Missing wind turbine may not have been stolen

Germany Energy Transition faces offshore wind expansion, grid bottlenecks, and North-South transmission delays, while Nord Stream 2 boosts Russian gas reliance and lignite coal persists amid a nuclear phaseout and rising re-dispatch costs.

Key Points

Germanys shift to renewables faces grid delays, boosting gas via Nord Stream 2 and extending lignite coal use.

✅ Offshore wind grows, but grid congestion curtails turbines.

✅ Nord Stream 2 expands Russian gas supply to German industry.

✅ Lignite coal persists, raising emissions amid nuclear exit.

On a blazing hot August day on Germany’s Baltic Sea coast, a few hundred tourists skip the beach to visit the “Fascination Offshore Wind” exhibition, held in the port of Mukran at the Arkona wind park. They stand facing the sea, gawking at white fiberglass blades, which at 250 feet are longer than the wingspan of a 747 aircraft. Those blades, they’re told, will soon be spinning atop 60 wind-turbine towers bolted to concrete pilings driven deep into the seabed 20 miles offshore. By early 2019, Arkona is expected to generate 385 megawatts, enough electricity to power 400,000 homes.

“We really would like to give the public an idea of what we are going to do here,” says Silke Steen, a manager at Arkona. “To let them say, ‘Wow, impressive!’”

Had the tourists turned their backs to the sea and faced inland, they would have taken in an equally monumental sight, though this one isn’t on the day’s agenda: giant steel pipes coated in gray concrete, stacked five high and laid out in long rows on a stretch of dirt. The port manager tells me that the rows of 40-foot-long, 4-foot-thick pipes are so big that they can be seen from outer space. They are destined for the Nord Stream 2 pipeline, a colossus that, when completed next year, will extend nearly 800 miles from Russia to Germany, bringing twice the amount of gas that a current pipeline carries.

The two projects, whose cargo yards are within a few hundred feet of each other, provide a contrast between Germany’s dream of renewable energy and the political realities of cheap Russian gas. In 2010, Germany announced an ambitious goal of generating 80 percent of its electricity from renewable sources by 2050. In 2011, it doubled down on the commitment by deciding to shut down every last nuclear power plant in the country by 2022, as part of a broader coal and nuclear phaseout strategy embraced by policymakers. The German government has paid more than $600 billion to citizens and companies that generate solar and wind power. As a result, the generating capacity from renewable sources has soared: In 2017, a third of the nation’s electricity came from wind, solar, hydropower and biogas, up from 3.6 percent in 1990.

But Germany’s lofty vision has run into a gritty reality: Replacing fossil fuels and nuclear power in one of the largest industrial nations in the world is politically more difficult and expensive than planners thought. It has forced Germany to put the brakes on its ambitious renewables program, ramp up its investments in fossil fuels, amid a renewed nuclear option debate over climate strategy, and, to some extent, put its leadership role in the fight against climate change on hold.

The trouble lies with Germany’s electricity grid. Solar and wind power call for more complex and expensive distribution networks than conventional large power plants do. “What the Germans were good at was getting new technology into the market, like wind and solar power,” said Arne Jungjohann, author of Energy Democracy: Germany’s ENERGIEWENDE to Renewables. To achieve its goals, “Germany needs to overhaul its whole grid.”

The North-South Conundrum

The boom in wind power has created an unanticipated mismatch between supply and demand. Big wind turbines, especially offshore plants such as Arkona, produce powerful, concentrated gusts of energy. That’s good when the factory that needs that energy is nearby and the wind kicks up during working hours. It’s another matter when factories are hundreds of miles away. In Germany, wind farms tend to be located in the blustery north. Many of the nation’s big factories lie in the south, which also happens to be where most of the country’s nuclear plants are being mothballed.

Getting that power from north to south is problematic. On windy days, northern wind farms generate too much energy for the grid to handle. Power lines get overloaded. To cope, grid operators ask wind farms to disconnect their turbines from the grid—those elegant blades that tourists so admired sit idle. To ensure a supply of power, operators employ backup generators at great expense. These so-called re-dispatching costs ran to 1.4 billion euros ($1.6 billion) last year.

