US Northeast power markets are unwell. What’s next?

If the electricity markets of the North Eastern US were patients in a hospital, their condition would not be improving, and some might even describe it as critical.

New England’s redesigned capacity market, which ran in February under new rules for the first time, closed at a clearing price that was the lowest in six years. The second stage of the auction, designed to accommodate subsidized resources, cleared just 54 MW at $0/kW-m.

PJM Interconnection’s energy and capacity markets are both in the process of being redesigned, with the 2019 capacity auction recently delayed for a second time due to the complexity of the proceeding and delay from federal regulators. The regional transmission operator (RTO) and independent system operator (ISO) operates across 13 US Northeastern states and Washington DC. Serving 65 million people, PJM is the largest US power market.

And New York’s less liquid, short-term capacity market, along with its energy and ancillary services markets, could undergo design changes in the near term to improve price signals needed to attract new power plant investment and address other issues.

Capacity markets are intended to ensure there is adequate capacity at a future date by paying generators to commit to future supply obligations. They get paid for guaranteeing their plants will be available to provide a certain volume of power at a specific future date.

These markets are also supposed to encourage older, less efficient and often more expensive-to-run plants to retire, while incentivizing construction of newer more efficient generation resources.

However, increasing volumes of resources that receive out-of-market payments through mechanisms like state renewable portfolio standards can lower power market prices, because these resources offer in at prices below their operating costs. Generators that do not receive such payments complain they are disadvantaged by an uneven playing field.

Additionally, an increasing number of states, most recently Ohio, are providing financial support to nuclear generators. The reasoning is that nuclear has struggled in merchant markets due to historically low power prices that have followed natural gas prices lower as a result of the shale-gas-fueled supply boom.

The introduction of out-of-market payments for one form of generation can also benefit another. In light of the passage of House Bill 6, First Energy Solutions, the owner of the Ohio nuclear generators which were recently saved by Ohio, rescinded the retirement for 1.5 GW of the Sammis coal-fired plant (slated to retire in 2022), in addition to recalling the retirements for the 2 GW of nuclear capacity previously expected to retire in 2020/21.

S&P Global Platts detailed the pressure facing wholesale competitive power markets in a story last year and while it is clear that capacity markets are straining under the pressure of state clean energy mandates, public policies and subsidies, it is now important to explore how the markets might evolve.

Assuming the Northeastern US power markets persevere through this upheaval, what will they look like in five or ten years?

Subsidies swell

“Policymakers are subsidizing certain resources to enter the market and policymakers are also subsidizing other resources to prevent them from leaving,” Travis Kavulla, director of energy and environmental policy at free market think tank R Street Institute said in February testimony before the US Senate Committee on Energy and Natural Resources.

According to a 2018 report by PJM’s independent market monitor, in the PJM market alone, subsidies were estimated to total $3.8 billion, although the number would be higher today, Kavulla said.

“This is a significant number when compared to the total revenue resulting from the PJM capacity auction—$10.3 billion for 2018,” he said.

Kavulla suggests a two-staged future could occur where in the short term, more state legislatures adopt policies that subsidize politically favored sources of electricity.

“However, in the medium-to-longer term, subsidies for electricity will cause regulated rates in those subsidy-prone states to rise, even while the overall effect of the subsidies—keeping more supply than is necessary to meet regional consumer demand—will suppress prices available on the wholesale market,” Kavulla told the Senate.

Others agree these trends could lead to hybrid power market structure or greater focus on energy markets as capacity market efficacy is worn down by subsidized oversupply.

“In some cases, the price at which new and existing resources are being procured for long tenures far exceeds power prices currently reflected in wholesale markets,” Kieran Kemmerer, power market analyst with S&P Global Platts Analytics, said.

“At large enough volumes of generation, where these subsidized resources continue to partake as price takers in wholesale markets, individual states paying for a particular subsidy will begin doing so at the benefit of neighboring regions, where that power will be dispatched to serve load at the lowest possible cost by the system operator,” Kemmerer said.

One can look at the province of Ontario for the effects of a hybrid power market structure, where the large majority of resources have long-term contracts with the province’s Independent Electric System Operator (IESO). “Despite wholesale power prices declining over the last decade, the total cost to ratepayers has only gone up,” Kemmerer said.

“I think in the future … you will really need to dial back on the capacity requirement and focus more on the energy side,” John Moore, director of the sustainable Federal Energy Regulatory Commission project at the Natural Resources Defense Council, said at the National Association of Regulatory Utility Commissioners ’ meeting in July.

The energy markets themselves could also change, for example, to cover multiple days to account for weather patterns, he explained.

“Over the next five to ten years, I believe Northeastern markets are going to rely more heavily on an increasing number of complex capacity and ancillary services products to counteract the deleterious effects of state subsidy programs on wholesale market price signals,” AJ Goulding, faculty affiliate of Columbia University’s Center for Global Energy Policy and president of London Economics International, said.

But some caution against this approach and maintain that accurate market-based price signals can shepherd the power markets through this transition to greater volumes of intermittent, zero marginal cost renewable generation.

“The big mistake would be to continue to create new products and subsidies in the futile attempt to replace market incentives with central procurement directives,” William Hogan, the Raymond Plank Professor of Global Energy Policy at Harvard University’s John F. Kennedy School of Government, wrote earlier this year.

Hogan argues that over the longer term, the top-down subsidy approach toward stimulating development of certain resources will diminish because the cost of the subsidies and mandates will be too great or renewable energy costs will decline to a point where the resources are fully economic without them, causing the subsidies to naturally decay and disappear.

“The good news is competitive wholesale markets have an excellent track record,” Matthew Cordaro, former utility CEO and power market expert, said in an email. “Studies have consistently found that they drive down prices and ensure ample power, in both the short and long term, while helping ensure grid reliability,” Cordaro said.

“The markets, though, are facing escalating interference from policy makers. In New York, New Jersey and Massachusetts, for example, this includes recent mandates to have large amounts of offshore wind power. Increasingly, policy makers do not only want to set carbon reduction emission levels 10 to 20 years out, they want to specify how those reductions will be attained. This distorts, and can even paralyze, markets,” Cordaro said.

Carbon price

A major policy wild card that could alleviate some of the market irritation driven by subsidized generation is pricing carbon dioxide emissions into the wholesale power markets. This would provide the price signals needed to incentivize construction of lower emission resources – a major state policy goal – while making it more expensive to operate higher emitting resources.

The New York Independent System Operator is furthest along among the regional ISOs on such an initiative, but as a single-state grid operator there are fewer stakeholders who need to agree on the approach.

“New York has attempted to address the issue more systematically with the application of a carbon price beginning in 2021-2022, but still has ambitious renewable energy mandates that will likely be met with out-of-market state procurements,” Kemmerer said. The state is supporting the development of 9 GW of offshore wind power by 2035.

“The implementation of something like a carbon price in PJM could aid in abating the detrimental effects of out-of-market payments to wholesale power markets, but the likelihood of accomplishing such a feat across the entirety of PJM’s footprint seems unlikely, at least in the near future,” he added.

While New York’s approach of seeking to utilize carbon pricing in dispatch “has merit,” LEI’s Goulding said, it remains to be seen whether it or any other ISO will be able to proceed with implementation.

ISOs are going to continue to struggle to adapt market designs to politically driven mandates, he said.

“Regrettably, over the next decade we are likely to see greater state-level interventions to procure more costly, unneeded generation which fails to meet environmental or reliability goals in a sensible, least cost fashion. This will make finances more precarious for the existing generators who are required to balance the system, leading to a vicious cycle of subsidies begetting more requests for subsidies,” Goulding said.