Is Clean Energy Really More Expensive Than Traditional Energy?
Judging from the news story, a PR firm had an assignment: to inform the world that clean energy prices exceed dirty energy prices, just as Republicans in Congress try to repeal large parts of the Inflation Reduction Act (which boosts clean energy). Maybe a coincidence. Politics is not our area of expertise. But the arguments that were made sure read like talking points that politicians repeat in cable news interviews: Clean new industries will need workers, especially engineers, and won’t get them by raiding staff from fast food restaurants. This is true, of course. The new industries will have to compete for experienced workers, attract American students into engineering, entice engineers from abroad, and offer competitive wages. The old industries will have to compete for the workforce with the new industries. That’s what happens in markets. The new policies will upend our decades-long dependence on global markets to provide goods and services at the lowest prices. Well, isn’t the point of going local to protect our national security? Extra security costs money, just as insurance does. So, do you want security or low prices? Government handouts to particular technologies distort the market. Economists agree that the least market-distorting way to deal with the problem is to tax carbon and let the market figure out how to reduce emissions. But let’s be realistic. Congress will not approve any new tax. So Biden had the choice of a sub-optimal policy or doing nothing. As Voltaire said, “The perfect is the enemy of the good.” These dazzlingly unhelpful bullet points don’t mention a principal reason why clean energy prices may exceed dirty energy prices: the latter do not include costs borne by society, not the producer or user. If the cost of damage to health or the environment were included, the dirty product might cost as much as or more than the clean product. So, switching to a clean product might affect the price paid but not the cost to society. Marketers and product developers might brush off the argument altogether. New products often sell for more than seemingly similar old products. Consumers who want to be first on the block willingly pay more, especially for a product they see as different. And the cost and price of new products decline as producers attain economies of scale. What’s the big deal, then? Maybe a big part of the problem is that incumbent energy companies, which have political influence and money don’t spend much on research and development, relatively speaking, do not develop new products and will lose out if the new competitors succeed. So they have every reason to lobby against the new competitors, especially if the government is giving them a boost. ExxonMobil, Shell, and Chevron, between them, spend only 0.3% of revenues on research and development, and the electricity and natural gas industries in the United States around 0.1% of revenues. On the other hand, automotive giants General Motors and Ford, together, spend 5% of revenues on research and development, and fuel cell manufacturers Bloom Energy and Plug Power 13%. Our point is not that when you don’t spend on your future, you might not have one, but rather if you don’t spend on improving your products you may not find ways to reduce their costs or improve their attractiveness, while your competitors are doing just that. Projections show a continued decline in the costs of alternative energy that will soon bring them below legacy energy costs. But that analysis does not take into account any number of projects that could disrupt the energy market even more: Co-fire fossil fuel plants with ammonia. (A project that involves major Japanese utilities and global ammonia producers.) Improve perovskites, which could substantially reduce solar costs and revolutionize its uses. (Work ongoing in China and USA.) Turn hydrogen into the new storage, fuel, and energy transfer medium. (Huge projects underway throughout the world.) Establish the existence of commercial deposits of renewable hydrogen underground. (A small-scale Australian enterprise with potentially big prospects.) Demonstrate via an expensive exploratory drill hole in Utah the possibility that we can tap deep, dry rock geothermal energy (enough to replicate the U.S. generating fleet 500 times over). Build superconductor grids to connect renewable energy. (A European energy firm wants to do just that, arguing that the existing grid cannot do it. What about here?) Any of these possibilities could dramatically raise the prospects for decarbonization, largely by improving the cost and reliability of electrification. We would get a better notion of future costs by looking forward not backward.
India’s imports from OPEC at all-time low as Russian oil buy peaks
India’s oil imports from oil producers cartel OPEC’s share fell to an all-time low of 46% in April as purchases of cheaper Russian oil peaked, recently released industry data has shown. The Organization of the Petroleum Exporting Countries(OPEC) nations, mainly in the Middle East and Africa, had a 72% share of all crude oil India imported in April 2022. This share fell to 46% in April 2023, according to energy cargo tracker Vortexa. OPEC made up for as much as 90% of all crude oil India imported at one point of time but this has been sliding since Russian oil became available at discount in the aftermath of Moscow’s invasion of Ukraine in February last year. OPEC supplied 2.1 million barrels per day out of 4.6 million bpd oil India imported in April. This gave it a 46% share, according to Vortexa. Russia continued to be the single largest supplier of crude oil, which is converted into petrol and diesel at refineries, for a seventh straight month by supplying more than one-third of all oil India imported.