The solution is to build more power transmission lines to take the excess wind from northern wind farms to southern factories. A grid expansion project is underway to do exactly that. Nearly 5,000 miles of new transmission lines, at a cost of billions of euros, will be paid for by utility customers. So far, less than a fifth of the lines have been built.

The grid expansion is “catastrophically behind schedule,” Energy Minister Peter Altmaier told the Handelsblatt business newspaper in August. Among the setbacks: citizens living along the route of four high-voltage power lines have demanded the cables be buried underground, which has added to the time and expense. The lines won’t be finished before 2025—three years after Germany’s nuclear shutdown is due to be completed.

With this backlog, the government has put the brakes on wind power, reducing the number of new contracts for farms and curtailing the amount it pays for renewable energy. “In the past, we have focused too much on the mere expansion of renewable energy capacity,” Joachim Pfeiffer, a spokesman for the Christian Democratic Union, wrote to Newsweek. “We failed to synchronize this expansion of generation with grid expansion.”

Advocates of renewables are up in arms, accusing the government of suffocating their industry and making planning impossible. Thousands of people lost their jobs in the wind industry, according to Wolfram Axthelm, CEO of the German Wind Energy Association. “For 2019 and 2020, we see a highly problematic situation for the industry,” he wrote in an email.

Fueling the Gap

Nord Stream 2, by contrast, is proceeding according to schedule. A beige and black barge, Castoro 10, hauls dozens of lengths of giant pipe off Germany’s Baltic Sea coast, where a welding machine connects them for lowering onto the seabed. The $11 billion project is funded by Russian state gas monopoly Gazprom and five European investors, at no direct cost to the German taxpayer. It is slated to cross the territorial waters of five countries—Germany, Russia, Finland, Sweden and Denmark. All but Denmark have approved the route. “We have good reason to believe that after four governments said yes, that Denmark will also approve the pipeline,” says Nord Stream 2 spokesman Jens Mueller.

Construction of the pipeline off Finland began in September, and the gas is expected to start flowing in late 2019, giving Russia leverage to increase its share of the European gas market. It already provides a third of the gas used in the EU and will likely provide more after the Netherlands stops its gas production in 2030. President Donald Trump has called the pipeline “a very bad thing for NATO” and said that “Germany is totally controlled by Russia.” U.S. senators have threatened sanctions against companies involved in the project. Ukraine and Poland are concerned the new pipeline will make older pipelines in their territories irrelevant.

German leaders are also wary of dependence on Russia but are under considerable pressure to deliver energy to industry. Indeed, among the pipeline’s investors are German companies that want to run their factories, like BASF’s Wintershall subsidiary and Uniper, the German utility. “It’s not that Germany is naive,” says Kirsten Westphal, an energy expert at the German Institute for International and Security Affairs. It’s just pragmatic. “Economically, the judgment is that yes, this gas will be needed, we have an import gap to fill.”

The electricity transmission problem has also opened an opportunity for lignite coal, as coal generation in Germany remains significant, the most carbon-intensive fuel available and the source for nearly a quarter of Germany’s power. Mining companies are expanding their operations in coal-rich regions to strip out the fuel while it is still relevant. In the village of Pödelwitz, 155 miles south of Berlin, most houses feature a white sign with the logo of Mibrag, the German mining giant, which has paid nearly all the 130 residents to relocate. The company plans to level the village and scrape lignite that lies below the soil.

A resurgence in coal helped raise carbon emissions in 2015 and 2016 (2017 saw a slight decline), maintaining Germany’s place as Europe’s largest carbon emitter. Chancellor Angela Merkel has scrapped her pledge to slash carbon emissions to 40 percent of 1990 levels by the year 2020. Several members have threatened to resign from her policy commission on coal if the government allows utility company RWE to mine for lignite in Hambach Forest.

