By Rich Heidorn Jr.
NASHVILLE, Tenn. — PJM’s Capacity Performance rules got little love last week during a panel discussion on the role of states versus markets in procuring electric generation.
Other Eastern RTO capacity markets and New York’s planned nuclear subsidies also came under fire in a discussion at the National Association of Regulatory Utility Commissioners summer conference.
Economist William Hogan, of the Harvard Kennedy School, and Allison Clements, a Natural Resources Defense Council representative to the Sustainable FERC Project, led the criticism of PJM’s Capacity Performance rules.
Clements said the environmental community does not have a preference between wholesale markets and bilateral trading. “But if [markets are] going to exist, we want to make sure that the rules are fair so that clean energy resources can compete to provide services,” she said.
Aside from FERC Order 745, which helped demand response resources enter the wholesale markets, she said, “we haven’t been that successful, and we’ve come to this point where the energy/capacity market construct, at least in the Eastern Interconnect RTOs … [is] broken.”
Clements said PJM’s Capacity Performance rules, which favor baseload generation available 24 hours a day year-round, “locks in this traditional, outdated resource mix view” that favors nuclear energy over renewables and DR, a case NRDC and other environmental groups made last month in asking the D.C. Circuit Court of Appeals to review FERC’s approval of PJM’s rules. (See Clean Energy Advocates Appeal FERC’s Capacity Performance Rulings.)
While CP rules allow summer and winter resources to aggregate a single capacity offer, no aggregate offers were submitted in the first Base Residual Auction with CP for delivery year 2018/19. In the second auction under the new rules in May, only 6% of cleared DR resources qualified as CP, compared with 9% of wind and one-tenth of 1% of solar.
“Because renewables can’t provide baseload Capacity Performance … the capacity they do provide doesn’t get counted, which means that your state policy to encourage clean energy that your customers are paying for isn’t getting full value,” Clements said.
Hogan also was critical of CP and of FERC’s oversight. He said the commission needs to ask the question: “‘Are the changes we’re making in market design going in the right direction?’ And when it’s not, to stand up and face it squarely and don’t succumb to double talk.”
PJM’s CP penalty mechanism means generators could face penalties of $5,000/MWh for shortfalls while the demand side will be seeing prices that are only $500/MWh, Hogan said.
“This can’t make sense,” he said. “You should be able to test these designs against [a] Platonic vision … and where there’s a dramatic difference like that you should be able to ask ‘Why are we doing this? Why are we sending signals to the generators and not to the load when we get into critical capacity situations?’”
Clements said it’s not necessary to abandon capacity markets and go to shortage pricing, as in ERCOT. “I think there’s something in between there,” she said, praising the “flexibility products” being offered in CAISO and MISO.
Jay Morrison, vice president of regulatory issues for the National Rural Electric Cooperative Association, also contended that RTO capacity markets aren’t working.
“Where’s the tangible evidence that they’re failing in their mission?” asked panel moderator and NARUC President Travis Kavulla, noting the new resources that have cleared PJM and other capacity markets.
“My litigation budget,” Morrison quipped. “I could save a lot of money if these markets were working properly.”
But Morrison also challenged Hogan. “There’s no Platonic ideal of a market out there,” he said. “Markets are designed for specific purposes. These markets should be designed to meet the needs that the consumers express through the utilities that serve them, through their politically elected or appointed officials.
“The market should be designed to meet the needs that the consumers want,” he continued. “The consumer shouldn’t be asked to buy the product that the market says is the right product. We need to remember which is the dog and which is the tail.”
Morrison said states have intervened — sometimes running afoul of FERC jurisdiction — “because there are important values that they are trying to pursue … that aren’t important to the market operators and aren’t incorporated into the market design.”
“Yes there are new resources [from capacity markets], but are they the right resources?” Morrison asked. “Yes, there are new resources, but are some of the people investing in them risking that they’re going to pay twice? Both for the resource in which they’re investing and the one that the market operator says they’re supposed to buy.”
RTOs have developed valuable new products for managing system operations but have not responded with the environmental or risk management products sought by consumers and state policymakers, he said. “Those are the kind of products for which bilateral markets are ideally suited,” he said. “And so long as we have the minimum offer price rule [and] buyer-side mitigation, we have trouble accessing those resources.”
The only panelists to offer much support for RTO capacity markets were Michael Haugh, assistant director of analytics for the Ohio Consumers’ Counsel, and Sarah Novosel, senior vice president and managing counsel for Calpine.
Haugh said PJM’s markets have brought new generation to serve Ohio and encourages sharing of resources among states, which reduces costs.
Novosel said her company would prefer capacity markets in all regions. She reserved her criticism for state interventions, such as proposals in Illinois, Connecticut, New Jersey and New York to subsidize nuclear plants. She said New York’s zero-emission credit program for its upstate nuclear fleet is discriminatory, will hurt markets and intrudes on federal jurisdiction, in violation of the U.S. Supreme Court’s ruling in Hughes v. Talen. (See related story, New York Adopts Clean Energy Standard, Nuclear Subsidy.)
“We’re troubled by all of these proposals because all of them, we feel, are going to undermine the wholesale markets, which competitive generators rely on for our revenue,” she said. “And once you start to pull the string and start to unravel these wholesale markets, you’re going to end up with having other generators who rely on the wholesale market needing a subsidy or long-term contract in order for them to also receive sufficient revenue to continue operations. … And by entering long-term contracts, you’re putting the risk back onto the ratepayers.”
Novosel acknowledged that “we don’t have any answers — yet.” But she said she is encouraged by the efforts being taken by RTOs to address the challenges. She cited PJM’s white paper in May and its Aug. 18 Grid 20/20 forum on public policy goals and market efficiency, and the New England Power Pool’s planned stakeholder meeting on Aug. 11 on how to preserve markets while also reducing states’ carbon footprints. “We’ve got a lot of smart people in this industry. We can come together and come up with a solution that works,” she insisted.
The simplest fix for the plight of nuclear generation and the desire for less polluting resources, the panel agreed, was to internalize the cost of carbon into the markets — a no-brainer to economists but a nonstarter for many politicians.
“I just don’t believe that” enacting a carbon tax is impossible, Hogan said, noting that he heard similar warnings before ERCOT’s move to scarcity pricing.
“I’ve been involved in lots of things that were ‘politically impossible’ when we first started talking about them,” he said. “And now they’re old hat and conventional wisdom.”
