dividend last year off the back of a 19 per cent fall in net income.

And Anglo American slashed its dividend by more than half for 2023.

The company, which has seen its stock drop more than 40 per cent year-on-year, is shopping a stake in its Woodsmith fertiliser mine as it seeks to share the $9bn (£7bn) development cost.

It could also be looking at spinning off the struggling de Beers diamond brand, which is suffering setbacks at the hand of waning consumer demand for expensive gems.

The last and biggest factor in the commodity mining landscape continues to be China, the largest single consumer of copper, coal and others in the world.

For as long as the Chinese proeprty market remains in flux, Morningstar contends, it will weigh on miners with exposure to resources involved in energy, steel-making, the green transition, automotive and consumer goods.

If commodity prices continue to tighten as projects become harder to find, finance and bring online in short order, investors will have to reckon with the fact that the good old days of bumper payouts may be numbered.

By CityAM 

The Dark Side of the Lithium Boom

By Haley Zaremba - Mar 20, 2024

• Increased renewable energy production requires a massive increase in lithium production.
• 
  
• Lithium extraction in South America's Atacama Desert is highly water-intensive and threatens local water supplies.
• 
  
• Locals fear environmental damage and economic exploitation from foreign mining companies.

Lithium has become one of the most sought-after metals in the world as the clean energy transition accelerates around the world. This ‘white gold’ is an integral part of many technologies at the heart of the decarbonization movement, including solar panels, electric vehicle batteries, and batteries used for renewable energy storage. As a result, demand for lithium is rapidly increasing, and countries around the world are racing to shore up supplies. 

According to estimates from the International Energy Agency (IEA), renewable electricity capacity additions reached 507 GW in 2023, almost 50% higher than the previous year. “Solar PV and wind additions are forecast to more than double by 2028 compared with 2022, continuously breaking records over the forecast period to reach almost 710 GW,” IEA stated in its Renewables 2023 report.

The breakneck growth rate will require a major intensification of manufacturing capacity addition for key components such as photovoltaic solar panels, wind turbines, and lithium-ion batteries for EV engines as well as renewable energy storage –  which is to say, it will require a whole lot of lithium. A 2023 report from Popular Mechanics calculated that “an electrified economy in 2030 will likely need anywhere from 250,000 to 450,000 tonnes of lithium.” To put that massive number in perspective: “In 2021, the world produced only 105—not 105,000—tonnes.”

While the rapidly increasing value of lithium presents some benefits to the economies where large lithium deposits are found, it also brings with it some very serious trade-offs. In South America’s lithium triangle, for example, the expansion of lithium extraction in the salt flats of Argentina, Bolivia, and Chile is a highly contentious issue. As industry from the United States, Russia, and China offer major deals for extraction of the white gold that stand to enrich some players in South America, locals fear that such deals will cause irreparable damage to the ecosystems they depend on for their livelihoods.

Traditional lithium extraction is an extremely water-intensive endeavor. According to a report from WIRED magazine, extracting a single ton of lithium requires approximately 500,000 liters of water. It also poses a potential threat of contaminating existing water reserves. This is because lithium is typically extracted by pumping brine into ponds, allowing them to evaporate, and harvesting the remaining lithium salts. 

This water use poses a major issue to the communities where the lithium is found, as it is concentrated in desert environments. The famous lithium triangle encompasses the Atacama Desert and surrounding arid regions, which just happens to be the driest desert in the world. Water is extremely precious to those who live there, and opposition to competition for the scarce resource is understandably fierce.

On top of these problems, the chemicals used in lithium extraction are extremely toxic and pose a threat to human health. "The release of such chemicals through leeching [sic], spills or air emissions can harm communities, ecosystems and food production," reads a recent report from international environment activism group Friends of the Earth. "Moreover, lithium extraction inevitably harms the soil and also causes air contamination."

Locals in the Atacama Desert are also highly vulnerable to the effects of climate change, which they are already feeling to an intense degree. This is a painful irony – lithium production is essential to curbing climate change, but may wipe out their water resources even more quickly than global warming ever could. Moreover, the locals that stand to face the highest cost for this industry will likely reap none of the benefits. Bolivian quinoa farmers living in rural areas that may or may not have access to electricity have relatively little use for electric cars. They will also almost certainly see none of the money from high level lithium deals. 