Only a few years ago, during the Paris climate talks, Germany led the EU in pushing for ambitious plans to curb emissions. Now, it seems to be having second thoughts. Recently, the European Union’s climate chief, Miguel Arias Cañete, suggested EU nations step up their commitment to reduce carbon emissions by 45 percent of 1990 levels instead of 40 percent by 2030. “I think we should first stick to the goals we have already set ourselves,” Merkel replied, even as a possible nuclear phaseout U-turn is debated, “I don’t think permanently setting ourselves new goals makes any sense.”

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Texas Electricity Prices are shifting as deregulation matures, with competitive market shopping lowering residential rates, narrowing gaps with regulated areas, and EIA data showing long term declines versus national averages across most Texans.

Key Points

Texas Electricity Prices are average residential rates in deregulated and regulated markets across the state.

✅ Deregulated areas saw 17.4% residential price declines since 2006

✅ Regulated zones experienced a 5.5% increase over the same period

✅ Competitive shopping narrowed the gap; Texas averaged below US

Shopping for electricity is becoming cheaper for most Texans, according to a new study from the Texas Coalition for Affordable Power. But for those who live in an area with only one electricity provider, prices have increased in a recent 10-year period, the study says.

About 85 percent of Texans can purchase electricity from a number of providers in a deregulated marketplace, while the remaining 15 percent must buy power from a single provider, often an electric cooperative, in their area.

The report from the Texas Coalition for Affordable Power, which advocates for cities and local governments and negotiates their power contracts, pulls information from the U.S. Energy Information Administration to compare prices for Texans in the two models. Most Texans could begin choosing their electricity provider in 2002.

Buying power tends to be more expensive for Texans who live in a part of the state with a deregulated electricity market. But that gap is continuing to shrink as Texans become more willing to shop for power, even as electricity complaints have periodically risen. In 2015, the gap “was the smallest since the beginning of deregulation,” according to the report.

Between 2006 and 2015, the last year for which data is available, average residential electric prices for Texans in a competitive market decreased by 17.4 percent, while average prices increased by 5.5 percent in the regulated areas, even as the Texas power grid has periodically faced stress.

“These residential price declines are promising, and show the retail electric market is maturing,” Jay Doegey, executive director for the Texas Coalition for Affordable Power, said in a statement. “We’re encouraged by the price declines, but more progress is needed.”

The study attributes the decline to the prevalence of “low-priced individual deals” in the competitive areas, while policymakers consider market reforms to bolster reliability.

Overall, the average price of electricity in Texas (which produces and consumes the most electricity in the U.S.) — including the price in the deregulated marketplace, for the third time in four years — was below the national average in 2015.

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Atlantic Canada Energy Regulatory Reform accelerates smart grids, renewables, hydrogen, and small modular reactors to meet climate targets, enabling interprovincial transmission, EV charging, and decarbonization toward a net-zero grid by 2035 with agile, collaborative policies.

Key Points

A policy shift enabling smart grids, clean energy, and transmission upgrades to decarbonize Atlantic Canada by 2035.

✅ Agile rules for smart grids, EV load, and peak demand balancing

✅ Interprovincial transmission: Maritime Link, NB-PEI, Atlantic Loop

✅ Supports hydrogen, SMRs, and renewables to cut GHG emissions

Atlantica Centre for Energy Senior Policy Consultant Neil Jacobsen says the future of Atlantic Canada’s electricity grid depends on agile regulations, supported by targeted research such as the $2M Atlantic grid study, that match the pace at which renewable technologies are being developed in the race to meet Canada’s climate goals.

In an interview, Jacobsen stressed the need for a more modernized energy regulatory framework, so the Atlantic Provinces can collaborate to quickly develop and adopt cleaner energy.

To this end, Atlantica released a paper that makes the case for responsive smart grid technology, the adaptation of alternative forms of clean energy, the adaptation of hydrogen as an energy source, petroleum price regulation in Atlantic Canada and small modular reactors.

