Almost 50,000 megawatts of new capacity began operating in the United States in 2016 and 2017.
These new resources were developed by everyone from traditional vertically-integrated utilities and merchant developers to factories, schools, and hospitals. Geography plays a major role in who owns this new capacity, which is in large part a reflection of the nature of the market and regulations of the area. Therefore, how this new capacity is getting funded offers some insight on the performance of the wholesale electricity markets, and particularly, the capacity markets with regard to resource development.
For many years following the implementation of retail restructuring and the development of wholesale electricity markets operated by the RTOs in the late 1990s, there was no evidence that developers would build new generation without a guaranteed stream of revenue, as provided for in a long-term bilateral contract or ownership. As recently as 2014, most new capacity was constructed under long-term bilateral contracts or utility or customer ownership, with almost no project developers choosing to rely on more volatile wholesale market revenues. Beginning in 2015, merchant generation began to increase dramatically from prior years, amounting to 19.3 percent of new capacity in 2015, 7.2 percent in 2016, and 29.1 percent in 2017.
Not only is the share of merchant capacity increasing, but the total capacity constructed nationwide has been increasing steadily, even though electricity demand declined by two percent between 2016 and 2017 and remained flat between 2015 and 2016. Moreover, retirements of capacity in 2016 and 2017 were both significantly below the new capacity constructed in each year. This mismatch is likely due to state, local, and business decisions to shift the types of capacity used to generate electricity, rather than a focus on the sufficiency of the total amount of capacity.
Utility projects more diverse
Utility projects, including both ownership and contracts, accounted for 67 percent of all new capacity. New capacity contracted for or owned by a utility shows a much greater diversity than the merchant projects, with roughly one-third comprised of natural gas, one-third solar, and one-quarter wind.
Public power accounted for 28 percent of all utility-owned or contracted new capacity, although these utilities provide 15 percent of sales to final customers. Public power also accounted for a significant share of new hydropower (96 percent) and nuclear power (92 percent).
In contrast, new merchant capacity is 86 percent natural gas and 12 percent wind, with a small amount of storage and solar. Hydropower and nuclear power are not present in the merchant projects but represent just under two and four percent of the utility projects, respectively. Almost 17 percent of the new capacity was merchant generation.
Almost all of the capacity constructed under an ownership model was constructed by utilities. Customer-owned generation tends to be smaller and has generally involved solar panels, wind turbines, combined heat and power, or biomass facilities owned by hospitals, colleges, data centers, wastewater treatment plants, factories, and others.
Half of the new capacity constructed in 2016 and 2017 was built under a bilateral contract. Nearly all contracted capacity (close to 98 percent) in those years is for renewable sources, whereas most new capacity constructed by the owner was natural gas (about 70 percent). Seventy percent of the contracted capacity was developed by a utility or community choice aggregator. All of the CCAs responsible for new capacity in these two years are in California.
Direct contracts with customers accounted for 23 percent of all contracts, including customers such as Google, Amazon, Kimberly Clark, Whirlpool, as well as hospitals and universities. Such contracts represented seven percent of all capacity in 2015, and three percent in 2014. These contracts are almost entirely for the purchase of wind and solar power.
Merchant capacity focused on natural gas and in the Eastern RTOs
Merchant generation is primarily developed in regions with restructured states and where Regional Transmission Organizations and Independent System Operators operate wholesale electricity markets. These include the PJM Interconnection (PJM), ISO New England (ISO-NE), and the New York ISO (NYISO), collectively referred to as the “Eastern RTOs.” Outside of these regions, vertically integrated utilities play the primary role in resource development, with a growing role by end users, such as factories, businesses, towns, or universities.
Most of the merchant generation that began service in this two-year period in PJM is comprised of natural gas plants. Developers cite the availability of low-cost natural gas and projected retirements of coal plants as reasons for the development. One merchant plant -- the St. Charles Energy Center, however, was refinanced as a merchant plant after the Supreme Court’s decision in Hughes v. Talen invalidated the original long-term contract with the Maryland Public Service Commission.
Natural gas plant construction in Texas in 2016 and 2017 was primarily comprised of two large plants, Wolf Hollow II and Colorado Bend II.
Six merchant wind projects were also constructed in this time, two in the PJM portion of Illinois, three in Texas, and one smaller wind farm in New Mexico that was constructed for sale into the SPP real-time market.
The increase in merchant capacity doesn’t mean merchants are assuming risk
The expansion of merchant power shows that the RTO-operated capacity and energy markets can attract new generation development despite the price volatility in these markets. However, there are several reasons to question whether this is a positive development and one that FERC and the market operators should seek to promote, such as:
- These plants all use a variety of equity financing and Term Loan B debt, which incurs a higher cost of capital than traditional debt.
- Merchant development does not involve long-term planning to determine if the development of a large amount of natural gas within one region will be beneficial or will exacerbate concerns about fuel security and resource diversity.
- The capacity market is procuring excess capacity in PJM, yet merchant development is increasing, indicating a disconnect between reliability needs and new capacity development.
- Merchant developers are unlikely to fully account for other merchant projects in their projections of natural gas, energy, and capacity prices. If the increase in merchant natural gas development causes natural gas prices to rise or energy prices to remain low, then the projected earnings from an individual project might not materialize. If that occurs, will the plant owners close the plants, or will they instead seek market rule changes to preserve these plants’ earnings?
- The growth in merchant natural gas plants may not be matched by an expansion of natural gas pipeline capacity.
An often-stated benefit of the merchant model is that the risk is shifted away from customers and on to the investors in the plant. But the history of the capacity markets in the Eastern RTOs demonstrates an unwillingness of merchant owners to accept the risks of competing supply. For example, in response to the expansion of direct procurement of capacity by the states, merchant generators have continually advocated for rules (such as the imposition of a minimum offer price for sellers) that are aimed at protecting the merchant earnings from any resulting reductions in the capacity price.
In sum, an increasing reliance on merchant generation may be at odds with the growing interest in developing specific capacity types to meet local, state, and FERC policy goals, whether they are environmental, reliability, fuel diversity, or grid resilience. Moreover, policies put in place to protect prices increase customer costs and detract from the claimed benefit that the merchant generation model shifts risk away from customers.
Read more about these trends in our report, Financial Arrangements Behind New Generating Capacity.