No oil exploration in disputed areas without consulting all stakeholders and tribal bodies in the area, says Nagaland government
Following opposition to oil exploration in Nagaland, the state government has stated that exploration in the disputed areas with Assam will not start before consulting all stakeholders and tribal bodies of the area. Nagaland deputy chief minister Y Patton on Friday said, “The government will hold a consultative meeting with all stakeholders before signing the MoU with Assam government. The government will hold consultation with tribal bodies and civil societies of the oil-bearing areas of Nagaland—Mon, Longleng, Mokokchung, Wokha, Nuiland, Dimapur and Peren.” The NSCN-IM and Working Committee of Naga National Political Groups (NNPGs) , both of which are in the peace process, said that the natural minerals and resources should not be explored without arriving at a final solution to the Naga political issue. Oil India Limited (OIL) plans to start exploration in Nagaland once the climate is conducive. OIL is planning to do a 3D seismic survey of 4000 sq km of area in Upper Assam. OIL has done seismic data accusation of the areas in the Northern bank of Brahmaputra in Assam. OIL has a 3000 sq. km area in Nagaland. Dr Ranjit Rath chairman and Managing Director OLI who was in Guwahati on Monday while talking to media persons said, “We already started exploration in Mizoram. Further study is going on to further explore. In Tripura we have assets and exploration is done. In the Northern bank of Brahmaputra River Pathshala and Mangaldoi are covered under Open Acreage Licensing Policy (OALP) bidding. We have done seismic data acquisition.” He added, “We are carrying out exploration in Arunachal Pradesh, we have planned extensive drilling and production is going on. In Nagaland till the time there was a dispute between Assam and Nagaland that was getting sorted out. There is a lot of discussion going on. We have 3000 sq km of exploration acreage in Nagaland. “ Rath said, “Once there is a climate of sorted out issues we will immediately have started exploration. We strongly believe that both the Assam shelf where we have the main producing area, and the Assam- Arakan fold belt which is in the South East of Assam shelf covering Nagaland has enough potential.” CMs of Assam, Nagaland held talks on settlement of border dispute, agreed in-principle on exploring oil in disputed areas for economic benefit recently. Both states have in-principle decided to go in for a MoU on oil exploration in the disputed areas along the inter-state boundary so that oil can be extracted and royalties shared between the neighbouring states. ONGC had earlier stopped E&P activities in Nagaland in 1994 after the militant outfit NSCN (IM) asked it to quit the state. Rath said, “In Manipur we are taking up baseline assessment of the areas in Nagaland border and some areas will be picked up for explorations.
India’s oil imports from Russia seen peaking in May amid China competition
Russia remained the top crude supplier to India in April, further improving its market share to 36%, but a slow month-on-month increase fuelled expectations that the imports from the country could peak in May. That’s being attributed to competition from China for the oil. Russia supplied 1.68 million barrels a day (mbd) of crude to Indian refiners in April, 4% higher than 1.61 mbd in March, according to energy cargo tracker Vortexa. China imported 1.3 mbd by sea from Russia while Europe imported 206,000 barrels per day in April. India’s overall crude imports fell 3.5% to 4.6 mbd in April from March. Russia’s share in India’s crude imports expanded to 36.4% in April from 33.8% in March. This compares to a share of 0.2% before the Russia-Ukraine war. However, the increase in imports of the deeply discounted Russian oil has slowed in recent months. After rising sequentially by 29% in December and 26% in February, the increase slowed to 1.8% in March and 4% in April. Indian Refiners Focus on Europe for Exports Iraq’s share in the Indian market shrank to 17.6% in April from 18.4% in March, while Saudi Arabia’s share dropped to 14.5% from 21%. The UAE’s share fell to 4% from 6.5%. The US and Africa marginally gained. “India’s imports of Russian crude in April have set a new record once again, but the month-on-month increase has slowed and could possibly be peaking this month. Increased competition for Urals from China will likely put a lid on upsides to India’s imports of Russian crude,” said Serena Huang, an analyst at Vortexa. Urals, the Russian flagship mid-sulphur crude, has been the biggest draw for both India and China as it has sold at a deep discount to the global benchmark Brent. It’s easier to ship Urals and pay for it as it’s mostly traded below the G7-imposed price cap of $60 per barrel on Russian oil. India’s import of Urals rose 9% in April over March when it had registered a 5% month-on-month decline. The share of Urals in Russian oil imported by India rose after several months in April to 73.6% from 70% in March and 79% in January. The share of ESPO, another Russian grade, nearly doubled to 10.5% in April from March. India’s imports of Russian refined products fell 31% sequentially to 125,000 barrels per day in April. Chinese imports of Russian products increased 44% to 321,000 bar .. India’s imports of Russian refined products fell 31% sequentially to 125,000 barrels per day in April. Chinese imports of Russian products increased 44% to 321,000 barrels per day while Europe’s remained steady at around 479,000 barrels per day. “While India’s clean product exports in April have fallen by 25% month-on-month, exports to Europe have remained robust, amid a supportive arbitrage,” said Huang. India exported 264,000 barrels per day of refined products to Europe in April compared with 285,000 barrels per day in March. Its exports to the US fell to 30,000 barrels per day in April from 106,000 barrels per day in March. Better margins in the European market have shifted Indian refiners’ focus away from the US to Europe. Europe, the biggest market for Russian crude as well as refined products before the Ukraine war, is seeking supplies from elsewhere in the world after deciding to largely cut dependence on Russia.
Just How Important Is The U.S. Shale Industry?