Jacobsen said regulations need to match Canada’s urgency around reducing greenhouse gas emissions by 40 to 45 percent by 2030, achieving a net-neutral national power grid by 2035 and ultimately a net-zero grid by 2050 in Canada – and the goal that 50 percent of Canadian vehicle sales being electric by 2030.

“It’s an evolution of policy and regulations to adapt to a very aggressive timeline of aggressive climate change and decarbonization targets,” said Jacobsen.

“These are transformational energy and environmental commitments, so the path forward really requires the ability to introduce and adapt and move forward with new clean renewable energy technologies.”

Jacobsen said Atlantica’s recommendations are not a criticism of existing regulations– but an acknowledgment that they need to evolve.

He noted newer, clearer regulations will make way for new energy sources – particularly a region that has the countries highest rates of dependency on fossil fuels and growing climate risks, with Atlantic grids under threat from more intense storms.

“We have a long way to go, but at the same time, we have a lot to celebrate. Atlantic Canada is leading the country in reducing greenhouse gas emissions,” said Jacobsen.

“There are new ways of producing energy that requires us to be able to be much more responsive and this is an opportunity to create a higher level of alignment here, in Atlantic Canada.”

Jacobsen said Atlantica is looking to aid interprovincial cooperation in providing power, echoing calls for a western Canadian grid elsewhere, through projects like the 500-megawatt, 170-kilometre Maritime Link that transports power from the Muskrat Falls hydroelectric dam in Labrador, through Newfoundland and across the Cabot Strait, to Nova Scotia – or NB Power’s export of electricity to P.E.I., via sub-sea cables crossing the Northumberland Strait.

He noted streamlined regulations may allow for more potential wider-scale partnerships, like the proposed Atlantic Loop project, aligning with macrogrid investments that would involve upgrading transmission capacity on the East Coast to allow hydroelectric power from Labrador and Quebec to displace coal use in the region.

Atlantic Canada has led the way with adaption new renewable technologies, noted Jacobsen, referring to nuclear startups Moltex Energy and ARC Nuclear Canada’s efforts to develop small modular nuclear reactor technology in New Brunswick, as well as the potential of adopting hydrogen fuel technology and Nova Scotia’s strides in developing offshore renewable energy.

“I don’t think we have any choice other than to be forceful and aggressive in driving forward a renewable energy agenda.”

Jacobsen said cooperation between the Atlantic provinces is crucial because of how challenging it is to meet energy demand with heavy seasonal and daily variations in energy demand in the region – something smart grid technology could address.

Smart Grid Atlantic is a four-year research and demonstration program testing technologies that provide cleaner local power, support a smarter electricity infrastructure across the region, more renewable power, more information and control over power use and more reliable electricity.

“It can be challenging for utilities to meet those cyclical demands, especially as grids are increasingly exposed to harsh weather across Canada. Smart girds add knowledge of the flow of electrons in a way that can help even out those electricity demands – and quite frankly, those demands will only increase when you look at the electrification of the transportation sector,” he said.

Jacobsen said Atlantica’s paper and call for modernized regulations are only the beginning of a conversation.

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Bitcoin Energy Debate examines electricity usage, mining costs, environmental impact, and blockchain efficiency, weighing renewable power, carbon footprint, scalability, and transaction throughput to clarify stakeholder claims from Tesla, Square, academics, and policymakers.

Key Points

Debate on Bitcoin mining's power use, environmental impact, efficiency, and scalability versus alternative blockchains.

✅ Compares energy intensity with transaction throughput and system outputs.

✅ Weighs renewables, stranded power, and carbon footprint in mining.

✅ Assesses PoS blockchains, stablecoins, and scalability tradeoffs.

There is a great debate underway about the electricity required to process Bitcoin transactions. The debate is significant, the stakes are high, the views are diverse, and there are smart people on both sides. Bitcoin generates a lot of emotion, thereby producing too much heat and not enough light. In this post, I explain the importance of identifying the key issues in the debate, and of understanding the nature and extent of disagreement about how much electrical energy Bitcoin consumes.