Such farmers are a microcosm of a bigger issue of exploitative extraction. The companies that are targeting these lithium reserves are almost exclusively foreign companies, which means that the benefits to local economies are relatively limited. While Lithium Triangle companies have already signed a number of deals with Chinese and Russian firms, the political climate is changing in favor of domestic production and processing of lithium. “Adding value is central for us,” Argentina Mining Undersecretary Fernanda Avila was quoted by Bloomberg last year. “We know the industry today is growing and there’s a lot of pressure and price volatility. But it’s about making the most of this window of opportunity, not just by shipping out lithium carbonate.”

By Haley Zaremba for Oilprice.com

 

Oman Takes The Lead in Green Hydrogen

By Alan Mammoser - Mar 20, 2024

• Yara, the Norwegian fertilizer and industrial chemicals producer, entered a long-term contract with ACME Cleantech Solutions Pvt. Ltd. to supply 100,000 tonnes per annum (mtpa) of ‘green’ ammonia beginning early 2027.
• 
  
• ACME will soon start construction on a fully integrated plant on 12 sq. km in the Special Economic Zone at Duqm.
• 
  
• As carbon-free hydrogen moves closer to market, it’s clear that companies are now dealing with more than demand risk.

Hydrogen produced with renewable power had a significant breakthrough this month, with the signing of an offtake agreement between a European buyer and an Indian producer in Oman.

Yara, the Norwegian fertilizer and industrial chemicals producer, entered a long-term contract with ACME Cleantech Solutions Pvt. Ltd. to supply 100,000 tonnes per annum (mtpa) of ‘green’ ammonia beginning early 2027.

ACME will soon start construction on a fully integrated plant on 12 sq. km in the Special Economic Zone at Duqm (SEZAD) on Oman’s central coast.

It’s the first major agreement between non-affiliated companies for green ammonia and an important breakthrough for Oman.\

Anatomy of an agreement

Ashwani Dudeja, Group President and Director, ACME Cleantech Solutions,  says that the companies went through 20 months of negotiation. The agreement was signed just two weeks ago for a long-term contract of up to 30 years.

Now, with the binding agreement in place, and financing arrangements with Indian lender REC Limited (Rural Electrification Corporation) finalized last year, the company is moving forward with the project’s first phase.

Basic work at the site is underway and major work will begin this year.

The Yara contract is for 100% offtake from phase 1. Production will occur at a fully integrated self-contained plant including electrolysis, hydrogen storage, ammonia production, and a flexible pipeline and jetty, which can load ammonia carrier ships directly from the plant.

The production area encompasses 12 sq. km containing the solar power plant and a small wind plant to maintain EU Renewable Fuels of Non-Biological Origin (RFNBO) compliance, as Yara will take the volumes mostly to Europe.

A land reservation agreement for 92 sq km was signed with SEZAD in 2022, with a usufruct agreement for the 12 sq. km phase 1. For this, the company worked with different ministries in the Omani government.Related: UK Plans £60 Billion Grid Overhaul To Support Offshore Wind Boom

Later, when the government’s new facilitating agency Hydrogen Oman (Hydrom) came into existence, ACME entered negotiations with Hydrom for a subsequent phase on the remaining 80 acres. The company intends to expand the project to 0.9 million tonnes per annum with approximately 3.5 GW of electrolyser capacity, to be powered by a 5.5 GWp solar PV plant.

ACME is one of several companies operating in Oman with legacy project agreements now overseen by Hydrom. More projects in Duqm were announced in Hydrom’s Round 1 earlier this year. Hydrom is now conducting Round 2 for projects at Salalah on the south coast.

A major concern is certification to meet evolving requirements for net-zero carbon hydrogen products. Early on, ACME retained testing and certifications services company TUV Rhineland to get the Oman project pre-certified based on plan. This has now expired and the company will seek new certification of the finished plant as per the prevailing standards. 

“This is an evolving area, there's no unified standard globally at the moment for hydrogen or ammonia,” says Dudeja.

