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

ens ure the reliability of the grid within their region.

The capacity markets provide payments to owners of power plants who agree to stand re ady 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 , st ated 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 o ther 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 unreg ulated 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 utilitie s ). This standard is the MW of capacity these entities must have in place through ownership, contracts or market purchase s

. The capacity markets hold periodic auctions where capacity is offered and purchased , typically once a year. These auc tions 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 actual ly 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 add itional 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 s ubmit ted an offer below the clearing price. Until

recen tly, 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 differe nt 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 combined

cycle 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 Marylan d, 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 m any 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 e nsure an appropriate mix of resource types

. B ecause the capacity markets do not distinguish between technology types or specific location s 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 resul t, 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 transmi ssion 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 se ek 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 constructionmay 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 d o 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 gene ration resulting from these state efforts, owners of existing power plants sought to block this competition by obtaining approval from FERC for “minimum offer price rule s ” 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 c apacity (once for the plant and a second time through the market ). This risk mak es 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 utili ties 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 addre ss a reliability concern. But in response to the complaints from generators, FERC eliminated th ese 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 b y state s 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

.