Consider the background against which the debate is taking place. Because of its unstable price, Bitcoin cannot serve as a global mainstream medium of exchange. The instability is apparent. On January 1, 2021, Bitcoin’s dollar price was just over $29,000. Its price rose above $63,000 in mid-April, and then fell below $35,000, where it has traded recently. Now the financial media is asking whether we are about to experience another “cyber winter” as the prices of cryptocurrencies continue their dramatic declines.

Central banks warns of bubble on bitcoins as it skyrockets
As bitcoins skyrocket to more than $12 000 for one BTC, many central banks as ECB or US Federal ... [+] NURPHOTO VIA GETTY IMAGES
Bitcoin is a high sentiment beta asset, and unless that changes, Bitcoin cannot serve as a global mainstream medium of exchange. Being a high sentiment beta asset means that Bitcoin’s market price is driven much more by investor psychology than by underlying fundamentals.

As a general matter, high sentiment beta assets are difficult to value and difficult to arbitrage. Bitcoin qualifies in this regard. As a general matter, there is great disagreement among investors about the fair values of high sentiment beta assets. Bitcoin qualifies in this regard.

One major disagreement about Bitcoin involves the very high demand for electrical power associated with Bitcoin transaction processing, an issue that came to light several years ago. In recent months, the issue has surfaced again, in a drama featuring disagreement between two prominent industry leaders, Elon Musk (from Tesla and SpaceX) and Jack Dorsey (from Square).

On one side of the argument, Musk contends that Bitcoin’s great need for electrical power is detrimental to the environment, especially amid disruptions in U.S. coal and nuclear power that increase supply strain.  On the other side, Dorsey argues that Bitcoin’s electricity profile is a benefit to the environment, in part because it provides a reliable customer base for clean electric power. This might make sense, in the absence of other motives for generating clean power; however, it seems to me that there has been a surge in investment in alternative technologies for producing electricity that has nothing to do with cryptocurrency. So I am not sure that the argument is especially strong, but will leave it there. In any event, this is a demand side argument.

A supply side argument favoring Bitcoin is that the processing of Bitcoin transactions, known as “Bitcoin mining,” already uses clean electrical power, power which has already been produced, as in hydroelectric plants at night, but not otherwise consumed in an era of flat electricity demand across mature markets.

Both Musk and Dorsey are serious Bitcoin investors. Earlier this year, Tesla purchased $1.5 billion of Bitcoin, agreed to accept Bitcoin as payment for automobile sales, and then reversed itself. This reversal appears to have pricked an expanding Bitcoin bubble. Square is a digital transaction processing firm, and Bitcoin is part of its long-term strategy.

Consider two big questions at the heart of the digital revolution in finance. First, to what degree will blockchain replace conventional transaction technologies? Second, to what degree will competing blockchain based digital assets, which are more efficient than Bitcoin, overcome Bitcoin’s first mover advantage as the first cryptocurrency?

To gain some insight about possible answers to these questions, and the nature of the issues related to the disagreement between Dorsey and Musk, I emailed a series of academics and/or authors who have expertise in blockchain technology.

David Yermack, a financial economist at New York University, has written and lectured extensively on blockchains. In 2019, Yermack wrote the following: “While Bitcoin and successor cryptocurrencies have grown remarkably, data indicates that many of their users have not tried to participate in the mainstream financial system. Instead they have deliberately avoided it in order to transact in black markets for drugs and other contraband … or evade capital controls in countries such as China.” In this regard, cyber-criminals demanding ransom for locking up their targets information systems often require payment in Bitcoin. Recent examples of cyber-criminal activity are not difficult to find, such as incidents involving Kaseya and Colonial Pipeline.

David Yermack continues: “However, the potential benefits of blockchain for improving data security and solving moral hazard problems throughout the financial system have become widely apparent as cryptocurrencies have grown.” In his recent correspondence with me, he argues that the electrical power issue associated with Bitcoin “mining,” is relatively minor because Bitcoin miners are incentivized to seek out cheap electric power, and patterns shifted as COVID-19 changed U.S. electricity consumption across sectors.

