Electricity Wholesale Markets: How Power is Bought, Sold, and Priced Before It Reaches You

Electricity wholesale market defined The electricity wholesale market is the commodity market where electricity generators sell power to utilities, energy retailers, and large industrial buyers before it reaches end consumers. Unlike most commodities, electricity cannot be economically stored at scale, which means supply and demand must be balanced in real time — and the market pricing mechanisms reflect this unique constraint. Wholesale electricity prices are set through auctions that clear every five minutes to 24 hours in advance, depending on the market structure. In the United States, approximately two-thirds of electricity load is served by regions operating organised wholesale markets regulated by the Federal Energy Regulatory Commission (FERC).

Table of Contents

1. What Is the Electricity Wholesale Market?
2. How Wholesale Electricity Prices Are Set: The Merit Order
3. Day-Ahead and Real-Time Markets: The Two Layers
4. Locational Marginal Pricing (LMP) and Grid Congestion
5. Capacity Markets: Paying for Readiness, Not Just Output
6. Ancillary Services: The Grid’s Emergency Services
7. ISOs and RTOs: Who Runs the Wholesale Market?
8. How Wholesale Prices Flow to Your Bill
9. Frequently Asked Questions
10. Key Takeaways

What Is the Electricity Wholesale Market?

About one-third of your electricity bill is set by a commodity market you’ve probably never heard of — the wholesale electricity market. The other two-thirds covers transmission wires, local distribution infrastructure, and state policy costs. Here’s how the commodity-market third actually works.

Electricity is generated at power plants — nuclear reactors, natural gas turbines, coal plants, wind farms, solar arrays — and transmitted over high-voltage transmission lines to population centres. Before any of that power reaches a consumer, it passes through the wholesale market: the venue where generators sell bulk electricity and utilities or energy retailers buy it.

Electricity is a commodity with an unusual property: it cannot be stored at scale. Unlike oil in a tank or wheat in a silo, electrons produced at a power plant must be consumed almost simultaneously with their production. Supply and demand must balance in real time — to the second. If they don’t, grid frequency deviates from 60 Hz (in North America) or 50 Hz (in Europe), and systems trip offline. Managing this balance is the central operational challenge of wholesale electricity markets.

The deregulation backstory: The modern US wholesale electricity market structure emerged from federal deregulation in the 1990s. Before deregulation, utilities were vertically integrated monopolies — they owned generation, transmission, and distribution in a single service territory and sold electricity at regulated rates. FERC Order 888 (1996) required utilities to open their transmission lines to competitors. FERC Order 2000 (1999) encouraged formation of Regional Transmission Organizations (RTOs) to manage the grid independently of generators. These two orders created the framework for competitive wholesale markets.

How Wholesale Electricity Prices Are Set: The Merit Order

The merit order is the mechanism that determines which power plants run and at what price electricity clears in the wholesale market.

Here’s the core logic: every power plant has a short-run marginal cost (SRMC) — the cost of producing one additional megawatt-hour of electricity given that the plant is already built and operational. This is primarily fuel cost. A solar or wind farm has near-zero SRMC (no fuel). A nuclear plant’s SRMC is primarily uranium fuel and operating labour — low but not zero. A natural gas peaker plant’s SRMC is primarily the cost of gas it burns — relatively high.

The grid operator (ISO or RTO) collects bids from all generators in the region. Generators submit the minimum price at which they’re willing to generate electricity. The grid operator then stacks these bids from lowest to highest — this stack is the merit order.

The merit order in practice:

Rank	Plant Type	Typical SRMC	Why Low Bid?
1	Wind and solar	~$0/MWh	No fuel cost; operators bid at or near zero
2	Nuclear	$10–20/MWh	Low fuel cost; designed to run continuously
3	Coal (base load)	$20–40/MWh	Cheap fuel; designed for continuous operation
4	Combined-cycle gas (CCGT)	$30–70/MWh	Moderate gas fuel cost
5	Simple-cycle gas (peaker)	$60–150+/MWh	High gas use per MWh; only runs at peak demand

The grid operator accepts bids starting from the cheapest until the demand requirement is met. The last (most expensive) bid accepted sets the clearing price — this is called the uniform clearing price or market clearing price (MCP). Every generator whose bid was accepted receives this same price, regardless of their own bid amount.

This is the mechanism that made the famous Texas cold weather event in February 2021 so expensive: demand was extreme (heating load during a historically cold week), and most generation capacity was offline or constrained by extreme cold temperatures. The clearing price hit the ERCOT market price cap of $9,000/MWh — the maximum allowed — for extended periods. Consumers and retail providers exposed to real-time market prices faced electricity bills orders of magnitude above normal.