In 2022, almost 7.8 million barrels of crude oil daily were produced from so-called tight oil resources. The other name for these is unconventional resources. Yet a third and a lot more popular name is shale. Shale is a porous rock that traps hydrocarbon molecules in its pores and makes their release tricky. Or it used to be tricky. Back in the early 20th century, a technology called hydraulic fracturing was developed that allowed the extraction of those hydrocarbon molecules from the pores of the shale rock. Some trace the origins of fracking back to the 19th century when some producers used liquid and solid nitroglycerin to stimulate yields from oil wells in several U.S. states. Modern fracking, luckily for all involved, does not use nitroglycerin. It uses water, chemicals, and sand. Although known for decades, fracking only gathered pace in the early 2000s after a landmark study by the Environmental Protection Agency, which concluded that hydraulic fracturing does not pose a contamination threat to drinking water resources. What followed this study was aptly named a revolution. A historical U.S. oil production chart by the Energy Information Administration reveals a fascinating story. Until about the end of 2010, production grows gradually and consistently, with a few dips here and there following the industry boom and bust cycles. From 2011 onwards, growth is no longer smooth and gradual—it is a literal spike from around 5.6 million barrels daily at the end of 2010 to 13 million barrels daily by late 2019. All thanks to fracking. Fracking, which not everyone in the oil and gas industry likes, by the way, because it was used as a euphemism for a curse word on Battlestar Galactica, turned the United States into the world’s biggest oil producer and also the world’s biggest gas producer. It was gas production that hydraulic fracturing was first used for, and only later expanded to oil. To date, despite slowing production growth and forecasts from some analysts that the revolution is over for good, hydraulic fracturing still contributes the bulk of U.S. total oil and gas production and keeps it higher than anyone back in the 1970s, for instance, could have expected. The process of hydraulic fracturing is simple, on the face of it. It involves drilling a well into the shale rock and injecting into it a mixture of water, chemicals, and what the industry calls proppant, or a special sort of sand, that lodges in the porous rock and keeps the pores open so the oil and gas can ooze out and be collected from the well. Yet simple does not mean easy. Fracking requires massive amounts of the abovementioned materials—the longer and deeper wells become, the more water, chemicals, and sand fracturing them requires. Then there is the wastewater problem. A few years ago, Oklahoma drew media attention because of the significantly increased frequency of earthquakes since the start of the shale boom. The state, one of the big oil producers in the U.S., had negligible seismic activity before 2009, when fracking really took off. By 2016, Oklahoma was recording an average of two quakes a day—what was earlier the average for a year. To date, quakes are just as frequent. Some blame hydraulic fracturing for unsettling the rock and stimulating seismic activity. The U.S. Geological Survey conducted a study and found that it’s not fracking itself that is the problem. The problem was the massive amounts of wastewater that get disposed of in underground reservoirs after the fracturing process is completed. Wastewater wells, the USGS said in its study, operate longer than it takes to frack a production well, and they absorb greater quantities of fluid. This is what causes increased seismic activity, according to the USGS, which only found a causal link between fracking and quakes for just 2% of quakes in Oklahoma. Wastewater disposal regulations have expectedly tightened since that study was published but opposition to hydraulic fracturing has not diminished—at least outside the United States. Amid the energy crunch last year in Europe, some from the industry called on European governments to start exploiting their own, sometimes considerable, shale oil and gas resources. The backlash was immediate and powerful, just as it was years earlier when it led to fracking bans in France, Bulgaria, Denmark, and the Netherlands. In some cases, however, it’s a question of economic viability. Poland, for example, has ample shale resources, but extensive exploration failed to find a way to extract these economically. Norway, too, declared its shale resources uneconomical, focusing on conventional offshore drilling. Whether hydraulic fracturing has been a boon or a bane depends on the perspective. From an energy security perspective, it has most certainly been a boon, and not just for the United States. Argentina is now drawing on U.S. producers’ experience to develop its own shale oil and gas riches in the Vaca Muerta formation, and Europe has enjoyed a steady flow of American oil and gas, most of them extracted from the same shale formations exploiting which Europe’s shale-rich countries have banned. Yet in a reminder that there is always a tradeoff, Oklahoma still experiences earth tremors on a much more frequent basis than it did before the shale revolution began. There is also growing pressure on the industry to reduce its methane emissions, which are considerable. The industry is working on that. After all, methane is a marketable product—another fruit of the shale rock.
Increasing compressed biogas share in total gas mix can reduce annual import bill by $25 bn by 2030: IBA
The Indian Biogas Association(IBA) has pitched for increasing the share of compressed biogas in total gas mix, saying it will help reduce the country’s annual import bill by USD 20-25 billion by 2030. In a letter to Petroleum and Natural Gas Minister Hardeep Singh Puri recently, IBA suggested that in the process of attaining a gas-based economy by 2030, the oil ministry has to keep a strict vigil on the overall sustainability. The industry body suggested gradually increasing the share of compressed biogas (CBG) in the overall gas mix to at least 10 per cent by 2025 and to 20 per cent in 2030. Furthermore, the CBG-CGD (city gas distribution) synchronization plan, which was launched in April 2021 and is due for review three years later (in 2024), should be extended for at least ten years to provide long-term certainty to players in the CBG ecosystem, it suggested. Increasing the share of CBG will ensure guaranteed offtake and a transparent ecosystem for CBG producers.