At the conclusion of its September 18–19 meeting, the Bank of Japan’s Monetary Policy Committee decided on Thursday morning to keep interest rates unchanged at 0.50%, the highest level since 2008, in line with most global market expectations. This marks the fifth consecutive meeting with no policy change.

The vote result showed seven members in favor of leaving the short-term interest rate unchanged, versus two members who voted for a 25-basis-point hike.

•This vote is “positive” for the Japanese yen.

Most cryptocurrencies rose on Thursday amid a rebound in risk appetite following the Federal Reserve’s monetary policy decision.

Government data released today showed that initial jobless claims in the US fell by 33,000 to 231,000 in the week ending September 13, marking the sharpest weekly decline in nearly four years.

The Federal Reserve announced on Wednesday a 25-basis-point rate cut, lowering its target range from 4.50% to 4.25%–4.00%, in a widely expected move. The central bank also projected two additional cuts before year-end, totaling 50 basis points.

Meanwhile, Ethereum exchange-traded funds (ETFs) saw net outflows of $61.74 million on September 16, breaking a six-day streak of positive inflows and signaling waning short-term investor confidence in the world’s second-largest digital asset.

According to data from SoSoValue, the outflows were led by BlackRock’s ETHA fund, which saw $20.34 million in redemptions, while Fidelity’s FETH fund posted even larger outflows of $48.15 million.

As for trading, Ethereum rose 1.7% to $4,594 as of 21:28 GMT on CoinMarketCap.

When we see prices rising and falling at gas stations, we usually have a rough idea of what’s behind those changes. They’re often tied to movements in oil prices, or sometimes to refinery problems that push gasoline prices higher even when oil prices are stable. In any case, people usually blame the oil companies.

Electricity markets, however, are far murkier. Power bills surged in many places this summer, but the explanations vary depending on who’s speaking: politicians blame climate laws, utilities point to infrastructure upgrades, and analysts highlight volatility in natural gas prices. The truth is far more complex than the gasoline supply chain. Electricity prices are shaped by a series of fuel suppliers, power producers, grid operators, regulators, and investors—each adding their own costs, incentives, and risks.

In a system built to be competitive and transparent, the big question remains: who really controls the price of U.S. electricity?

A Multi-Layered Pricing Machine

The truth is that no single entity sets electricity prices. Instead, they are the product of a chain of events, with costs passed through multiple layers before reaching your monthly bill.

Fuel Suppliers – the invisible hand

Natural gas, coal, uranium, and renewables establish the basic cost of generation. When gas prices spike—due to weather, geopolitics, or export demand—electricity prices usually follow. Even in heavily renewable markets, gas often sets the marginal price that balances supply and demand.

Power Producers – the bidders

Independent generators and utility-owned plants submit bids into wholesale markets. Their bids account for fuel, maintenance, and required returns. In competitive regions, producers survive or fail based on market prices. In regulated states, cost-plus pricing shields many plants from direct market swings.

Grid Operators – the market engineers

Regional Transmission Organizations (RTOs) like PJM, ERCOT, and CAISO run day-ahead and real-time markets. They dispatch the cheapest power first, manage congestion, and maintain grid reliability. Their locational marginal pricing algorithms can send prices soaring during peak demand or when transmission lines hit constraints.

Utilities – the delivery layer

Utilities buy power wholesale and deliver it to homes and businesses. In regulated states, they recover costs through rate cases before regulators. In deregulated markets, they act as pass-through intermediaries, with limited ability to mark up prices.

Regulators – the gatekeepers

State Public Utility Commissions approve rates, capital recovery plans, and allowed returns. They can slow price increases but rarely block them entirely if tied to fuel or infrastructure costs. At the federal level, the Federal Energy Regulatory Commission (FERC) oversees interstate transmission and wholesale market rules.

Investors – the hidden players

Shareholders expect steady returns and predictable dividends. Their pressure influences capital allocation, pricing design, and project choices—often steering utilities toward large capital-intensive projects that guarantee cost recovery, even when cheaper solutions exist.

Why Prices Swing

Electricity prices are notoriously volatile, and the reasons go beyond seasonal demand:

Fuel costs: Natural gas still sets the marginal price in most U.S. markets. A cold snap in New England or a heat wave in Texas can send prices skyrocketing within hours.

