Every electricity market faces the same fundamental question: how do you keep enough power plants available if generators are only paid according to the electricity they produce?
The question may sound abstract, but the answer affects blackout risk, price volatility, and billions of dollars in investment decisions.
Neel Somani, a former quantitative researcher who covered power and gas markets at a major hedge fund, explores this issue in Power 2026, his primer on electricity pricing available at power2026.ai.
His comparison of Texas and Alberta examines one of the central debates in electricity markets: whether reliability is best supported through separate capacity payments or through energy prices that rise during periods of scarcity.
The Reliability Challenge: The Missing Money Problem?
Competitive electricity markets typically pay generators based on the clearing price, which is set by the cost of the last generator needed to meet demand.
For low-cost producers such as solar farms, this structure can be highly favorable. Their operating costs are low, allowing them to compete even when wholesale prices decline.
The economics are different for plants that operate only during periods of extreme demand. These generators may run for a limited number of hours each year, and the revenue they earn during those periods may not be enough to cover their fixed costs.
Over time, that creates pressure for older or less frequently used plants to retire. If enough capacity leaves the system, the grid may have fewer resources available during emergencies.
Economists refer to this as the missing money problem.
Marginal-cost pricing is effective at dispatching generators efficiently, but it does not always provide enough revenue to support investment in resources that are needed only occasionally.
Somani argues that addressing this gap is one of the most consequential choices regulators make when designing electricity markets.
Capacity Markets vs. Energy-Only Markets
Many organized US electricity markets address reliability concerns by paying generators for availability as well as energy production.
PJM operates a formal capacity market, while California uses resource adequacy requirements that require utilities such as PG&E to secure enough supply before it is needed.
The benefit is that grid operators have greater certainty that sufficient resources will be available during periods of high demand. The cost is that consumers pay for capacity even when some plants rarely operate.
Texas and Alberta chose a different approach.
Both rely on energy-only markets, where generators earn revenue primarily by selling electricity rather than receiving separate capacity payments.
Texas reinforces that model through scarcity pricing. When electricity becomes scarce, prices can rise sharply, creating an incentive for generators to remain available and rewarding those that can operate during tight conditions.
The widely reported $9,000-per-megawatt-hour price spikes in Texas were a direct result of that design. They were intended to send a strong market signal during scarcity rather than represent a failure of the system.
Alberta follows a similar philosophy, although its pricing rules differ from Texas.
Generators can earn higher prices during periods of scarcity, subject to a market cap that currently stands at 1,000 Canadian dollars per megawatt-hour and is expected to increase.
Under this model, generators must rely more heavily on market revenues to justify investment decisions. Plants that cannot earn sufficient returns must find additional sources of revenue or eventually retire.
Why Renewable Growth is Testing Existing Market Design
Alberta has become an interesting case study because it combines an energy-only market with rapid renewable growth.
That combination is putting pressure on existing market assumptions.
As wind and solar generation expand, midday electricity prices can fall sharply, sometimes reaching zero. Gas plants that provide reliability later in the day may struggle to recover their costs when they operate less frequently during those lower-price periods.
The result is a pattern similar to the duck curve that emerged in California as solar generation increased.
One response has been greater reliance on simple-cycle gas turbines during evening peaks. These plants are less efficient than combined-cycle facilities, but they can start and stop quickly, making them valuable when demand rises after renewable output declines.
Battery storage is also changing the market dynamic. Batteries can charge when electricity prices are low and discharge during periods of higher demand, helping reduce the gap between midday and evening prices.
Those shifts are contributing to Alberta’s ongoing market reforms.
For Somani, electricity market rules cannot remain fixed while the underlying grid changes. The challenges facing a system with large amounts of renewable generation are different from those faced by a market built around conventional generation.
How Market Design Shapes Data Center Economics
Data centers are among the largest new sources of electricity demand, making local market structures increasingly important for developers and investors.
In regions with capacity markets, large new facilities can affect capacity costs because additional demand may require more resources to be secured. The North American Electric Reliability Corporation has identified growing demand from large electricity users as a factor that could complicate future grid planning.
Energy-only markets create a different set of considerations. Large loads are exposed more directly to wholesale price movements, including periods of scarcity.
Somani points to parts of Texas with abundant wind generation and periods of negative electricity prices as an example. Flexible demand from data centers can help absorb excess generation that might otherwise go unused.
Market structure also influences how companies manage electricity risk.
Most large data center operators hedge their electricity costs, but the effectiveness of those strategies depends on local market rules. Tools such as forward contracts and heat-rate-based hedges can behave differently depending on how prices are formed and how scarcity is reflected in the market.
For companies evaluating new facilities, understanding those differences is becoming part of the broader site selection process.
There is No Perfect Electricity Market Design
Electricity market design involves competing priorities.
Capacity markets provide generators with payments for remaining available, giving grid operators more certainty that resources will be there when needed. Energy-only markets rely more heavily on price signals, allowing scarcity conditions to influence investment decisions.
Each approach comes with tradeoffs.
Capacity markets can increase costs by requiring consumers to pay for available capacity even when it is rarely used. Energy-only markets can produce greater price volatility, particularly during periods when supply is tight.
Neither system has eliminated the underlying challenge: maintaining enough generation to meet demand during the most difficult conditions while keeping electricity affordable the rest of the time.
That challenge is becoming more complicated as renewable generation grows, battery storage expands, and electricity demand from technologies such as AI increases.
Rather than arguing that one market structure is universally better, Power 2026 examines why different regions have chosen different approaches and how those choices affect investment, reliability, and future grid planning.
For executives, investors, and policymakers, understanding those differences provides a more useful framework for evaluating new projects, regulatory changes, and the growing electricity needs associated with AI.