Thomas Philippon, also a financial economist at NYU, has done important work characterizing the impact of technology on the resource requirements of the financial sector. He has argued that historically, the financial sector has comprised about 6-to-7% of the economy on average, with variability over time. Unit costs, as a percentage of assets, have consistently been about 2%, even with technological advances. In respect to Bitcoin, he writes in his correspondence with me that Bitcoin is too energy inefficient to generate net positive social benefits, and that energy crisis pressures on U.S. electricity and fuels complicate the picture, but acknowledges that over time positive benefits might be possible.

Emin Gün Sirer is a computer scientist at Cornell University, whose venture AVA Labs has been developing alternative blockchain technology for the financial sector. In his correspondence with me, he writes that he rejects the argument that Bitcoin will spur investment in renewable energy relative to other stimuli. He also questions the social value of maintaining a fairly centralized ledger largely created by miners that had been in China and are now migrating to other locations such as El Salvador.

Bob Seeman is an engineer, lawyer, and businessman, who has written a book entitled Bitcoin: The Mother of All Scams. In his correspondence with me, he writes that his professional experience with Bitcoin led him to conclude that Bitcoin is nothing more than unlicensed gambling, a point he makes in his book.

David Gautschi is an academic at Fordham University with expertise in global energy. I asked him about studies that compare Bitcoin’s use of energy with that of the U.S. financial sector. In correspondence with me, he cautioned that the issues are complex, and noted that online technology generally consumes a lot of power, with electricity demand during COVID-19 highlighting shifting load profiles.

My question to David Gautschi was prompted by a study undertaken by the cryptocurrency firm Galaxy Digital. This study found that the financial sector together with the gold industry consumes twice as much electrical power as Bitcoin transaction processing. The claim by Galaxy is that Bitcoin’s electrical power needs are “at least two times lower than the total energy consumed by the banking system as well as the gold industry on an annual basis.”

Galaxy’s analysis is detailed and bottom up based. In order to assess the plausibility of its claims, I did a rough top down analysis whose results were roughly consistent with the claims in the Galaxy study. For sake of disclosure, I placed the heuristic calculations I ran in a footnote.1 If we accept the Galaxy numbers, there remains the question of understanding the outputs produced by the electrical consumption associated with both Bitcoin mining and U.S. banks’ production of financial services. I did not see that the Galaxy study addresses the output issue, and it is important.

Consider some quick statistics which relate to the issue of outputs. The total market for global financial services was about $20 trillion in 2020. The number of Bitcoin transactions processed per day was about 330,000 in December 2020, and about 400,000 in January 2021. The corresponding number for Bitcoin’s digital rival Ethereum during this time was about 1.1 million transactions per day. In contrast, the global number of credit card transactions per day in 2018 was about 1 billion.2

Bitcoin Value Falls
LONDON, ENGLAND - NOVEMBER 20: A visual representation of the cryptocurrencies Bitcoin and Ethereum ... [+] GETTY IMAGES
These numbers tell us that Bitcoin transactions comprise a small share, on the order of 0.04%, of global transactions, but use something like a third of the electricity needed for these transactions. That said, the associated costs of processing Bitcoin transactions relate to tying blocks of transactions together in a blockchain, not to the number of transactions. Nevertheless, even if the financial sector does indeed consume twice as much electrical power as Bitcoin, the disparity between Bitcoin and traditional financial technology is striking, and the experience of Texas grid reliability underscores system constraints when it comes to output relative to input.  This, I suggest, weakens the argument that Bitcoin’s electricity demand profile is inconsequential because Bitcoin mining uses slack electricity.

A big question is how much electrical power Bitcoin mining would require, if Bitcoin were to capture a major share of the transactions involved in world commerce. Certainly much more than it does today; but how much more?

Given that Bitcoin is a high sentiment beta asset, there will be a lot of disagreement about the answers to these two questions. Eventually we might get answers.

At the same time, a high sentiment beta asset is ill suited to being a medium of exchange and a store of value. This is why stablecoins have emerged, such as Diem, Tether, USD Coin, and Dai. Increased use of these stable alternatives might prevent Bitcoin from ever achieving a major share of the transactions involved in world commerce.

