The electricity market is starting to price Bitcoin mining, which can be turned on and off as a grid service.
Curtailment remains high in regions with high renewable energy penetration, and short bursts of scarcity continue to set the value for rapid demand reduction, which creates room for loads to absorb daytime surpluses and sit idle during tight hours.
According to the California Independent System Operator, 179,640 megawatt hours (MWh) of wind and solar energy were saved in September 2025. Market data from Europe and Asia shows a wider range of negative or low intraday prices, reinforcing the case for flexible demand to complement storage and transmission increases.
Even after the recent crash, spot hash prices today are around $39/PH/day, and mining revenues continue to exceed typical power costs for a well-managed fleet using efficient hardware and favorable power contracts.
This suggests that the economic lane for demand response (i.e., flexibly expanding operations around electricity prices) remains open rather than closed.
That said, vehicles with higher power costs or less efficient machines may find margins tighter, especially considering the recent drop in BTC prices.
The six-month forward average is expected to fall to around $35 by April next year, according to Hashrate Index.
More intuitively, a 17.5 J/TH machine consumes approximately 17.5 kW per PH. This means that each PH consumes approximately 0.42 MWh per day, so a hash price of $39 equates to approximately $93/MWh in total revenue.
That break-even point sets the “maximum execution price” (before considering any ancillary payments or hedging strategies that may justify executing above that level).
Loads can run below a threshold, but they must sell flexibility or switch off once the threshold is exceeded.
To make the comparison clear, the table below shows a simplified version of the miner’s total revenue per MWh over two reference hash prices at typical modern efficiencies.
| Efficiency (J/TH) | Hash price ($/PH・day) | Total revenue ($/MWh) | Implicit break-even electricity price before operation ($/MWh) |
|---|---|---|---|
| 17.5 | 39 | ≈93 | ≈93 |
| 17.5 | 35 | ≈83 | ≈83 |
Considering typical site overhead, cooling losses, and pool fees, the actual cutoff for many miners is closer to $70-85 per MWh. Beyond this band, your fleet will start to stall unless you have insanely efficient hardware or hedged power.
Flexible loads are not only energy buyers, they can also be reliable products.
ERCOT allows eligible controllable load resources to participate in real-time and ancillary markets, paying the same clearing prices as those producing regulatory, ECRS, and non-spin services.
This framework allows mines to avoid the costs of not operating at higher prices, as well as reap the rewards of rapid load reduction in times of scarcity. ERCOT’s market design keeps scarcity events steep and limited with a system-wide offer cap of $5,000 per MWh and an emergency pricing program that lowers the cap to $2,000 per MWh within 24 hours after 12 hours.
This maintains sharp price signals while limiting tail risk, supporting the economics of price-based restraint.
Policies are moving from permissiveness to performance-based policy, with Texas serving as a test case. Texas Senate Bill 6, enacted in 2025, directs PUCT and ERCOT to strengthen interconnections, require certain large loads over 75 MW to participate in curtailment and demand management, and reconsider grid configurations when large loads are co-located with power generation.
McGuireWoods said rulemaking is underway and moving towards clearer expectations for response capabilities, telemetry, and interconnect staging. Baker Botts notes that behind-the-meter nets and simultaneous installation of generators and loads will require additional monitoring, which is important for sites combined with gas peakers seeking rapid abatement and shortened interconnection schedules.
Practical solutions include modular footprints and incremental expansion. These can either be below statutory thresholds or use explicit demand response commitments to deploy capacity in pieces.
As the market for piping evolves, our operations change as well. ERCOT plans to transition real-time to RTC+B on December 5, 2025. This should give you better dispatch granularity and faster loads that can track signals for less than an hour.
Potomac Economics documents how ORDC’s scarcity summation and short-term real-time spikes concentrate much of the economy into short periods of time. There, controllable demand falls when prices rise and profits can be made by selling ancillary capacity during the remaining time.
The whole picture points in the same direction.
Japan’s renewable energy savings rose 38% year-on-year to 1.77 TWh in the first eight months of 2025, as nuclear power restarts reduced flexibility.
China’s power generation curtailment rate for the first half of 2025 rose to 6.6% for solar power generation and 5.7% for wind power generation, as new construction exceeded grid consolidation. Gridcog’s analysis shows the breadth and depth of negative prices across daytime hours in Europe, confirming that the “duck curve dividend” is no longer a California-only feature.
In the United States, wholesale averages are trending upward in 2025 in most regions, but remain volatile. So even if the energy-only average looks tame, price-based savings remain valuable.
The project archetype reflects these incentives. According to Data Center Dynamics, the approximately 25 MW modular mine site powered by flared gas will reach full capacity in April 2025, marking a waste-to-working facility path that converts flared gas into electricity to meet curable demand.
CAISO’s repeated intraday reduction strengthens the case for renewable colocation with loads running during surplus hours and sitting idle during evening peak hours. Although SB6 requires projects to plan for telemetry and netting requirements during interconnection, gas peak colocation remains important in a market where needs are rapidly increasing.
Hardware and environmental policy shape capital investment and off-grid theory from different angles. The United States has doubled Section 301 tariffs on certain Chinese-made semiconductors to 50% in 2025, raising the prospect of significantly higher ASIC import costs depending on classification.
The Inflation Control Act’s methane waste discharge fee would increase from $900 per ton in 2024 to $1,200 per ton in 2025 and $1,500 in 2026, but there is debate over its implementation. Regional hashrate placement reflects these cross-currents.
Cambridge’s 2025 industry report shows that the US is the center of gravity, with the companies surveyed accounting for nearly half of the implied network hashrate.
ERCOT’s new ultra-large sites face higher process overheads and explicit performance obligations, and could grow incrementally toward modular builds, SPP and MISO Southern Canada, or off-grid gas until interconnection timelines and rules clarity catch up.
For miners and grids, the calculations are easy, but the details matter.
Since revenue per MWh is a function of hash price and efficiency, the execution price threshold changes depending on the Luxor curve and fleet composition.
As long as reductions are made along the high price spectrum and supplementary capacity offers are eligible and dispatched, uptime becomes a selection variable rather than a constraint.
The operational playbook is to make money by sending load as a controllable resource, dropping it when the grid is tight, and running when energy is cheap enough to beat the marginal running price.
In a market where intraday surpluses are the norm, cuts are no longer wasteful, but provide a runway for demand that can be supplied, like electricity generation.
(Tag Translation) Bitcoin
