February 11, 2014

CAPACITY MARKETS FACT SHEET

What is a capacity market?

Capacity markets are complex constructs operated by entities known as regional transmission 

organizations (RTOs). RTOs are large bureaucratic, quasi-governmental entities that operate 

markets for capacity, electricity and other services, control transmission, dispatch generation and 

ensure the reliability of the grid within their region.

The capacity markets provide payments to owners of power plants who agree to stand ready to 

supply power when needed or to customers who agree to curtail power use when called upon

(known as demand response). Capacity is the maximum amount of electricity that a power plant 

is designed to produce or that a customer is willing to curtail, stated in megawatts (MW). An 

adequate supply of capacity at all times is necessary to ensure a reliable supply of power, and the

intent of capacity payments is to cover power plants’ fixed capital and other costs not recovered 

through electricity sales and other markets. Prior to the creation of capacity markets, many 

unregulated generation owners argued that the energy markets were not providing sufficient 

revenue for the construction of new resources and that an extra market was needed to provide 

this so-called “missing money.” But the capacity markets instead provided excess revenue to a 

large segment of these unregulated generators.

The RTO-operated capacity markets in the mid-Atlantic, New England, and New York City are 

mandatory markets because all capacity must be bought and sold through these constructs. 

Because of the significant amount of revenue earned from these markets and the approval by the 

Federal Energy Regulatory Commission (FERC) of market rules that restrict new supply, owners 

of unregulated merchant generation have been advocating for similar mandatory capacity 

markets in other RTOs in the Midwest, California and Texas. 

How do these markets work?

Each RTO establishes a reliability standard for all load-serving entities (such as public power 

utilities). This standard is the MW of capacity these entities must have in place through 

ownership, contracts or market purchases. The capacity markets hold periodic auctions where 

capacity is offered and purchased, typically once a year. These auctions produce a single price 

per MW that will be paid to all capacity resources, regardless of the type and cost. All customers 

within the RTO region pay the costs of these capacity payments, though there is no requirement 

that the generation owners actually use the revenue to build new power plants.

With a few exceptions, that capacity price will be in place for one year in a future time period, 

typically three years after the auction. RTOs also hold incremental auctions to allow for the 

procurement of additional capacity that may be needed in the near term. 
Resources can only be counted toward the RTO reliability standard if they “clear” the auction for 

the applicable year, meaning that the resource submitted an offer below the clearing price. Until 

recently, capacity owned by a utility or subject to a long-term contract could offer to sell into the 

auction at a zero price to ensure such clearing. Because such resources are paid under another 

arrangement, they are indifferent to the capacity auction price and submit a zero offer as a “price 

taker.”

Are the capacity markets the least-cost means to achieve reliability?

These constructs are costing consumers billions of dollars for little in return, for the following 

reasons:

Different resources have different costs. In these markets, a 50-year old coal plant is paid the 

same amount per MW and for the same duration as is a brand new highly efficient combinedcycle natural gas plant as is an agreement by a factory to curtail load when needed. As a result, 

excess windfall revenue is paid to the older depreciated plants and the revenue stream is not 

stable enough to attract investors in new resources.

The bulk of revenue has been paid to existing plants. In the PJM Interconnection (primarily 

covering Maryland, New Jersey, Pennsylvania, Virginia, West Virginia, Ohio, northern Illinois, 

and Delaware), $65 billion has been paid by consumers to generators and other capacity 

providers. Yet over 90 percent of this revenue has gone to existing generation, although many 

older plants have paid off much of their fixed costs. Moreover, most of the new generation 

capacity that has been built was done so under utility ownership and long-term contracts, not as a 

result of capacity market payments. 

Capacity markets do not ensure an appropriate mix of resource types. Because the capacity 

markets do not distinguish between technology types or specific locations on the grid, critical 

needs are not addressed, including adequate flexible ramping capability to match the variability 

of renewable resources, reliability gaps created by retiring coal plants, the coordination of natural 

gas infrastructure and delivery with the significant expansion of natural gas generation. As a 

result, the RTOs often create systems of side payments to ensure reliability, such as direct 

payments through what are known as reliability-must-run agreements to coal plants to remain in 

place to ensure reliability. 

Price signals are not effective. If transmission congestion limits the ability of capacity in one area 

to deliver lower cost power to another zone, the more congested zones may have a higher price.

The theory behind zonal price differentials is that higher prices will act as a “signal” for the 

development of new generation or transmission. But such higher prices are not effective signals

because owners of generation have no financial interest in building new resources and lowering

prices for their existing units; investors seek steady and predictable revenue flows, not 

fluctuating prices; and many other factors influence the decision to build, including land and 

transmission availability, local acceptance, and environmental rules. Transmission construction 
may alleviate these price differentials, meaning that consumer paid both for higher prices and for 

the cost of the transmission.

Do capacity markets encourage new, cleaner generation?

As described, the capacity markets by design do not incent newer resources. A few years ago,

several states located within RTOs became frustrated with the lack of new, more efficient 

generation given the billions of dollars spent on capacity payments, and sought to take control of 

their energy resource future and protect their residents from high electricity prices. New Jersey, 

Maryland and Connecticut all took steps to establish competitive bidding processes for the 

procurement of capacity for long-term bilateral contracts. 

Fearful of the lower prices that would result from the entry of new generation resulting from

these state efforts, owners of existing power plants sought to block this competition by obtaining 

approval from FERC for “minimum offer price rules” or “buyer-side” mitigation rules that 

impose a floor price on the offers from new resources, making it more difficult for these new 

plants to clear the auctions. (These rules apply just to natural gas units in PJM but to all resource 

types in New England.) A failure to clear means that the load-serving entities would pay twice 

for new capacity (once for the plant and a second time through the market). This risk makes

investment in such new plants more difficult to obtain, which raises the cost of capital. 

When capacity markets were created, the states, public power and cooperative utilities carefully 

negotiated exemptions from these minimum offer price rules for resources built by local utilities 

to supply their own load or for a state to address a reliability concern. But in response to the 

complaints from generators, FERC eliminated these negotiated and reasonable exemptions. 

What is the alternative to the capacity markets?

APPA has proposed that FERC mandate a transition from mandatory capacity markets to 

voluntary residual markets, with the primary procurement of capacity conducted by states and 

local public power and cooperative utilities in a competitive process through bilateral contracts. 

This new paradigm would replace an irrational centrally-administered construct with the ability 

of states and local utilities to determine the optimal mix of resources, and to structure a portfolio 

of contracts of varying lengths and terms, or direct ownership that would lower costs to 

consumers, maximize reliability and provide environmental benefits.