Anxiety common, consensus elusive over power market reforms at first day of FERC conference
At FERC's technical conference, stakeholders expressed worries over the long-term viability of the wholesale market model. But the federal agency's hands are tied until it has a quorum.
Anxiety was rife and consensus elusive during the first day of the Federal Energy Regulatory Commission's technical conference on state policies and wholesale market operations on Monday.
FERC commissioners and their staff questioned stakeholders from each electricity market in the Eastern Interconnect — ISO-New England, the New York ISO and the PJM Interconnection — about how state policies are affecting market functions.
FERC called for the technical conference in March after widespread concern from generators about state power incentives — such as nuclear subsidies and renewable portfolio standards — interfering with market operations.
The conference aimed to find what Acting FERC Chair Cheryl LaFleur has called a “negotiated solution” — policies that could integrate state policy aims into market functions, so lawmakers would have less reason to alter market outcomes with subsidies or mandates.
Without that kind of solution, LaFleur voiced worries in the lead-up to the conference about “unintentional re-regulation,” in which successive awarding of subsidies to various generation sources leads to a complete unraveling of the wholesale market model.
Kicking off the conference, LaFleur and Commissioner Colette Honorable laid out their key questions for stakeholders.
“Do you anticipate relying on capacity markets to attract investment in the future, or do you see all future resources being chosen by states to meet state goals?” LaFleur asked. “We can best design a solution and modify the existing resource adequacy cost construct if we have an idea of where you're headed — not just in the short run, but going forward.”
“Should wholesale markets approach cost efficiency differently in order to best serve consumers?” Honorable asked. “Should state policy be reflected in efficiency decisions … and if so what broader reforms should we consider to reflect or potentially price these resource attributes?”
State regulators, generators and economists gave a variety of answers, demonstrating a keen attention to market functioning in each power market in the Eastern Interconnect. But stakeholders displayed broad disagreement over the causes of organized market upheavals, potential solutions and even urgency of the problem — offering no easy answers for federal regulators.
State regulators and stakeholders in ISO-New England largely endorsed a mixed market model in their testimonies, saying they believe organized markets can coexist with state power policies in the short term.
“Will all the entry come from state procurements? I don’t think that’s true,” said Jeffrey Bentz, director of analysis at the New England States Committee on Electricity. “I think there will be some retirements that continue to have the markets to run as they are.”
Regulators from Massachusetts and Connecticut both embraced the role states can play in procuring resources for what they deem a market failure to site low-carbon generation. Both states have a renewable portfolio standard, Massachusetts last year passed a bill for the procurement of large-scale hydro resources and offshore wind, and Connecticut lawmakers are considering subsidies for the state’s sole nuclear plant.
However, they said, these actions need not take place by state fiat. If power markets were reorganized so they deliver the outcomes that lawmakers in each state are looking for, stakeholders said they could imagine meeting policy aims through the market, rather than by state mandate.
The difficulty, in ISO-NE and other regions, comes in how to define those policy aims and market fixes. Last month, ISO-NE officials unveiled a two-part capacity market proposal that would provide different auctions for subsidized and unsubsidized resources in an attempt to prop up capacity prices for gas generators.
LaFleur characterized that proposal as “a phased step toward the market getting out of resource adequacy,” in which each year the unsubsidized market would price fewer resources as old generators retire and are replaced by subsidized generation.
That proposal, ISO-NE officials said, could be ready for the 2019 capacity auction if federal regulators give the green light by March of next year. But it is still under consideration by the ISO’s own board of directors and stakeholders did not endorse it outright, leaving the question open as to how the region would approach resource adequacy in the future.
Like New England, the New York ISO is integrating a number of around-market policies into its wholesale markets. In addition to a 50% RPS and 80% long-term decarbonization goal, the PSC last year approved “zero-emission credits” (ZECs) to support the continued operation of upstate nuclear plants threatened by retirement.
But the New York ISO covers only one state, LaFleur noted, making the integration of state policies and market operations an easier task if common aims can be found. Even so, stakeholders were largely split on what they wanted out of the market.
NYISO CEO Brad Jones characterized the ZEC program, which funnels hundreds of millions to certain upstate plants to preserve their low-carbon generation, as a “bridge to the future.” But like other ISO-NE stakeholders, he eventually wants to find a market-based solution.
“NYISO has supported the ZEC program but we’ve been very specific that we think it needs to move toward a competitive environment, that the wholesale markets can resolve this problem,” said Jones.
The ISO is currently studying how to integrate higher carbon prices into its wholesale power markets, despite being a part of the Regional Greenhouse Gas Initiative (RGGI) — a nine-state carbon cap-and-trade system in the Northeast. Whether that price would be better instituted by New York alone or as part of RGGI was the subject of some debate, with the Sierra Club pushing the cap-and-trade system as the preferred route.
