By Robbie Orvis

America’s wholesale electricity markets are at a turning point.

Their rules, products and software were developed in the late 20th century around a fossil fuel-based resource mix in which large central station plants are dispatched to meet unalterable demand. Marginal cost dispatch, in large part determined by fuel costs, has been the principle factor supporting prices and revenues; helping introduce competition into a growing system composed of large baseload power plants with high fixed costs and low production costs; and more flexible power plants with lower fixed costs and higher production costs.

But the 21st century electricity mix is evolving in significantly different ways from the 20th century system. The share of non-fuel resources like wind and solar is growing thanks to falling costs and states like California, Nevada and New York setting 100% clean energy goals. These resources differ in several important ways:

• They typically have near-zero production costs, creating implications for market prices and plant revenue.
• Newer resources tend to have smaller minimum unit sizes and can be deployed more quickly and in smaller sizes.
• These resources have different production characteristics than many existing plants (e.g., output tied to sunlight). Operating the grid around resource availability is not a new concept, but doing so daily for many resources is pushing operators to consider new rules and products.
• These resources can provide services better or cheaper than older ones — such as creating (very) fast frequency response using power electronics as a replacement for inertia.

Meanwhile, technological barriers limiting demand-side flexibility are disappearing through smart thermostats, water heaters and the “Internet of things.” Serious technological changes are upon us, but concomitant changes in market incentives and rules are lagging behind.

Given these changes, a new series of research papers by energy policy think tank Energy Innovation seeks to answer the question of whether and how wholesale electricity markets must evolve by asking: “Which market design provides the best framework for reliably integrating clean energy at least cost?”

A Vision of the Future for Wholesale Electricity Markets

Future market designs must answer several important questions as the resource mix evolves; for example, how can sufficient investment signals be maintained, and how will new resources be efficiently financed? Similarly, how will markets expose the value of important system characteristics, such as flexibility, through this transition? Finally, given the trend in state policy, how can future market designs address carbon policy?

Two pathways have emerged in conversations that aim to answer these questions about future markets. The “Robust Spot Market” model emphasizes improving today’s markets for energy and services, eschewing capacity markets, and relying on voluntary decentralized bilateral contracting. The “Long-Term Plus Short-Term Markets” model envisions complementing those improved energy and services markets with an advanced, centralized, forward market for needed resources and services.

Both pathways agree on important features for modern markets:

• Competitive wholesale electricity markets are a good thing: Trading over a diverse portfolio of resources augments reliability and decreases overall costs. The larger the market, the greater the benefits.
• Wholesale electricity markets need to work with external (state or federal) policies governing the electricity system, not work against (i.e., mitigate) them.
• Shorter dispatch intervals and multiperiod optimization can make markets more efficient.
• The capacity markets in use around the U.S. today, which largely trade capacity without much regard to the operational characteristics of the energy resources being traded, should be fundamentally transformed or eliminated.

But important differences exist between the pathways, driven in part by differing views on key questions:

• How big of a risk is political interference in markets?
• How much do we expect the “real world” to behave as theory suggests?
• How strong are the counterparties in markets, and how strong do we expect them to be in the future; i.e., can we expect utilities or other load-serving entities to be able to buy flexible and well hedged smart energy resource portfolios to serve customers over the long term?
• What extent can factors other than strict production costs set LMPs; i.e., congestion in the transmission system, ancillary service needs or other opportunity costs? If those other factors do play a substantial role setting LMPs, what is the risk that real-world prices (which may be in part driven by uneven retirements) are too low to attract needed flexibility resources or too high to expose their value?
• Is keeping voluntary bilateral markets (which already underlie centralized wholesale electricity markets) decentralized the best approach, or would centralizing and organizing those bilateral contracts be more beneficial?

Wholesale electricity markets will evolve differently in various regions, but the macro issues facing markets are extremely important for grid managers to study and deliberately consider as the electricity system decarbonizes.

Robbie Orvis is the Director of Energy Policy Design at Energy Innovation, where he works on the firm’s Energy Policy Solutions and Power Sector Transformation programs.