Wholesale Electricity Markets: The Times They Are a Changin' (Again)

Starting in the late 1990s, many regions around the United States changed the way they regulated the electric power system. Vertically integrated monopolies and state-regulated rates gave way to systems in which generation is separated from transmission and distribution and generators compete in wholesale electricity markets.

Over the past 20 years, a common framework for the design of these markets has emerged across the independent system operators (ISOs) and regional transmission organizations (RTOs) that manage transmission grids and operate these markets. In general, these systems do not use a single commodity market, but rather consist of a collection of markets for products and services. These include: capacity markets to incentivize new investments, day-ahead and real-time (hour-ahead) energy markets for electricity, and multiple products, such as reserves, that are collectively referred to as ancillary services markets. Generation asset owners operating within an RTO/ISO must increase the asset's combined revenue from these several markets, as well as long-term bilateral supply contracts.

Competitive Wholesale Markets: Concerns and Stressors

The current paradigm of competitive wholesale markets is widely viewed as successful at effectively managing the operations and reliability of power systems and at keeping electricity prices for consumers relatively low. In addition, over the past two decades, there has been considerable new investment in transmission and in generation, primarily from natural gas, wind, and solar. Recently, however, concerns have been growing from a number of perspectives that the current paradigm for electricity markets may need adjustments.

The concerns stem from the confluence of two major stressors on the electricity market. The first stressor is the dramatic and sustained decrease in the price of natural gas due to extensive shale gas development. This may seem counterintuitive, and indeed the low gas prices have directly led to lower electricity prices, which benefit consumers. To understand why this is a stressor requires a quick review of generation economics.

Decrease in Natural Gas Prices Drives Down Inframarginal Rents

First, the day-ahead and real-time markets, which determine the output of each generator and the price received in each hour, are generally implemented as auctions. Generators submit their variable costs as bids, and the system operator orders the bids by increasing cost. The last generator required to meet demand for that hour is the marginal generator, and its cost determines the price received by all generators for that hour. In the United States, the marginal generator is most frequently a natural gas plant, either a combined cycle or, more likely, a combustion turbine. Thus, the natural gas price directly translates into the electricity price paid to all generators.

All other generators besides the marginal unit that are producing electricity at a given hour—the inframarginal generators—receive revenues in excess of their variable costs for that hour, since the price is above their cost. Generators must use this inframarginal rent to cover their fixed costs, and revenues beyond that provide profit. The sustained lower electricity prices of the past several years have led to a significant reduction in these inframarginal rents to the point where some generation types are no longer economically viable. This is particularly a problem for generation technologies that have relatively high fixed costs and low variable costs. This includes nuclear, coal, hydro, wind, and solar; nuclear and coal generators have been particularly hard hit.

Fixed costs that are not covered from revenues from the energy markets can be supplemented from the other markets, particularly capacity payments from capacity markets. However, most capacity markets were not designed to compensate large baseload technologies, but rather to incentivize peak generation investments, such as combustion turbines. As a result, the combined revenues across the various electricity markets have fallen to a level that does not allow some of these units to fully recover their costs.

State-Level Subsidies Distort Price Signals

This leads to the second stressor on electricity markets: a set of state-level policies that have proliferated across many states that participate in RTOs. One type of policy is a subsidy for a particular technology type, such as nuclear, coal, wind, solar, or even hydro, depending on the state. Other policies mandate some share of generation must come from specific technologies, most notably renewable energy standards. Finally, in some states, individual specific power plants are being subsidized.

Although each of these policies are motivated by important policy goals of that state, these policies nevertheless distort the price signals that markets use to induce efficient decisions. It also raises issues of competitiveness and fairness for non-subsidized technologies and for units in states with less generous support. The level of activity of this type, particularly in support of nuclear and coal technologies, has increased rapidly in response to the drop in natural gas and electricity prices.

Impact of Stressors on Stakeholders

Concern about these recent trends is widely shared across a range of stakeholders in the electricity market, although often for different reasons. Owners of high-fixed-cost generation, particularly nuclear and coal, find themselves with uneconomic assets. Even state-level support is unlikely to be the first choice of many of these firms, nor would they necessarily want to continue to rely on state legislatures for the long-run viability of these units.

Owners of other generation technologies may feel disadvantaged participating in markets where prices are distorted by subsidies for competing units. This situation could discourage new investment across technology types. Finally, many RTOs are increasingly worried about both the distortions to the markets they operate, and also the long-run reliability and resilience of the power system for which they are responsible. The resilience concern stems primarily from the increasing share of generation from natural gas and intermittent renewables. The security of natural-gas-dominated systems will depend on the natural gas pipeline infrastructure and the gas markets.

A Look Toward Future Reforms

The broad range of organizations that are unhappy with current trends raises the likelihood that market designs will be altered in the future, in either minor or even dramatic ways. The ideas in circulation for reforms are as varied as are the reasons for worrying. There are generally three broad types of proposals.

One type of proposal is a patch, in which one or more new markets are added to the existing suite of capacity, energy, and ancillary services markets. For example, a market for a fuel security product could provide additional payments to nuclear or coal units; natural gas units with on-site storage or dual-fuel capability could also compete to provide this service. Another example is a proposal to add a carbon price to electricity markets; in addition to environmental motivation, this would provide additional revenues to nuclear and other non-fossil generation.

A second type of proposal is the retreat type, which argues for the advantages of a return to average-cost or cost-of-service pricing, or perhaps a hybrid of this with some market elements.

A third type of proposal is an overhaul, in which the fundamental paradigm of capacity/energy/ancillary services and their relative roles is rethought. This type of proposal would value a competitive market approach, but perhaps with different and fewer products and services, rather than more.

It is far too soon to say in which direction electricity markets will evolve in the next decade. The one outcome that does seem likely is that market configurations will change, and that existing assets and new investments will need to operate under this evolving system.