Why natural gas sets the price so often: In most North American and European wholesale markets, natural gas generation is frequently the “marginal” (last accepted, price-setting) plant because gas plants are flexible (can ramp up and down) and there are typically enough of them to clear the market at most demand levels. This means wholesale electricity prices are closely correlated with natural gas prices — particularly in gas-heavy markets like PJM and ERCOT. When gas prices spike (as in winter 2021–2022 in Europe following Russia’s Ukraine invasion), wholesale electricity prices spike proportionally.

Day-Ahead and Real-Time Markets: The Two Layers

Wholesale electricity markets operate in two sequential time frames that together handle the uncertainty of forecasting demand and generation.

Day-Ahead Market (DAM)

The day-ahead market is an auction conducted the day before delivery. Grid operators publish demand forecasts for each hour of the following day. Generators and load-serving entities submit bids and offers. The grid operator clears the market and publishes day-ahead prices for each hour.

Participants who clear in the day-ahead market are financially committed to those schedules and locked in at day-ahead prices — even if real-time conditions differ.

The day-ahead market provides:

• Price certainty for most participants (they know their cost/revenue 24 hours in advance)
• Grid planning information (the operator knows approximately what will run tomorrow)
• Hedging against volatile real-time prices

In well-functioning markets, approximately 80–90% of electricity is committed and priced in the day-ahead market.

Real-Time Market (RTM)

The real-time market handles the deviations from the day-ahead schedule — actual demand is always somewhat different from the forecast, and generators may be unable to deliver their scheduled output due to equipment issues.

Real-time prices are cleared every 5 minutes in most US markets. The clearing mechanism is the same as day-ahead (merit order) but using actual, current demand and availability conditions.

Real-time prices are more volatile than day-ahead prices — sometimes dramatically so. A sudden summer heat wave, a large plant tripping offline, or a wind generation shortfall can cause real-time prices to spike sharply above day-ahead prices within minutes.

The relationship between the two: Most market participants hedge their real-time exposure by transacting in the day-ahead market. A generator selling power into the day-ahead market at $50/MWh is protected if real-time prices fall to $20/MWh (they receive $50 regardless). A load-serving entity that bought day-ahead at $50 is protected if real-time spikes to $200/MWh. The difference between day-ahead and real-time is a “basis risk” that sophisticated participants manage actively.

Locational Marginal Pricing (LMP) and Grid Congestion

Most US wholesale markets use Locational Marginal Pricing (LMP) — a system where the electricity price varies by location on the grid, rather than being uniform across the entire region.

This sounds technical but the logic is straightforward: electricity prices should reflect not just the cost of generating the power but also the cost of getting that power to where it’s needed through the transmission network.

Why prices vary by location: The transmission grid has physical limits. A 500 kV transmission line can only carry a certain number of megawatts. When demand exceeds the line’s capacity, the grid operator faces congestion — it cannot simply deliver power from the cheapest generator to all locations.

When a transmission line is congested, the operator must:

1. Reduce output from cheap generators on the “heavy” side of the congestion
2. Increase output from more expensive generators on the “light” (demand) side

This raises the effective price at the constrained location. LMP captures this cost explicitly: the LMP at any node on the grid is the sum of three components:

LMP = Energy Component + Congestion Component + Loss Component

• Energy component: The uniform system-wide energy price (merit order clearing price)
• Congestion component: The cost of routing power around transmission constraints — can be positive or negative
• Loss component: The cost of transmission losses (electricity dissipated as heat in transmission lines)

Practical significance: A renewable energy project in a remote location — a wind farm in western Kansas, a solar farm in rural New Mexico — may face significantly lower LMPs than the system average if the transmission path between it and load centres is chronically congested. Investors modelling the economics of such projects must account for the expected LMP at the project’s location (the “bus bar” price), not the regional average.

The LMP framework also creates Financial Transmission Rights (FTRs) — financial instruments that hedge against congestion costs. Participants who face congestion risk (load-serving entities on the constrained side of a bottleneck) can buy FTRs to lock in the congestion component of their LMP.

Capacity Markets: Paying for Readiness, Not Just Output

A pure energy-only market — where generators are paid only when they produce electricity — creates a well-known problem: it may not provide sufficient incentive for generators to invest in and maintain the excess capacity needed for reliability during extreme peak demand periods.

The missing money problem: A peaking gas plant may earn most of its revenue in just a few hundred hours per year (during summer peaks). If the energy market price cap is too low, or if there are too few peak hours to generate sufficient revenue, peaker operators may retire their plants — leaving the grid with inadequate backup capacity.

The solution in most US markets: Capacity markets, which are separate from energy markets and pay generators for their availability — their commitment to be ready to produce — rather than actual output.