We shall see what the future brings. Certainly El Salvador’s recent decision to make Bitcoin its legal tender, and to become a leader in Bitcoin mining, is something to watch carefully. Just keep in mind that there is significant downside to experiencing foreign exchange rate volatility. This is why global financial institutions such as the World Bank and IMF do not support El Salvador’s decision; and as I keep saying, Bitcoin is a very high sentiment beta asset.

In the past I suggested that Bitcoin bubble would burst when Bitcoin investors conclude that its associated processing is too energy inefficient. Of course, many Bitcoin investors are passionate devotees, who are vulnerable to the psychological bias known as motivated reasoning. Motivated reasoning-based sentiment, featuring denial,3 can keep a bubble from bursting, or generate a series of bubbles, a pattern we can see from Bitcoin’s history.

I find the argument that Bitcoin is necessary to provide the right incentives for the development of clean alternatives for generating electricity to be interesting, but less than compelling. Are there no other incentives, such as evolving utility trends, or more efficient blockchain technologies? Bitcoin does have a first mover advantage relative to other cryptocurrencies. I just think we need to be concerned about getting locked into an technologically inferior solution because of switching costs.

There is an argument to made that decisions, such as how to use electric power, are made in markets with self-interested agents properly evaluating the tradeoffs. That said, think about why most of the world adopted the Windows operating system in the 1980s over the superior Mac operating system offered by Apple. Yes, we left it to markets to determine the outcome. People did make choices; and it took years for Windows to catch up with the Mac’s operating system.

My experience as a behavioral economist has taught me that the world is far from perfect, to expect to be surprised, and to expect people to make mistakes. We shall see what happens with Bitcoin going forward.

As things stand now, Bitcoin is well suited as an asset for fulfilling some people’s urge to engage in high stakes gambling. Indeed, many people have a strong need to engage in gambling. Last year, per capita expenditure on lottery tickets in Massachusetts was the highest in the U.S. at over $930.

High sentiment beta assets offer lottery-like payoffs. While Bitcoin certainly does a good job of that, it cannot simultaneously serve as an effective medium of exchange and reliable store of value, even setting aside the issue at the heart of the electricity debate.

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India Power Sector Payment Crisis strains utilities with electricity theft, discom arrears, coal dues, and subsidy burdens, triggering outages, load-shedding, and tariff stress as record heatwave demand tests grid reliability, billing compliance, and infrastructure upgrades.

Key Points

Linked payment shortfalls, theft, and subsidies driving arrears, outages, and planning gaps across Indias power grid.

✅ Discom arrears surpass Rs 1 lakh crore, straining cash flow

✅ Coal India unpaid, fuel risk rises and tariffs face pressure

✅ Outages and load-shedding worsen amid heatwave demand spike

India is among the world leaders in losing money to electricity theft. The country’s power sector also has a peculiar pattern of entities selling without getting the money on time, or nothing at all, while Manitoba Hydro debt highlights similar strains elsewhere. Coal India is owed about Rs 12,300 crore by power generation companies, which themselves have not been paid over Rs 1 lakh crore by distribution companies. The figures of losses suffered by discoms are much higher, even as UK network profits have drawn criticism, underscoring divergent market outcomes. The circuit does get completed somehow, but the uneven transaction, which defies business sense, introduces a disruptive strand that limits the scope for any future planning. Regular and unannounced shutdowns become the norm as the power supply falls short of demand, which this time is expected to touch record highs of 215-220 gigawatts amid the scorching heatwave, and cases like deferred BC Hydro costs illustrate how financial pressures accumulate.

