Electricity Markets

Potential Benefits of a Southeast Regional Market and Pitfalls to Avoid

If one were to map out the service areas of regional transmission organizations (RTOs) and independent system operators (ISOs) in the United States and overlay the rapidly expanding Western Energy Imbalance Market (EIM), there would be a significant amount of white space in the Southeast. This region is the largest geographic area without some form of a centrally dispatched energy market. It is therefore no surprise that various entities are giving attention to the development of a coordinated energy market in the Southeast.

The South Carolina legislature recently established a committee to study whether the state should adopt electricity market reforms, including creating or joining an RTO, establishing an EIM or joint dispatch, implementing retail choice, and other options.  Utility Dive reported in July that a group of large utilities in the region have been discussing the formation of a “centralized, region-wide, automated intra-hour energy exchange" termed the Southeast Energy Exchange Market (SEEM).

In August, R Street, a public policy research organization, released a paper, How Voluntary Electricity Trading Can Help Efficiency in the Southeast, describing the potential benefits from an RTO/ISO or Energy Imbalance Market in the region, and the Energy Transition Institute released an analysis of the production costs savings from Duke Energy’s participation in an EIM.

Energy Innovation and Vibrant Clean Energy also released a report in August, Economic and Clean Energy Benefits of Establishing a Southeast U.S. Competitive Wholesale Electricity Market, projecting $384 billion in savings by 2040, along with significant reductions in carbon emissions and the creation of hundreds of thousands of jobs, from the implementation of a “competitive Southeastern RTO.”

Lessons Learned from RTO/ISOs

While the American Public Power Association does not have a position on whether some form of organized energy market should be adopted in the Southeast, there are some important lessons to be learned from other regions.

The history of the RTOs/ISOs and the Western EIM shows that the centralized dispatch of energy over a wide geographic area can provide significant benefits, including greater efficiencies in the dispatch of energy, improved integration of variable resources, and a reduced need for individual utility procurement of generation. The California ISO reported in July that cumulative benefits from the EIM had reached $1 billion. The Midcontinent ISO estimated its benefits to be about $3.6 billion in 2019, with $3.1 billion attributable to the avoided need for new assets. The PJM Interconnection calculates its annual benefits to be between $3.2 and $4 billion, mostly due to the avoided need for new generation and the replacement of less efficient with more efficient plants (although the latter is not entirely attributable to the markets).

While the benefits associated with efficient generation dispatch in RTO/ISO markets are significant, experiences in some RTO/ISO regions point to potential drawbacks.  Mandatory capacity constructs within some RTOs/ISOs along with large proportions of non-utility merchant generation have counteracted the benefits achieved through centrally coordinated energy markets. These countervailing considerations are discussed further below.

Estimated Southeast RTO/ISO Benefits Reflect Different Model

Energy Innovation’s projection of a $384 billion cost savings by 2040 exceeds the benefits estimated by MISO and PJM on an annual basis by a far greater degree than can be explained by differences in the amount of generation in each footprint. The greater benefit is attributable to the fact that the Energy Innovation modeled something far different than an actual RTO/ISO. Instead, Energy Innovation defines a “competitive RTO” as one that “co-optimizes generation, distribution, and transmission benefits while planning to meet capacity in the most economically efficient way.” However, RTOs/ISOs are not involved in either generation or distribution resource planning or construction, and therefore do not achieve such a mathematical optimization of resources. Instead, where there is a large amount of non-utility merchant generation, the resource mix tends to be characterized by a lack of diversity, misalignment with state and local policy goals, and excess procurement – all of which are far from an optimal cost-minimizing generation mix.

The Energy Innovation study does acknowledge that the model “will certainly diverge from a real-world regional wholesale electricity market,” and that “the RTO Scenario represents a maximum for the benefits of competition in the region, as contrasted with the uncompetitive IRP Scenario.” Such a scenario is not just divergent, but almost the opposite of what has occurred in the PJM Interconnection, ISO-New England and the New York ISO (the “Eastern RTOs”), each of which is characterized by significant amounts of non-utility merchant generation and mandatory capacity constructs.

Where RTO/ISOs Create Costs

In the Eastern RTOs, the investor-owned utilities (but not public power and cooperatives) have mostly undergone retail restructuring and no longer own generation. In these RTOs/ISOs, there is a significant amount of merchant generation – where investment decisions are made outside of an integrated utility planning process and are based primarily on maximizing earnings. Because many utilities in these RTOs/ISOs no longer directly own or contract for generation, mandatory capacity constructs were created based on the argument that additional sources of revenue were needed to ensure there is an adequate amount of generation capacity in place to ensure reliability. But the retail restructured states have realized that these constructs are not producing a resource outcome that matches their policy goals and have increasingly pursued policies to encourage the development and operation of resources with certain attributes – primarily carbon-free renewable and nuclear resources. Public power and electric cooperatives have always sought to develop resources to meet specific policy goals, such as minimizing costs, reducing emissions, and increasing fuel diversity.

Many merchant generation owners have deemed such state and local resource procurement to be “out-of-market subsidies” that will lead to “price suppression.” The Federal Energy Regulatory Commission agreed and ordered rule changes in the Eastern RTOs that create impediments to state and local utility efforts to develop preferred resources – primarily in the form of price floors on offers from such resources into the capacity auctions.

The capacity constructs and these problematic rules create difficulties for states and local utilities, increase costs to consumers, and have led to a resource mix that is far from optimal. In a forthcoming report, I found that 99% of merchant generation constructed in 2019 was comprised of natural gas-fired resources. Natural gas merchant generation is concentrated within the Eastern RTOs, accounting for 87% of the new capacity within PJM and 81% in ISO-New England. Moreover, PJM procured 9,500 MW of excess capacity in 2018 and 11,000 MW in 2019.

In contrast to the merchant capacity, generation planned by utilities that came online in 2019 was about evenly split between natural gas, wind and solar with small amounts of other resources, including storage, hydropower and geothermal resources. For public power entities, about 60% of new development that year was wind, 30% solar, 7% natural gas, and 3% storage.

The key lesson for any region considering coordinated or centrally operated energy and ancillary service markets is that those markets will achieve the greatest benefits both for consumers and for the overall resource mix if states and local utilities fully retain the ability to determine their resource needs.