In capacity markets:

• Grid operators determine how much capacity (in megawatts) the region needs 3–4 years in advance to ensure reliability
• Generators and demand response resources bid to provide that capacity
• A capacity auction clears, and accepted resources receive a capacity payment (in $/MW-year)
• Generators receiving capacity payments are obligated to be available during high-demand periods

Major US capacity markets:

Market	Region	Operator
RPM (Reliability Pricing Model)	PJM (Mid-Atlantic, Midwest)	PJM Interconnection
ICAP (Installed Capacity)	New England	ISO-NE
ICAP	New York	NYISO
Not used	ERCOT (Texas)	ERCOT (energy-only market)
Not used	MISO (Midwest, South)	MISO (moving toward capacity market)

ERCOT’s energy-only model (Texas) relies on allowing energy prices to spike to very high levels during scarcity — theoretically incentivising adequate investment. The February 2021 winter storm was a stress test of this model: prices cleared at $9,000/MWh but still could not prevent widespread blackouts because the problem was generation capability in extreme cold rather than a capacity deficit per se.

Ancillary Services: The Grid’s Emergency Services

Even with a well-functioning energy market and adequate capacity, the grid operator needs additional services to maintain reliability second-by-second. These are ancillary services — paid for separately from energy.

Key ancillary service types:

Frequency regulation: The grid must maintain 60 Hz (North America) or 50 Hz (Europe). Frequency falls when demand exceeds supply and rises when supply exceeds demand. Grid operators procure regulation services from generators (and increasingly from batteries) that can adjust output up or down within seconds in response to automatic control signals. Regulation providers are paid a reservation fee plus a performance payment.

Spinning reserve: Generators that are online, synchronised to the grid, and able to increase output within 10–15 minutes. If a large generator suddenly trips offline, the grid operator needs immediate replacement capacity. Spinning reserve providers are paid to hold capacity ready even if they never have to use it.

Non-spinning reserve (operating reserve): Generators that can come online within 30 minutes. Less valuable than spinning reserve because they cannot respond as fast.

Voltage support (reactive power): The grid also needs voltage maintained within acceptable ranges. Certain generators provide reactive power — a type of power that supports voltage levels — as an ancillary service.

Demand response: Large industrial consumers who agree to curtail their electricity use on request from the grid operator. They are paid for agreeing to reduce load when needed, effectively acting as a “virtual generator” that reduces demand rather than increasing supply. Aluminium smelters, water treatment plants, and large manufacturing facilities are typical demand response participants.

Ancillary services add revenue streams for generators with flexible capabilities — particularly gas peakers, hydro, and increasingly large-scale batteries. For grid operators, procuring adequate ancillary services is a reliability management exercise that runs alongside the energy and capacity markets.

ISOs and RTOs: Who Runs the Wholesale Market?

In regions with competitive wholesale markets, the market is operated by an Independent System Operator (ISO) or Regional Transmission Organization (RTO). These are non-profit organisations that operate the transmission grid and run the wholesale markets without owning any generation or transmission assets themselves.

Major US ISOs and RTOs:

Operator	Region	States Covered	Approximate Load
PJM Interconnection	Mid-Atlantic and Midwest	DC, DE, IL, IN, KY, MD, MI, NJ, NC, OH, PA, TN, VA, WV	~900 TWh/year
MISO	Midwest and South	15 states + Manitoba	~700 TWh/year
CAISO	California	Primarily California	~280 TWh/year
SPP	Central US	14 states	~280 TWh/year
ERCOT	Texas	Most of Texas	~400 TWh/year
ISO-NE	New England	6 New England states	~125 TWh/year
NYISO	New York	New York State	~165 TWh/year

Approximately two-thirds of US electricity load falls within RTO/ISO regions. The remaining third — parts of the Southeast, Pacific Northwest, and other areas — is still served by vertically integrated utilities operating under state-regulated rate structures, without organised wholesale markets in the same sense.

FERC regulates ISOs and RTOs under the Federal Power Act, setting rules for market design, tariff transparency, and non-discrimination. State public utility commissions regulate retail electricity sales — the connection between wholesale prices and what consumers actually pay.

How Wholesale Prices Flow to Your Bill

Wholesale electricity prices represent roughly one-third of the typical residential electricity bill. The rest covers the physical infrastructure and regulatory overhead.

Typical US residential electricity bill breakdown:

Component	Approximate Share	What It Covers
Energy (wholesale)	~30–35%	The actual electricity commodity cost
Transmission	~10–15%	High-voltage lines moving power from generators to distribution
Distribution	~25–35%	Local wires, transformers, and infrastructure delivering power to homes
System benefits / policy	~15–25%	State programs: renewables subsidies, low-income assistance, efficiency programs

ISO New England data consistently shows wholesale energy as approximately one-third of retail bills for residential customers — though this varies by state and utility.