“It’s big draw-back at the moment, the rules for certification in Europe may be different than in Asia, so which certification method to follow?” he says.

"Negotiating what happens if there are changes becomes a tough exercise."

The company, with others, is advocating with regulatory bodies to create some kind of standardized certification methodology for project developers to follow.

Seeking certification

As carbon-free hydrogen moves closer to market, it’s clear that companies are now dealing with more than demand risk. They are trying to adapt to regulations at an early design phase, to comply with the European RFNBO requirements under RED II and III, which lay down the conditions that will make hydrogen products compliant.  

But these requirements for ‘green’ certification are evolving in different regions including Asia, adding complexity to project design and causing companies in Oman and elsewhere to proceed cautiously.

Oman has set up a framework for a pre-certification exercise, to help  developers seeking to reduce uncertainty.  

"The pre-certification work, to stress test what will be the certification, the degree of greenness of the molecules if we would export them to Europe, has been essential,” said Stefani Giuseppe, General Manager Green Hydrogen, DEME Concessions NV, speaking at the World Hydrogen MENA conference in Dubai last month.

"It's one of the pieces of the puzzle we need before investing further in the project,” he said.   

His company, partnered with Oman’s OQ Alternative Energy in the Hyport Duqm consortium, is among the multinational consortia that were awarded land blocks by Hydrom last year.  

Hyport Duqm plans to produce approximately 330,000 metric tons of green ammonia from a combined renewable power capacity of around 1.3 GW in a first phase.

"It (certification) is a major challenge very much related to the off-take, which is essential,” said Giuseppe.

First mover know-how

Ashwani Dudeja came to ACME two years ago after nearly three decades in the gas, LNG and power business including stints at BG Group, Shell and ADNOC.

He says that the company came to Oman with experience that gave it confidence to assume first-mover risk and have a head start.

“With green ammonia, about 90% of the commodity price is capex, so everything is up front, so with an up front commitment on capex you need certainty of cash flows for the project finance to happen."

“We assumed a lot of risk,” he says.

The 20 months of negotiation with Yara produced a contract that did not have much precedent. While most (grey) ammonia trades on short-term contracts, the green product required a long-term contract to match the project financing period.

"It was a great learning for both organizations."

Another important part of the company’s learning came from its pilot plant, which it built at Bikaner in Rajasthan. It’s an integrated green hydrogen and ammonia plant, operating for two years now, producing 5 tonnes per day with power from a dedicated 5 MWp solar plant.

This pilot, built at considerable cost, does not earn a commercial return; the product is sold on the market at grey ammonia prices. Yet it gave the company important knowledge

"We wanted to learn how to operate the electrolysers and how to integrate the entire chain," he says.

Added to this is the company’s experience as a renewable power developer, with more than 8 GWp renewable power capacity built or under construction in India.

It’s critical knowledge in the hydrogen sector, where approximately 50% or more of project cost is renewable power, the balance 50% split between electrolysis and ammonia production.

The company also enjoys deep relationships with technology providers that facilitate procurement on a consolidated basis.  

A little disruptive

ACME has more large hydrogen projects in the works.  

"We are building a pipeline of projects, not stopping just at Oman," says Dudeja.   

Following closely on the Oman project is planning for a project at a port in the Indian state Odisha, for green ammonia production of 400k tonnes per annum. ACME has received government incentives for this project and has signed a term sheet with IHI Corp. of Japan, with FID study now underway. ACME is also considering starting its own electrolyser manufacturing for the Odisha project. 

The company also secured land for a plant in Port of Victoria, Texas following passage of the IRA legislation last year. Black & Veatch is undertaking design studies, while financial decisions may wait for the US election outcome.  

ACME is also one of the short-listed parties in the first H2Global contract-for-difference tender, financed by the German government to stimulate import of net-0 hydrogen derivatives to Europe.

Dudeja says that the company, which started 20 years ago producing energy management systems for mobile cell towers in India, has the agility, determination and risk appetite to make green hydrogen work. While others delay, it’s moving forward.

"We have always been a little disruptive," he says.

By Alan Mammoser for Oilprice.com