Time to Update Wholesale Electric Markets – But Don’t Forget the Benefits of Traditional Utility Regulation

Time to Update Wholesale Electric Markets – But Don’t Forget the Benefits of Traditional Utility Regulation
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The blackouts and price spikes in Texas this winter have raised doubts about the viability of wholesale electric markets like the Electric Reliability Council of Texas (ERCOT). Over four million people lost power, there were numerous blackout-related deaths, and some customers saw electric bills totaling thousands of dollars. Moreover, a recent analysis by The Wall Street Journal determined that Texans have paid $28 billion more than customers in regulated markets since 2004.

And Texas is not an anomaly. From the Polar Vortex in the Northeast and Mid-Atlantic in 2014 to the blackouts in California in August 2020, we are seeing a disturbing trend showing that the American power grid is less reliable when it is most needed – during extreme cold and heat. Though much analysis remains to be done about what happened in Texas, these reliability issues are rooted in the failure of the wholesale market paradigm to evolve with changes in energy generation and public policy preferences.

The development of wholesale electric markets over the past two decades has been one of the biggest experiments in harnessing competition to drive efficiency and benefit electric customers. But the premises on which the electric market paradigm was designed are changing. We need a rethink of wholesale electric markets, including a reconsideration of and comparison to the benefits of the state-regulated utility model.

Before the development of wholesale electric markets for transmission and generation of electricity toward the end of the 1990s, the generation, transmission, and distribution of electricity was provided primarily by vertically integrated utilities with exclusive service territories and authorized rates of return set by state public utility commissions.  

After the high-voltage transmission system was opened up and generators of electricity were allowed to bid into organized markets to provide power, the wholesale sale of electricity was no longer just a rate-regulated necessity; instead, electric generation and sales became a commodity in an administrative market designed to drive down capital and operating costs through competition. Today, there are seven regional regional transmission organizations (RTOs) and independent system operators (ISOs) serving nearly 70% of American electric customers.  

But in recent years, issues of cost, reliability, and regulatory complexity in these electric markets have raised questions about the viability of RTOs. The problem, however, is not necessarily electric markets as an idea; rather, the premises that underlie the current market structure have changed, but the market structure paradigm has not.

When the wholesale markets were created, virtually all power was generated by consuming fuel – coal, natural gas, and uranium. In the early 2000s, coal and nuclear generation was relatively cheap, natural gas was relatively expensive, and the generation-dispatch stack was designed to use the cheapest generation first. Coal and nuclear units often would run 24/7. Natural gas generation, using more expensive fuel (pre-fracking), would supplement energy needs and typically set the clearing price in energy auctions.

The key here was that all megawatts of electricity were fungible. The market’s only concern was whether there was enough electricity to serve load reliably as electricity demand went up and down and to generate power in the most efficient and economical manner.  

With concerns over pollution and climate change, a number of states that were part of RTOs and ISOs started to pass renewable portfolio standards (RPSs) mandating that a percentage of the electricity consumed come from renewable resources. Congress passed investment tax credits and production tax credits to encourage the development of renewables.

These subsidies have changed the market’s fundamental premises. First, no longer is every electron fungible; electricity generated by renewables is preferred. Second, those renewable resources have no fuel costs. Third, out-of-market subsidies allow renewables to participate in the market and provide a price advantage when bidding in the market, skewing price formation and the allocation of resources. Fourth, because renewables, such as wind and solar, are not always available, other generation resources are still needed to keep the lights on.

The financial effects have varied. Renewables, inexpensive natural gas, and environmental regulations made coal and nuclear less economical to operate, and many coal and some nuclear generators retired. Older, less efficient gas plants have been displaced, as well. All of this would be the proper result in a true market, but the mixture of mandates and subsidies distorted price signals, undermining the notion that RTOs were competitive, free markets. 

Moreover, because the markets use a clearing price model where all generation resources bid and selected in an auction are paid the same marginal price, customers are not necessarily receiving all of the financial benefits that “cheap” renewables could provide. Customers are paying the natural gas clearing price for wind and solar resources; and renewable generators and their investors are not passing along the benefits of free fuel, federal tax credits, and state subsidies to customers, but are pocketing the economic windfall.

