Integrating Renewable Energy Part 2: Electricity Market & Policy Challenges

Written by Kasparas Spokas

The rising popularity and falling capital costs of renewable energy make its integration into the electricity system appear inevitable. However, major challenges remain. In part one of our ‘integrating renewable energy’ series, we introduced key concepts of the physical electricity system and some of the physical challenges of integrating variable renewable energy. In this second instalment, we introduce how electricity markets function and relevant policies for renewable energy development.

Modern electricity markets were first mandated by the Federal Energy Regulatory Commission (FERC) in the United States at the turn of millennium to allow market forces to drive down the price of electricity. Until then, most electricity systems were managed by regulated vertically-integrated utilities. Today, these markets serve two-thirds of the country’s electricity demand (Figure 1) and the price of wholesale electricity in these regions is historically low due to cheap natural gas prices and subsidized renewable energy deployment.

The primary objective of electricity markets is to provide reliable electricity at least cost to consumers. This objective can be further broken down into several sub-objectives. The first is short-run efficiency: making the best of the existing electricity infrastructure. The second is long-run efficiency: ensuring that the market provides the proper incentives for investment in electricity system infrastructure to guarantee to satisfy electricity demand in the future. Other objectives are fairness, transparency, and simplicity. This is no easy task; there is uncertainty in both supply and demand of electricity and many physical constraints need to be considered.

While the specific structure of electricity markets varies slightly by region, they all provide a competitive market structure where electricity generators can compete to sell their electricity. The governance of these markets can be broken down into several actors: the regulator, the board, participant committees, an independent market monitor, and a system operator. FERC is the regulator for all interstate wholesale electricity markets (all except ERCOT in Texas). In addition, reliability standards and regulations are set by the North American Electric Reliability Council (NERC), which FERC gave authority in 2006. Lastly, markets are operated by independent system operators (ISOs) or Regional Transmission Operators (RTOs) (Figure 1). In tandem, regulations set by FERC, NERC, and system operators drive the design of wholesale markets.

Wholesale energy market ISO/RTO locations (colored areas) and vertically-integrated utilities (tanned area). Source: https://isorto.org/

Before we get ahead of ourselves, let’s first learn about how electricity markets work. A basic electricity market functions as such: electricity generators (i.e. power plants) bid to generate an amount of electricity into a centralized market. In a perfectly competitive market, the price of these bids is based on the costs of an individual power plant to generate electricity. Generally, costs are grouped by technology and organized along a “supply stack” (Figure 2). Once all bids are placed, the ISO/RTO accepts the cheapest assortment of generation bids that satisfies electricity demand while also meeting physical system and reliability constraints (Figure 2a). The price of the most expensive accepted bid becomes the market-clearing price and sets the price of electricity that all accepted generators receive as compensation (Figure 2a). In reality it is a bit more complicated: the ISO/RTOs operate day-ahead, real-time, and ancillary services markets and facilitate forward contract trading to better orchestrate the system and lower physical and financial risks.

Figure 2. Schematics of electricity supply stacks (a) before low natural gas prices, (b) after natural gas prices declined, (c) after renewable deployment.

Because real electricity markets are not completely efficient and competitive (due to a number of reasons), some regions have challenges providing enough incentives for the long-run investment objective. As a result, several ISO/RTOs have designed an additional “capacity market.” In capacity markets, power plants bid for the ability to generate electricity in the future (1-3 years ahead). If the generator clears this market, it will receive extra compensation for the ability to generate electricity in the future (regardless of whether it is called upon to generate electricity) or will face financial penalties if it cannot. While experts continue to debate the merits of these secondary capacity markets, some ISO/RTOs argue capacity markets provide the necessary additional financial incentives to ensure a reliable electricity system in the future.

Sound complicated? It is! Luckily, ISO/RTOs have sophisticated tools to continuously model the electricity system and orchestrate the purchasing and transmission of wholesale electricity. Two key features of electricity markets are time and location. First, market clearing prices are time dependent because of continuously changing demand and supply. During periods of high electricity demand, prices can rise because more expensive electricity generators are needed to meet demand, which increases the settlement price (Figure 2a). In extreme cases, these are referred to as price spikes. Second, market-clearing prices are regional because of electricity transmission constraints. In regions where supply is low and the transmission capacity to import electricity from elsewhere is limited, electricity prices can increase even more.

Several recent developments have complicated the economics of generating electricity in wholesale markets. First, low natural gas prices and the greater efficiency of combined cycle power plants have resulted in low electricity bids, restructuring the supply stack and lowering market settlement prices (Figure 2b). Second, the introduction of renewable power plants, which have almost-zero operating costs, introduce almost-zero electricity market bids. As such, renewables fall at the beginning of the supply stack and push other technologies towards the right (higher-demand periods that are less utilized), further depressing settlement prices (Figure 2c). A recent study by the National Renewable Energy Laboratory expects these trends to continue with increasing renewable deployment.

In combination, these developments have reduced revenues and challenged the operation of less competitive generation technologies, such as coal and nuclear energy, and elicited calls for government intervention to save financial investments. While the shutdown of coal plants is welcome news for climate advocates, nuclear power provided 60% of the U.S. carbon-free electricity in 2016. Several states have already instated credits or subsidies to prevent these low-emission power plants from going bankrupt. However, some experts argue that the retirement of uneconomic resources is a welcome indication that markets are working properly.

As traditional fossil-fuel power plants struggle to remain in operation, the development of new renewable energy continues to thrive. This development has been aided by both capital cost reductions and federal- and state-level policies that provide out-of-market economic benefits. To better achieve climate goals, some have argued that states need to write policies that align with wholesale market structures. Proposed mechanisms include in-market carbon pricing, such as a carbon tax or stronger cap-and-trade programs, and additional clean-energy markets. Until now however, political economy constraints have limited policies to weak cap-and-trade programs, investment and production tax credits, and renewable portfolio standards.

While renewable energy advocates support such policies, system operators and private investors argue these out-of-market policies could potentially distort wholesale electricity markets by suppressing prices and imposing regulatory risks on investors. Importantly, they argue that this leads to inefficient resource investment decisions and reduced competition that ultimately increases costs for consumers. As a result, several ISO/RTOs are attempting to reform electricity capacity market rules to satisfy these complaints but are having difficulty finding a solution that satisfies all stakeholders. How future policies will be dealt with by FERC, operators and stakeholders remains to be resolved.

As states continue to instate new renewable energy mandates and technologies yet to be well-integrated with wholesale markets, such as battery storage, continue to evolve and show promise, wholesale market structures and policies will need to adapt. In the end, the evolution of electricity market rules and policies will depend on a complex interplay between technological innovation, stakeholder engagement, regulation, and politics. Exciting!

Kasparas Spokas is a Ph.D. candidate in the Civil & Environmental Engineering Department and a policy-fellow in the Woodrow Wilson School of Public & International Affairs at Princeton University. Broadly, he is interested in the challenge of developing low-emissions energy systems from a techno-economic perspective. Follow him on Twitter @KSpokas.

Leave a Reply

Your email address will not be published. Required fields are marked *

This site uses Akismet to reduce spam. Learn how your comment data is processed.