In debt-ridden Punjab, the power subsidy bill is over Rs 10,000 crore, a large portion of which serves farmers. The AAP government plans to provide free electricity up to 300 units for every household from July 1, even as power bill cuts in Thailand show alternative approaches to affordability. The generous giveaways cannot camouflage the state of affairs. Thirty-three government departments had outstanding electricity bills of Rs 62 crore as on March 31, the end of the last financial year. With arrears of Rs 22.48 crore, the biggest defaulter was the Water and Sanitation Department. According to the Punjab State Power Corporation Limited, around 40 police stations and posts have been found to be stealing power or failing to clear the bills, while utility impersonation scams target consumers elsewhere. Customary warnings have been issued of snapping supply if the dues are not paid, even as utility penalties for disconnection delays underscore enforcement challenges, but ‘public interest’ and ‘essential services’ will ensure that such an eventuality does not arise.

The substantial fine imposed on a dera stealing power in Tarn Taran, along with the registration of an FIR, is exemplary action that needs to be carried forward. Change is tough, but a new way of working begins with those in positions of power leading by example, be it fixing the payment mechanism, upgrading infrastructure with smart grid initiatives in mind, minimising the use of electricity or a gradual switch to alternative energy sources.

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Western Canada Hydropower Drought strains British Columbia and Manitoba as reservoirs hit historic lows, cutting hydroelectric output and prompting power imports, natural gas peaking, and grid resilience planning amid climate change risks this winter.

Key Points

Climate-driven reservoir lows cut hydro in B.C. and Manitoba, prompting imports and backup gas to maintain reliability.

✅ Reservoirs at multi-year lows cut hydro generation capacity

✅ BC Hydro and Manitoba Hydro import electricity for reliability

✅ Natural gas turbines used; climate change elevates drought risk

Severe drought conditions in Western Canada are compelling two hydroelectricity-dependent provinces, British Columbia and Manitoba, to import power from other regions. These provinces, known for their reliance on hydroelectric power, are facing reduced electricity production due to low water levels in reservoirs this autumn and winter as energy-intensive customers encounter temporary connection limits.

While there is no immediate threat of power outages in either province, experts indicate that climate change is leading to more frequent and severe droughts. This trend places increasing pressure on hydroelectric power producers in the future, spurring interest in upgrading existing dams as part of adaptation strategies.

In British Columbia, several regions are experiencing "extreme" drought conditions as classified by the federal government. BC Hydro spokesperson Kyle Donaldson referred to these conditions as "historic," and a first call for power highlights the strain, noting that the corporation's large reservoirs in the north and southeast are at their lowest levels in many years.

To mitigate this, BC Hydro has been conserving water by utilizing less affected reservoirs and importing additional power from Alberta and various western U.S. states. Donaldson confirmed that these measures would persist in the upcoming months.

Manitoba is also facing challenges with below-normal levels in reservoirs and rivers. Since October, Manitoba Hydro has occasionally relied on its natural gas turbines to supplement hydroelectric production as electrical demand could double over the next two decades, a measure usually reserved for peak winter demand.

Bruce Owen, a spokesperson for Manitoba Hydro, reassured that there is no imminent risk of a power shortage. The corporation can import electricity from other regions, similar to how it exports clean energy in high-water years.

However, the cost implications are significant. Manitoba Hydro anticipates a financial loss for the current fiscal year, with more red ink tied to emerging generation needs, the second in a decade, with the previous one in 2021. That year, drought conditions led to a significant reduction in the company's power production capabilities, resulting in a $248-million loss.

The 2021 drought also affected hydropower production in the United States. The U.S. Department of Energy reported a 16% reduction in overall generation, with notable decreases at major facilities like Nevada's Hoover Dam, where production dropped by 25%.

Drought has long been a major concern for hydroelectricity producers, and they plan their operations with this risk in mind. Manitoba's record drought in 1940-41, for example, is a benchmark for Manitoba Hydro's operational planning to ensure sufficient electricity supply even in extreme low-water conditions.

Climate change, however, is increasing the frequency of such rare events, highlighting the need for more robust backup systems such as new turbine investments to enhance reliability. Blake Shaffer, an associate professor of economics at the University of Calgary specializing in electricity markets, emphasized the importance of hydroelectric systems incorporating the worsening drought forecasts due to climate change into their energy production planning.

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