Markets are also facing reliability and resiliency challenges. In traditionally regulated markets, investor-owned utilities submit detailed integrated-resource plans that explain how they will meet future electric needs through a mix of generation resources. Meanwhile, electric markets were designed to pick short-term least-cost resources through these clearing prices.

Unfortunately, these energy prices in electric markets are failing to provide the necessary revenue to cover the capital costs for the power plants needed to ensure system reliability. Capacity-pricing systems instituted by various RTOs and ISOs are failing to ensure reliability. And Texas’ ERCOT, with its “energy only” market and integration of subsidized resources, is just the most recent example of market failure to properly price reliability.  

Finally, a big disconnect in the electric markets is that no one has an obligation to serve customers. Each generator determines if it wants to bid into the market each day; it may or may not be picked to operate. And though a generator may face a financial penalty for its failure to deliver power on a particular day, there is no overall obligation to make investments in weatherization and secure fuel supplies to ensure that it can serve end-use customers. Likewise, RTOs have no obligation to serve end-use customers. When one takes an objective look, it becomes apparent that these RTOs and ISOs are designed to serve and benefit the participants in the market – generators, marketers, investors, and large industrial or commercial customers – not residential customers and small businesses.

It’s time to rethink the electric wholesale markets so as to better accommodate public policy goals, promote reliability, and reduce costs to customers. To do so, policymakers should consider the following:

1. First, restructure electric markets to better facilitate clean energy goals, reliability, and customer benefits by creating a reliability market (and eliminate capacity markets) that would identify the attributes needed for reliability, including dispatchability on demand, secure fuel sources, and winterization.

2. Second, abandon the old practice of establishing reserve margins based on absolute peak. Instead, use net peak or relative peak to address reliability. California and its ISO, CAISO, have demonstrated that the traditional ways of measuring peak load and the resources to meet it do not work as we deploy more renewables. Therefore, markets should determine if the grid has the right type of generation to meet demand when needed, especially when intermittent renewable resources are unavailable, or the weather is extremely cold or hot.

3. Ensure that all users of the grid pay for it by promoting transparency. There is a growing trend for large electricity consumers to access 24/7 grid-based electricity from coal, nuclear, and natural gas, but use offsets to claim that they are using 100% renewables. This approach supports renewables up to a point; but as renewables make up larger proportions of the generation mix, its value is reduced, and indirect costs for reliability are borne by other generators and other customers. There needs to be transparency about how the grid works and the fuels used to support it. This approach would promote lower costs to consumers and boost grid reliability. In the long run, it would likely help achieve clean energy goals by making it clear where the challenges to achieving those goals remain and ensure that proper investments are made.

4. Rethink how transmission is planned, built, and paid for. The right type of transmission is not being built to expand access to renewables. Planning transmission, figuring out what is cost-effective, and allocating costs have all proved vexing. In addition, impacts to landowners and environmental justice communities from transmission build-outs need to be considered.

5. Look to what is working in the states that have not joined an RTO or ISO. In these states, regulators use resource planning to promote clean energy, ensure reliability, and protect ratepayers. In the Southeast, one of the major regions without an RTO, ISO, or EIM (energy imbalance market), electric rates are below the national average, reliability is strong, and renewables are responsibly integrated onto the grid and their benefits passed on to customers. Customers are protected because state regulators provide oversight for utility investments, rates, and reliability. In addition, transmission costs can be socialized as a public good so as to allow more renewables on the grid.

The electric grid is in transition. This change must be acknowledged and dealt with forthrightly. Markets need to be rethought, including consideration of the benefits of the traditional state-regulated utility model. Only then can we ensure that more of the benefits of renewables are passed on to customers, that reliability is maintained, and that state public policy goals are achieved.   

 

Bernard L. McNamee is a former Commissioner on the Federal Energy Regulatory Commission. He is a partner at McGuireWoods LLP, senior advisor at McGuireWoods Consulting, and The Street Distinguished Visiting Professor of Law at Appalachian School of Law. 



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