Independent generators, on the other hand, assailed the ZEC program, saying it distorts price signals for unsubsidized resources and defies federal jurisdiction.
“The mere fact that we’re here today … indicates to us that the states are in fact in some instances encroaching on FERC’s jurisdiction,” said John Shelk, CEO of the Electric Power Supply Association. “And for that reason, EPSA and many of its members are party to litigation in New York and Illinois [over ZECs].”
The concern from generators in NYISO and elsewhere is that subsidies for some resources depress the clearing price in capacity markets, making it unprofitable to source new generation. While capacity margins in each eastern RTO are healthy today, some stakeholders worry that the absence of a long-term solution to subsidy issues will deter investors from building plants from which costs must be recovered over decades.
“Any dollar an investor spends is going to be based on an expected set of revenues over many years,” said David Patton of Potomac Economics, the market monitor for NYISO. “If there’s no long-term solution at this moment and, as an investor, if you’re asking me to put money in, I don't know why they would.”
“What we’re afraid we’re going to get to is a very competitive market for rents and subsidies rather than a competitive market for generating assets,” he added.
As in ISO-NE, no consensus on solutions emerged from the NYISO stakeholder discussions. The Sierra Club proposed limiting the Minimum Offer Price Rule (MOPR) to violations of the Federal Power Act and more specifically pricing generation attributes, while EPSA’s Shelk worried that, without intervention, the state would move toward allocating “tranches,” or specific amounts, of each generation resource.
The organized market model, Shelk said, is “on the precipice of falling over unless there is a concrete plan with specific dates and deadlines.”
“In three more years, we will be at the discussion — I hate to say it — of how to contract what kind of out-of-market mechanism everyone will have to receive to keep the lights on,” he said.
Discussions among stakeholders from the PJM interconnection, the nation’s largest organized power market, largely echoed those concerns about the long-term viability of the market model.
PJM Market Monitor Joseph Bowring noted that the market has replaced about 20 GW of coal generation with competitive procurements in recent years and the main reason wholesale power prices are low is because the cost of a key input — natural gas — remains low.
Even so, he said, state generation policies can have an impact on price formation. Where FERC deems that impact is “significant,” they should intervene.
Generators say that time is now, attacking nuclear ZECs in Illinois.
“The new war on coal is subsidies,” said Bob Flexon, CEO of Dynegy. “Coal cannot compete with subsidies.”
Flexon worries that the spread of subsidies — nuclear supports are now under consideration in Ohio, Pennsylvania, New Jersey and Connecticut — will move PJM toward a “hybrid” model that effectively mixes competitive generation markets with traditional cost-of-service regulation for certain plants.
“Hybrid is the worst market. You are doomed to failure when you go down the hybrid road,” he said. “MISO’s Zone 4 is hybrid. All of the generation in southern Illinois will vanish with the latest subsidy given to Exelon … those plants were just put into the uneconomic category.”
Nuclear plant owners, however, said the subsidies are necessary because markets do not value important aspects of nuclear generation, such as fuel diversity and low-carbon attributes.
“We’re clearly missing something” when it comes to the valuation of nuclear energy, said Lathrop Craig, vice president for ISO operations at PSEG, a utility and nuclear operator. “We see customers choosing to value the same attributes nuclear brings and choosing to pay more, an indication that prices may be right from one perspective are not completely right, and that changes the view.”
Nuclear will also play a role in ensuring natural gas is not the only fuel providing a backstop for intermittent generation in a high-renewables power mix, said Richard Mroz, president of the New Jersey Board of Public Utilities. “We just do not know enough about the risk associated with that oversupply of natural gas.”
As in NYISO and ISO-NE, state regulators called for negotiated solutions rather than litigation and regulatory challenges, with Maryland PSC General Counsel Robert Erwin saying he does not want FERC or PJM to “turn into a court.” However, as in other regions, stakeholders were unable to enumerate concrete policy steps, leaving federal regulators to consider the record for future reforms.
No change without a quorum
That no consensus emerged over market issues at the first day of the technical conference is of little surprise, as the event was set up primarily as a fact-finding mission for federal regulators as they consider if and how wholesale market constructs should be reformed.
The conference continues today with testimony from academics, economists and other analysts on the state of the power markets — after which FERC can consider next steps.
But, as Chair LaFleur cautioned, FERC cannot take any concrete actions until new commissioners are approved. The five-person regulatory body needs at least three members to issue orders — and it could be down to just one commissioner after Honorable steps down in June.
“We need more commissioners to be able to address some of these things. So whoever’s listening out there in cyberspace, that would be my devout hope,” LaFleur said, quickly quipping — “@POTUS."
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