How the wholesale-to-retail connection works:

In regulated utility states, a vertically integrated utility buys (or generates) wholesale power and sells it at retail rates set by the state public utility commission. Rate cases are infrequent — sometimes years apart — so short-term wholesale price changes don’t immediately appear on customer bills.

In deregulated retail states (Texas, Illinois, Ohio, parts of the Northeast), consumers can choose their electricity supplier. Those who signed fixed-rate contracts are insulated from short-term wholesale price spikes. Those on variable-rate or indexed contracts (where retail prices track wholesale prices) are exposed to volatility. This is why some Texas residential customers received electricity bills of $5,000–17,000 during the February 2021 crisis — they were on variable contracts exposed to the $9,000/MWh real-time prices.

Frequently Asked Questions

Why can’t we just store excess electricity and use it when prices are high?

We increasingly can, but at limited scale. Battery energy storage systems (BESS) can store electricity for hours, and pumped hydro reservoirs can store energy for days. But the total installed storage capacity globally is a tiny fraction of instantaneous demand — far too small to meaningfully smooth the demand curve. Storage is growing rapidly (especially utility-scale batteries in the US and Europe), but the grid’s real-time balancing requirement will remain the fundamental constraint for decades.

Why does wind generation sometimes receive negative electricity prices?

Wind generators often bid at negative prices in real-time markets because they have zero fuel cost and, in the US, receive a Production Tax Credit (PTC) worth approximately $26–28/MWh for every MWh generated. They will continue to generate (and receive the tax credit) even if the market price is negative, as long as the price is not lower than the value of the tax credit. This is why wind-heavy markets like ERCOT and MISO regularly see negative real-time prices in overnight hours when wind is blowing and demand is low.

What’s the difference between a utility and an ISO?

A utility owns generation, transmission, and/or distribution assets and serves retail customers. An ISO/RTO owns no assets — it’s the market operator and grid coordinator. In competitive markets, an ISO coordinates hundreds of generators and utilities, running the auctions and ensuring the system stays in balance, without having any financial interest in the outcome. This independence is what allows the competitive market to function — no participant controls the market.

How does the price of natural gas affect my electricity bill?

In most US markets, natural gas generation is the marginal price-setting fuel — meaning gas plants set the wholesale electricity price for a large fraction of hours. When Henry Hub natural gas prices rise, wholesale electricity prices follow, and eventually retail rates reflect this through utility rate cases or variable-rate contract adjustments. This is why European electricity prices in 2022 — when Russian gas supply was curtailed — reached extraordinary levels: the gas price surge directly translated to electricity price surges through the merit order mechanism.

Can individuals or companies hedge their electricity price risk?

Yes. Large industrial consumers (factories, data centres, aluminium smelters) commonly hedge through Power Purchase Agreements (PPAs) — long-term contracts with renewable generators that lock in a fixed price for electricity. Utilities hedge through forward purchasing in wholesale markets. Retailers in deregulated states offer fixed-rate retail contracts that pass the hedging cost through to consumers in exchange for price certainty. The complexity of electricity hedging is high because prices vary by location, time of day, and season simultaneously.

Key Takeaways

• The electricity wholesale market is where generators sell bulk power to utilities and retailers before it reaches consumers — it accounts for approximately one-third of a typical residential electricity bill.
• Prices are set by the merit order: generators stack bids from lowest to highest marginal cost, and the last bid accepted sets the clearing price for all accepted generators.
• Two sequential market layers handle electricity scheduling: day-ahead markets commit most supply 24 hours ahead; real-time markets (clearing every 5 minutes) handle deviations.
• Locational Marginal Pricing (LMP) causes electricity prices to vary by grid location based on transmission congestion — remote renewable generators may face significantly lower prices than system averages due to congestion.
• Capacity markets (PJM, ISO-NE, NYISO) pay generators for their availability rather than output, addressing the “missing money” problem in energy-only markets and ensuring adequate peak capacity.
• Approximately two-thirds of US electricity load sits within ISO/RTO regions regulated by FERC; FERC Order 888 (1996) and Order 2000 (1999) were the foundational deregulation milestones.
• The February 2021 ERCOT (Texas) crisis, where prices hit $9,000/MWh, is the clearest recent example of how extreme demand plus constrained supply can produce catastrophic wholesale price spikes in energy-only markets.

Related Reading

To deepen your understanding of the topics covered in this article, explore these related guides: how carbon costs feed directly into wholesale power prices, the cap-and-trade programme that prices CO2 in European power markets and the fuel that still sets the marginal generation cost in many grids.