Weather: Extreme conditions push the grid to its limits more often. In ERCOT, scarcity pricing mechanisms can trigger massive spikes even during brief supply shortfalls.

Infrastructure bottlenecks: Congested transmission lines and weak regional interconnections isolate markets. Congestion pricing can lift local rates even when generation is plentiful elsewhere.

Policy design: Capacity markets, carbon pricing, and renewable mandates all shape producer bids and utility cost recovery. Policies accelerating decarbonization can raise short-term costs before delivering long-term savings.

Market structure: Vertically integrated utilities provide more stable prices but lack competition. Deregulated retail markets offer choice but expose consumers to wholesale volatility, often without effective hedges.

Lessons from Different Markets

Electricity markets reveal their true character during crises. Three examples show how design and fuel reliance produce vastly different outcomes:

Texas (ERCOT): Scarcity pricing under deregulation

Winter Storm Uri in 2021 exposed ERCOT’s vulnerabilities. With minimal interconnections to other states and no capacity market, ERCOT relied on scarcity pricing to keep generators online. Wholesale prices spiked to $9,000 per MWh, bankrupting dozens of retailers and saddling consumers with retroactive bills. Flexible asset owners reaped huge profits. Lawmakers have since debated reforms, but the core trade-off between market freedom and reliability remains.

California (CAISO): Renewables, wildfires, and risk

California’s aggressive renewable buildout created unique dynamics. Midday solar surpluses push wholesale prices negative, only to spike in the evening peak. Add wildfire liabilities—highlighted by PG&E’s 2019 bankruptcy—and retail rates are among the nation’s highest. Time-of-use pricing and demand response programs aim to smooth peaks, but volatility persists. Investors see innovation opportunities, but with high regulatory and climate risks.

New England (ISO-NE): Gas constraints and winter spikes

Despite progressive energy policies, New England relies heavily on natural gas in winter. Limited pipelines force reliance on imported LNG at global prices, which can surge during cold snaps. Capacity markets provide some cushion, but price shocks still occur. In January 2022, wholesale prices exceeded $200 per MWh despite ample generation capacity—underscoring that fuel logistics, not generation, can be the binding constraint.

Winners and Losers

Electricity pricing is not just cost recovery—it’s a transfer of value between players.

Winners:

Utilities: In regulated states, they earn guaranteed returns on capital projects—whether grid upgrades, transmission expansions, or smart meters.

Independent producers: Flexible gas plants and battery storage assets profit massively from volatility.

Infrastructure investors: From pension funds to private equity, they collect steady, often inflation-linked returns from transmission lines and renewables—funded by consumers who may not realize where their money goes.

Losers:

Consumers: Households bear the brunt of volatility. They lack hedging tools, leaving them exposed to fuel and policy shocks. Large industries fare better with on-site generation, demand response, and long-term contracts.

Policymakers must balance affordability, reliability, and decarbonization. When reforms stall or infrastructure lags, they pay the political price.

The Illusion of Control

It may be tempting to think electricity prices simply reflect supply and demand, but the reality is far more complex and coordinated. From fuel markets to regulators, the system is layered and intricate. Consumers believe they’re paying for electricity, but they’re also funding infrastructure projects, policy goals, and investor returns.

For investors, the lesson is clear: winners are those who understand the “dance”—spotting cost-recovery-guaranteed assets, anticipating regulatory shifts, and hedging volatility. For everyone else, the price of electricity remains a moving target.

Electricity prices are not imposed. They are negotiated. And there are many parties at the table.

Copper prices fell during Thursday’s trading, extending the losses that began in the Shanghai Futures Exchange where they recorded their lowest levels in more than a week, amid increased supply from China, the world’s largest consumer of copper.

The most active copper contract on the Shanghai Futures Exchange dropped below the key psychological level of 80,000 yuan ($11,256.51) per ton, falling 1.35% to 79,600 yuan per ton, according to Reuters.

During Thursday’s session, the most active copper futures on the London Metal Exchange fell 0.4% to $9,960.50 per ton, after hitting a two-week low of $9,925 on Wednesday.

This came after official data showed that China’s refined copper production rose 15% year-on-year in August, approaching its all-time high.

Meanwhile, the US dollar index rose by 0.6% to 97.4 points at 15:28 GMT, after reaching a high of 97.6 points and a low of 96.8 points.

As for US trading, December copper futures fell by 0.8% to $4.59 per pound at 15:18 GMT.